Otter Tail Power Company Before the Minnesota …$19,251,135 on April 16, 2016, pursuant to Minn. Stat. 216B.16, Subd. 3. The interim rate will be applied as a uniform 10.95 percent

Otter Tail Power Company Before the

Minnesota Public Utilities Commission

Application for Authority to Increase Electric Rates in Minnesota

Docket No. E017/GR-15-1033

February 16, 2016

Otter Tail Power Company

Before the Minnesota Public

Utilities Commission

Application for Authority to Increase Electric Rates in Minnesota


February 16, 2016

Volume 1 Notice of Change in Rates – Interim Rate Petition

Volume 1 Notice of Change in Rates –

Interim Rate Petition

1/3 tab

Volume 1

Index

Otter Tail Power Company Minnesota General Rate Case Documents


Volume

1 Notice of Change in Rates – Interim Rate Petition

Index

Filing Letter

Notice of Change in Rates

Notice and Petition for Interim Rates

Agreement and Undertaking, and Certification

Interim Supporting Schedules and Workpapers

Summary of Present and Interim Revenue

Interim Tariff Sheets – Redlined

Interim Tariff Sheets – Non-Redlined

Proposed Notices

2A Direct Testimony and Supporting Schedules Index Thomas R. Brause Policy Peter J. Beithon Revenue Deficiency

Proposed Test Year 2016 Cost of Service Study Class Revenue Responsibility

Stuart D. Tommerdahl Rider Roll-in

Allocation Factors Compliance Items

Tyler A. Akerman Budgeting Process Rate Base

Operating Statement

2B Direct Testimony and Supporting Schedules Index Kevin G. Moug Financial Soundness Capital Structure Cost of Capital Robert B. Hevert Return on Equity Brian H. Draxten Sales Forecast Peter E. Wasberg Employee Compensation Mark A. Rolfes

Environmental Projects


Docket No. E017/GR-15-1033 Volume

2C Amparo Nieto Fixed Charges and Rate Design Policy David G. Prazak Rate Design

2D Proposed Redlined and Non-Redlined Tariff Sheets

Index

Proposed Tariff Sheets – Redlined

Proposed Tariff Sheets – Non-Redlined

3 Required Information

Index

Required Information

A. Jurisdictional Financial Summary Schedules (Rule 7825.3900)

Definitions

Summary of Revenue Requirements – Proposed Test Year 2016

Jurisdictional Financial Summary Schedule

B. Rate Base Schedules (Rule 7825.4000)

Definitions

1. Rate Base Summary

2. Detailed Rate Base Components

a. Materials and Supplies

b. Fuel Stocks

c. Prepayments

d. Customer Advances and Deposits

e. Cash Working Capital

3. Rate Base Adjustments

4. Summary of Approaches and Assumptions Used

5. Rate Base Jurisdictional Allocation Factors

C. Operating Income Schedules (Rule 7825.4100)

Definitions

1. Jurisdictional Statement of Operating Income

2. Statement of Operating Income - Jurisdictional

3. Statement of Operating Income – Proposed Test Year 2016

4. Computation of Federal and State Income Taxes

5. Computation of Deferred Income Taxes

6. Development of Federal and State Income Tax Rates

7. Operating Income Statement Adjustments Schedule

8. Summary of Approaches and Assumptions Used

9. Operating Income Statement Allocation Factors

D. Rate of Return Cost of Capital Schedules (Rule 7825.4200)

1. Summary Schedule

2. Composite Cost of Long-Term Debt

3. Average Short-Term Debt

4. Average Common-Equity


Docket No. E017/GR-15-1033 Volume

3 E. Rate Structure and Design Information (Rule 7825.4300)

1. Proposed Test Year 2016 Operating Revenue Summary Comparison

2. Proposed Test Year 2016 Operating Revenue Detailed Comparison

3. Class Cost of Service Study

F. Other Supplemental Information

1. Annual Report and Statistical Supplement

2. Gross Revenue Conversion Factor

G. Commission Policy Information

1. Advertising

2. Charitable Contributions

3. Organization Dues

4. Research Expense

H. Travel, Entertainment, and Related Employee Expenses (Statute 216B.16, Subp. 17)

4A Work Papers

Index

A. Proposed Test Year 2016 Workpapers

1. Jurisdictional Cost of Service Study (JCOSS)

2. Class Cost of Service Study (CCOSS)

3. Functionalization

4. Input Summary

5. Proposed Test Year 2016 Adjustments

TY-01 - Normalized Plant in Service

TY-02 - BSP II Deferred Recovery

TY-03 - Rate Case Expenses

TY-04 – KPA

TY-05 - TCR MISO Removal

TY-06 – Prepaid Pension

B. Unadjusted Projected Fiscal Year 2016 Workpapers

1. Jurisdictional Cost of Service Study (JCOSS)

2. Functionalization

3. Input Summary

4. Work Papers A-D, MN

C. Interim Cost of Service Study

D. Hevert Cost of Capital Workpapers

4B Lead Lag Study

Index

Lead Lag Study

5 Budget Documentation

Index

O&M Budget Process Capital Budget Process

1/3 tab

Volume 1

Filing Letter

215 South Cascade Street

PO Box 496

Fergus Falls, Minnesota 56538-0496

218 739-8200

www.otpco.com (web site)

An Equal Opportunity Employer

February 16, 2016

Daniel P. Wolf

Executive Secretary


121 Seventh Place East, Suite 350

St. Paul, MN 55101-2147

Re: In the Matter of the Application of Otter Tail Power Company for

Authority to Increase Rates for Electric Service in Minnesota


Dear Mr. Wolf:

Enclosed is an Application for Proposed Increase in Electric Rates (Application) for Otter Tail Power

Company (OTP or the Company). This Application is being filed with the Minnesota Public Utilities

Commission (Commission) pursuant to Minn. Stat. § 216B.16, Subd. 1. The Application includes a

Notice of Change in Rates and a Notice and Petition for Interim Rates, made pursuant to Minn. Stat. §

216B.16, Subd. 3.

By filing this Application, OTP seeks authority to increase revenues by $19,295,627 or 9.80 percent to

recover the current cost of providing electric service to our customers, including an appropriate return

on common equity.

Pursuant to Minn. Stat. § 216B.16, Subd. 1, which authorizes changes in rates upon 60 days’ notice to

the Commission, the proposed rates would become effective on April 16, 2016 if not suspended by the

Commission. If the Commission suspends the proposed rate increase pursuant to Minn. Stat. §

216B.16, Subd. 2, OTP requests authority to implement the proposed rates within 10 months of the

date of the Notice, pursuant to Minn. Stat. § 216B.16, Subd. 2(a). OTP acknowledges that due to the

number of rate cases currently pending, the Commission may extend the review period pursuant to

Minn. Stat. § 216B.16, Subd. 2(f ). If the Commission suspends the proposed rate increase and

extends the review period, OTP requests authority to implement final rates no later than 90 days after

the end of the 10 month period.

As described in the Notice and Petition for Interim Rates, if the Commission suspends the proposed

rate increase as described above, OTP requests authority to implement an interim rate increase of

$19,251,135 on April 16, 2016, pursuant to Minn. Stat. § 216B.16, Subd. 3. The interim rate will be

applied as a uniform 10.95 percent increase to base rate components of customers’ bills.

http://www.otpco.com/

Daniel P. Wolf

February 16, 2016

Page 2

OTP’s Application for Proposed Increase in Electric Rates is presented in five volumes as described

below:

Application/Interim Rates Volume 1 Notice of Change in Rates

Interim Rate Petition

Volumes 2A, 2B, 2C, 2D Testimony and Schedules

Proposed Rates and Tariffs

Volume 3 Required Information

Volumes 4A, 4B Test Year Workpapers

Lead Lag Study

Volume 5 Budget Documentation

In addition, Volume 1 includes a proposed Notice of Filing to be provided to each municipality and

county in OTP’s electric service territory. A list of the counties and communities served by OTP is

attached to that Notice. The Notice and Petition for Interim Rates, also included in Volume 1,

describes the interim rate schedules for each customer class and contains proposed customer notices.

Once approved, these notices will be provided to the municipalities, counties, and customers.

Pursuant to Minn. R. 7825.2400-2600, OTP is also submitting a separate miscellaneous rate change

filing seeking to restate the Base Energy Adjustment Charge for interim rates (Docket No.

E017/MR-15-1034).

A copy of the Application has been served on the Department of Commerce – Division of Energy

Resources and the Office of the Attorney General – Antitrust & Utilities Division, and the Summary

of Filing has been served on all intervenors from the Company’s most recent electric rate case (Docket

No. E017/GR-10-239), as well as on persons on the Company’s general electric service list, as shown

on the Certificate of Service included with the Notice of Change in Rates.

OTP will cooperate fully with the Commission and the state agencies as they review the Application.

Sincerely,

/s/ THOMAS R. BRAUSE

Vice President Administration


wao

Enclosures

By electronic filing

c: Service List

1/3 tab

Volume 1

Notice of Change in Rates

STATE OF MINNESOTA

BEFORE THE

MINNESOTA PUBLIC UTILITIES COMMISSION

Beverly Jones Heydinger Chair

Nancy Lange Commissioner

Dan Lipschultz Commissioner

Matt Schuerger Commissioner

John Tuma Commissioner

In the Matter of the Application of Otter Tail

Power Company For Authority to Increase

Rates for Electric Utility Service in Minnesota


NOTICE OF CHANGE IN RATES

I. INTRODUCTION

Otter Tail Power Company (OTP or the Company) hereby provides notice of and applies for

authority from the Minnesota Public Utilities Commission (Commission) to increase retail

electric rates in Minnesota pursuant to Minn. Stat. § 216B.16 and Minn. R. 7825.3100-

7825.4600 and 7829.2400 (Notice). This Notice is for a proposed increase in revenues of

$19,295,627 or 9.80 percent.

Pursuant to Minn. Stat. § 216B.16, Subd. 1, which authorizes changes in rates upon 60 days’

notice to the Commission, the proposed rates would become effective on April 16, 2016 if not

suspended by the Commission. If the Commission suspends the proposed rate increase pursuant

to Minn. Stat. § 216B.16, Subd. 2, OTP requests authority to implement the proposed rates

within 10 months of the date of the Notice, pursuant to Minn. Stat. § 216B.16, Subd. 2(a). OTP

acknowledges that due to the number of rate cases currently pending, the Commission may

extend the review period pursuant to Minn. Stat. § 216B.16, Subd. 2(f ). If the Commission

suspends the proposed rate increase and extends the review period, OTP requests authority to

implement final rates no later than 90 days after the end of the 10 month period.

The average monthly impact of the proposed rate increase for residential customers will be $9.53

per month or $114.36 per year. The impact on individual customers will be higher or lower

depending on each individual customer’s actual electric consumption. If the Commission

suspends the proposed rate increase as described above, OTP requests authority to implement an

interim rate increase of $19,251,135 on April 16, 2016, pursuant to Minn. Stat. § 216B.16, Subd.

3. The interim rate will be applied as a uniform 10.95 percent increase to base rate components

of customers’ bills.

OTP proposes to maintain its Transmission Cost Recovery Rider and Environmental Cost

Recovery Rider in place through the course of the proceeding. At the time final rates are

implemented, OTP proposes to move project costs recovered through those riders into base rates.

OTP is also proposing changes to its rate design and terms of service.

2

This Notice includes the following information in accordance with Minnesota Statutes and

Commission rules:

II. NOTICE AND PROPOSAL REGARDING GENERAL RATE CHANGE (Minn. R. 7825.3200A(1) and 7825.3500)

A. Name, address and telephone number of utility and attorneys for the utility



Fergus Falls, MN 56537

218-739-8200

Bruce Gerhardson

Associate General Counsel


P.O. Box 496


Fergus Falls, MN 56538-0496

218-739-8475

Cary Stephenson



PO Box 496



218-739-8956

Richard J. Johnson

Moss & Barnett, A Professional Association

Suite 1200

150 South Fifth Street

Minneapolis, MN 55402

612-877-5275

B. Date of filing and date modified rates are to be effective

The date of this filing is February 16, 2016. Pursuant to Minn. Stat. § 216B.16, Subd. 1, without

a suspension, the proposed rate changes would become effective April 16, 2016, sixty days after

filing. A schedule of rates and tariffs, reflecting the overall revenue increase requested and the

proposed rate design described in the attached documents is included with the Application.

As described in the Notice and Petition for Interim Rates, if the Commission suspends the

proposed rate increase as described above, OTP requests authority to implement an interim rate

increase of $19,251,135 on April 16, 2016, pursuant to Minn. Stat. § 216B.16, Subd. 3. The

interim rate will be applied as a 10.95 percent uniform increase to base rate components of

customers’ bills.

3

C. Description and purpose of the change in rates requested

This Application for a change in rates applies to all of the Company’s retail electric customers in

the State of Minnesota, and the proposed rates are designed to produce additional revenues

sufficient to meet the Company’s cost of service for the Test Year ending December 31, 2016.

This filing complies with the provisions of Minn. Stat. § 216B.16 and the Commission’s rules

governing rate changes.

D. Effect of the change in rates

The overall proposed increase in revenues is $19,295,627 or 9.80 percent.


per month or $114.36 per year. The impact on an individual customer may be higher or lower

depending on the individual customer’s actual electric consumption.

E. Signature and title of utility officer authorizing the proposal

This Application is signed on behalf of OTP by Thomas R. Brause, Vice President

Administration of Otter Tail Power Company.

III. MODIFIED RATES (Minn. R. 7825.3200(A)(2) and 7825.3600)

Attached to this Application are rate schedules containing the proposed modifications to rates

and other changes to OTP’s rate book. These schedules and tariffs are included in Volume 2D of

the Application and are supported by the pre-filed Direct Testimony of Mr. David G. Prazak.

IV. EXPERT OPINIONS AND SUPPORTING DOCUMENTS (Minn. R. 7825.3200(A)(3) and 7825.3700)

Attached to this Application are statements of fact, expert opinions, substantiating documents

and exhibits supporting the change in retail electric rates. Pursuant to Minn. R. 7825.3700,

Thomas R. Brause provides Direct Testimony as the Company’s designated official in support of

the Application. A list of the Company’s other witnesses is provided in Mr. Brause’s Direct

Testimony.

V. INFORMATION REQUIREMENTS (Minn. R. 7825.3200(A)(4) and 7825.3800-7825.4400)

Included in this Application in Volumes 2A, 2B and 2C are the Direct Testimonies of the

Company’s witnesses, Volume 2D contains our proposed tariffs, which along with Volume 3,

Required Information, Volumes 4A and 4B, Test Year Workpapers, and Volume 5 Budget

Documentation represent the Company’s supporting documentation and contains the information

in support of a general rate increase required by Minn. R. 7825.3800 through Minn. R.

7825.4400.

4

The data for the most recent fiscal year is 2015. The projected fiscal year is calendar year 2016.

The proposed Test Year is the projected fiscal year ending December 31, 2016, with test year

adjustments. Data from 2014 is also provided for informational purposes.

VI. METHODS AND PROCEDURES FOR REFUNDING (Minn. R. 7825.3200(A)(5) and 7825.3300)

Included with this Application is an Agreement and Undertaking signed and verified by Thomas

R. Brause, Vice President, Administration of Otter Tail Power Company.

VII. NOTICE TO MUNICIPALITIES AND COUNTIES. (Minn. Stat. § 216B.16, Subd. 1)

Pursuant to Minn. Stat. § 216B.16, Subd. 1, OTP proposes to mail the Notice to Counties and

Municipalities to all municipalities and counties in OTP’s Minnesota electric service territory.

This notice includes a discussion of the proposed interim rates, as well as information regarding

the general electric rate case filing. The Company requests Commission approval of the notice so

it may be mailed in a timely fashion.

VIII. CUSTOMER NOTICE (Minn. R. 7829.2400, Subpt. 3)

OTP will use a bill insert to notify customers of its Application to increase retail electric rates

and explain the proposed rate increase. If OTP’s requested retail electric rate increase is

suspended, the Company will also explain the impact of OTP’s interim rates on customer bills in

the same bill insert.

Included in this Application is the Company’s proposed notice of its rate increase. The Company

requests approval of the customer notice so it can be included with the first bills issued with

interim rates. The Company will also be posting this Application, Testimony and Supporting

Documentation on our website (www.otpco.com/MNRateCase).

IX. FILINGS REQUIRING DETERMINATION OF GROSS REVENUE

REQUIREMENT (Minn. R. 7829.2400)

Pursuant to Minn. R. 7829.2400, OTP is submitting the following information in addition to that

required by Minn. R. 7825.3100-7825.4600.

A. Summary

A summary of the Application is attached to this notice.

B. Service; proof of service

OTP has served copies of the Application on the Department of Commerce – Division of Energy

Resources and the Office of the Attorney General – Antitrust and Utilities Division. OTP will

serve a copy of the Summary of Filing on all the parties on the general service list for OTP and

http://www.otpco.com/MNRateCase

5

on the parties in the Company’s last electric rate case proceedings (Docket No. E017/GR-10-

239). A certificate of service is attached.

C. Notice to public and governing bodies

See Sections VII. and VIII., above. In addition, OTP will, as directed by the Commission,

publish a notice of the proposed change in newspapers of general circulation in all county seats

in OTP’s Minnesota electric service territory.

D. Notice of hearing

OTP will notify ratepayers of hearings held in connection with this Application as directed by

the Commission. OTP will also publish notice of the hearings in newspapers of general

circulation in all county seats in OTP’s Minnesota electric service area, as directed by the

Commission.

X. REQUEST FOR PROTECTION OF NONPUBLIC INFORMATION

OTP balanced the need for transparency in the Application with the need to provide non-public

information in supporting data. A limited number of schedules include Protected Data designated

as Trade Secret or Not Public information according to Minn. Stat. § 13.37, Subd. 1(b). and

Minn. Rule 7829.0500. The Company has taken reasonable efforts to maintain the secrecy of this

Protected Data, which derives independent economic value, actual or potential, from not being

generally known to, and not being readily ascertainable by proper means by, other persons who

can obtain economic value from its disclosure or use. The Direct Testimony of Mr. Peter E.

Wasberg includes the following schedules that OTP requests be treated as protected data:

- Schedule 2 – 2015 Mercer Compensation Benchmark Study NOT PUBLIC

- Schedule 3 – 2015 Mercer Executive Compensation Review NOT PUBLIC

- Schedule 6 – Report of the 2015 Towers Watson Energy Services BenVal Study NOT

PUBLIC

- Schedule 7b – 5-year payouts of the OTP Mgmt Incentive Plan NOT PUBLIC

- Schedule 10a – 2015 Pension Accounting Expense Report – Mercer NOT PUBLIC

- Schedule 10b – 2015 Pension DAMP – Mercer NOT PUBLIC

- Schedule 10c – 2015 Post-retirement Medical and LTD Medical DAMP – Mercer NOT

PUBLIC

Additionally, OTP requests the compensation information provided for the sixth through tenth

highest paid employees be treated as Non-Public data pursuant to Minn. Stat. § 216B.16 Subd.

17(5). This information should be protected to preserve the privacy of these individuals. This

information also derives independent economic value from not being known to competitors who

may seek to hire these employees. OTP is filing complete Public and Non-Public versions of the

portions of this Application that contain Trade Secret or Non-Public information.

6

XI. SERVICE LIST

Pursuant to Minn. R. 7829.0700, the Company requests the following persons representing OTP

be placed on the Commission’s official service list for this proceeding:

Matthew Olsen

Manager Regulatory Proceedings and Compliance


P.O. Box 496



[email protected]

Bruce Gerhardson



P.O. Box 496



[email protected]

Cary Stephenson



P.O. Box 496



[email protected]

Richard J. Johnson

Moss & Barnett, A professional Association

Suite 1200



[email protected]

Patrick T. Zomer

Moss & Barnett, A professional Association

Suite 1200



[email protected]

mailto:[email protected]





7

XII. CONCLUSION

The Company respectfully requests consideration and acceptance of its Application.

Dated: February 16, 2016

Respectfully submitted,


Thomas R. Brause

Vice President, Administration


Subscribed and sworn to before

me this 16th day of February, 2016

/s/ WENDI A. OLSON

Notary Public

My Commission expires January 31, 2020.

STATE OF MINNESOTA

BEFORE THE











SUMMARY OF FILING

On February 16, 2016, Otter Tail Power Company (OTP) filed with the Minnesota Public

Utilities Commission (Commission) an application to increase base retail electric rates in the

State of Minnesota (Application). OTP requests an increase in revenues of $19,295,627 or 9.80

percent.

OTP proposes to keep its Transmission Cost Recovery Rider and Environmental Cost Recovery

Rider in place through the course of the proceeding. At the time final rates are implemented,

OTP proposes to move project costs recovered through those riders into base rates.


per month or $114.36 per year. The impact on individual customers will be higher or lower

depending on each individual customer’s actual electric consumption.

If the Commission elects to suspend the proposed rate increase under Minn. Stat. § 216B.16,

Subd. 2, OTP requests authority to implement an interim rate increase of $19,251,135 on April

16, 2016, pursuant to Minn. Stat. § 216B.16, Subd. 3. The interim rate will be applied as a

uniform 10.95 percent increase to base rate components of customers’ bills.

OTP is also proposing changes to rate designs and terms of service.

The proposed rate schedules and a comparison of present and proposed rates are available at

www.otpco.com/MNRateCase and can also be examined during normal business hours at either

OTP’s General Offices located at 215 South Cascade Street, Fergus Falls, Minnesota 56537, or

at the Minnesota Department of Commerce, 85 Seventh Place East, Suite 500, St. Paul,

Minnesota 55101.

http://www.otpco.com/MNRateCase

CERTIFICATE OF SERVICE

RE: In the Matter of the Application of Otter Tail Power Company for Authority to

Increase Rates for Electric Utility Service in Minnesota


I, Wendi A. Olson, hereby certify that I have this day served a copy of the following, or a

summary thereof, on Daniel P. Wolf and Sharon Ferguson by e-filing, and to the Office of Attorney

General – Antitrust & Utilities Division and all other persons on the attached service list by electronic

service or by First Class mail or by personal service.


Initial Filing

Dated this 16th

day of February 2016.

/s/ WENDI A. OLSON

Wendi A. Olson

Regulatory Filing Coordinator



Fergus Falls MN 56537

(218) 739-8699

First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name

Christopher Anderson [email protected] Minnesota Power 30 W Superior StDuluth,MN558022191

Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding

Julia Anderson [email protected]

Office of the AttorneyGeneral-DOC

1800 BRM Tower445 Minnesota StSt. Paul,MN551012134

Electronic Service Yes SPL_SL_15-1033_Potentially InterestedParties - Harding

Thomas Bailey [email protected] Briggs And Morgan 2200 IDS Center80 S 8th StMinneapolis,MN55402


Ryan Barlow [email protected]

Office of the AttorneyGeneral-RUD

445 Minnesota StreetBremer Tower, Suite 1400St. Paul,Minnesota55101


Peter Beithon [email protected] Otter Tail Power Company P.O. Box 496215 South Cascade StreetFergus Falls,MN565380496


William Black [email protected] MMUA Suite 4003025 Harbor Lane NorthPlymouth,MN554475142


William A. Blazar [email protected] Minnesota Chamber OfCommerce

Suite 1500400 Robert Street NorthSt. Paul,MN55101


Thomas R Brause [email protected] Otter Tail Power Company PO Box 496215 S Cascade StFergus Falls,MN56538-0496


Christina Brusven [email protected] Fredrikson Byron 200 S 6th St Ste 4000Minneapolis,MN554021425


Michael J. Bull [email protected] Center for Energy andEnvironment

212 Third Ave N Ste 560Minneapolis,MN55401


Tammie Carino [email protected] Great River Energy 12300 Elm Creek Blvd.Maple Grove,MN55369-4718


2


Ray Choquette [email protected] Ag Processing Inc. 12700 West Dodge RoadPO Box 2047Omaha,NE68103-2047


Piedmont Consulting N/A Piedmont Consulting, Inc., 701 4th Ave S Ste 500Minneapolis,MN55402

Paper Service No SPL_SL_15-1033_Potentially InterestedParties - Harding

Leigh Currie [email protected] Minnesota Center forEnvironmental Advocacy

26 E. Exchange St., Suite206St. Paul,Minnesota55101


Derick O. Dahlen [email protected]

Avant Energy Services 220 S. Sixth St Ste 1300Minneapolis,MN55402


William T Davis N/A - 23456 Garland LnBattle Lake,MN56515-9665


Ian Dobson [email protected]


Antitrust and UtilitiesDivision445 Minnesota Street, 1400BRM TowerSt. Paul,MN55101


Dennis R Eicher [email protected]

D.R. Eicher Consulting, Inc. 28947 River Ridge Rd NWIsanti,MN55040


James C. Erickson [email protected] Kelly Bay Consulting 17 Quechee StSuperior,WI54880-4421


Emma Fazio [email protected] Stoel Rives LLP 33 South Sixth StreetSuite 4200Minneapolis,MN55402


3


Sharon Ferguson [email protected]

Department of Commerce 85 7th Place E Ste 500Saint Paul,MN551012198


Edward Garvey [email protected] Residence 32 Lawton StSaint Paul,MN55102


John R. Gasele [email protected] Fryberger Buchanan Smith& Frederick PA

700 Lonsdale Building302 West Superior StreetDuluth,MN55802


Bruce Gerhardson [email protected] Otter Tail Power Company PO Box 496215 S Cascade StFergus Falls,MN565380496


Jeffrey Haase [email protected] Great River Energy 12300 Elm Creek BlvdMaple Grove,MN55369


Annete Henkel [email protected] Minnesota Utility Investors 413 Wacouta Street#230St.Paul,MN55101


Jim Horan [email protected] Minnesota Rural ElectricAssociation

11640 73rd Ave NMaple Grove,MN55369


Arshia Javaherian [email protected]

Enbridge Energy 26 East Superior StreetSuite 309Duluth,MN55802


Linda Jensen [email protected]


1800 BRM Tower 445Minnesota StreetSt. Paul,MN551012134


Richard Johnson [email protected]

Moss & Barnett 150 S. 5th StreetSuite 1200Minneapolis,MN55402


4


J. Vincent Jones [email protected]

Woods, Fuller, Shultz &Smith P.C.

300 S Phillips Ave Ste 300PO Box 5027Sioux Falls,SD57117-5027


Michael Krikava [email protected] Briggs And Morgan, P.A. 2200 IDS Center80 S 8th StMinneapolis,MN55402


James D. Larson [email protected]

Avant Energy Services 220 S 6th St Ste 1300Minneapolis,MN55402


Elizabeth A. Lewis [email protected]




John Lindell [email protected] Office of the AttorneyGeneral-RUD



Peter Madsen [email protected]


Bremer Tower, Suite 1800445 Minnesota StreetSt. Paul,Minnesota55101


Kavita Maini [email protected] KM Energy Consulting LLC 961 N Lost Woods RdOconomowoc,WI53066


Pam Marshall [email protected] Energy CENTS Coalition 823 7th St ESt. Paul,MN55106


Patrick Mastel N/A Missouri River EnergyServices

3724 W. Avera DrivePO Box 88920Sioux Falls,SD57109-8920


Sara G McGrane [email protected] Felhaber Larson 220 S 6th St Ste 2200Minneapolis,MN55420


5


Brian Meloy [email protected] Stinson,Leonard, StreetLLP

150 S 5th St Ste 2300Minneapolis,MN55402


Tim Miller_ N/A Missouri River EnergyServices



Andrew Moratzka [email protected] Stoel Rives LLP 33 South Sixth StreetSuite 4200Minneapolis,MN55402


Darrell Nitschke [email protected] North Dakota PublicService Commission

600 E. Boulevard AvenueState Capital, 12th Floor,Dept 408Bismarck,ND585050480


Gary Oetken [email protected] Ag Processing, Inc. 12700 West Dodge RoadP.O. Box 2047Omaha,NE681032047


Lisa Pickard [email protected] Minnkota PowerCooperative

1822 Mill RdPO Box 13200Grand Forks,ND582083200


Marcia Podratz [email protected] Minnesota Power 30 W Superior SDuluth,MN55802


Charles Riesen [email protected] PKM Electric Cooperative 406 North Minnesota Street PO Box 108Warren,MN567620108


Steve Sanda 101 Park CircleOttertail City,MN565717003


6


Richard Savelkoul [email protected]

Martin & Squires, P.A. 332 Minnesota Street SteW2750St. Paul,MN55101


Larry L. Schedin [email protected] LLS Resources, LLC 12 S 6th St Ste 1137Minneapolis,MN55402


Michael Schmidt [email protected] PKM Electric Coop Inc PO Box 108406 North Minnesota StWarren,MN56762


Christopher Schoenherr [email protected]

SMMPA 500 First Ave SWRochester,MN55902-3303


Robert H. Schulte [email protected]

Schulte Associates LLC 1742 Patriot RdNorthfield,MN55057


Janet Shaddix Elling [email protected]

Shaddix And Associates Ste 1229100 W Bloomington FrwyBloomington,MN55431


Mrg Simon [email protected] Missouri River EnergyServices

3724 W. Avera DriveP.O. Box 88920Sioux Falls,SD571098920


Cari Snaza [email protected] Office of AdministrativeHearings

PO Box 64620St. Paul,MN55155


Ron Spangler, Jr. [email protected] Otter Tail Power Company 215 So. Cascade St.PO Box 496Fergus Falls,MN565380496


SaGonna Thompson [email protected]

Xcel Energy 414 Nicollet Mall FL 7Minneapolis,MN554011993


7


Stuart Tommerdahl [email protected] Otter Tail Power Company 215 S Cascade StPO Box 496Fergus Falls,MN56537


Patricia Van Gerpen [email protected]

South Dakota PublicUtilities Commission

State Capitol Building500 E Capitol AvePierre,SD57501-5070


Kevin Walli [email protected] Fryberger, Buchanan,Smith & Frederick

380 St. Peter St Ste 710St. Paul,MN55102


Daniel P Wolf [email protected] Public Utilities Commission 121 7th Place EastSuite 350St. Paul,MN551012147




Electronic Service No OFF_SL_15-1033_GR-15-1033




Electronic Service Yes OFF_SL_15-1033_GR-15-1033






Thomas R Brause [email protected] Otter Tail Power Company PO Box 496215 S Cascade StFergus Falls,MN56538-0496










Paper Service No OFF_SL_15-1033_GR-15-1033





2






Thomas E. Ferguson N/A Ferguson Consulting, LLC 5740 Kehtel RdDuluth,MN55811

Paper Service No OFF_SL_15-1033_GR-15-1033










Shane Henriksen [email protected]

Enbridge Energy Company,Inc.

1409 Hammond Ave FL 2Superior,WI54880









3


Joel W. Kanvik [email protected] Enbridge Energy Company,Inc.

26 E Superior St Ste 309Duluth,MN55802


Bill Lachowitzer [email protected]

IBEW Local Union 949 12908 Nicollet Ave SBurnsville,MN55337-3527


Douglas Larson [email protected]

Dakota Electric Association 4300 220th St WFarmington,MN55024














Tom Micheletti [email protected]

Excelsior Energy Inc. 225 S 6th St Ste 2560Minneapolis,MN55402-4638




Jeffrey L. Nelson [email protected] East River Electric PowerCoop.

121 SE First StreetPO Box 227Madison,SD57042


4




David G. Prazak [email protected] Otter Tail Power Company P.O. Box 496215 South Cascade StreetFergus Falls,MN565380496


Anna K Roberts [email protected] Otter Tail Power Company 215 S Cascade StPO Box 496Fergus Falls,MN56538-0496


Tim Rogelstad [email protected] Otter Tail Power Company 215 South Cascade StreetFergus Falls,MN56538















William Taylor [email protected]

Taylor Law Firm 2921 E 57th StPO Box 10,Sioux FallsSD


5





Pat Treseler [email protected] Paulson Law Office LTD Suite 3257301 Ohms LaneEdina,MN55439


Cam Winton [email protected] Minnesota Chamber ofCommerce

400 Robert Street NorthSuite 1500St. Paul,Minnesota55101






Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case




























2






Matt Olsen [email protected] Otter Tail Power Company 215 South Cascade StreetFergus Falls,MN56537




Cary Stephenson [email protected] Otter Tail Power Company 215 South Cascade StreetFergus Falls,MN56537


Stuart Tommerdahl [email protected] Otter Tail Power Company 215 S Cascade StPO Box 496Fergus Falls,MN56537




Patrick Zomer [email protected]

Moss & Barnett aProfessional Association

150 S. 5th Street, #1200Minneapolis,MN55402






Electronic Service Yes OFF_SL_10-239_Official


Electronic Service No OFF_SL_10-239_Official










Piedmont Consulting N/A Piedmont Consulting, Inc., 701 4th Ave S Ste 500Minneapolis,MN55402

Paper Service No OFF_SL_10-239_Official










2






Thomas E. Ferguson N/A Ferguson Consulting, LLC 5740 Kehtel RdDuluth,MN55811






















3


Joel W. Kanvik [email protected] Enbridge Energy Company,Inc.

26 E Superior St Ste 309Duluth,MN55802


Michael Krikava [email protected] Briggs And Morgan, P.A. 2200 IDS Center80 S 8th StMinneapolis,MN55402


Bill Lachowitzer [email protected]

IBEW Local Union 949 12908 Nicollet Ave SBurnsville,MN55337-3527



















Patrick Mastel N/A Missouri River EnergyServices



4


Tom Micheletti [email protected]

Excelsior Energy Inc. 225 S 6th St Ste 2560Minneapolis,MN55402-4638


Tim Miller_ N/A Missouri River EnergyServices





Jeffrey L. Nelson [email protected] East River Electric PowerCoop.

121 SE First StreetPO Box 227Madison,SD57042




Marcia Podratz [email protected] Minnesota Power 30 W Superior SDuluth,MN55802


Michelle Rebholz [email protected]

Public Utilities Commission Suite 350121 SeventhPlace EastSt. Paul,MN55101


Tim Rogelstad [email protected] Otter Tail Power Company 215 South Cascade StreetFergus Falls,MN56538


Steve Sanda 101 Park CircleOttertail City,MN565717003





5












William Taylor [email protected]

Taylor Law Firm 2921 E 57th StPO Box 10,Sioux FallsSD





Pat Treseler [email protected] Paulson Law Office LTD Suite 3257301 Ohms LaneEdina,MN55439


Cam Winton [email protected] Minnesota Chamber ofCommerce

400 Robert Street NorthSuite 1500St. Paul,Minnesota55101




1/3 tab

Volume 1

Notice and Petition for Interim Rates

STATE OF MINNESOTA

BEFORE THE











NOTICE AND PETITION

FOR INTERIM RATES

I. INTRODUCTION

Otter Tail Power Company (OTP or the Company) hereby submits to the Minnesota Public

Utilities Commission (Commission) this Notice and Petition for Interim Rates (Petition),

pursuant to Minn. Stat. § 216B.16, Subd. 3, the Commission’s Statement of Policy on Interim

Rates dated April 14, 1982, and relevant Commission rules.

II. INFORMATION PROVIDED PURSUANT TO THE COMMISSION

STATEMENT OF POLICY ON INTERIM RATES AND RELEVANT

COMMISSION RULES

A. Name, address, and telephone number of utility and attorneys

(Policy Statement, Item 1, page 2)


PO Box 496



218-739-8200

Bruce Gerhardson



PO Box 496



218-739-8475

2

Cary Stephenson



PO Box 496



218-739-8956

Richard J. Johnson

Moss & Barnett, A Professional Association

Suite 1200



612-877-5275

B. Date of filing and date proposed interim rates are requested to become

effective


The date of the submission of this Petition is February 16, 2016. This Petition is submitted as

part of the Company’s Application for a general electric rate increase (Application). If the

Commission suspends the operation of the general rate schedules which accompany the

Application pursuant to Minn. Stat. § 216B.16, Subd. 2, the Company requests that the proposed

interim rates be made effective on April 16, 2016, pursuant to Minn. Stat. § 216B.16, Subd. 3.

The interim rates will be subject to refund, with interest, pending final Commission

determination on the Application.

C. Description and need for interim rates


Interim rates are needed because OTP is currently incurring the increased costs of service

reflected in the Application. Without interim rate relief, OTP would be unable to recover these

increased costs of service.

The Interim Supporting Schedules and Workpapers accompanying this Petition set forth the

calculation of the interim revenue deficiency of $19,251,135, which represents a 10.95 percent

increase over present base revenue (excluding riders). The 2016 Test Year Revenue Deficiency

represents a proposed increase of 9.80 percent over 2016 Test Year present revenues (including

riders). The percentage increase for interim rates is higher than the percentage increase for final

rates because the interim rate adjustments only apply to the base rate portion of customers’ bills.

Higher interim rate percentage increases are required to collect the interim revenue deficiency.

A similar relationship was presented in Xcel Energy’s interim rate petition in Docket No.

E002/GR-15-826.

3

Interim-only Impacts

The $19,251,135 proposed interim Revenue Deficiency includes $541,507 (MN) of costs that are

only in the interim rate request and not included in the 2016 Test Year. These interim-only costs

are explained below.

In the Commission’s April 17, 2013, Order in Docket No. E017/M-12-708, it was determined

that the remaining balance ($68,361 (MN)) in OTP’s Renewable Resource Adjustment Rider

should be addressed as part of OTP’s next rate case. OTP proposes to amortize this remaining

balance over an assumed interim rate collection period of 18 months, which contributes $45,574

(MN) to the annual interim rate revenue requirement. After the interim rate collection period, the

amount will be fully recovered, so the amount is not included in the 2016 Test Year revenue

requirement.

Big Stone II development costs were authorized for recovery in OTP’s last rate case, Docket No.

E17/GR-10-239. The interim rates include both generation-related and transmission-related

development costs. The generation-related costs contribute $180,962 (MN) to the annual interim

rate revenue requirement and will be fully recovered over the 18 month interim rate period.

Because these generation-related development costs will be fully recovered in the interim rate

period, they are not included in the 2016 Test Year revenue requirement. Transmission-related

development costs are included in both interim and 2016 Test Year revenue requirements. These

costs are further explained in the Direct Testimony of Mr. Peter J. Beithon (Section IV.F.).

The roll-in of Environmental Cost Recovery Rider (ECRR) projects and Transmission Cost

Recovery Rider (TCRR) projects into base rates at the conclusion of this case has an interim-

only impact of $314,971 (MN) (ECRR of $172,967 plus TCRR of $142,004). The revenue

requirement for the ECRR and TCRR is based on the rate of return and allocation factors

approved in OTP’s last electric rate case. When rolled into base rates, however, the revenue

requirement for the ECRR and TCRR projects will be calculated using the 2016 Test Year

overall rate of return and allocations being proposed in this case. Additional explanation of the

impacts of the ECRR and TCRR roll-in on interim rates can be found in the Direct Testimony of

Mr. Stuart D. Tommerdahl (Section III.A (ECRR) and Section III.B (TCRR)).

Costs Excluded from Interim Rates

The costs included in interim rates, including those discussed above, are appropriate for recovery

in interim rates because they are “the same in nature and kind as those allowed” by the

Commission’s Order in OTP’s last electric rate case. As required by Minn. Stat. § 216B.16,

subd. 3, and the Commission’s Statement of Policy on Interim Rates, OTP has removed $12,239

(MN) of Hoot Lake emissions allowance costs from the interim rate request. Details of this

removal are show in the Column E of the Interim Supporting Schedules and Workpapers, Part B,

Schedule 6.

High Voltage Test Lab Adjustment

OTP included a credit of $158,501(MN) in the calculation of interim rates related to OTP’s sale

of its high voltage test lab in 1997. This adjustment is necessary to complete, during the interim

period, the ten year amortization ordered by the Commission in Docket E017/PA-97-697. Details

4

of this adjustment are shown in Column F of the Interim Supporting Schedules and Workpapers,

Part B, Schedule 6.

Return on Equity Used for Interim Rates

The interim rate revenue requirement is based on the 10.40 percent return on equity used to

determine the 2016 Test Year revenue requirement, rather than the 10.74 percent approved in

OTP’s last general rate case.

Inclusion of Prepaid Pension Asset in Interim Rates

OTP has included in interim rates the $2,462,679 (MN) revenue requirement associated with

OTP’s Prepaid Pension Asset, which is the same in nature and kind as other prepayments being

recovered in rates. The Prepaid Pension Asset reduces OTP pension expense by an amount

greater than the return on the Prepaid Pension asset, resulting in a net reduction of costs for

customers. The Commission’s exclusion of a pension asset in OTP’s last rate case was based on

time constraints that did not allow comprehensive evidentiary development and rigorous analysis

of the issue.1 The costs and benefits to customers resulting from the prepaid pension asset are

further explained in the Direct Testimony of Mr. Beithon (Section IV.D.1.).

Riders Continuing

OTP is proposing that costs currently recovered through the ECRR, TCRR, and the Conservation

Cost Recovery Adjustment (CCRA) will continue to be recovered through those riders during the

interim rate period. Adjustments for this treatment are shown in Part B, Schedule 6.

D. Description and corresponding dollar amount of changes included in interim

rates as compared with most current approved general rate case and with the

most recent year for which audited data is available


A comparison of the changes included in interim rates as compared with OTP’s last rate case is

contained in the Interim Supporting Schedules and Workpapers, Part E of this filing.

E. Effect of the interim rates expressed in gross revenue dollars and as a

percentage of test year gross revenues


The 2016 Test Year for OTP’s general electric rate increase filing is the calendar year ending

December 31, 2016. The revenue requirement study supporting the necessity for interim rate

relief shows a deficiency in revenue of $19,251,135 under present rates. Present rates, as referred

to in this Petition, are the rates authorized by the Commission in its final order in OTP’s last rate

case. OTP is requesting an interim rate adjustment which will increase OTP’s revenues,

1 In discussing OTP’s request for recovery of the prepaid pension asset, the Commission said: “Their late

introduction into an already complex case litigated under tight time constraints may have prevented the

comprehensive evidentiary development and rigorous analysis required to sustain them.” Findings of Fact,

Conclusions of Law, and Order, Docket No. E017/GR-10-239 (April 25, 2011), page 40.

5

exclusive of separately collected revenues related to franchise fees or gross earnings taxes

imposed by local governmental units, by $19,251,135 or 10.95 percent on base rate components

other than riders.

F. Certification by chief executive officer of the utility


This Petition contains a certificate signed by Timothy J. Rogelstad President, Otter Tail Power

Company, affirming that this interim rate Petition complies with Minnesota Statutes.

G. Methods and procedures for refunding

Pursuant to Minn. Stat. § 216B.16, Subd. 3, attached to this filing is the Company’s Agreement

and Undertaking of Refund by OTP.

H. Signature and title of the utility officer authorizing the proposed interim

rates (Policy Statement, Item 7, page 2)

This Petition is signed by Thomas R. Brause, Vice President Administration, Otter Tail Power

Company.

I. Supporting schedules and workpapers

(Policy Statement, Items 1-4, page 3)

The supporting schedules and workpapers described in the Commission’s Policy Statement are

included along with this Petition as Interim Supporting Schedules and Workpapers. These

schedules include the rate base amounts, income statement amounts, revenue deficiencies, capital

structures and rates of return required for interim rates as compared to: (i) the same information

for OTP’s Application; (ii) the allowed amounts in Docket No. E017/GR-10-239; and (iii) the

most recent actual year. Volumes 2A, 2B and 2C of the Application are the direct testimony and

proposed tariffs, and Volume 3 contains the jurisdictional cost of service study supporting the

interim rate data.

J. Interim rate schedules. Revenue rate comparisons

(Minn. R. Part 7825.3600)

The rate schedules containing proposed interim rates are included along with the Petition in

Volume 1 (Redlined and Non-redlined formats, respectively). Consistent with Minn. Stat. §

216B.16, Subd. 3, no change has been made in the existing rate design. We are proposing to

apply a uniform percentage increase of 10.95 percent to all base rate components other than

riders, which would provide an additional $19,251,135 of base rate revenues on an annualized

basis. The Company also filed a petition in Docket E017/MR-15-1034 to reset the base cost of

energy from 2.3163 cents to 2.4640 cents (an increase of 0.1477 cents). To reflect this change,

we have changed the energy charge on each rate schedule to reflect the difference between the

new and previous base cost of energy. Also included in this Petition is a schedule of interim

revenue impacts in the Summary of Present and Interim Revenue.

6

K. Customer notice

(Minn. R. Part 7829.2400, Subpt. 3; Minn. Stat. § 216B.16, Subd. 1)

Pursuant to Minn. R. Part 7829.2400, Subpt. 3, and Minn. Stat. § 216B.16, Subd. 1, OTP

proposes to deliver the provided enclosed interim rate notice to its electric customers in the State

of Minnesota, and notice to the counties and municipalities it serves in Minnesota. The proposed

notice to counties and municipalities and a proposed customer notice pursuant to Minn. Stat. §

216B.16, Subd. 1, are included with this filing. In addition, OTP will publish a display

advertisement in the newspapers of general circulation in all county seats in OTP’s service

territory. The display advertisement will replicate the notice to the counties and municipalities.

L. Interim Bills

The Commission’s Policy Statement on Interim Rates suggests that changes in interim rates be

shown on customer bills as a separate line item if practical. The interim rate amount will be

shown as a separate line item identified as “Interim Rate Adj,” and will reflect the total amount

of the interim charge applied to the bill.

III. CONCLUSION

OTP hereby submits this Notice and Petition for Interim Rates. If the Commission suspends the

operation of the general rate schedules under Minn. Stat. § 216B.16, Subd. 2, the Company

respectfully requests that the Notice and Petition for Interim Rates be promptly considered and

accepted by the Commission, and that the interim rate schedules be approved and made effective

on April 16, 2016, pursuant to Minn. Stat. § 216B.16, Subd. 3, subject to refund pending final

Commission action on the general rate increase Application.


Respectfully submitted,


Thomas R. Brause




me this 16th day of February, 2016.

/s/ WENDI A. OLSON

Notary Public


1/3 tab

Volume 1

Agreement and Undertaking,

and Certification

STATE OF MINNESOTA

BEFORE THE











Agreement and Undertaking

Otter Tail Power Company (OTP), in conjunction with the Notice and Petition for Interim Rates

filed with the Minnesota Public Utilities Commission (Commission), makes the following

unqualified agreement concerning refunding any portion of the requested increase in rates

determined by the Commission to be unreasonable.

Pursuant to Minn. R. 7825.3300, OTP hereby agrees and undertakes to refund to its customers

the amount, if any, collected during the interim rate period, plus interest at the current rate as

determined by the Commission, computed from the effective date of the interim rates through the

date of refund. The refund shall be made in accordance with Minn. Stat. § 216B.16, subd. 3, and

in a manner approved by the Commission.

In addition, OTP agrees to keep such records of sales and billings under the proposed interim

rates as will be necessary to compute any potential refund.

This Agreement and Undertaking is made pursuant to authority granted by the Board of

Directors of Otter Tail Power Company.


By: /s/ THOMAS R. BRAUSE

Thomas R. Brause

Vice President Administration


CERTIFICATION

As required by the Minnesota Public Utilities Commission’s Statement of Policy on Interim

Rates dated April 14, 1982, I hereby certify and affirm that the petition of Otter Tail Power

Company for approval of Proposed Interim Rates and Final Rates is in compliance with

Minnesota Statutes.


/s/ TIMOTHY ROGELSTAD

Timothy Rogelstad

President



me this 16th day of February, 2016

/s/ WENDI A. OLSON

Notary Public


1/3 tab

Volume 1

Interim Supporting Schedules

and Workpapers


Schedule No.

Revenues and Percent Increase 1

Minnesota Policy Statements 2

Definitions 3

Summary of Revenue Requirements 4

Statement of Operating Income 5

Detailed Rate Base Components 6

Schedule No.


Description of Adjustments to Rate Base 2

Rate Base with Adjustments (Bridge Schedule) 3


Description of Adjustments to Operating Statement 5

Statement of Operating Income with Adjustments (Bridge Schedule) 6


Schedule No.


Description of Changes to Rate Base 2


Description of Changes to Operating Statement 4


Capital Structure and Rate of Return Calculations 6

Description of Changes to Capital Structure and Rate of Return Calculations 7

Schedule No.


Description of Changes to Rate Base 2




Schedule No.


Description of Changes to Rate Base Components 2




PART D: Comparison of Proposed Interim Test Year to 2016 Unadjusted

Projected Fiscal Year

PART E: OTP's Most Recent General Rate Case to Proposed Test Year

INTERIM RATE SCHEDULES

INDEX

PART A: Interim Rate Summary

PART B: Comparison of Proposed Interim Test Year to Proposed Test Year

PART C: Comparison of Proposed Interim Test Year to OTP's Most Recent

General Rate Case

OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033

INTERIM RATE INCREASE PART A

REVENUES & PERCENT INCREASE Schedule 1

Page 1 of 1

Total Interim Retail Revenues $175,833,397

Interim Deficiency $19,251,135

Total Interim Revenue % Increase 10.95%


Electric Utility - State of Minnesota PART A

INTERIM RATE SCHEDULE Schedule 2

Policy Statements Page 1 of 2

DESCRIPTION OF INTERIM RATE PETITION REQUIREMENTS, SUPPORTING SCHEDULES AND WORKPAPERS

The Minnesota Public Utilities Commission (Commission), in its Statement of Policy on Interim Rates, encourages any regulated company seeking interim rates to submit to the Commission an interim rate petition as part of its general rate case filing. The interim rate petition should include a cover letter and supporting schedules. The supporting schedules should include the following:

1) A schedule showing the interim rate of return calculation. This schedule should show the capital structure and rate of return calculation approved by the Commission in the most recent general rate case; the capital structure and rate of return calculation proposed for interim rates; and a description and corresponding dollar amount of any changes between the two capital structures.

Note:Part C, Schedule 7, contains this information.

2) A schedule showing the interim operating income statement. This schedule should show the same operating income statement accounts as filed in the general rate case. Also, the schedule should include the operating income statement approved by the Commission in the most recent general rate case, the operating income statement for the unadjusted projected fiscal year, and the operating income statement proposed for interim rates. A description of all changes and corresponding dollar amounts between each of the operating income statements should be provided. Workpapers should be provided which show how revenues, AFUDC, taxes, expenses, and other income statement components have been determined.

Notes:Part C, Schedule 3, compares the operating income statement approved by the Commission in the most recent general rate case with the income statement for the proposed interim test year, including a description of all changes and corresponding dollar amounts.

Part D, Schedule 3, compares the operating income statement for the unadjusted projected fiscal year with the income statement for the proposed test year, as adjusted, for interim rates, including a description of all changes and corresponding dollar amounts.

Part E, Schedule 3, compares the operating income statement approved by the Commission in the most recent general rate case with the operating income statement for the proposed test year.

Although the Commission’s Statement of Policy does not require regulated companies to do so, OTP has included as Part B, Schedule 6, an operating statement bridge schedule for the proposed interim test year, as well as Part B, Schedule 4, a comparison of proposed interim rates to the statement of operating income for the proposed test year with the income statement for the proposed interim test year that includes a description of all known and measurable adjustments and corresponding dollar amounts.

Workpapers for the above Interim Rate Petition Schedules are located in Volume 4 of this filing.




Policy Statements Page 2 of 2

DISCUSSION OF INTERIM RATE PETITION REQUIREMENTS,SUPPORTING SCHEDULES AND WORKPAPERS

3) A schedule showing the interim proposed rate base. This schedule should show the same rate base accounts as filed in the general rate case. This schedule should include the average rate base approved by the Commission in the most recent general rate case; the average rate base with the unadjusted projected fiscal year, and the average rate base proposed for interim rates. A description of all changes and corresponding dollar amounts between each of the rate bases should be provided. Workpapers should be provided which show how the rate base components have been determined.

Notes:Part C, Schedule 1, compares the average rate base approved by the commission in the most recent general rate case with the average rate base proposed for interim rates, including a description of all changes and corresponding dollar amounts.

Part D, Schedule 1, compares the average rate base for the unadjusted projected fiscal year with the average rate base proposed for interim rates, including a description of all changes and corresponding dollar amounts.

Part E, Schedule 1, compares the average rate base approved by the Commission in the most recent general rate case with average rate base for the proposed test year, including a description of all changes and corresponding dollar amounts.

4) Although not required by the Commission’s Policy Statement, OTP has included as Part B, Schedule 1, comparison of the average rate base for the proposed test year with the average rate base for the proposed interim test year, as well as Part B, Schedule 3, a bridge schedule of the average rate base for the proposed test year with the average rate base for the proposed interim test year that includes a description of all known and measurable adjustments and corresponding dollar amounts.

Workpapers for the above Interim Rate Petition Schedules are located in Volume 1 of this filing. The Interim Jurisdictional Cost of Service Study is located in Volume 4A, Section C.

A schedule showing revenue deficiency calculations for each of the operating income statements and rate bases requested in (2) and (3) above. The revenue deficiency should be calculated for the actual data and the interim data using the rate of return calculated in (1) above.

Notes:Part C, Schedule 5, shows the revenue deficiency calculations for the most recent general rate case and for the proposed interim rates.

Part D, Schedule 5, shows the revenue deficiency calculations for the unadjusted projected fiscal year and for the proposed interim rates.

Part E, Schedule 5, shows the revenue deficiency calculations for the most recent general rate case and the proposed test year.

Although not required by the Commission’s Policy Statement, OTP has included as Part B, Schedule 7 of this volume, the revenue deficiency calculations for this general rate case filing and for the proposed interim rates.




Page 1 of 1

DEFINITIONS

The following definitions have been used in this filing:

Proposed Interim Test YearThe proposed interim test year information is for the calendar year endingDecember 31, 2016 and includes the effect of rate making adjustments for interim rates.

Proposed Test YearThe Proposed Test Year information represents the test year financial information for the 2016 calendar year and includes the effects of rate making adjustments for final rates.

OTP’s Most Recent General Rate CaseThis information represents the financial data for the 12 months test year ending December 31, 2009, from Otter Tail Power Company’s last Minnesota electric rate case (Docket No. E017/GR-10-239), as approved by the Commission.

Unadjusted Projected Fiscal YearThe unadjusted projected fiscal year is the fiscal year immediately following the most recent fiscal year. For the purposes of this filing, this information represents projected financial information for the calendar year ending December 31, 2016.

Note on RoundingThe cost of service study on which these supporting schedules are based rounds numbers to the nearest whole dollar for display purposes. However, the subtotals and subsequent totals in the cost of service study may be based on actual values resulting in occasional differences in the totals displayed when compared to the sum of the line items. These supporting schedules were prepared using individual line items with subtotals and totals calculated on each schedule separately. This may result in occasional rounding differences of a few dollars when comparing between the subtotals and totals on the cost of service study to those on the supporting schedules.




SUMMARY OF REVENUE REQUIREMENTS Page 1 of 1

Line Proposed Interim

No. Description Test Year

1 Average Rate Base $362,299,321

2 Operating Income (Before AFUDC) $17,279,172

3 Allowance for Funds Used During Construction (AFUDC) $671,443

4 Total Available for Return (Line 2 + Line 3 + Rounding) 17,950,615

5 Overall Rate of Return (Line 4 / Line 1) 4.95%

6 Required Rate of Return 8.07%

7 Operating Income Requirement (Line 1 x Line 6) $29,237,555

8 Income Deficiency (Line 7 - Line 4) $11,286,940

9 Gross Revenue Conversion Factor 1.70561

10 Revenue Deficiency (Line 8 x Line 9) $19,251,135

11 Retail Related Revenues Under Present Rates $175,833,397

12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 10.95%




STATEMENT OF OPERATING INCOME Page 1 of 1



OPERATING REVENUES

1 Retail $175,833,397

2 Other Operating Revenue $7,311,132

3 TOTAL OPERATING REVENUE $183,144,530

4 OPERATING EXPENSES

5 Production Expenses $87,047,754

6 Transmission Expenses $7,816,881

7 Distribution Expenses $7,594,039

8 Customer Accounting Expenses $6,565,033

9 Customer Service & Information Expenses $5,950,790

10 Sales Expenses $108,214

11 Administration & General Expenses $20,612,538

12 Charitable Contributions $93,027

13 Depreciation Expense $23,405,388

14 General Taxes $6,044,979

15 TOTAL OPERATING EXPENSES $165,238,642

16 NET OPERATING INCOME BEFORE INCOME TAXES $17,905,888

17 INCOME TAX EXPENSE

18 Investment Tax Credit ($4,478,056)

19 Deferred Income Taxes $3,199,612

20 Income Taxes $1,905,159

21 TOTAL INCOME TAX EXPENSE $626,715

22 NET OPERATING INCOME $17,279,172

23 Allowance for Funds Used During Construction $671,443

24 TOTAL AVAILABLE FOR RETURN $17,950,615

Note: Revenues reflect calendar month sales.




DETAILED RATE BASE COMPONENTS Page 1 of 1



Utility Plant in Service:

1 Production $380,275,743

2 Transmission 143,446,620

3 Distribution 206,471,049

4 General 43,708,142

5 Intangible 4,987,994

6 TOTAL Utility Plant in Service $778,889,548

7 Accumulated Depreciation

8 Production ($176,440,662)

9 Transmission (53,817,600)

10 Distribution (90,174,014)

11 General (19,344,522)

12 Intangible (2,460,800)

13 TOTAL Accumulated Depreciation ($342,237,598)

14 NET Utility Plant in Service

15 Production $203,835,081

16 Transmission 89,629,020

17 Distribution 116,297,035

18 General 24,363,620

19 Intangible 2,527,195

20 NET Utility Plant in Service $436,651,950

21 Utility Plant Held for Future Use $13,813

22 Construction Work in Progress $12,903,888

23 Materials and Supplies $9,405,728

24 Fuel Stocks $5,824,626

25 Prepayments ($5,615,204)

26 Customer Advances & Deposits ($1,028,345)

27 Cash Working Capital $5,073,644

28 Accumulated Deferred Income Taxes (100,930,779)

29 Total Average Rate Base $362,299,321


Electric Utility - State of Minnesota PART B

COMPARISON OF PROPOSED INTERIM RATES TO Schedule 1

PROPOSED TEST YEAR Page 1 of 1

DETAILED RATE BASE COMPONENTS

(A) (B) (C)

Proposed

Line Test Year Proposed Interim Change

No. Description 2016 Test Year (B) - (A)


1 Production $474,971,844 $380,275,743 ($94,696,101)

2 Transmission 203,387,403 143,446,620 (59,940,784)

3 Distribution 206,471,049 206,471,049 0

4 General 43,721,726 43,708,142 (13,584)

5 Intangible 4,989,544 4,987,994 (1,550)

6 TOTAL Utility Plant in Service $933,541,568 $778,889,548 ($154,652,019)

Accumulated Depreciation

7 Production ($177,864,084) ($176,440,662) $1,423,422

8 Transmission (56,299,033) (53,817,600) 2,481,433

9 Distribution (90,174,014) (90,174,014) 0

10 General (19,350,534) (19,344,522) 6,012

11 Intangible (2,461,564) (2,460,800) 765

12 TOTAL Accumulated Depreciation ($346,149,230) ($342,237,598) $3,911,632


14 Production $297,107,760 $203,835,081 ($93,272,679)

15 Transmission 147,088,370 89,629,020 (57,459,350)

16 Distribution 116,297,035 116,297,035 0

17 General 24,371,192 24,363,620 (7,572)

18 Intangible 2,527,980 2,527,195 (785)

19 NET Utility Plant in Service $587,392,337 $436,651,950 ($150,740,387)

20

21 Utility Plant Held for Future Use $13,813 $13,813 $0

22 Construction Work in Progress 12,905,889 12,903,888 (2,001)

23 Materials and Supplies 9,408,372 9,405,728 (2,643)

24 Fuel Stocks 5,824,626 5,824,626 0

25 Prepayments (5,679,130) (5,615,204) 63,926

26 Customer Advances & Deposits (1,034,643) (1,028,345) 6,298

27 Cash Working Capital 4,905,898 5,073,644 167,745

28 Accumulated Deferred Income Taxes (130,736,573) (100,930,779) 29,805,794

29 Total Average Rate Base $483,000,588 $362,299,321 ($120,701,267)





DESCRIPTION OF ADJUSTMENTS

There are a total of five adjustments that convert the Rate Base of the Proposed Test Year to the Rate Base Proposed for Interim Rates. A bridge from the Proposed Test Year rate base to the Interim Rate Petition rate base is provided in Part B, Schedule 3.

Net Electric Plant in Service (Two related adjustments – Columns B and C)OTP’s proposed test year requests approval to include costs currently recovered in the Environmental Cost Recovery Rider (ECRR) and Transmission Cost Recovery Rider (TCRR) to be included in base rates at the conclusion of the general rate case. An adjustment is being made to the Interim Rate Application to remove the costs associated with the TCRR and ECRR because these riders will remain in effect during the interim period.

Cash Working Capital (Column D)An interim rate adjustment made to Cash Working Capital accounts for the removal of the ECRR and TCRR and other interim adjustments, and their associated impacts on operation and maintenance expense, property tax expense, and income tax expense components of the Cash Working Capital calculation. The Cash Working Capital requirement is determined through the application of Lead-Lag study factors against applicable expense categories.

Accumulated Deferred Income TaxesAn adjustment is being made to the Interim Rate Application to remove the costs associated with the TCRR and ECRR that are included in accumulated deferred income taxes in the General Rate Application.

Changes in Allocations due to Interim Rate Adjustments (Column E)OTP uses its jurisdictional cost of service study (JCOSS) model to calculate all operating statement and rate base schedules for both interim rates and the application for final rates. Certain allocation factors are developed within the JCOSS model. Any adjustment has the potential to change some of these allocation factors. This column shows the effect of the allocations on rate base components caused by adjustments.




RATE BASE WITH ADJUSTMENTS (BRIDGE SCHEDULE) Page 1 of 1

(A) (B) (C) (D) (E) (F)

Impact of Operating Changes inProposed Environmental Transmission Statement Allocations Due to

Line Test Year Rider Amounts Rider Amounts Adjustments on Cash Effect of Interim Proposed Interim

No. Description 2016 Removed Removed Working Capital Adjustments Test Year (1)

1 Electric Plant in Service $933,541,568 ($94,696,101) ($59,940,784) $0 ($15,135) $778,889,548

2 Less: Accumulated Depreciation (346,149,230) 1,423,422 2,481,433 0 $6,777 (342,237,598)

3 Net Electric Plant in Service $587,392,337 ($93,272,679) ($57,459,350) $0 ($8,358) $436,651,950

4 Other Rate Base Components:

5 Plant Held for Future Use $13,813 $0 $0 $0 $0 $13,813

6 Construction Work in Progress 12,905,889 0 0 0 (2,001) 12,903,888

7 Materials and Supplies 9,408,372 0 0 0 (2,643) 9,405,728

8 Fuel Stocks 5,824,626 0 0 0 0 5,824,626

9 Prepayments (5,679,130) 0 0 0 63,926 (5,615,204)

10 Customer Advances (1,034,643) 0 0 0 6,298 (1,028,345)

11 Cash Working Capital 4,905,898 0 0 167,745 0 5,073,644

12 Accumulated Deferred Income Taxes (130,736,573) 15,751,389 13,259,585 0 794,820 (100,930,779)

13

14 TOTAL $483,000,588 ($77,521,290) ($44,199,765) $167,745 $852,043 $362,299,321

(1) Electric Utility - Minnesota Jurisdiction





(A) (B) (C)

Proposed



OPERATING REVENUES

1 Retail $196,817,160 $175,833,397 ($20,983,762)

2 Other Operating Revenue 7,177,664 7,311,132 133,468

3 TOTAL OPERATING REVENUE $203,994,824 $183,144,530 ($20,850,294)


5 Production Expenses $87,059,992 $87,047,754 ($12,239)

6 Transmission Expenses 8,091,378 7,816,881 (274,497)

7 Distribution Expenses 7,594,039 7,594,039 0

8 Customer Accounting Expenses 6,565,033 6,565,033 0

9 Customer Service & Information Expenses 7,297,375 5,950,790 (1,346,584)

10 Sales Expenses 108,214 108,214 0

11 Administration & General Expenses 20,645,066 20,612,538 (32,528)

12 Charitable Contributions 93,027 93,027 0

13 Depreciation Expense 27,039,957 23,405,388 (3,634,570)

14 General Taxes 7,327,555 6,044,979 (1,282,576)

15 TOTAL OPERATING EXPENSES $171,821,636 $165,238,642 ($6,582,995)

16 NET OPERATING INCOME BEFORE INCOME TAXES $32,173,187 $17,905,888 ($14,267,300)


18 Investment Tax Credit ($4,509,538) ($4,478,056) $31,482

19 Deferred Income Taxes 3,203,663 3,199,612 (4,051)

20 Income Taxes 6,485,488 1,905,159 (4,580,329)

21 TOTAL INCOME TAX EXPENSE $5,179,613 $626,715 ($4,552,898)

22 NET OPERATING INCOME $26,993,574 $17,279,172 ($9,714,402)

23 Allowance for Funds Used During Construction 671,547 671,443 (105)

24 TOTAL AVAILABLE FOR RETURN $27,665,121 $17,950,615 ($9,714,506)

Notes: Revenues reflect calendar month sales






Part B, Schedule 6, contains a bridge schedule itemizing the changes from the Proposed Test Year operating income statement to the Interim Rate Petition operating income statement. Eight adjustments have been made to bridge the Proposed Test Year operating income statement to the Proposed Interim operating income statement.

Adjustment to Remove Environmental Rider CostsAn adjustment has been made to remove the costs currently tracked in the environmental cost recovery rider that OTP is proposing to move to base rates in the Proposed Test Year. Since the rider will remain in effect during the interim period, an adjustment is needed to remove the costs from interim rates to avoid double recovery.

Adjustment to Remove Transmission Rider CostsAn adjustment has been made to remove the costs currently tracked in the transmission cost recovery rider that OTP is proposing to move to base rates in the Proposed Test Year. Since the rider will remain in effect during the interim period, an adjustment is needed to remove the costs from interim rates to avoid double recovery.

Adjustment to Collect the Renewable Rider BalanceAn adjustment has been made to collect the balance associated with the renewable rider.

Adjustment for Emission Allowance CostsAn adjustment has been made to remove the costs associated with Emission Allowances for Hoot Lake Plant.






Adjustment for High Voltage Test Lab RevenueThe Settlement Stipulation dated September 18, 1997 and by Commission Order dated October 17, 1997 in Docket No. E017/PA-97-697 required OTP to reduce revenue requirements, adjusted for inflation, for a minimum of ten years from the date of OTP’s next rate case related to a High Voltage Test Lab that was transferred out of the regulated utility. OTP expects the 10 year period to end by the time the final rates go into effect in this case; therefore no revenue credit was included in the Proposed Test Year. This adjustment adds back in the revenue credit necessary to complete the 10 year amortization during the interim period.

Adjustment to remove CIP SurchargeAn adjustment was made to remove Conservation Improvement Program (CIP) revenues and expenses from the proposed interim rates that will continue to be recovered in the Conservation Cost Recovery Adjustment during the interim period.

Adjustment for Recovery Balance of Big Stone IIAn adjustment was made to amortize a portion of the cancelled Big Stone II plant project.

Changes in Allocations due to Interim Rate AdjustmentsOTP uses its jurisdictional cost of service study (JCOSS) model to calculate all operating statement and rate base schedules for both interim rates and the application for final rates. Certain allocation factors are developed within the JCOSS model. Any adjustment has the potential to change some of these allocation factors. This column shows the effect of the allocations on the operating statement components caused by adjustments.



COMPARISON OF PROPOSED INTERIM RATES TO Schedule 6STATEMENT OF OPERATING INCOME WITH ADJUSTMENTS (BRIDGE SCHEDULE) Page 1 of 1

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

Changes in

Proposed Environmental Transmission Collect the Emission Allocations Due

Line Test Year Rider Amounts Rider Amounts Renewable Allowance for High Voltage Removal of MN Big Stone II to Effect of Interim Proposed Interim

No. Description 2016 Removed Removed Rider Balance Hoot Lake Plant Test Lab CIP Surcharge Recovery Adjustments Test Year

OPERATING REVENUES

1 Retail $196,817,160 ($12,520,890) ($7,070,714) ($45,574) $0 $0 ($1,346,584) $0 $0 $175,833,397

2 Other Operating Revenue 7,177,664 0 0 0 0 158,501 0 0 (25,033) 7,311,132

3 TOTAL OPERATING REVENUE $203,994,824 ($12,520,890) ($7,070,714) ($45,574) $0 $158,501 ($25,033) $183,144,529

OPERATING EXPENSES

4 Production Expenses $87,059,992 $0 $0 $0 ($12,239) $0 $0 $0 $0 87,047,754

5 Transmission Expenses 8,091,378 0 0 0 0 0 0 0 (274,497) 7,816,881

6 Distribution Expenses 7,594,039 0 0 0 0 0 0 0 0 7,594,039

7 Customer Accounting Expenses 6,565,033 0 0 0 0 0 0 0 0 6,565,033

8 Customer Service & Information Expenses 7,297,375 0 0 0 0 0 (1,346,584) 0 0 5,950,790

9 Sales Expenses 108,214 0 0 0 0 0 0 0 0 108,214

10 Administration & General Expenses 20,645,066 0 0 0 0 0 0 0 (32,528) 20,612,538

11 Charitable Contributions 93,027 0 0 0 0 0 0 0 0 93,027

12 Depreciation Expense 27,039,957 ($2,849,313) (1,082,773) 0 0 0 0 298,210 (695) 23,405,387

13 General Taxes 7,327,555 0 (1,208,847) 0 0 0 0 0 (73,730) 6,044,979

14 TOTAL OPERATING EXPENSES $171,821,636 ($2,849,313) ($2,291,619) $0 ($12,239) $0 ($1,346,584) $298,210 ($381,450) $165,238,642

15 NET OPERATING INCOME BEFORE INCOME TAXES $32,173,187 ($9,671,577) ($4,779,095) ($45,574) $12,239 $158,501 $1,346,584 ($298,210) $356,417 $17,905,888

INCOME TAX EXPENSE

17 Investment Tax Credit (4,509,538) $0 $0 $0 $0 $0 $0 $0 $31,482 ($4,478,056)

18 Deferred Income Taxes 3,203,663 0 0 0 0 0 0 0 (4,051) 3,199,612

19 Income Taxes 6,485,488 (4,001,132) (1,977,112) (18,854) 5,063 65,572 557,082 (123,369) 912,420 1,905,159

20 TOTAL INCOME TAX EXPENSE $5,179,613 ($4,001,132) ($1,977,112) ($18,854) $5,063 $65,572 $557,082 ($123,369) $939,851 $626,715

21 NET OPERATING INCOME $26,993,574 ($5,670,446) ($2,801,983) ($26,720) $7,176 $92,929 $789,502 ($174,841) ($583,434) $17,279,173

22 Allowance for Funds Used During Construction 671,547 0 0 0 0 0 0 0 (105) 671,442

23 TOTAL AVAILABLE FOR RETURN $27,665,121 ($5,670,446) ($2,801,983) ($26,720) $7,176 $92,929 $789,502 ($174,841) ($583,539) $17,950,615





(A) (B) (C)

Proposed



1 Average Rate Base $483,000,588 $362,299,321 ($120,701,267)

2 Operating Income (Before AFUDC) $26,993,574 $17,279,172 ($9,714,402)

3 Allowance for Funds Used During Construction (AFUDC) $671,547 $671,443 ($105)

4 Total Available for Return (Line 2 + Line 3 + Rounding) $27,665,121 $17,950,615 ($9,714,506)

5 Overall Rate of Return (Line 4 / Line 1) 5.73% 4.95% -0.77%

6 Required Rate of Return 8.07% 8.07% 0.00%

7 Operating Income Requirement (Line 1 x Line 6) $38,978,147 $29,237,555 ($9,740,592)

8 Income Deficiency (Line 7 - Line 4) $11,313,026 $11,286,940 ($26,086)

9 Gross Revenue Conversion Factor 1.70561 1.70561 0

10 Revenue Deficiency (Line 8 x Line 9) $19,295,627 $19,251,135 ($44,492)

11 Retail Related Revenues Under Present Rates $196,817,160 $175,833,397 ($20,983,762)

12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 9.80% 10.95% -(1.14)%


Electric Utility - State of Minnesota PART C

Schedule 1


(A) (B) (C)

Results of Most

Recent General

Line Rate Case Proposed Interim Change

No. Description E017/GR-10-239 Test Year (B) - (A)


1 Production $331,371,153 $380,275,743 $48,904,590

2 Transmission 102,098,558 143,446,620 41,348,062

3 Distribution 155,690,830 206,471,049 50,780,219

4 General 35,999,840 43,708,142 7,708,302

5 Intangible 1,838,921 4,987,994 3,149,073

6 TOTAL Utility Plant in Service $626,999,301 $778,889,548 $151,890,246


8 Production ($126,360,960) ($176,440,662) ($50,079,702)

9 Transmission (38,885,216) (53,817,600) (14,932,384)

10 Distribution (65,176,678) (90,174,014) (24,997,336)

11 General (14,876,247) (19,344,522) (4,468,275)

12 Intangible (521,072) (2,460,800) (1,939,728)

13 TOTAL Accumulated Depreciation ($245,820,173) ($342,237,598) ($96,417,425)


15 Production $205,010,193 $203,835,081 (1,175,112)

16 Transmission 63,213,342 89,629,020 26,415,678

17 Distribution 90,514,152 116,297,035 25,782,883

18 General 21,123,593 24,363,620 3,240,027

19 Intangible 1,317,849 2,527,195 1,209,346

20 NET Utility Plant in Service $381,179,129 $436,651,950 $55,472,821

21 Big Stone Plant capitalized items 0 0 0

22 Utility Plant Held for Future Use 13,501 13,813 312

23 Construction Work in Progress 7,896,901 12,903,888 5,006,987

24 Materials and Supplies 7,748,957 9,405,728 1,656,771

25 Fuel Stocks 4,385,378 5,824,626 1,439,248

26 Prepayments (17,177,346) (5,615,204) 11,562,142

27 Customer Advances & Deposits (486,354) (1,028,345) (541,991)

28 Cash Working Capital 2,257,803 5,073,644 2,815,841

29 Unamortized Rate Case Expense (2,400)

30 Accumulated Deferred Income Taxes (93,099,342) (100,930,779) (7,831,437)

31 Total Average Rate Base $292,716,226 $362,299,321 $69,580,694

COMPARISON OF PROPOSED INTERIM RATES TO OTP'S MOST RECENT GENERAL RATE CASE



Schedule 2


DESCRIPTION OF CHANGES

COMPARISON OF PROPOSED INTERIM RATES TO OTP'S MOST RECENT GENERAL RATE CASE

Total Average Rate Base proposed by OTP for interim rates has increased by approximately $69.6 million since OTP’s Most Recent General Rate Case. As noted earlier, interim rates exclude rate base being recovered in the ECRR and TCRR during the interim period.

A majority of the increase in Average Rate Base was related to the net effect of Utility Plant in Service, Construction Work in Progress (CWIP), Prepayments, and Accumulated Deferred Income Taxes. Total Net Plant in Service increased approximately $55.5 million. Gross Plant in Service increased by $151.9 million and Total Accumulated Depreciation increased by $96.4 million. In addition, Construction Work in Progress increased approximately $5.0 million. Prepayments decreased $11.6 million, which is an increase to rate base. The increases in Utility Plant in Service , CWIP, and Prepayments were offset by an increase in Accumulated Deferred Income Taxes, which is a reduction to rate base, of approximately $7.8 million. These four components account for $64.3 million of the $69.6 million increase to rate base.

Distribution Plant now comprises 26.6 percent of Net Plant compared to 23.7 percent for OTP’s Most Recent General Rate Case, increasing distribution plant by $25.8 million, (capital additions of $50.8 million offset by increases in depreciation reserves of $25.0 million).

Transmission Plant has increased by $26.4 million (capital additions of $41.3 million offset by increases in depreciation reserves of $14.9 million). Transmission Plant now comprises 20.5 percent of Net Plant as compared to 16.6 percent in OTP’s Most Recent General Rate Case.

Net Production Plant in Service decreased $1.2 million since OTP’s Most Recent General Rate Case. Production Plant is now 46.7 percent of Plant in Service compared to 53.8 percent in that case.

As mentioned earlier, Accumulated Deferred Income Taxes, a reduction to average Rate Base, increased by $7.8 million. This increase is mainly caused by timing differences between book and tax depreciation on plant in service investment.

Cash Working Capital increased approximately $2.8 million, Materials and Supplies comprised an increase of $1.7 million, Fuel Inventory increased by $1.4 million, Prepayments decreased by $11.6 million (increase to rate base) and Customer Advances and Deposits increased by $542,000 (reduction to rate base) since OTP’s Most Recent General Rate Case.

The net effect of the $55.5 million increase in Net Plant in Service, the $5.0 million increase in CWIP, the $11.6 million decrease in Prepayments (which results in a increase to Average Rate Base), the $7.8 million increase in Accumulated Deferred Income Taxes (a reduction to Average Rate Base), the $2.8 million increase in Cash Working Capital, the $3.1 million increase in Materials and Supplies and Fuel Inventory along with the $542,000 increase in Customer Advances and Deposits (a reduction to Average Rate Base) account for the $69.6 million increase in Total Average Rate Base for the interim rate period.



COMPARISON OF PROPOSED INTERIM RATES TO OTP'S MOST RECENT GENERAL RATE CASE Schedule 3


(A) (B) (C)

Results of MostRecent General



OPERATING REVENUES

1 Retail $146,009,997 $175,833,397 $29,823,400


3 TOTAL OPERATING REVENUE $152,376,056 $183,144,530 $30,768,474


5 Production Expenses $64,889,152 $87,047,754 $22,158,602

6 Transmission Expenses 5,189,612 7,816,881 2,627,269

7 Distribution Expenses 6,883,548 7,594,039 710,490

8 Customer Accounting Expenses 5,481,309 6,565,033 1,083,723

9 Customer Service & Information Expenses 4,796,162 5,950,790 1,154,628

10 Sales Expenses 252,584 108,214 (144,370)

11 Administration & General Expenses 14,800,113 20,612,538 5,812,425

12 Charitable Contributions 77,252 93,027 15,775

13 Depreciation Expense 19,737,491 23,405,388 3,667,897

14 General Taxes 4,642,902 6,044,979 1,402,077

15 TOTAL OPERATING EXPENSES $126,750,126 $165,238,642 $38,488,517




18 Deferred Income Taxes 15,467,063 3,199,612 (12,267,450)

19 Income Taxes (9,026,293) 1,905,159 10,931,452

20 TOTAL INCOME TAX EXPENSE $1,510,564 $626,715 ($883,848)


22 Allowance for Funds Used During Construction 421,564 671,443 249,879








The Total Available for Return approved by the Commission in OTP’s Most Recent General Rate Case compared to Total Available for Return in the Proposed Interim Test Year shows a decrease of $6.6 million.

Major components of the change in utility available for return include the following:

Retail Electric Revenues increased by $29.8 million or 20.4%.

Other Revenue increased by $0.9 million from $6.4 million in OTP’s Most Recent General Rate Case to $7.3 million in the Proposed Interim Test Year.

Fuel, Purchased Energy and Power Production costs have increased by approximately $22.2 million compared to the OTP’s Most Recent General Rate Case. This increase is due primarily to the increased electricity sales.

Other Operating Expenses increased by approximately $11.2 million. The changes that occurred in the various cost functions are: Transmission expense, an increase of $2.6 million; Distribution expense, an increase of $0.7 million; Customer Accounting, an increase of $1.1 million; Customer Services combined with Information and Sales, an increase of $1.0 million; and Administrative and General expense, an increase of $5.8 million.

Depreciation expense increased by approximately $3.7 million which represents a 18.5 percent increase over OTP’s Most Recent General Rate Case.

General Taxes increased $1.4 million since OTP’s Most Recent General Rate Case, primarily due to the additional investment in plant in service.

Deferred Income Taxes and Investment Tax Credits have decreased by $11.8 million while Income Tax Expense has increased by $10.9 million resulting in a decrease of approximately $883,000 in Total Income Taxes since OTP’s Most Recent General Rate Case.

Compared to OTP’s Most Recent General Rate Case, Allowance for Funds Used During Construction (AFUDC) increased by $250,000 reflecting an increase in projects with long development lead times carried in CWIP.





(A) (B) (C)

Results of MostRecent General



1 Average Rate Base $292,716,226 $362,299,321 $69,583,095


3 Allowance for Funds Used During Construction (AFUDC) $421,564 $671,443 $249,879


5 Overall Rate of Return (Line 4 / Line 1) 8.38% 4.95% (3.43)%

6 Required Rate of Return 8.61% 8.07% (0.54)%

7 Operating Income Requirement (Line 1 x Line 6) $25,202,867 $29,237,555 $4,034,688

8 Income Deficiency (Line 7 - Line 4) $665,937 $11,286,940 $10,621,003


10 Revenue Deficiency (Line 8 x Line 9) $1,135,832 $19,251,137 $18,115,305

11 Retail Related Revenues Under Present Rates $146,009,997 $175,833,397 $29,823,400

12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 0.78% 10.95% 10.17%




CAPITAL STRUCTURE AND RATE OF RETURN CALCULATIONS Page 1 of 1

(A) (B) (C) (D)

Line % of Total Cost of Weighted Cost

No. Capitalization: Amount Capitalization Capital of Capital

1 Long-Term Debt $288,367,295 45.5% 6.68% 3.04%

2 Short-Term Debt 17,956,893 2.8% 0.79% 0.02%

3 Long-Term and Short-Term Debt $306,324,188 48.3% 6.33% 3.06%

4 Preferred Stock 0 0.00% 0.00% 0.00%

5 Net Common Equity 328,112,867 51.7% 10.74% 5.55%

6 Total Equity $328,112,867 51.7% 5.55%

7 Total Capitalization $634,437,055 100.00% 8.61%

8 Long-Term Debt 440,700,278$ 44.9% 5.62% 2.52%

9 Short-Term Debt 25,676,482 2.6% 3.28% 0.09%

10 Long-Term and Short-Term Debt $466,376,760 47.5% 5.49% 2.61%

11 Preferred Stock 0 0.0% 0.00% 0.00%

12 Net Common Equity 515,490,561 52.5% 10.40% 5.46%

13 Total Equity $515,490,561 52.5% 5.46%

14 Total Capitalization $981,867,321 100.0% 8.07%

Most Recent

General Rate Case

Filing

Proposed

Interim

Rate Change

(A) (B) (C) = (B) - (A)

15 Long-Term Debt $288,367,295 $440,700,278 $152,332,983

16 Short-Term Debt 17,956,893 $25,676,482 $7,719,589

17 Long-Term and Short-Term Debt $306,324,188 $466,376,760 $160,052,572

18 Preferred Stock 0 0 $0

19 Net Common Equity 328,112,867 515,490,561 187,377,694

20 Total Equity $328,112,867 $515,490,561 $187,377,694

21 Total Capitalization $634,437,055 $981,867,321 $347,430,266

I. Capital Structure and Rate of Return Calculation Approved by the Commission in the

Most Recent General Rate Case (Docket E017/GR-10-239)

II. Capital Structure and Rate of Return Calculation for Proposed Interim Test Year

III. Amount of Changes Between I and II

Amount




CAPITAL STRUCTURE AND RATE OF RETURN CALCULATIONS Page 1 of 1


Long-Term Debt in the Proposed Interim Test Year has increased by approximately $152.3 million, compared to OTP’s Most Recent General Rate Case. The increase in Long-Term Debt was necessary to support OTP’s capital expenditure plan and maintain an appropriate balance of debt and equity and a balanced capital structure.

The capital structure for Interim Rates includes $25.7 million of Short-Term Debt as compared to $18.0 million in OTP’s Most Recent General Rate Case.

Common Equity has increased by approximately $187.4 million primarily due to reinvestment of retained earnings and infusions of equity from Otter Tail Corporation to support OTP’s capital expenditure plan and provide an appropriate balance of debt and equity and a balanced capital structure.

The overall cost of capital has decreased from OTP’s Most Recent General Rate Case. The decrease has been driven primarily by a decrease in the cost of debt. The 10.40% cost of common equity is slightly lower than the 10.74% cost of common equity in OTP’s Most Recent General Rate Case.


Electric Utility - State of Minnesota PART D

COMPARISON OF PROPOSED INTERIM RATES TO UNADJUSTED PROJECTED FISCAL YEAR Schedule 1


(A) (B) (C)Unadjusted

Line Projected Year Proposed Interim Change



1 Production $471,279,046 $380,275,743 ($91,003,303)

2 Transmission 201,692,793 143,446,620 (58,246,173)

3 Distribution 206,471,049 206,471,049 0

4 General 43,720,944 43,708,142 (12,802)

5 Intangible 4,989,455 4,987,994 (1,461)

6 TOTAL Utility Plant in Service $928,153,287 $778,889,548 ($149,263,739)


8 Production ($177,689,338) ($176,440,662) $1,248,676

9 Transmission (56,203,615) (53,817,600) 2,386,015

10 Distribution (90,174,014) (90,174,014) 0

11 General (19,350,189) (19,344,522) 5,666

12 Intangible (2,461,520) (2,460,800) 721

13 TOTAL Accumulated Depreciation ($345,878,676) ($342,237,598) $3,641,078


15 Production $293,589,708 $203,835,081 ($89,754,627)

16 Transmission 145,489,178 89,629,020 (55,860,158)

17 Distribution 116,297,035 116,297,035 0

18 General 24,370,755 24,363,620 (7,136)

19 Intangible 2,527,935 2,527,195 (740)

20 NET Utility Plant in Service $582,274,611 $436,651,950 ($145,622,661)

21


23 Construction Work in Progress 15,145,571 12,903,888 (2,241,683)

24 Materials and Supplies 9,408,219 9,405,728 (2,491)

25 Fuel Stocks 5,824,626 5,824,626 0

26 Prepayments (26,352,061) (5,615,204) 20,736,856

27 Customer Advances & Deposits (1,034,452) (1,028,345) 6,107

28 Cash Working Capital 5,459,892 5,073,644 (386,249)

29 Accumulated Deferred Income Taxes (130,704,838) (100,930,779) 29,774,058

30 Total Average Rate Base $460,035,382 $362,299,321 ($97,736,061)


Electric Utility - State of MN PART D

Schedule 2

Page 1 of 1

DETAILED RATE BASE COMPONENTS


COMPARISON OF PROPOSED INTERIM RATES TO UNADJUSTED

PROJECTED FISCAL YEAR

Total Average Rate Base for the Company’s Interim Rate Petition decreased by approximately $97.7 (1) million from the Unadjusted Projected Fiscal Year. The decrease is primarily the net result of a $145.6 million decrease in Net Plant in Service, a decrease of $2.2 million in CWIP, offset by an increase of $29.8 million in ADIT, and a $20.7 million increase in Prepayments.

PrepaymentsOne component of Prepayments is the Prepaid Pension Asset. A Test Year adjustment was made to include the balance of the Prepaid Pension Asset in Rate Base. The treatment of the Prepaid Pension Asset is described in more detail in the direct testimony of Mr. Peter J. Beithon.

Construction Work in Progress (CWIP)An adjustment made to reduce CWIP by $2.2 million is primarily due to the removal of the Environmental and Transmission Cost Recovery Riders from the Interim Rate petition.

Accumulated Deferred Income Taxes (ADIT)An adjustment made to increase ADIT by $29.8 million is primarily due to the removal of the environmental and transmission cost recovery riders from the Interim Rate petition. The treatment of these two riders is described in more detail in the direct testimony of Mr. Stuart Tommerdahl.

In summary, the net effect of the $145.6 million decrease in Net Plant in Service, $2.2 million in CWIP, offset by a $20.7 million increase in Prepayments, and a $29.8 million increase in ADIT account for the most significant changes in Total Average Rate Base for the proposed interim rate period.

(1) The primary reason for this change is that the Unadjusted Projected Test Year includes riders while the interim rates petition excludes the riders.



Schedule 3

Page 1 of 1

STATEMENT OF OPERATING INCOME


Projected

Line Fiscal Year Proposed Interim Change


OPERATING REVENUES

1 Retail $196,817,160 $175,833,397 ($20,983,762)

2 Other Operating Revenue 17,240,816 7,311,132 (9,929,683)

3 TOTAL OPERATING REVENUE $214,057,975 $183,144,530 ($30,913,446)


5 Production Expenses $87,059,992 $87,047,754 ($12,239)

6 Transmission Expenses 17,367,755 7,816,881 (9,550,874)

7 Distribution Expenses 7,594,039 7,594,039 0

8 Customer Accounting Expenses 6,565,033 6,565,033 0

9 Customer Service & Information Expenses 7,297,375 5,950,790 (1,346,584)

10 Sales Expenses 108,214 108,214 0

11 Administration & General Expenses 20,552,799 20,612,538 59,739

12 Charitable Contributions 93,027 93,027 0

13 Depreciation Expense 26,484,872 23,405,388 (3,079,484)

14 General Taxes 7,325,055 6,044,979 (1,280,076)

15 TOTAL OPERATING EXPENSES $180,448,160 $165,238,642 ($15,209,518)




19 Deferred Income Taxes 3,203,513 3,199,612 (3,901)

20 Income Taxes 7,328,359 1,905,159 (5,423,200)

21 TOTAL INCOME TAX EXPENSE $6,023,421 $626,715 ($5,396,705)


23 Allowance for Funds Used During Construction 818,137 671,443 (146,694)



COMPARISON OF PROPOSED INTERIM RATES TO

UNADJUSTED PROJECTED FISCAL YEAR



Schedule 4

Page 1 of 1

STATEMENT OF OPERATING INCOME




Total Retail Electric revenues decreased by $21.0 million from the Unadjusted Projected Fiscal Year compared to the Interim Rate Petition in this filing. The decrease is driven primarily by the adjustments to remove the environmental and transmission cost recovery riders.

Other Operating Revenue decreased by $9.9 million from the Unadjusted Projected Fiscal Year to the Interim Rate Petition, due to the removal of transmission rider related MISO revenues and expenses.

In comparing the cost of Fuel, Purchased Energy and Power Production Expenses in the Unadjusted Projected Fiscal Year to the Interim Petition, there was an decrease of $12,000 in the Interim Rate Petition or less than one percent.

Excluding the cost of Fuel, Purchased Energy and Power Production, other operating expenses decreased $10.8 million in total. Transmission expenses decreased $9.6 million; Customer Service, Information and Sales expenses decreased by $1.3 million; and Administrative and General (A&G) expenses increased by approximately $59,000.

Depreciation expense is lower by $3.1 million driven primarily by an as the removal of the environmental and transmission cost recovery riders.

Current Federal and State Income Taxes decreased by $5.4 million because taxable income is lower in the Proposed Interim Year than in the Unadjusted Projected Fiscal Year. Deferred Income Taxes and Investment Tax Credits had a net increase of $26,000.

The changes described above help to account for the $10.3 million reduction in utility operating income for the Proposed Interim Rate period compared to the Unadjusted Projected Fiscal Year.



Schedule 5

Page 1 of 1

SUMMARY OF REVENUE REQUIREMENTS


Projected

Line Fiscal Year Proposed Interim Change


1 Average Rate Base $460,035,382 $362,299,321 ($97,736,061)


3 Allowance for Funds Used During Construction (AFUDC) $818,137 $671,443 ($146,694)




7 Operating Income Requirement (Line 1 x Line 6) $37,124,855 $29,237,555 ($7,887,300)

8 Income Deficiency (Line 7 - Line 4) $8,720,324 $11,286,940 $2,566,617



11 Retail Related Revenues Under Present Rates $196,817,160 $175,833,397 ($20,983,762)





Electric Utility - State of Minnesota PART E

OTP'S MOST RECENT GENERAL RATE CASE TO PROPOSED TEST YEAR Schedule 1


(A) (B) (C)

Results of Most

Recent General Proposed

Line Rate Case Test Year Change

No. Description E017/GR-10-239 2016 (B) - (A)


1 Production $331,371,153 $474,971,844 $143,600,691

2 Transmission 102,098,558 203,387,403 101,288,845

3 Distribution 155,690,830 206,471,049 50,780,219

4 General 35,999,840 43,721,726 7,721,886

5 Intangible 1,838,921 4,989,544 3,150,623

6 TOTAL Utility Plant in Service $626,999,302 $933,541,568 $306,542,266


8 Production ($126,360,960) ($177,864,084) ($51,503,124)

9 Transmission (38,885,216) (56,299,033) (17,413,817)

10 Distribution (65,176,678) (90,174,014) (24,997,336)

11 General (14,876,247) (19,350,534) (4,474,287)

12 Intangible (521,072) (2,461,564) (1,940,492)

13 TOTAL Accumulated Depreciation ($245,820,173) ($346,149,230) ($100,329,057)


15 Production $205,010,193 $297,107,760 $92,097,567

16 Transmission 63,213,342 147,088,370 83,875,028

17 Distribution 90,514,152 116,297,035 25,782,883

18 General 21,123,593 24,371,192 3,247,599

19 Intangible 1,317,849 2,527,980 1,210,131

20 NET Utility Plant in Service $381,179,129 $587,392,337 $206,213,208

21


23 Construction Work in Progress 7,896,901 12,905,889 5,008,988

24 Materials and Supplies 7,748,957 9,408,372 1,659,415

25 Fuel Stocks 4,385,378 5,824,626 1,439,248

26 Prepayments (17,177,346) (5,679,130) 11,498,216

27 Customer Advances & Deposits (486,354) (1,034,643) (548,289)

28 Cash Working Capital 2,257,803 4,905,898 2,648,095

29 Unamortized Rate Case Expense (2,400)

30 Accumulated Deferred Income Taxes (93,099,342) (130,736,573) (37,637,231)

31 Total Average Rate Base $292,716,226 $483,000,588 $190,281,961



Schedule 2



OTP'S MOST RECENT GENERAL RATE CASE TO PROPOSED TEST YEAR

Total Average Rate Base of the Company for the Minnesota jurisdiction in the 2016 proposed test year has increased by approximately $190.3 million since OTP's Most Recent General Rate Case. The Proposed Test Year includes investments being recovered in OTP's ECRR and TCRR. OTP proposes these investments be rolled into base rates when final rates go into effect.

A majority of the increase in Average Rate Base was related to the net effect of the $206.2 million increase in Net Utility Plant in Service, which is the result of Gross Plant in Service increasing by $306.5 million and the Reserve for Depreciation and Amortization increasing by $100.3 million. There were also increases in Construction Work in Progress of $5.0 million, Materials and Supplies of $1.7 million, Fuel Stocks of $1.4 million, Prepayments of $11.5 million, and Cash Working Capital of $2.7 million, offset by decreases in Customer Advances & Deposits of $0.5 million and a $37.6 million decrease in Accumulated Deferred Income Taxes.

Distribution Plant in the Proposed Test Year comprises 19.8 percent of Net Plant compared to 23.7 percent in OTP's Most Recent General Rate Case, increasing by $25.8 million, (capital additions of $50.8 million offset by increases in depreciation reserves of $25.0 million).

Transmission Plant represents 25 percent of total Net Plant in the Proposed Test Year versus 16.6 percent in OTP's Most Recent General Rate Case. The value of Transmission Plant has increased by $83.9 million (capital additions of $101.3 million offset by increases in depreciation reserves of $17.4 million).

The value of Production Plant as a percent of Net Plant in Service has decreased from 53.8 percent of Net Plant in OTP's Most Recent General Rate Case to 50.6 percent in the Proposed Test Year. Net Production Plant increased by $92.1 million, (capital additions of $143.6 million offset by increases in depreciation reserves of $51.5 million)

Construction Work in Progress (CWIP) increased by approximately $5.0 million driven in large part by significant investment in environmental and on-going transmission related projects.

The net impact of the changes between OTP’s Most Recent General Rate Case and its Proposed Test Year is an increase of $190.3 million in Total Average Rate Base.



OTP'S MOST RECENT GENERAL RATE CASE TO PROPOSED TEST YEAR Schedule 3


(A) (B) (C)

Results of Most




OPERATING REVENUES

1 Retail $146,009,997 $196,817,160 $50,807,163


3 TOTAL OPERATING REVENUE $152,376,056 $203,994,824 $51,618,768


5 Production Expenses $64,889,152 $87,059,992 $22,170,840

6 Transmission Expenses 5,189,612 8,091,378 2,901,766

7 Distribution Expenses 6,883,548 7,594,039 710,490

8 Customer Accounting Expenses 5,481,309 6,565,033 1,083,723

9 Customer Service & Information Expenses 4,796,162 7,297,375 2,501,213

10 Sales Expenses 252,584 108,214 (144,370)

11 Administration & General Expenses 14,800,113 20,645,066 5,844,953

12 Charitable Contributions 77,252 93,027 15,775

13 Depreciation Expense 19,737,491 27,039,957 7,302,466

14 General Taxes 4,642,902 7,327,555 2,684,654

15 TOTAL OPERATING EXPENSES $126,750,126 $171,821,636 $45,071,511

16 NET OPERATING INCOME BEFORE INCOME TAXES $25,625,930 $32,173,187 $6,547,257



18 Deferred Income Taxes 15,467,063 3,203,663 (12,263,399)

19 Income Taxes (9,026,293) 6,485,488 15,511,782

20 TOTAL INCOME TAX EXPENSE $1,510,564 $5,179,613 $3,669,050

21 NET OPERATING INCOME $24,115,366 $26,993,574 $2,878,207

22 Allowance for Funds Used During Construction 421,564 671,547 249,983

23 TOTAL AVAILABLE FOR RETURN $24,536,930 $27,665,121 $3,128,190




Schedule 4




Comparing OTP’s utility operating income approved by the Commission in OTP’s Most Recent General Rate Case, to operating income for the Proposed Test Year, shows an increase of approximately $2.9 million.

Major components of the change in utility operating income include the following:

Retail Electric Revenues increased by $50.8 million reflecting increased investment in transmission and environmental projects. Other Revenue increased by $812,000 .

Fuel, Purchased Energy and Power Production costs have increased by $22.2 million compared to OTP’s Most Recent General Rate Case. Approximately $12.3 million of this increase is in Purchased Energy costs.

Other Operating Expenses increased by approximately $12.9 million. The changes that occurred in the various cost functions are: Transmission expense, an increase of $2.9 million; Distribution expense, an increase of $0.7 million; Customer Accounting expense, an increase of $1.1 million; Customer Services and Information and Sales, an increase of $2.4 million; and Administrative and General expense, an increase of $5.8 million.

Depreciation expense increased $7.3 million for an increase of 37 percent.

General Taxes in the Proposed Test Year increased $2.7 million since OTP’s Most Recent General Rate Case. This is due to the fact there has been several legislated property tax changes related to depreciation allowed, changes in mill rates and lower assessed percentages that have benefited the Company even though investment in plant in service has increased since the last electric rate case.

Deferred Income Taxes and Investment Tax Credits have decreased overall by $11.8 million while Income Tax Expense has increased by $15.5 million resulting in an increase of approximately $3.7 million in Total Income Taxes since OTP’s Most Recent General Rate Case due to an increase in net operating income of $6.5 million.

Compared to OTP’s Most Recent General Rate Case, Allowance for Funds Used During Construction (AFUDC) increased by approximately $250,000 reflecting an increase in projects with long development lead times carried in CWIP.



Schedule 5


(A) (B) (C)

Results of Most




1 Average Rate Base $292,716,226 $483,000,588 $190,284,362

2 Operating Income (Before AFUDC) $24,115,366 $26,993,574 $2,878,208

3 Allowance for Funds Used During Construction (AFUDC) $421,564 $671,547 $249,983

4 Total Available for Return (Line 2 + Line 3 + Rounding) $24,536,930 $27,665,121 $3,128,191



7 Operating Income Requirement (Line 1 x Line 6) $25,211,673 $38,978,147 $13,766,474

8 Income Deficiency (Line 7 - Line 4) $674,743 $11,313,026 $10,638,283

9 Gross Revenue Conversion Factor 1.705611 1.705611 0.000000


11 Retail Related Revenues Under Present Rates $146,009,997 $196,817,160 $50,807,163



1/3 tab

Volume 1

Summary of Present and Interim Revenue


Electric Utility - State of Minnesota Page 1 of 1

INTERIM RATE SCHEDULE

SUMMARY COMPARISON OF OPERATING REVENUE

UNDER PRESENT AND PROPOSED INTERIM RATES FOR THE TEST YEAR

Percent

Rate Schedule Present Interim Increase Change

Residential Service $39,381,020 $43,692,655 $4,311,634 10.95%

Residential Demand Control 3,998,742 4,436,544 437,803 10.95%

Total Residential Class Revenue $43,379,762 $48,129,199 $4,749,437 10.95%

Farm Service $2,801,867 $3,108,630 $306,763 10.95%

General Service < 20 kW $8,835,876 $9,803,273 $967,397 10.95%

General Service >= 20 kW 17,256,033 19,145,311 1,889,278 10.95%

Commercial Time of Use 1,961,705 2,176,483 214,777

Total GS Class Revenue $28,053,614 $31,125,066 $3,071,452 10.95%

Large General Service $25,623,327 $28,428,699 $2,805,372 10.95%

Large General Service Time of Day 62,363,135 69,190,968 6,827,833 10.95%

Real Time Pricing 0 0 0 0.00%

Large General Service Rider 0 0 0 0.00%

Standby Service 0 0 0 0.00%

Total LGS Class Revenue $87,986,462 $97,619,668 $9,633,206 3.80%

Irrigation Services $358,351 $397,585 $39,234 10.95%

Outdoor Lighting - Energy Only $343,338 $380,929 $37,590 10.95%

Outdoor Lighting 2,200,286 2,441,184 240,898 10.95%

Total Lighting Class Revenue $2,543,624 $2,822,113 $278,489 10.95%

Municipal Pumping Service $1,403,471 $1,557,130 $153,659 10.95%

Civil Defense - Fire Sirens 4,423 4,907 484 10.95%

Total OPA Class Revenue $1,407,894 $1,562,037 $154,143 10.95%

Water Heating, Controlled $1,464,579 $1,624,929 $160,350 10.95%

Interruptible Load >= 80 kW $4,859,276 $5,391,294 $532,018 10.95%

Interruptible Load < 80 kW 1,539,271 1,707,798 168,527 10.95%

Total Interruptible Class Revenue $6,398,547 $7,099,092 $700,545 10.95%

Deferred Load Controlled Service $895,537 $993,584 $98,048 10.95%

Fix Time of Delivery Service 543,160 602,628 59,468 10.95%

Total Def. Ld. Class Revenue $1,438,697 $1,596,213 $157,516 10.95%

Total $175,833,397 $195,084,532 $19,251,135 10.95%

Operating Revenue

1/3 tab

Volume 1

Interim Tariff Sheets – Redlined

Fergus Falls, Minnesota

Interim Minnesota Public Utilities Commission

Section 9.01

ELECTRIC RATE SCHEDULE Residential Service

Page 1 of 2

Twenty-sixthfifth Revision

MINNESOTA PUBLIC UTILITIES COMMISSION Approved: April 25, 2011 Docket No. E-017/GR-15-1033GR-10-239

Thomas R. Brause Vice President, Administration

EFFECTIVE with bills rendered on and after

October 1, 2011 in Minnesota

RESIDENTIAL SERVICE

DESCRIPTION RATE

CODE

Residential Service 31-101

RULES AND REGULATIONS: Terms and conditions of this electric rate schedule and the

General Rules and Regulations govern use of this service.

APPLICATION OF SCHEDULE: This schedule is applicable to Residential Service as defined

in the General Rules and Regulations.

RATE:

RESIDENTIAL SERVICE

Customer Charge per Month: $8.50

Monthly Minimum Bill: Customer + Facilities Charges

Facilities Charge per Month: $0.00

Energy Charge per kWh: Summer Winter

7.9768.124 ¢/kWh

8.1928.340 ¢/kWh

INTERIM RATE ADJUSTMENT:

A 10.95 percent increase will be added to the sum of the following, as applicable: Customer

Charge, Energy Charge, Demand Charge, Fixed Charge, Facilities Charge, and the monthly

Minimum Charge.

MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be

modified by any Mandatory Rate Riders that must apply and by any Voluntary Rate

Riders selected by the Customer, unless otherwise noted in this schedule. See Sections 12.00,

13.00 and 14.00 of the Minnesota electric rates for the matrices of riders.

DEFINITIONS OF SEASONS:

Summer: June 1 through September 30.

Winter: October 1 through May 31.



Section 9.01

ELECTRIC RATE SCHEDULE Residential Service

Page 2 of 2

Twenty-sixthfifth Revision





SEASONAL RESIDENTIAL SERVICE:

1. These rates and regulations shall apply to Seasonal Residential Service without voluntary

rate riders.

2. Seasonal Residential Customers will be billed at the same rate as Residential Customers,

except as follows:

A one-time seasonal fixed charge of $34.00 will be billed for each Meter in addition to the

rate provided above. The fixed charge will be included on the first bill rendered for each

season.

Each Seasonal Residential Customer will be billed for the number of months each season

that the residence is in use, but not less than a minimum of four months, plus the seasonal

fixed charge. At the option of the Company, Meters may be read during the off-season

and a bill will be rendered if Energy recorded on the Meter exceeds 200 Kilowatt-Hours.

If the first bill of the season exceeds an average usage of 200 Kilowatt-Hours per month

during the off-season months, the Customer, at the option of the Company, may no longer

be eligible for Seasonal Residential Service.

Bills may be rendered on a two-month basis at the Company’s discretion when the Energy

used exceeds 200 Kilowatt-Hours and more than 55 days have elapsed since the previous

Meter reading.

Seasonal Residential Customers also will be subject to a connection charge of $40.00

when the Account is established.



Section 9.02

ELECTRIC RATE SCHEDULE Residential Demand Control Service

(RDC) Page 1 of 2

ThirteenthTwelfth Revision





RESIDENTIAL DEMAND CONTROL SERVICE

(Commonly identified as RDC)

DESCRIPTION RATE

CODE

Residential Demand Control 31-241



APPLICATION OF SCHEDULE: This schedule is applicable to Residential Customers with a

UL-approved Demand-control system.

RATE:



Monthly Minimum Bill: Customer + Facilities + Demand Charges



4.6714.819 ¢/kWh 5.0585.206 ¢/kWh

Demand Charge per kW: Summer Winter

$6.08 /kW $5.11 /kW




Minimum Charge.



Section 9.02


(RDC) Page 2 of 2

ThirteenthTwelfth Revision





MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified

by any Mandatory Rate Riders that must apply and by any Voluntary Rate Riders selected by the

Customer, unless otherwise noted in this schedule. See Sections 12.00, 13.00 and 14.00 of the

Minnesota electric rates for the matrices of riders.




BILLING DEMAND DETERMINATION: The Demand will be determined based on the peak

one-hour Demand reading recorded during the Winter period for the most recent 12 months. An

estimated Demand of three kW will be used for Customers new to this rate until a Demand is

established.

DEMAND SIGNAL: Service may receive a Demand signal for up to a total of 14 hours during a

24-hour period, as measured from midnight to midnight. Water heaters served on this schedule also

will be included in the Company’s Summer water heater load control program.



Section 9.03

ELECTRIC RATE SCHEDULE Farm Service

Page 1 of 2

Twenty-fifthfourth Revision





FARM SERVICE

DESCRIPTION RATE

CODE

Farm Service 31-361



APPLICATION OF SCHEDULE: This schedule is applicable to general Farm and home use.

The Customer may elect to have the following service offerings in the farm home (for residential

uses); Residential Service (Section 9.01) or Residential Demand Control Service Schedule

(Section 9.02) if all the requirements specified for the schedules are satisfied.

RATE:

FARM SERVICE



Facilities Charge per Month:

Single-phase $0.00

Three-phase: $8.00


7.6667.814 ¢/kWh 7.8738.021 ¢/kWh




Minimum Charge.



Section 9.03


Page 2 of 2

Twenty-fifthfourth Revision














Section 10.01

ELECTRIC RATE SCHEDULE Small General Service

Page 1 of 4

ThirdSecond Revision





SMALL GENERAL SERVICE

Under 20 kW

DESCRIPTION Secondary Primary

Metered Service – under 20 kW 31-404 31-405

Non-metered Service - 1000 Watts or less – CLOSED TO

NEW INSTALLATIONS

31-408 Not Available



APPLICATION OF SCHEDULE: This schedule is applicable to Three-phase Residential

Customers, and both Single- and Three-phase nonresidential Customers. This schedule is not

applicable for outdoor lighting. Emergency and supplementary/standby service will be supplied only

as allowed by law.

RATE:

SECONDARY SERVICE PRIMARY SERVICE

Customer Charge per Month: $15.50 $15.50

Monthly Minimum

Bill: Customer + Facilities Charges Customer + Facilities Charges

Facilities Charge per Month: $0.00 $0.00

Energy Charge per kWh: Summer Winter Summer Winter

7.579

7.727 ¢/kWh

7.784

7.932 ¢/kWh

7.331

7.479 ¢/kWh

7.484

7.632 ¢/kWh



Section 10.01


Page 2 of 4






NON-METERED SERVICE-SECONDARY ONLY-1000 WATTS OR LESS

***CLOSED TO NEW INSTALLATIONS***





All kWh 7.715

7.863 ¢/kWh

7.715

7.863 ¢/kWh


A 10.95 percent increase will be added to the sum of the following, as applicable: Customer Charge,

Energy Charge, Demand Charge, Fixed Charge, Facilities Charge, and the monthly Minimum

Charge.








TERMS AND CONDITIONS: The Customer may remain on the Small General Service schedule

as long as Customer's maximum Demand does not equal or exceed 20 kW for more than two of the

most recent 12 months. If the Customer achieves an actual Demand of 20 kW or greater for a third

time in the most recent 12 months, the Customer will be placed on the General Service schedule

(Section 10.02) in the next billing month.

SEASONAL SMALL GENERAL SERVICE:

1. These rates and regulations shall apply to Seasonal Small General Service without voluntary

rate riders.



Section 10.01


Page 3 of 4






2. Seasonal Small General Service Customers will be billed at the same rate as Small General

Service Customers, except as follows:



season.

Each Seasonal Small General Service Customer will be billed for the number of months each

season that the property is in use, but not less than a minimum of four months, plus the

seasonal fixed charge. At the option of the Company, Meters may be read during the off-

season and a bill will be rendered if Energy recorded on the Meter exceeds 400 Kilowatt-

Hours. If the first bill of the season exceeds an average usage of 400 Kilowatt-Hours per

month during the off-season months, the Customer, at the option of the Company, may no

longer be eligible for Seasonal Small General Service.



Meter reading.

Seasonal Small General Service Customers also will be subject to a connection charge of

$40.00 when the Account is established.

NON-METERED 1000 WATTS AND UNDER SERVICE:

For applications where no metering is installed, the applicable lower monthly Customer

Charge shall apply. For purposes of applying the appropriate Customer service charge, one

Customer Charge shall be applied for every point of delivery. A point of delivery shall be any

location where a Meter would otherwise be required under this schedule.

For applications where Customer owns and operates multiple electronic devices such

electronic devices are: 1) individually located at each point of delivery, 2) rated at less than

1000 watts or as specified in contract, and 3) operated with a continuous and constant load

level year round. Each individual electronic device must not in any way interfere with

Company operations and service to adjacent Customers. This optional service is not

applicable to electric service for traffic lights, civil defense-fire sirens, or lighting. Company

reserves the right to evaluate Customer requests for this optional service to determine

eligibility.



Section 10.01


Page 4 of 4






In place of metered usage for each device, Customer will be billed for the predetermined

Energy usage in kWh per device. The Energy Charge shall equal the sum of the

predetermined Energy usage for Customer’s approved devices in service for the billing month

multiplied by the Energy Charge applicable for the billing month.

DETERMINATION OF DEMAND: Unless otherwise established, the Billing Demand shall be the

maximum Demand in kW as measured by a Demand Meter, for the highest 15-minute period during

the month for which the bill is rendered.



Section 10.02

ELECTRIC RATE SCHEDULE General Service

Page 1 of 2

Twenty-fourththird Revision





GENERAL SERVICE

20 kW or Greater

DESCRIPTION RATE

CODE

General Service – Secondary Service 31-401

General Service – Primary Service 31-403

RULES AND REGULATIONS: Terms and conditions of this electric rate schedule and the General

Rules and Regulations govern use of this service.

APPLICATION OF SCHEDULE: This schedule is applicable to Three-phase Residential Customers,

and both Single and Three-phase nonresidential Customers with a measured Demand of at least 20 kW

within the most recent 12 months. This schedule is not applicable for outdoor lighting. Emergency and

supplementary/Standby service will be supplied only as allowed by law.

RATE:



Monthly

Minimum Bill: Customer + Facilities + Demand Charges Customer + Facilities + Demand Charges

Facilities Charge per Month

per annual max. kW

(minimum 20 kW per Month): $0.60 /kW $0.40 /kW


6.7916.939 ¢/kWh

7.3537.501 ¢/kWh

6.5836.731 ¢/kWh

7.0907.238 ¢/kWh

Demand Charge per kW: Summer Winter Summer Winter

(minimum 20 kW) $1.22 /kW $1.02 /kW $1.17 /kW $0.97 /kW



Section 10.02


Page 2 of 2

Twenty-fourththird Revision








Charge.

MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by

any Mandatory Rate Riders that must apply and by any Voluntary Rate Riders selected by the Customer,

unless otherwise noted in this schedule. See Sections 12.00, 13.00 and 14.00 of the Minnesota electric

rates for the matrices of riders.




TERMS AND CONDITIONS: A Customer with a Billing Demand of less than 20 kW for 12

consecutive months will be required to take service under the Small General Service schedule

(Section 10.01).

METERED DEMANDS: The maximum kW as measured by a Demand Meter for any period of 15

consecutive minutes during the month for which the bill is rendered.

ADJUSTMENT FOR EXCESS REACTIVE DEMAND: For billing purposes, the Metered

Demand may be increased by 1 kW for each whole 10 kVar of measured Reactive Demand in excess

of 50% of the Metered Demand in kW.

DETERMINATION OF BILLING DEMAND: The Billing Demand shall be the greater of 20

kW or the Metered Demand adjusted for Excess Reactive Demand.

DETERMINATION OF FACILITIES CHARGE: The Facilities Charge Demand will be based

on the greater of 1) 20 kW or 2) the largest of the most recent 12 monthly Billing Demands.



Section 10.03

ELECTRIC RATE SCHEDULE General Service – Time of Use

Page 1 of 3

SeventeenthSixteenth Revision





GENERAL SERVICE - TIME OF USE

DESCRIPTION RATE

CODE

Declared-Peak 31-708

Intermediate 31-709

Off-Peak 31-710



APPLICATION OF SCHEDULE: This schedule is applicable to nonresidential Customers with

one Meter providing electrical service.

RATE:





Per annual maximum kW

(minimum 20kW per Month): $0.60 /kW


Declared-Peak

20.33220.480 ¢/kWh

21.62421.772 ¢/kWh

Intermediate 5.1625.310 ¢/kWh 4.7034.851 ¢/kWh

Off-Peak 2.3312.479 ¢/kWh 3.5053.653 ¢/kWh

Demand Charge per kW

(minimum of 20 kW):

Summer Winter

Declared-Peak N/A /kW N/A /kW

Intermediate $2.64 /kW $1.36 /kW

Off-Peak $0.00 /kW $0.00 /kW




Minimum Charge.



Section 10.03


Page 2 of 3










METERED DEMANDS: The maximum kW as measured for one hour during each period of the

Declared-Peak, Intermediate and Off-Peak periods during the month for which the bill is rendered.


Demand may be increased by 1 kW for each whole 10 kVar of Reactive Demand in excess of 50%

of the Metered Demand in kW.


kW or the Metered demand during the Intermediate Period and adjusted for Excess Reactive

Demand.

DETERMINATION OF FACILITIES CHARGE: The Facilities Charge Demand will be the

greater of 1) 20 kW, or 2) the largest of the most recent 12 monthly Metered Demands adjusted for

Excess Reactive Demand.

DEFINITION OF DECLARED, INTERMEDIATE AND OFF-PEAK PERIODS BY SEASON:

WINTER SEASON - OCTOBER 1 THROUGH MAY 31 BILLINGS Declared-Peak: For all kW and kWh used during the hours declared (see Declared-Peak Notification)

Intermediate: For all kW and kWh used during the hours other than declared-peak and off-peak Off-Peak: For all kW and kWh used Monday through Saturday from10:00 p.m. to 6:00 a.m., and all day Sunday

SUMMER SEASON - JUNE 1 THROUGH SEPTEMBER 30 BILLINGS Declared-Peak: For all kW and kWh used during the hours declared (see Declared-Peak Notification)

Intermediate: For all kW and kWh used during the hours other than declared-peak and off-peak



Section 10.03


Page 3 of 3






Off-Peak: For all kW and kWh used Monday through Saturday from10:00 p.m. to 6:00 a.m., and all day Sunday

DECLARED-PEAK NOTIFICATION: The Company shall make available to the Customers, no

later than 4:00 p.m. (Central Time) of the preceding day, "declared-peak" designations for the next

business day. Except for unusual periods, the Company will make "declared-peak" designations for

Saturday through Monday available to Customers on the previous Friday. More than one-day-ahead

"declared-peak" designations may also be used for the following holidays: New Year’s Day,

Memorial Day, Independence Day, Labor Day, Thanksgiving, and Christmas.

Because circumstances prevent the Company from projecting "declared-peak" designations more

than one day in advance, the Company reserves the right to revise and make available to Customers

"declared-peak" designations for Sunday, Monday, any of the holidays mentioned above, or for the

day following a holiday. Any revised "declared-peak" designations shall be made available by the

usual means no later than 4:00 p.m. of the day prior to the prices taking effect.

The Company is not responsible for the Customer's failure to receive or obtain and act upon the

"declared-peak" designations. If the Customer does not receive or obtain the "declared-peak"

designations made available the Company, it is the Customer's responsibility to notify the Company

by 4:30 p.m. (Central Time) of the business day preceding the day that the "declared-peak"

designations are to take effect. The Company will be responsible for notifying the Customer if

prices are revised.



Section 10.04

ELECTRIC RATE SCHEDULE Large General Service

Page 1 of 3

TwentiethNineteenth Revision





LARGE GENERAL SERVICE

DESCRIPTION RATE

CODES

Secondary Service 31-603

Primary Service 31-602

Transmission Service 31-632



APPLICATION OF SCHEDULE: This schedule is applicable to nonresidential Customers. This

schedule is not applicable for outdoor lighting. Emergency and supplementary/Standby service will

be supplied only as allowed by law.

RATE:

SECONDARY SERVICE




per annual max. kW (minimum 80 kW per Month)

Less than 1000 kW: $0.33 /kW

Greater than or equal to 1000 kW: $0.24 /kW


4.6184.766 ¢/kWh 5.0005.148 ¢/kWh


(minimum of 80 kW): Summer Winter

$7.22 /kW $6.07 /kW



Section 10.04


Page 2 of 3






PRIMARY SERVICE




per annual max. kW (minimum 80kW per Month)

All kW: $0.12 /kW


4.4774.625 ¢/kWh 4.8214.969 ¢/kWh

Demand Charge per kW Summer Winter

(minimum of 80 kW): $6.93 /kW $5.76 /kW

TRANSMISSION SERVICE





All kW: $0.00 /kW


4.2444.392 ¢/kWh 4.5334.681 ¢/kWh






Minimum Charge.



Section 10.04


Page 3 of 3













METERED DEMAND: The maximum kW as measured by a Demand Meter for any period of 15



Demand may be increased by 1 kW for each whole 10 kVar of measured Reactive Demand in

excess of 50% of the Metered Demand in kW.







Section 10.05

ELECTRIC RATE SCHEDULE Large General Service – Time of Day

Page 1 of 4

SeventhSixth Revision





LARGE GENERAL SERVICE - TIME OF DAY

DESCRIPTION On-Peak Shoulder Off-Peak

Secondary Service 31-611 31-615 31-613

Primary Service 31-610 31-614 31-612

Transmission Service 31-639 31-637 31-640

RULES AND REGULATIONS: Terms and conditions of this electric rate schedule and the General Rules and Regulations govern use of this service.

APPLICATION OF SCHEDULE: This schedule is applicable to nonresidential Customers with a measured Demand of at least 80 kW within the most recent 12 months.

RATE:

SECONDARY SERVICE





Less than 1000 kW: $0.33/kW

Greater than or equal to 1000 kW:

$0.24/kW


On-Peak

7.3197.467 ¢/kWh 6.5076.655 ¢/kWh

Shoulder 5.3975.545 ¢/kWh 4.9175.065 ¢/kWh

Off-Peak

2.4372.585 ¢/kWh

3.6653.813 ¢/kWh


On-Peak $5.54 /kW $5.13 /kW

Shoulder $1.68 /kW $0.94 /kW

Off-Peak $0.00 /kW $0.00 /kW



Section 10.05


Page 2 of 4






PRIMARY SERVICE




per annual max. kW (minimum 80 kW per Month): $0.12/kW


On-Peak

7.0677.215 ¢/kWh 6.2516.399 ¢/kWh

Shoulder 5.2285.376 ¢/kWh 4.7424.890 ¢/kWh

Off-Peak

2.3762.524 ¢/kWh

3.5463.694 ¢/kWh


On-Peak $5.32 /kW $4.94 /kW


Off-Peak $0.00 /kW $0.00 /kW



Monthly Minimum Bill

per annual max. kW

(minimum 80 kW per Month): Customer + Facilities Charges



On-Peak

6.6606.808 ¢/kWh

5.8445.992 ¢/kWh

Shoulder

4.9525.100 ¢/kWh 4.4604.608 ¢/kWh

Off-Peak

2.2722.420 ¢/kWh

3.3523.500 ¢/kWh




Section 10.05


Page 3 of 4






On-Peak $4.31 /kW $4.27 /kW


Off-Peak $0.00 /kW $0.00 /kW




Charge.








METERED DEMAND: The maximum kW as measured for one hour during each of the On-peak,

Shoulder and Off-Peak periods during the month for which the bill is rendered.

ADJUSTMENTS FOR EXCESS REACTIVE DEMANDS: For billing purposes, the Metered

Demands may be increased by one kW for each whole ten kVar of Reactive Demand in each period

in excess of 50% of the Metered Demand in kW.

DETERMINATION OF BILLING DEMAND: The Billing Demand shall be the Metered

Demand adjusted for Excess Reactive Demand.

DETERMINATION OF FACILITIES CHARGE: The Facilities Charge Demand will be based on

the greater of 1) 80 kW, or 2) the largest of the most recent 12 monthly Metered Demands adjusted

for Excess Reactive Demand.

DEFINITION OF ON-PEAK, SHOULDER AND OFF-PEAK PERIODS BY SEASON:

WINTER SEASON - OCTOBER 1 THROUGH MAY 31 BILLINGS On-Peak: For all kW and kWh used Monday through Friday between 7:00 a.m. and 12:00 noon, and between 5:00 p.m. and 9:00 p.m.



Section 10.05


Page 4 of 4






Shoulder: For all kW and kWh used Monday through Friday hour 6:00 a.m. to 7:00 a.m., hours 12:00 noon to 5:00 p.m. and hour 9:00 p.m. to 10:00 p.m. and, Saturday through Sunday 6:00 p.m. to 10:00 p.m.

Off-Peak: For all kW and kWh used Monday through Friday hours 10:00 p.m. to 6:00 a.m. and , Saturday and Sunday all hours except 6:00 p.m. to 10:00 p.m..

SUMMER SEASON - JUNE 1 THROUGH SEPTEMBER 30 BILLINGS On-Peak: For all kW and kWh used Monday through Friday between 1:00 p.m. and 7:00 p.m.

Shoulder: For all kW and kWh used Monday through Friday 9:00 a.m. to 1:00 p.m., and 7:00 p.m. to 10:00 p.m., Saturday through Sunday 9:00 a.m. to 10:00 p.m.

Off-Peak: For all kW and kWh used Monday through Friday hours 10:00 p.m. to 9:00 a.m.

and, Saturday and Sunday all hours except 9:00 a.m. to 10:00 p.m.



Section 11.01

ELECTRIC RATE SCHEDULE Standby Service

Page 1 of 8

EighthSeventh Revision

MINNESOTA PUBLIC UTILITIES COMMISSION Approved: January 27, 2014 Docket No. E-017/GR-15-1033M-13-609



February 1, 2014 in Minnesota

STANDBY SERVICE

OPTION A: FIRM OPTION B: NON-FIRM

On-Peak Shoulder Off-Peak On-Peak Shoulder Off-Peak

Transmission Service 31-941 31-942 31-943 31-950 31-951 31-952

Primary Service 31-944 31-945 31-946 31-953 31-954 31-955

Secondary Service 31-947 31-948 31-949 31-956 31-957 31-958



AVAILABILITY: This schedule, including Attachment 1 - Definitions and Useful Terms,

provides Backup, Scheduled Maintenance, and Supplemental Services, is applicable to any

Customer who has the following conditions:

1. Requests to become a Standby Service Customer of the Company. Otherwise, the

Company views the Customer as a Non-Standby Service Customer. For information about

the different categories of Non-Standby Service Customers, including exemptions from

Standby Service, please see Attachment No. 1 – Definitions.

2. Utilizes Extended Parallel Generation Systems to meet all or a portion of electrical

requirements, which is capable of greater than 100 kW. Customers with Extended Parallel

Generation Systems used to meet all or a portion of electrical requirements that are capable

of 100 kW or less are considered Non-Standby Service Customers and exempt from

paying standby charges. Please see Attachment No. 1-Definitions for more information

regarding Non-Standby Service Customers.

3. Enters into a contract for services related to its Generator. Contracts will be made for this

service provided the Company has sufficient Capacity available in production, transmission

and Distribution Facilities to provide such service at the location where the service is

requested.

The Company delivers alternating current service at transmission, primary or secondary voltage

under this rate schedule, supplied through one Meter.

Power production equipment at the Customer site shall not operate in parallel with the Company’s

system until the installation has been inspected by an authorized Company representative and final

written approval is received from the Company to commence parallel operation.



Section 11.01


Page 2 of 8






STANDBY RATE OPTIONS - FIRM AND NON-FIRM

OPTION A: FIRM STANDBY

Transmission Primary Secondary

Service Service Service

Firm Standby Fixed Charges

Customer Charge $199.00/month $199.00/month $199.00/month

Minimum Monthly Bill

Customer +

Reservation +

Standby Facilities

Charges

Customer +

Reservation +

Standby Facilities

Charges

Customer +

Reservation +

Standby Facilities

Charges

Summer Reservation Charge per

month per kW of Contracted

Backup Demand 14.90 ¢/kW 16.04 ¢/kW 16.77 ¢/kW

Winter Reservation Charge per



Standby Facilities Charge per


Backup Demand Not Applicable 52.83 ¢/kW 72.26 ¢/kW

Firm Standby On-Peak Demand Charge - Summer

Metered Demand per day per

kW On-Peak Backup Charge 63.67 ¢/kW 68.38 ¢/kW 71.38 ¢/kW

Firm Standby On-Peak Demand Charge - Winter



Firm Standby Energy Charges - Summer

Energy Charges per kWh

On-Peak Charge 6.6606.808 ¢/kWh 7.0677.215 ¢/kWh 7.3197.467 ¢/kWh

Shoulder Charge 4.9525.100 ¢/kWh 5.2285.376 ¢/kWh 5.3975.545 ¢/kWh

Off-Peak Charge 2.2722.420 ¢/kWh 2.3762.524 ¢/kWh 2.4372.585 ¢/kWh

Firm Standby Energy Charges - Winter


On-Peak Charge 5.8445.992 ¢/kWh 6.2516.399 ¢/kWh 6.5076.655 ¢/kWh





Section 11.01


Page 3 of 8






OPTION B: NON-FIRM STANDBY



Non-Firm Standby Fixed Charges



Customer +

Reservation +

Standby Facilities

Charges

Customer +

Reservation +

Standby Facilities

Charges

Customer +

Reservation +

Standby Facilities

Charges

Reservation Charge per month

per kW of Contracted Backup

Demand Not Available Not Available Not Available




Non-Firm Standby On-Peak Demand Charge - Summer

Metered Demand per day per kW

On-Peak Backup Charge Not Available Not Available Not Available

Non-Firm Standby On-Peak Demand Charge - Winter



Non-Firm Standby Energy Charges - Summer


On-Peak Charge Not Available Not Available Not Available



Non-Firm Standby Energy Charges - Winter








Minimum Charge.



Section 11.01


Page 4 of 8










DETERMINATION OF METERED DEMAND: Metered Demand shall be based on the

maximum kW registered over any period of one hour during the month in which the bill is

rendered.

TERMS AND CONDITIONS:

1. Company's Meter will be detented to measure power and Energy from Company to

Customer only. Any flow of power and Energy from Customer to Company will be

separately metered under one of Company's Purchase Power Rate Schedules, Distributive

Generation Rider, or by contract.

2. Option A - Firm Standby: Exclusive of any scheduled maintenance hours, if the number of

hours on which Backup Service is supplied exceeds 120 On-Peak hours in the Summer

season and 240 On-Peak hours in the Winter season, Customer may be required to take

service under a standard, non-standby, rate schedule.

3. Option B – Non-Firm Standby: Backup Service is not available during any on-peak season.

This service is only available in the Summer Shoulder and Summer Off-Peak and Winter

Shoulder and Winter Off-Peak hours on a non-firm basis. The Company makes no

guarantee that this service will be available, however, the Company will make reasonable

efforts to provide Backup Service under Option B whenever possible.

4. One year (12 months) written notice to Company is required to convert from this standby

service to regular firm service, unless authorized by the Company.

5. Any additional facilities, beyond normal transmission and Distribution Facilities, required

to furnish service will be provided at Customer's expense.

6. Customer shall indemnify Company against all liability which may result from any and all

claims for damages to property and injury or death to persons which may arise out of or be

caused by the erection, maintenance, presence, or operation of the Customer generation

facility or by any related act or omission of the Customer, its employees, agents, contractors

or subcontractors.



Section 11.01


Page 5 of 8






7. During times of Customer generation, Customer will be expected to provide vars as needed

to serve their load. Customer will provide equipment to maintain a unity power factor + or –

10% for Supplemental Service, and when Customer is taking Backup Service from

Company.

CONTRACT PERIOD: Standby Service is applicable only by signed agreement, setting forth the

location and conditions applicable to the electric service, such as the Contracted Backup

Demand, type of standby service (Option A or B), excess facilities required for service and other

applicable terms and conditions, and providing for an initial minimum contract period of one year,

unless otherwise authorized by Company.



Section 11.01


Page 6 of 8






ATTACHMENT NO. 1 DEFINITIONS AND USEFUL TERMS

Backup Demand (a component of Backup Service) is the Demand taken when on-peak

Demand provided by Company is used to make up for reduced output from Customer's generation.

Backup Demand Charge is the sum of the ten highest daily Backup Demands multiplied by

the applicable Backup Demand Charge for that season.

Backup Service is the Energy and Demand supplied by the utility during unscheduled

outages of the Customer’s Generator.

Billing Demand is the Customer’s Demand used by the Company for billing purposes.

Capacity is the ability to functionally serve a required load on a continuing basis.

Contracted Backup Demand is the amount of Capacity selected to backup the Customer’s

generation, not to exceed the capability of the Customer’s Generator.

Demand is the rate at which electric Energy is delivered to or by a system, part of a system,

or a piece of equipment and is expressed in Kilowatts (“kW”) or Megawatts;

Energy is the Customer’s electric consumption requirement, measured in Kilowatt-Hours

(“kWh”).

Extended Parallel Generation Systems are generation systems that are designed to remain

connected in parallel to and in phase to the utility Distribution system for an extended period of

time.

Excess Distribution Facility Investment are Distribution Facilities required to provide

service to the distributed generation system that are not provided in the Company retail service

schedules. The Customer is required to pay up-front for these facilities and pay maintenance costs

as long as the facilities are required.

MAPP is the Mid-Continent Area Power Pool or any successor agency assuming or

charged with similar responsibility.



Section 11.01


Page 7 of 8

EighthSeventh Revision

MINNESOTA PUBLIC UTILITIES COMMISSION Approved: January 27, 2014 Docket No. E-017/GR-15-1033M-13-609



February 1, 2014 in Minnesota

MISO is the Midcontinent Independent System Operator, Inc. assures industry consumers

of unbiased regional grid management and open access to the Transmission Facilities under

Midwest ISO's functional supervision.

Non-Standby Service Customer is a Customer that a) does not request and receive

approval of Standby Services from the Company or, b) is exempt from paying any standby charges

as allowed by law or Commission Order, or, c) in lieu of service under this Tariff, may provide

Physical Assurance, or d) will take service from any of the Company’s other approved base Tariffs.

Customers with Extended Parallel Generation Systems used to meet all or a portion of

electrical requirements that are capable of 100 kW or less are considered Non-Standby Service

Customers and exempt from paying standby charges.

Standby Service for Customers with Extended Parallel Generation Systems used to meet all

or a portion of electrical requirements that are capable of 100 kW or less is available under the

Customer’s base rate.

For more information regarding Extended Parallel Generation Systems, Physical

Assurance Customers, and Standby Service for Customers, please see these terms under

Definitions.

Physical Assurance Customer is a Customer who agrees not to require standby services

and has an approved mechanical device, inspected and approved by a Company representative, to

insure standby service is not taken. The cost of the mechanical device is to be paid by the

Customer.

Renewable Energy Attributes refers to the benefits of the Energy from being generated by

a renewable resource rather than a fossil-fueled resource.

Renewable Energy Credit is typically viewed as a certification that something was

generated by a renewable resource.

Renewable Resource Premium referred to the extra payment received on top of the regular

avoided costs. This extra payment is to reflect the value of the Renewable Energy Credit, which is

a certification of the Renewable Energy Attributes.

Scheduled Maintenance Service is defined as the Energy and Demand supplied by the

utility during scheduled outages. The daily on-peak backup Demand charge under Variable

Charges of the "Rate" section will be waived for a maximum continuous period of 30 days per

calendar year to allow for maintenance of Customer generation source. Waiver is only valid during

the months of April, May, October, and November, and with a minimum of five working days

(excludes weekend and holidays) written notice to Company. In certain cases, such as very large



Section 11.01


Page 8 of 8






Customers, the Company and the Customer will mutually agree to different maintenance schedules

as listed above.

Standby Service Customer is a Customer who receives the following services from the

Company, Sections 11.01; backup power for non-Company generation, supplemental power, and

scheduled maintenance power. These services are not applicable for resale, municipal outdoor

lighting, or customers with emergency standby Generators.

Summer On-Peak: For all kW and kWh used Monday through Friday between 1:00 p.m.

and 7:00 p.m.

Summer Off-Peak: For all other kW and kWh not covered by either shoulder or off-peak.

Summer Season is the period from June 1 through September 30.

Summer Shoulder: For all kW and kWh used Monday through Friday 9:00 a.m. to 1:00

p.m., and 7:00 p.m. to 10:00 p.m., Saturday through Sunday 9:00 a.m. to 10:00 p.m.

Supplemental Service is the Energy and Demand supplied by the utility in addition to the

capability of the on-site Generator. Except for determination of Demand, Supplemental Service

shall be provided under Standard Rate Schedule 10.06.

Supplemental Demand (a component of Supplemental Service) is the metered Demand

measured on Company Meter during on-peak and off-peak periods, less Contracted Backup

Demand.

Winter Season is the period from October 1 through May 31.

Winter Off-Peak: All other kW and kWh’s not covered by either shoulder or off-peak.

Winter On-Peak: For all kW and kWh used Monday through Friday between 7:00 a.m.

and 12:00 noon, and between 5:00 p.m. and 9:00 p.m.

Winter Shoulder: For all kW and kWh used Monday through Friday hour 6:00 a.m. to 7:00

a.m., hours 12:00 noon to 5:00 p.m. and hour 9:00 pm to 10:00 p.m. and, Saturday through Sunday

6:00 p.m. to 10:00 p.m.



Section 11.02

ELECTRIC RATE SCHEDULE Irrigation Service

Page 1 of 3

Twenty-thirdsecond Revision





IRRIGATION SERVICE

DESCRIPTIONESCRIPTION RATE

CODE

Option 1: Non-Time-of-Use 31-703

Option 2: Declared Peak 31-704

Option 2: Intermediate 31-705

Option 2: Off-Peak 31-706



APPLICATION OF SCHEDULE: This Irrigation Service is applicable to Customers for pumping

water for irrigation of land during the irrigation season, April 15 through November 1.

RATE:

OPTION 1


Monthly Minimum Bill: Customer + Fixed Charges

Fixed Charge per Month: Customer-Specific see Tariff


6.5016.649 ¢/kWh

4.2914.439 ¢/kWh



Section 11.02


Page 2 of 3






OPTION 2





Declared-Peak

19.99320.141 ¢/kWh

22.06122.209 ¢/kWh

Intermediate 4.2364.384 ¢/kWh 4.0884.236 ¢/kWh

Off-Peak 1.6231.771 ¢/kWh 1.8161.964 ¢/kWh


Declared-Peak $0.00 /kW $0.00 /kW


Off-Peak $0.00 /kW $0.00 /kW




Charge.

FIXED CHARGE: Customers served under this rate shall pay an annual fixed charge equal to 18%

of the investment of the Company in the extension of lines, including any rebuilding or cost of

Capacity increase in lines or apparatus, necessitated because of the irrigation pumping load.

Alternatively, Customers may prepay the installation and cost of the equipment and shall pay an

annual fixed charge equal to 3.5% of the investment of the Company, in lieu of the 18% annual

fixed charge.

In either option, equipment remains the property of Otter Tail Power Company. This charge shall be

reviewed if additional Customers are connected to the extension within five years. The annual fixed

charge will be billed in seven equal monthly installments, May through November of each year.



Customer, unless otherwise noted in this rate schedule. See Sections 12.00, 13.00, and 14.00 of the




Section 11.02


Page 3 of 3






CHARACTER AND CONDITIONS OF SERVICE: The Company reserves the right to interrupt

this service. As a condition to receiving service at this rate, the Customer shall, when notified to do

so, abide by such restrictions.


WINTER SEASON – APRIL 15 THROUGH MAY 31, AND OCTOBER 1 THROUGH NOVEMBER 1

Declared-Peak: For all kW and kWh used during the hours declared.

Intermediate: For all kW and kWh used during the hours other than declared-peak and off-peak.

Off-Peak: For all kW and kWh used Monday through Saturday from10:00 p.m. to 6:00 a.m., and all day Sunday.

SUMMER SEASON - JUNE 1 THROUGH SEPTEMBER 30 Declared-Peak: For all kW and kWh used during the hours declared.


Off-Peak: For all kW and kWh used Monday through Saturday from10:00 p.m. to 6:00 a.m., and all

day Sunday.

DETERMINATION OF DEMAND: The Billing Demand shall be the maximum Demand in kW

registered over any period of one hour during the month for which the bill is rendered.

CONTRACT PERIOD AND AGREEMENT: The minimum Contract Period shall be five years.

The Company shall enter into a written agreement with each Customer served at this rate and the

Customer shall agree to pay for service at this rate for a period of five years because of the

investment of the Customer in pumping and irrigation equipment, and of the Company in the

extension of lines.

If, during the terms of such agreement, the Company shall establish a superseding rate for this

service, the Customer shall be billed at the superseding rate for the balance of the term of the contract

and shall comply with all terms and conditions of the superseding rate. Unless there is additional

investment by the Company, there shall be no change in the amount of the fixed charge during the

term of such agreement regardless of the provisions of any superseding rate.

An agreement will be entered into with each Customer, specifying the investment necessary to supply

service and the fixed charge.



Section 11.03

ELECTRIC RATE SCHEDULE Outdoor Lighting – Energy Only

Dusk to Dawn Page 1 of 2

FifthFourth Revision





OUTDOOR LIGHTING – ENERGY ONLY

DUSK TO DAWN

DESCRIPTION RATE

CODE

Outdoor Lighting – Metered – Energy Only 31-748

Outdoor Lighting - Non-Metered – Energy Only 31-749



APPLICATION OF SCHEDULE: This schedule is applicable to all Customers who choose to

own, install, and maintain automatically operated dusk-to-dawn outdoor lighting equipment. Under

this schedule, the Company will provide only the dusk to dawn electric Energy.

EQUIPMENT AND SERVICE OWNERSHIP: The Customer or other third party shall install and

own all equipment necessary for service beyond the point of connection with Company’s electrical

system. The point of connection shall be at the Meter or disconnect switch, for service provided

either overhead or underground. The Customer will be responsible for furnishing and installing a

master disconnect switch at the point of connection so as to isolate the Customer’s equipment from

Company’s electrical system. The Customer’s disconnect switch must be UL-approved or meet

National Electric Code standards.

The Customer is responsible for the cost of providing maintenance on the equipment it owns. The

Company reserves the right to disconnect the Customer’s equipment from the Company’s electrical

system should the Company determine the Customer’s lighting equipment is operated or maintained

in an unsafe or improper manner.



Section 11.03

ELECTRIC RATE SCHEDULE Outdoor Lighting – Energy Only







RATE – METERED:

OUTDOOR LIGHTING - ENERGY ONLY

Metered Rate


Monthly Minimum Bill: Customer Charge


Energy Charge per kWh: 7.5187.666 ¢/kWh

RATE – NON-METERED:

OUTDOOR LIGHTING –NON-METERED RATE

Monthly charge = Connected kW x $25.6926.19, where Connected kW is the

rated power of the lighting fixture (including ballast)




Minimum Charge.


modified by any Mandatory Rate Riders that must apply and by any Voluntary Rate Riders

selected by the Customer, unless otherwise noted in this rate schedule. See Sections 12.00, 13.00

and 14.00 of the Minnesota electric rates for the matrices of riders.

SERVICE CONDITIONS: Company-owned lights shall not be attached to Customer-owned

property.

The Company shall have the right to periodically review the Customer’s lighting equipment to

verify that the rated power (kW) of the non-metered fixtures is consistent with the Company’s

records.



Section 11.04

ELECTRIC RATE SCHEDULE Outdoor Lighting







OUTDOOR LIGHTING

DUSK TO DAWN

DESCRIPTION RATE

CODE

Outdoor Lighting 31-745

Floodlighting 31-746



APPLICATION OF SCHEDULE: This schedule is applicable to any Customer for

automatically operated dusk to dawn outdoor lighting supplied and operated by the Company.

RATE:

Unit type Lumens Wattage

Monthly

Charge

MV-6* 6000 175 $7.107.20

MV-6PT* 6000 175 $9.279.37

MV-11* 11000 250 $13.2813.43

MV-21* 21000 400 $17.1717.40

MV-35* 35000 750 $25.8726.25

MV-55* 55000 1000 $35.5436.08

MH-8 8500 100 $8.088.14

MH-8PT 8500 100 $11.4811.54

MH-14 14000 175 $15.3915.49

MH-20 20500 250 $17.5717.71

MH-36 36000 400 $17.2417.47

MH-110 110000 1000 $36.8037.35

HPS-9 9000 100 $7.907.96

HPS-9PT 9000 100 $9.549.60

HPS-14 14000 150 $12.2512.34

HPS-14PT 14000 150 $12.2312.32

HPS-19 19000 200 $14.1914.31

HPS-23 23000 250 $16.0316.18

HPS-44 44000 400 $19.8620.09



Section 11.04








Fixture

Unit Type

Monthly

Charge

400 MV-Flood* Mercury Vapor $17.1717.40

400 MA-Flood Metal Additive $20.1420.37

400 HPS-Flood High Pressure Sodium $19.8620.09

1000 MV-Flood* Mercury Vapor $33.7634.30

1000 MA-Flood Metal Additive $37.3237.87

*Due to the U.S. Government Energy Act of 2005, after August 1, 2008, the Company will no

longer install Mercury Vapor fixtures for new installations.




Minimum Charge.



Riders selected by the Customer, unless otherwise noted in this rate schedule. See Sections 12.00,


SEASONAL CUSTOMERS: Seasonal Customers will be billed at the same rate as year-around

Customers, except as follows:

A fixed charge of $27.59 will be billed each Seasonal Customer once per season per fixture in

addition to the rate provided above. The fixed charge will be included in the first bill rendered

for each season.

Each Seasonal Customer will be billed for the number of months each season that the outdoor

lighting fixture is in use, but not less than a minimum of four months, plus the seasonal fixed

charge.

UNDERGROUND SERVICE: If the Customer requests underground service to any outdoor

lighting unit, the Company will supply up to 200 feet of wire and add an additional $2.12 to the

monthly rate specified above. If overhead service is not available, there is no additional charge.

There is no additional charge for the MV-6 PT*, HPS-9 PT or the HPS-14 PT fixtures.



Section 11.04








EQUIPMENT AND OVERHEAD SERVICE SUPPLIED BY THE COMPANY: The light

shall be mounted on a suitable new or existing Company-owned pole. Any extension beyond one

span of wire will be at the expense of the Customer.

The Company will install, own and operate, and have discretion to replace or upgrade a high

intensity discharge light including suitable reflector or a floodlight including a lamp, bracket for

mounting on wood poles with overhead wiring and photo-electric or other device to control

operating hours. Customers provided with pole top fixtures on fiberglass poles will not receive

overhead power supply. The light shall operate from dusk to dawn. The Company will supply the

necessary electricity and maintenance for the unit.

SERVICE CONDITIONS: Lighting will not be mounted on Customer-owned property. The

light shall be mounted upon a suitable new or existing Company-owned facility. The Company

shall own, operate, and maintain the lighting unit including the pole, fixture, lamp, ballast,

photoelectric control, mounting brackets, and all necessary wiring using the Company's standard

street lighting equipment. The Company shall furnish all electric Energy required for operation of

the unit.

In cases of vandalism or damages, the Company has the discretion to discontinue service and

remove Company equipment.



Section 11.05

ELECTRIC RATE SCHEDULE Municipal Pumping Service

Page 1 of 2

FourteenthThirteenth Revision





MUNICIPAL PUMPING SERVICE

DESCRIPTION RATE

CODE





APPLICATION OF SCHEDULE: This schedule is applicable to nonseasonal municipal or other

governmental loads only. It shall apply to electric service for motor driven pumps for use at water

pumping, sewage disposal and treating plants, sewage lift stations and may extend to all lighting and

other electrical requirements incidental to the operation of such plants and lift stations at those

locations. Municipal buildings adjacent to, but not incidental to pumping operation, may not be

served on this rate.

The appropriate rate and monthly minimum shall apply to each Meter in service.

RATE:



Monthly Minimum Bill: Customer + Facilities Charges Customer + Facilities Charges

Facilities Charge per Annual

Maximum kW per Month: $0.14 /kW $0.09 /kW


6.298

6.446 ¢/kWh

6.468

6.616 ¢/kWh

6.091

6.239 ¢/kWh

6.219

6.367 ¢/kWh




Minimum Charge.



Section 11.05


Page 2 of 2

FourteenthThirteenth Revision














ADJUSTMENT FOR EXCESS REACTIVE DEMAND: The Metered Demand may be increased

by 1 kW for each whole 10 kVar of measured Reactive Demand in excess of 50% of the Metered

Demand in kW.




on the largest of the most recent 12 monthly Billing Demands.



Section 11.06

ELECTRIC RATE SCHEDULE Civil Defense – Fire Sirens

Page 1 of 2






CIVIL DEFENSE – FIRE SIRENS

DESCRIPTION RATE

CODE

Civil Defense – Fire Sirens 31-843



APPLICATION OF SCHEDULE: This schedule is applicable to separately served civil defense

and municipal fire sirens.

RATE:

CIVIL DEFENSE - FIRE SIRENS


Monthly Minimum Bill: Customer Charge


Charge per HP: Summer Winter

59.482 ¢/HP 59.482 ¢/HP




Minimum Charge.







Section 11.06

ELECTRIC RATE SCHEDULE Civil Defense – Fire Sirens

Page 2 of 2









OTHER SIREN SERVICE: If the siren is served through a Tariff applicable to the City Hall, fire

hall or other tariffed service, no separate billing shall be made for the siren.

SERVICE CONDITIONS: Service shall be provided off of standard Distribution Facilities typical

of those in the general area. If it is necessary for the Company to install non-standard Distribution

Facilities in order to provide service, the Customer shall be responsible for any additional costs

associated with the non-standard facilities. As part of this rate schedule, the Company will provide

an extension of up to one span of wire, not to exceed 150 feet. No additional transformer Capacity

shall be provided without additional charges.

The Company shall have the right to periodically review the Customer’s Civil Defense – Fire Siren

rated horsepower (hp) to verify that the rated hp of the non-metered siren is consistent with the

Company’s records.



Section 12.01

ELECTRIC RATE SCHEDULE Small Power Producer Rider

Net Energy Billing Rate Page 1 of 3

Thirty-sixthfifth Revision

MINNESOTA PUBLIC UTILITIES COMMISSION Approved: NA Docket No. E-017/GR-15-1033E999/PR-16-09

Thomas R. Brause Vice President,

Administration


January 1, 2016 in Minnesota

SMALL POWER PRODUCER RIDER

(Net Energy Billing Rate)


Rules and Regulations govern use of this rider.

AVAILABILITY: This rider is available to any qualifying facility with generation Capacity not

exceeding 40 kW.

CUSTOMER CHARGE: $3.70 per month


A 10.95 percent increase will be added to the Customer Charge.

PAYMENT SCHEDULE: Payment per kWh for energy delivered to utility in excess used.

DESCRIPTION ENERGY

CREDIT

RATE

CODE

Residential 9.55¢ per kWh 31-910

Farm 9.67¢ per kWh 31-930

General Service 9.58¢ per kWh 31-940

Large General Service 9.50¢ per kWh 31-960

SPECIAL CONDITIONS OF SERVICE: The Customer will be required to sign a contract, agreeing to

terms and conditions specified for small power producers. The minimum term of the contract is 12

months.

TERMS AND CONDITIONS: The use of this rider requires that special precautions be taken in the

design of associated metering and control systems. The following terms and conditions describe these

precautions and shall be followed on all Customer-owned small qualifying facilities (SQF).

1. The Customer will be compensated monthly for all energy received from the SQF less the

Customer Charge. The schedule for these payments is subject to annual review.

2. If the SQF is located at a site outside of the Company's service territory and energy is delivered to

the Company through facilities owned by another utility, energy payments will be adjusted

downward reflecting losses occurring between the point of metering and the point of delivery.



Section 12.01



Thirty-thirdsecond Revision





3. A SQF must have a generation Capacity of at least 30 kW to qualify for wheeling by the Company

of the SQF output. In the event that the SQF desires, and qualifies for, wheeling by the Company

of the SQF output, arrangements will be made subject to special provisions to be determined by all

utilities involved. This also applies to SQF's outside the Company's service territory.

4. If required, a separate Meter will be furnished, owned and maintained by the Company to measure

the energy to the Company.

5. The SQF shall make provisions for the installation of Company owned on-site metering. All

energy received from and delivered to the Company shall be metered. On site use of the SQF

output shall be unmetered for purposes of compensation.

6. The Customer shall pay for any increased Capacity of the Distribution equipment serving him and

made necessary by the installation of his Generator.

7. Power and energy purchased by the SQF from the Company shall be billed under the available

retail rates for the purchase of electricity.

8. The Generator output must be compatible with the Utility system. The Customer's 60 hertz

Generator output must be at the voltage and phase relationship of the existing service or of one

mutually agreeable to the Company and the Customer.

9. The Customer will provide equipment to maintain a 100% power factor (+ or - 10%) during

periods of Generator operation.

10. The Company reserves the right to disconnect the Customer's Generator from its system if it

interferes with the operation of the Company's equipment or with the equipment of other

Company Customers.

11. The Customer is required to follow the Company’s interconnection process, which requires that

prior to installation, a detailed electrical diagram of the Generator and related equipment must be

furnished to the Company for its approval for connection to the Company's system. No

warranties, express or implied, will be made as to the safety or fitness of the said equipment by the

Company due to this approval.

12. The Customer shall execute an electric service contract with the Company which may include,

among other provisions, a minimum term of service.



Section 12.01



Thirty-secondfirst Revision





13. Equipment shall be provided by the Customer that provides a means of preventing feedback to the

Company during an outage or interruption of that system as well as a visible means to disconnect

the Generator from the Utility that is readily accessible by Utility employees.

14. The Customer shall install, own, and maintain all equipment deemed necessary by the Company to

assure proper parallel operation of the system.







Section 12.02


Simultaneous Purchase and Sale Billing Rate Page 1 of 3

Thirty-sixthfifth Revision






SIMULTANEOUS PURCHASE AND SALE BILLING RATE

DESCRIPTION RATE

CODE

Firm Power 31-981

Nonfirm Power 31-984


Rules and Regulations govern use of this rider.

AVAILABILITY: This rider is available to any qualifying facility with generation Capacity not

exceeding 40 kW.

CUSTOMER CHARGE: Firm Power $8.87 per month

Nonfirm Power $1.40 per month



PAYMENT SCHEDULE: For energy delivered to the utility.

DESCRIPTION SUMMER

CAPACITY

CREDIT

WINTER

CAPACITY

CREDIT

SUMMER

ENERGY

CREDIT

WINTER

ENERGY

CREDIT

Firm and

Non-Firm Power 1.57¢ per kWh 1.57¢ per kWh 3.707¢ per kWh 3.657¢ per kWh

SPECIAL CONDITIONS OF SERVICE:

1. The Customer will sign a contract agreeing to terms and conditions specified for small power

producers. The minimum term of the contract is 12 months.

2. If the qualifying facility does not meet the 65% on-peak Capacity requirement in any month,

the compensation will be the energy portion only.



Section 12.02








DEFINITIONS:

Firm Power: Energy delivered by the qualifying facility to the utility with at least a 65 percent

on-peak Capacity factor in the month.

Capacity Factor: The number of Kilowatt-Hours delivered during a period divided by the

product of (the maximum one hour delivered Capacity in Kilowatts in the period) times (the

number of hours in the period).



TERMS AND CONDITIONS: The use of this rate requires that special precautions be taken in the

design of associated metering and control systems. The following terms and conditions describe these

precautions and shall be followed on all Customer-owned small qualifying facilities (SQF).



2. If the SQF is located at a site outside of the Company's service territory and energy is

delivered to the Company through facilities owned by another utility, energy payments will be

adjusted downward reflecting losses occurring between the point of metering and the point of

delivery.

3. A SQF must have a generation Capacity of at least 30 kW to qualify for wheeling by the

Company of the SQF output. In the event that the SQF desires, and qualifies for, wheeling by

the Company of the SQF output, arrangements will be made subject to special provisions to be

determined by all utilities involved. This also applies to SQF's outside the Company's service

territory.

4. If required, a separate Meter will be furnished, owned and maintained by the Company to

measure the energy to the Company.


energy received from and delivered to the Company shall be metered. On-site use of the SQF

output shall be unmetered for purposes of compensation.

6. The Customer shall pay for any increased Capacity of the Distribution equipment serving him

and made necessary by the installation of his Generator.



Section 12.02











Generator output must be at the voltage and phase relationship of the existing service or of one

mutually agreeable to the Company and the Customer.




interferes with the operation of the Company's equipment or with the equipment of other

Company Customers.

11. The Customer is required to follow the Company’s interconnection process, which requires

that prior to installation, a detailed electrical diagram of the Generator and related equipment

must be furnished to the Company for its approval for connection to the Company's system.

No warranties, express or implied, will be made as to the safety or fitness of the said

equipment by the Company due to this approval.



13. Equipment shall be provided by the Customer that provides a means of preventing feedback to

the Company during an outage or interruption of that system as well as a visible means to

disconnect the Generator from the Utility that is readily accessible by Utility employees.

14. The Customer shall install, own and maintain all equipment deemed necessary by the

Company to assure proper parallel operation of the system.







Section 12.03

ELECTRIC RATE SCHEDULE Small Power Producer Rider Time of Day Purchase Rates

Page 1 of 4 Thirty-seventhsixth Revision






TIME OF DAY PURCHASE RATES

DESCRIPTION RATE

CODE

Firm Power

On-Peak

Off- Peak

31-982

31-985

Nonfirm Power

On-Peak

Off-Peak

31-983

31-986


General Rules and Regulations govern use of this rider.

AVAILABILITY: This rider is available to any qualifying facility with generation Capacity of

100 kW or less, and available to qualifying facilities with Capacity of more than 100 kW if firm

power is provided.






DESCRIPTION CAPACITY

PAYMENT

(ON-PEAK ONLY)

ENERGY

CREDIT

ON-PEAK

ENERGY CREDIT

OFF-PEAK

Summer (Firm Power and

Non-Firm Power) 3.45¢ per kWh 4.486¢ per kWh 3.093¢ per kWh

Winter (Firm Power and Non-

Firm Power) 3.45¢ per kWh 4.354¢ per kWh 3.058¢ per kWh

SPECIAL CONDITIONS OF SERVICE:

1. The Customer will sign a contract agreeing to terms and conditions specified for small

power producers. The minimum term of the contract is 12 months.



Section 12.03


Page 2 of 4 Thirty-secondfirst Revision





2. If the qualifying facility does not meet the 65% on-peak Capacity requirement in any

month, the compensation will be the energy portion only.

DEFINITIONS:

Firm Power: Energy delivered by the qualifying facility to the utility with at least a 65

percent on-peak Capacity factor in the month.

Capacity Factor: The number of Kilowatt-Hours delivered during a period divided by the

product of (the maximum one hour delivered Capacity in Kilowatts in the period) times

(the number of hours in the period).

Summer On-Peak: June 1 through September 30 including those hours from 8:00 a.m. to

10:00 p.m. Monday through Friday, excluding holidays.

Winter On-Peak: October 1 through May 31 including those hours from 7:00 a.m. to 10:00

p.m. Monday through Friday, excluding holidays.

Holidays: New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving

Day and Christmas Day.

TERMS AND CONDITIONS: The use of this rate requires that special precautions be taken in

the design of associated metering and control systems. The following terms and conditions

describe these precautions and shall be followed on all Customer-owned small qualifying facilities

(SQF).




delivered to the Company through facilities owned by another utility, energy payments

will be adjusted downward reflecting losses occurring between the point of metering and

the point of delivery.


Company of the SQF output. In the event that the SQF desires, and qualifies for, wheeling

by the Company of the SQF output, arrangements will be made subject to special

provisions to be determined by all utilities involved. This also applies to SQF's outside the

Company's service territory.



Section 12.03









5. The SQF shall make provisions for the installation of Company owned on-site metering.

All energy received from and delivered to the Company shall be metered. On-site use of

the SQF output shall be unmetered for purposes of compensation.

6. The Customer shall pay for any increased capacity of the distribution equipment serving

him and made necessary by the installation of his Generator.

7. Power and energy purchased by the SQF from the Company shall be billed under the

available retail rates for the purchase of electricity.


Generator output must be at the voltage and phase relationship of the existing service or of

one mutually agreeable to the Company and the Customer.

9. The Customer will provide equipment to maintain a 100% power factor (+ or - 10%)

during periods of Generator operation.

10. The Company reserves the right to disconnect the Customer's Generator from its system if

it interferes with the operation of the Company's equipment or with the equipment of other

Company Customers.

11. The Customer is required to follow the Company’s interconnection process, which

requires that prior to installation, a detailed electrical diagram of the Generator and related

equipment must be furnished to the Company for its approval for connection to the

Company's system. No warranties, express or implied, will be made as to the safety or

fitness of the said equipment by the Company due to this approval.

12. The Customer shall execute an electric service contract with the Company which may

include, among other provisions, a minimum term of service.

13. Equipment shall be provided by the Customer that provides a means of preventing

feedback to the Company during an outage or interruption of that system as well as a

visible means to disconnect the Generator from the Utility that is readily accessible by

Utility employees.



Section 12.03















Section 12.04

ELECTRIC RATE SCHEDULE Distributed Generation Service Rider

Page 1 of 6






DISTRIBUTED GENERATION SERVICE RIDER

DESCRIPTION RATE

CODE

Distributed Generation Service Rider 31-931



AVAILABILITY: The rider for Distributed Generation is available between any Customer, who

has entered into the “State of Minnesota Interconnection Agreement for the Interconnection of

Extended Parallel Distributed Generation Systems with Electric Utilities,” and the Company for

the interconnection and operation of on-site extended parallel distributed generation system, as

follows.

1. The distributed generation system must be fueled by natural gas or a renewable fuel, or

another similarly clean fuel or combination of fuels of no more than 10 MW of

interconnected Capacity at a point of common coupling to Company’s Distribution system.

The distributed generation facility must be an operable, permanently installed or mobile

generation facility serving the Customer receiving retail electric service at the same site.

2. The interconnection and operation of distributed generation systems at each point of

common coupling shall be considered as a separate application of the Rider.

3. Service hereunder is subject to Company’s ”Guidelines for Generation, Tie-Line, and

Substation Interconnections” and the “State of Minnesota Interconnection Process for

Distributed Generation Systems,” copies of which are available at the Company’s web

page at http://www.otpco.com. The requirements, terms and conditions contained in the

“State of Minnesota Interconnection Process for Distributed Generation Systems”

supersede the requirements, terms and conditions contained in the Company’s “Guidelines

for Generation, Tie-Line, and Substation Interconnections” in the event of an inconsistency

between the two documents.

4. All provisions of the applicable standard service schedule shall apply to distributed

generation service under this Rider except as noted below.

http://www.otpco.com/



Section 12.04


Page 2 of 6






In lieu of service under this Rider, Customer and Company may pursue reasonable transactions

outside the Rider; or Customer may take service, as applicable, under Company’s Small Power

Producer Riders as established under Minnesota Rules Chapter 7835 – Cogeneration and Small

Power Production.

SERVICES: Services provided under this Rider may include services from the Company to

Customer and from Customer to Company. The following rates, charges, credits and payments

are applicable for such services in addition to all applicable charges for service being taken under

Company’s rate schedules, as noted in the “Availability” section above.

Customer Charge: $11.57 per month for Customer Account expense

Distribution Maintenance Charge ($/Month): This charge will be based upon Customer-

specific Distribution Facilities required for operation of the distributed generation system.

Distribution Maintenance Charge ($/Month) = (Excess Distribution Facilities Investment x

0.344%)

Monthly Minimum Charge: The sum of the Customer Charge plus the Distribution Maintenance

Charge.




Minimum Charge.

Services from Company to Customer

Interconnection Services

Interconnection services include services such as engineering/design studies, Company

system upgrades and testing. The technical requirements, addressing the safe and reliable

interconnection of the Customer’s equipment to the Company’s system are described in

the State of Minnesota Interconnection Process for Distributed Generation Systems, a copy

of which is available at the Company’s web page at http://www.otpco.com.

Supply Services

Supply services include standby services such as Scheduled Maintenance, Backup and

Supplemental service as provided under Company’s Standby Service, Section 11.01.

Transmission Services

The Company will arrange the following services, as required, to the Customer without



Section 12.04


Page 3 of 6






additional charge. The Company reserves the right to monitor the impacts of these costs

and if found to be inequitable to other ratepayers, the Company will seek regulatory

approval to develop appropriate charges for these services.

Transmission Services can include reservation and delivery of Capacity and energy on

either a firm or non-firm basis and those ancillary services that are necessary to support the

transmission of Capacity and energy from resources to loads while maintaining reliable

operation over transmission providers’ transmission system. These ancillary services

include services such as scheduling, system control and dispatch service, reactive supply

and voltage control from generation sources service, regulation and frequency response

service, Generator imbalance service, operating reserve – spinning reserve and operating

reserve – supplemental reserve.

Distribution Services

Distribution services include reservation and delivery of Capacity and energy and those

indirect services that are necessary to support the delivery of Capacity and energy over

Company’s Distribution system. These indirect services include allocated support services

or expenses such as operation and maintenance, Customer accounting, Customer service

and information, administrative and general costs, depreciation, interest and taxes. These

costs are contained in the Company’s Standby Service, Section 11.01 and any of the other

approved Company Tariffs. The Company reserves the right to monitor the impacts of

these costs and if found to be inequitable to ratepayers, the Company will seek regulatory

approval to develop appropriate charges for these services.

Services from Customer to Company

Capacity/Energy

Customer may sell all of the energy produced by the distributed generation system to the

Company, use all the distributed generation energy to meet its own electrical requirements,

or use a portion of the energy from the distributed generation system to meet its own

electrical needs and sell the remaining energy to the Company.

If the Customer offers to sell energy to the Company, then all such energy and/or Capacity

offered will be purchased by the Company under the rates, terms and conditions for such

purchases as established by the Company under this Rider or under other mutually

agreeable arrangements between the Company and the Customer.

Capacity and/or energy payments shall be based on Company’s annual calculation of

avoided energy and Capacity costs. The Capacity credits in effect at the time Customer

enters into a power purchase agreement with Company shall remain in effect for the length



Section 12.04


Page 4 of 6






of the agreement. Energy payments for use under the power purchase agreement shall

reflect the current schedule. The Company’s avoided energy costs shall include

consideration of the actual value to the Company or avoided costs associated with

renewable energy credits or emissions credits. Customer may receive either renewable

credits or tradable emission credits but not both. Upon written request by Customer and

after signing a non-disclosure agreement, Company shall provide Customer the current

schedule of Capacity and energy credits.

Distribution Payments

Distribution payments to Customer equal the Company’s avoided Distribution costs

resulting from the installation and operation of the distributed generation system. Upon

written request by Customer and after signing a non-disclosure agreement a list of

substation areas or feeders that could be likely candidates for Distribution credits as

determined through the Company’s normal Distribution planning process. Upon receiving

an application from Customer for the interconnection and operation of a distributed

generation system, Company shall perform an initial screening study to determine if the

project has the potential to receive Distribution payments. Customer shall be responsible

for the cost of such screening study. If Company’s study shows that there exists potential

for Distribution payments, Company shall, at its own expense, pursue further study to

determine the Distribution payment.

Emission Payments

Any emission payments shall be included in the development of the Company’s avoided

energy costs and shall equal the value of any revenues received by the Company from the

emissions credit. Customer may receive either renewable credits or tradable emission

credits but not both.

Renewable Energy Credits

Customer who installs a renewable DG facility shall be paid (1) the Company’s regular

avoided cost and (2) for the transfer of the property rights to the Company of the

renewable energy attributes (or renewable energy credits in the event of the development

of a Commission-approved renewable energy tracking system) associated with the

generation of renewable energy, a Renewable Resource Premium. Any renewable energy

attributes (or renewable energy credits in the event of the development of a Commission-

approved renewable energy tracking system) associated with Customer generated energy

used on-site and not delivered to the Company will remain with the Customer who owns

the generator. The Company has the option to negotiate with the Customer regarding

purchases of the renewable energy attributes (or renewable energy credits in the event of

the development of a Commission-approved renewable energy tracking system) associated

with the Customer’s on-site usage.



Section 12.04


Page 5 of 6






Line Loss Credits

If Customer makes a written request to the Company to provide a specific line loss study,

at the Customer’s expense regardless of the study’s outcome, Customer may be eligible for

additional line loss credits if the study supports such credits.

DEFINITIONS: Definitions associated with Customer generation systems can be found in

Attachment 1 of Standby Service, Section 11.01.

The following terms and conditions apply to this Rider (specific conditions are elaborated upon in

Company’s Technical Handbook):


1. Company will install all metering equipment necessary to monitor services provided to

ensure adequate measurements are obtained to support necessary application of rates,

charges, credits and payments. Customer will be charged an up-front contribution in

aid of construction for the installed cost of such metering equipment.

2. The Customer will be compensated monthly for all energy delivered to Company. The

schedule for these payments is subject to annual review.

3. The Customer shall make provisions for the installation of Company owned on-site

metering. All energy received from and delivered to the Company shall be metered.

On-site use of the distributed generation system output shall be unmetered for purposes

of compensation. The Company may require metering of the generation output.

4. The Customer shall pay for all interconnection costs incurred by the Company, made

necessary by the installation of the distributed generation system.

5. Power and energy purchased by the Customer from the Company shall be billed under

the available retail rates for the purchase of electricity.

6. The Generator output must be compatible with the Utility system. The Customer's 60-

hertz Generator output must be at the voltage and phase relationship of the existing

service or of one mutually agreeable to the Company and the Customer.





Section 12.04


Page 6 of 6






8. The Company reserves the right to disconnect the Customer's Generator from its

system if the Generator or related equipment interferes with the operation of the

Company’s equipment or with the equipment of other Company Customers.

9. Prior to installation, a detailed electrical diagram of the Generator and related

equipment must be furnished to the Company for its approval for connection to the

Company’s system. No warranties, express or implied, will be made as to the safety or

fitness of the said equipment by the Company due to this approval.



11. Equipment shall be provided by the Customer that provides a positive means of

preventing feedback to the Company during an outage or interruption of that system as

well as a visible means to disconnect the Generator from the Utility that is readily

accessible by Utility employees.









Section 14.01

ELECTRIC RATE SCHEDULE Water Heating Control Rider

Page 1 of 2

Twenty-firstTwentieth Revision





WATER HEATING CONTROL RIDER

DESCRIPTION RATE

CODE

Separately Metered Water Heating Control Service 31-191

Water Heating Credit Control Service 31-192



AVAILABILITY: This rider is available for Customers with electric water heaters requesting

controlled service; refer to Section 14.00 for the Voluntary Riders – Availability Matrix.

RATE:

SEPARATELY METERED WATER HEATING CONTROL SERVICE - 191





5.9196.067 ¢/kWh

6.3286.476 ¢/kWh

WATER HEATING CREDIT CONTROL SERVICE - 192

Monthly Credit: $4.00




Minimum Charge. This Interim Rate Adjustment only applies to Separately Metered Water

Heating Control Service rate 191.



Section 14.01


Page 2 of 2

Twenty-firstTwentieth Revision






modified by any Mandatory Rate Riders that must apply and by any Voluntary Rate Riders selected

by the Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00 and 14.00 of the


TERMS AND CONDITIONS FOR SEPARATELY METERED WATER HEATING

CONTROL SERVICE - RATE 191: Service under this rate shall be supplied through a separate

Meter.

TERMS AND CONDITIONS FOR WATER HEATING CREDIT CONTROL SERVICE -

RATE 192: The Customer will be compensated by receiving the water heating credit. The credit

will be applied on the Customer’s Account, except the credit shall not reduce the monthly billing to

less than the Monthly Minimum Bill.

CONTROL CRITERIA: Service may be controlled for up to a total of 14 hours during a 24-hour

period, as measured from midnight to midnight. Under normal circumstances the Company will

schedule recovery time following control periods that approach 14 hours.




EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard

metering and/or control equipment.



Section 14.02

ELECTRIC RATE SCHEDULE Real Time Pricing Rider

Page 1 of 5






REAL TIME PRICING RIDER

DESCRIPTION RATE

CODE





General Rules and Regulations govern use under this rider.

AVAILABILITY: This rider is available on a voluntary basis and is limited to 20 Customers,

who have maintained a measured Demand of at least 200 kW during the historical period used

for Customer Baseline Load (“CBL”) development. Priority will be established based on the date

that an agreement is executed by both the Customer and the Company.





selected by the Customer, unless otherwise noted in this schedule. See Sections 12.00, 13.00 and

14.00 of the Minnesota electric rates for the matrices of riders.

ADMINISTRATIVE CHARGE: An Administrative Charge in the amount of $199 will be

applied to each monthly bill to cover billing, administrative, metering, and communication costs

associated with real-time pricing, plus any other applicable Tariff charges.

TERM OF SERVICE: Service under this rider shall be for a period not less than one year. The

Customer shall take service under this rider by either signing new electric service agreements

with the Company or by entering into amendments of existing electric service agreements. A

Customer who voluntarily cancels service under this rider is not eligible to receive service again

under this rider for a period of one year.

PRICING METHODOLOGY: Hourly prices are determined for each day based on

projections of the hourly system incremental costs, losses according to voltage level, hourly

outage costs (when applicable), and profit margin.



Section 14.02


Page 2 of 5






CUSTOMER BASELINE LOAD: The Customer Baseline Load is specific to each Real Time

Pricing (“RTP”) Customer and is developed using a 12-month period of hourly (8,760) Energy

levels (kWh) as well as the corresponding twelve monthly Billing Demands based on the

Customer's rate schedule under which it was being billed immediately prior to taking service

under the RTP Rider. The Customer's CBL must be agreed to in writing by the Customer as a

precondition of receiving service under this rider.

The Customer's CBL is a representation of its typical pattern of electricity consumption and is

derived from historical usage data. The CBL is used to produce the Standard Bill and from

which to measure changes in consumption for purposes of billing under the RTP rider.

STANDARD BILL: The Standard Bill is calculated by applying the charges in the rate

schedule under which the Customer was being billed immediately prior to taking service under

the RTP rider to both the Customer's CBL Demand (adjusted for Reactive Demand) and the CBL

level of Energy usage for each month of the RTP service year. The Company will immediately

adjust a Customer’s Standard Bill to reflect any changes which are approved by the Minnesota

Public Utilities Commission to the applicable rate schedule or resource adjustment.

BILL DETERMINATION: A Real Time Pricing bill will be rendered after each monthly

billing period. The bill consists of an Administrative Charge, a Standard Bill, a charge (or

credit) for consumption changes from the CBL, and an excess Reactive Demand charge/credit.

The monthly bill is calculated using the following formula:

RTP Bill Mo = Adm. Charge + Std BillMo + Consumption Changes from

CBLHr + Excess Reactive Demand

Where:

RTP BillMo = Customer's monthly bill for service under this Rider

Adm. Chg. = See Administrative Charge section below

Std. BillMo = See Standard Bill section above

Consumption Changes From CBL = ∑ {PriceHr x {LoadHr - CBLHr}}

Excess Reactive Demand = See Excess Reactive Demand section below

∑ = Sum over all hours of the monthly billing period

PriceHr = Hourly RTP price as defined under Pricing Methodology

LoadHr = Customer's actual load for each hour of the billing period

CBLHr = Customer's CBL Energy usage for each hour of the billing period



Section 14.02


Page 3 of 5






CONSUMPTION CHANGES FROM CBL: Hourly RTP prices are applied only to the

difference, determined in kWhs for each hour of the billing period, between the Customer's actual

Energy usage and its CBL Energy usage.

EXCESS REACTIVE DEMAND: The Reactive Demand shall be the maximum kVar

registered over any period of one hour during the month for which the bill is rendered. A

separate charge or credit will be made on the bill to reflect incremental changes from the Reactive

Demand used in the Standard Bill calculation.

DETERMINATION OF THE CBL:

1. Development of the Customer's CBL.

For a Customer who elects to take service under this RTP rider, the Company and the

Customer will develop a CBL using hourly load data from a representative 12-month

period. The representative hourly load data to be used will be historical data that

originates within two years (24 months) of the date that the Customer begins receiving

service under the RTP rider.

In situations where hourly data are not available for a particular Customer, a CBL will

be made by using available aggregate metered usage data and load shapes from

Customers with similar usage patterns along with engineering and operating data

provided by the Customer and which is verified by the Company.

2. Calendar Mapping of the Base-Year CBL to the RTP service year.

To provide the Customer with the appropriate CBL for each day of the RTP service

year, each day of the base-year CBL is calendar-mapped to the corresponding day of

the RTP service year. Calendar-mapping is a day-matching exercise performed to

assure that Mondays are matched to Mondays, Tuesdays are matched to Tuesdays,

holidays to holidays, and so forth. Calendar-mapping also reflects Customer

shutdown schedules. Calendar-mapping is performed prior to each year of RTP

service, after any necessary adjustments (as defined below) are made to the CBL.



Section 14.02


Page 4 of 5






CBL ADJUSTMENTS: In order to assure that the CBL accurately reflects the Energy that the

Customer would consume on its otherwise applicable rate schedule, adjustments to the CBL shall

be made for:

1. The installation of permanent Energy efficiency measures as a result of

participation in the Company’s Conservation Improvement Project or other

verifiable conservation or technology efficiency improvement measures. At any

time during the RTP service year, Customers can request that CBL adjustments be

made to reflect efficiency improvements and that the adjustment coincide with the

time of the installation or change-out.

2. The permanent removal of Customer equipment or a change to operating

procedures that results in a significant and permanent reduction of electrical load.

At any time before or during the RTP service year, the Company will make

adjustments to the CBL to coincide with the time that the equipment is removed or

changes to operating procedures.

3. The permanent addition of Customer equipment that has been or will be made

prior to the initial RTP service year is based upon known changes in Customer

usage and/or Demand that are not directly related to the introduction of RTP.

4. One-time, extraordinary events such as a tornado or other natural causes or

disasters outside the control of the Customer or the Company. In these cases, the

Company will make adjustments to the CBL as warranted by the circumstance.

CBL RECONTRACTING: RTP Customers, at the time of initial subscription and during future

re-subscription periods, shall select a recontracting Adjustment Factor that will be used in the

CBL adjustment rule defined below for the next RTP service year. The Adjustment Factor shall

be a number between zero and one inclusive.

After taking service under the RTP rider for one full year, the CBL for the second (and

subsequent) year(s) of RTP service will be based on both the CBL and the actual load. CBLs will

be developed for subsequent years based upon the following general rule:

CBLt+1 = CBLt + {Adjustment Factor x ( Actual loadt - CBLt )}



Section 14.02


Page 5 of 5






PRICE NOTIFICATION: The Company shall make available to Customers, no later than 4:00

p.m. (Central Time) of the preceding day, hourly RTP prices for the next business day. Except

for unusual periods where an outage is at high risk, the Company will make prices for Saturday

through Monday available to Customers on the previous Friday. More than one-day-ahead

pricing may also be used for the following holidays: New Year’s Day, Memorial Day,

Independence Day, Labor Day, Thanksgiving, and Christmas.

Because high-outage-risk circumstances prevent the Company from projecting prices more than

one day in advance, the Company reserves the right to revise and make available to Customers

prices for Sunday, Monday, any of the holidays mentioned above, or for the day following a

holiday. Any revised prices shall be made available by the usual means no later than 4:00 p.m. of

the day prior to the prices taking effect.

The Company is not responsible for a Customer's failure to receive or obtain and act upon the

hourly RTP prices. If a Customer does not receive or obtain the prices made available by the

Company, it is the Customer's responsibility to notify the Company by 4:30 p.m. (Central Time)

of the business day preceding the day that the prices are to take effect. The Company will be

responsible for notifying the Customer if prices are revised.

SPECIAL PROVISIONS:

1. If there is a change in the legal identity of the Customer receiving service under

this RTP rider, service shall be terminated unless the Company and the Customer make other

mutually agreeable arrangements.

2. All equipment to be served must be of such voltage and electrical characteristics so

that it can be served from the circuit provided for the main part of the load and so that the

electricity used can be properly measured by the Meter ordinarily installed on such a circuit. If

the equipment is such that it is impossible to serve from existing circuits, the Customer must

provide any necessary transformers, auto transformers, or any other devices so that connection

can be made to the circuit provided by the Company.

3. If the Customer's actual load exceeds the CBL by an amount that requires the

Company to install additional facilities to serve the Customer, the Customer will be responsible

for any and all costs incurred by the Company to install the facilities.



Section 14.03

ELECTRIC RATE SCHEDULE Large General Service Rider

Page 1 of 6






LARGE GENERAL SERVICE RIDER

DESCRIPTION Option 1 Option 2

Fixed Rate Energy Pricing 31-648 31-649

System Marginal Energy Pricing 31-642 31-645

Short-term Marginal Capacity Purchases 31-643 31-646

Short-term Marginal Capacity Releases 31-644 31-647

RULES AND REGULATIONS: Terms and conditions of this electric rate schedule and the General Rules and Regulations govern use of this rider.

AVAILABILITY: This rider is available at the request of Customers who take service under the rate schedules listed in the Application Section of this Tariff and have either (Option 1) a metered Demand of at least 1 MW, or (Option 2) a Total Coincident Demand of at least 10 MW for multiple, non-contiguous facilities that function in series.

ADMINISTRATIVE CHARGE: An Administrative Charge in the amount of $199.00 will be


associated with this rider.

INTERIM RATE ADJUSTMENT: A 10.95 percent increase will be added to the Administrative Charge, Demand Charge and Energy Charge for Fixed Rate Energy Pricing rates 648 and 649.

MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply and by any Voluntary Rate Riders selected by the Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00 and 14.00 of the Minnesota electric rates for the matrices of riders.

ELECTRIC SERVICE AGREEMENT: For service under this rider, the Company may, at its

discretion, require a written electric service agreement (“ESA”) between the Company and the

Customer that sets forth, among other things, the Customer’s Billing Demand, Firm Demand, and

Baseline Demands.

FIXED RATE ENERGY PRICING:

Background: Certain Company industrial and Commercial Customers have ESAs that designate, among other things, a Billing Demand, Baseline Demand(s) and a Firm Demand. With Baseline Demand(s), the Company agrees to provide and the Customer agrees to purchase all of its Energy requirements at rates set forth in the Customer’s applicable rate



Section 14.03


Page 2 of 6






schedule and/or a negotiated rate subject to Commission approval. Setting Firm and Baseline Demands benefit both the Company and the Customer. With Firm Demands, the Company is able to curtail participating Customers’ load to predetermined levels which allows the Company to more accurately forecast its native load Capacity and Energy requirements. Baseline Demands assure the Customer a fixed price for Energy up to the Baseline Demand(s) and the ability to purchase Energy above the Baseline Demand(s) at rates set forth in the Customer’s applicable rate schedule and/or a negotiated Energy rate subject to

Commission approval.

Energy: The Customer’s monthly rate for Energy will be determined in two parts: (1)

Energy consumed up to and including the Baseline Demand(s), and (2) Energy consumed

above the Baseline Demand. The price (rate) for Energy consumed up to and including the

Baseline Demand(s) will be determined by multiplying the Customer’s metered Energy

consumption by the Energy rate provided in the rate schedule applicable to the Customer

and/or a negotiated rate subject to Commission approval. The monthly rate for Energy

consumed above the Baseline Demand(s) will be determined by multiplying the Customer’s

metered Energy consumption by the Energy rate provided in the rate schedule applicable to

the Customer and/or a negotiated Energy rate subject to Commission approval.

Demand: A Customer’s monthly rate for Demand shall be determined by multiplying the

Customer’s Billing Demand by the Demand rate provided in the rate schedule applicable to

the Customer and/or a negotiated Demand rate subject to Commission approval.

SYSTEM MARGINAL ENERGY PRICING:

Background: Certain Company industrial and Commercial Customers have ESAs that designate, among other things, a Billing Demand, Baseline Demands and a Firm Demand. With Baseline Demands, the Company agrees to provide and the Customer agrees to purchase its Energy requirements up to the Baseline Demand(s) at rates set forth in the Customer’s applicable rate schedule. Setting a Firm and Baseline Demands benefits both the Company and the Customer. With Firm Demands, the Company is able to curtail participating Customers’ load to predetermined levels which allows the Company to more accurately forecast its native load Capacity and Energy requirements. Baseline Demands assure the Customer a fixed price for Energy up to the Baseline Demand(s) and the ability to purchase Energy above the Baseline Demand(s) on a “real time” basis, which can be higher or lower than the rates set forth in the applicable rate schedule. Accordingly, a Customer can adjust its Energy consumption above the Baseline Demand(s) according to the value the Customer places on that Energy in real-time.

Energy: A Customer’s monthly rate for Energy will be determined in two parts: (1) Energy consumed up to and including the Baseline Demand(s), and (2) Energy consumed above the Baseline Demand(s). The price (rate) for Energy consumed up to and including the Baseline



Section 14.03


Page 3 of 6






Demand(s) will be determined by multiplying the Customer’s metered Energy consumption by the Energy rate provided in the rate schedule applicable to the Customer. The monthly rate for Energy consumed above the Baseline Demand(s) will be determined by multiplying the Customer’s metered Energy consumption by the Company’s System Marginal Energy Price.

System Marginal Energy Price Notification: No later than 4:00 p.m. (Central Time) of the preceding day, the Company shall give its best efforts to make available to Customers the System Marginal Energy Price for the next business day. System Marginal Energy Prices for Saturday through Monday will be made available, whenever possible, the previous Friday. The Company may deviate from this procedure in abnormal operating conditions and for the following holidays: New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving, and Christmas.

The Company is not responsible for a Customer’s failure to receive or obtain and act upon the System Marginal Energy Prices. If a Customer does not receive or obtain the prices made available by the Company, it is the Customer’s responsibility to notify the Company by 4:30 p.m. of the business day preceding the day the prices are to take effect. The Company reserves the right to revise its System Marginal Energy Price at any time prior to Customer’s acceptance and will be responsible for notifying the Customer of such revised prices.

Demand: A Customer’s monthly rate for Demand shall be determined by multiplying the Customer’s Billing Demand by the Demand rate provided in the rate schedule applicable to the Customer.

SHORT-TERM MARGINAL CAPACITY PURCHASES:

Background: Certain Customers have ESAs that establish for the term of the ESA, among other things, a Billing Demand under which the Customer purchases a fixed level of Capacity and a Firm Demand that represents the load-level to which the Customer must curtail on being notified by the Company. On a Short-term basis, the Customer may desire either more or less Capacity than that established in the ESA. The Short-Term Marginal Capacity Purchases and Short-Term Marginal Capacity Releases sections provide a mechanism under which the Customer may, on a Short-term basis, purchase additional Capacity from the Company or third party (the “Marginal Capacity”) or release (sell) Capacity to the Company or third party (the “Released Capacity”).

Marginal Capacity: Where the Customer requests additional Capacity on a Short-term

basis, the Customer may reserve additional Capacity, to the extent available, from the

Company’s system, or request the Company to purchase available Capacity in the market

(the “Marginal Capacity”). Where the Company is unable to provide Marginal Capacity

within 60 days of the Customer’s notice under Section 4.3, the Customer may seek Marginal



Section 14.03


Page 4 of 6






Capacity indirectly from a third party. The Company would work with the third party to

effectuate the purchase. In each case, the Company agrees to give to the Customer its best

effort in seeking the Marginal Capacity. The Marginal Capacity purchase must be for a

minimum of 1000 kW (1MW) and will include charges for Transmission Service, a Reserve

Margin and applicable administrative and other costs. The Company does not guarantee the

availability of Capacity or Transmission Service for the Marginal Capacity.

Compensation: The rate for the Marginal Capacity shall be as negotiated by the parties.

Where the Marginal Capacity is provided by a third party, the compensation for such

Marginal Capacity shall be as negotiated between the Customer, the Company and the third-

party, and the Company shall be compensated for its efforts in assisting the transaction.

Purchase Period: The Purchase Period shall be either a Summer Season(s) or Winter Season(s), or combination thereof, unless otherwise agreed to by the Company and Customer, but in no case will be less than one (1) month.

Effect of Marginal Capacity: By purchasing Marginal Capacity, the Customer agrees that its Firm Demand, as established in the ESA, will be increased throughout the Purchase Period by the amount of Marginal Capacity purchased. The Customer will continue to be billed for the Billing Demand established in the ESA. For all eligible Customers not taking service under Rate Schedule 14.02 (the Real Time Pricing Rider), Energy consumed above the Baseline Demand(s) will continue to be billed at the System Marginal Energy Price. Real Time Pricing Rider Customers will continue to be billed under the provisions of Rate Schedule 14.02.

SHORT-TERM MARGINAL CAPACITY RELEASES:


Released Capacity: Where the Customer requests to release Capacity on a short-term basis, the Customer may release some but not all of the Capacity (the “Released Capacity”), and the Company agrees to give its best effort in finding a purchaser of the Released Capacity. Where the Company is unable or unwilling to purchase the Released Capacity for its own



Section 14.03


Page 5 of 6






use or to resell it off-system at wholesale, or otherwise find a purchaser, within 60 days of the Customer’s notice under Section 4.3, the Customer may have a third party market the Capacity. The Company would work with the third-party to effectuate the sale of the Released Capacity. The Released Capacity must be a minimum of 1000 KW (1MW).

Compensation: As compensation for the Released Capacity, the Customer shall receive a credit or payment during any billing month in which Customer and Company have cooperated to make a Released term Capacity sale, adjusted to take into account the Company’s applicable administrative and other costs. Where the Company purchases the Released Capacity, the rate will be as negotiated between the Company and the Customer. No credit will be given to the Customer for any Energy sold by the Company under the Released Capacity, and the Customer will have no cost responsibility associated with the sale of such Energy. Where the Released Capacity is marketed by a third party, the compensation for such Released Capacity shall be as negotiated between the Customer, the Company and the third-party, and the Company shall be compensated for its efforts in assisting the Released Capacity transaction.

Release Period: The Release Period shall be either a Summer Season(s) or Winter Season(s), or combination thereof, unless otherwise agreed to by the Company and Customer, but in no case will be less than one (1) month.

Effect of Release Capacity: By selling Released Capacity, the Customer agrees that its Firm Demand, as established in the ESA, will be reduced throughout the Release Period by the amount of Released Capacity. The Customer will continue to be billed for the Billing Demand established in the ESA.

PENALTY FOR INSUFFICIENT LOAD CONTROL: Upon notification from the Company, the Customer shall curtail its Demand to its Firm Demand, as adjusted to take into consideration any Marginal Capacity or Released Capacity. In the event the Customer fails to curtail its load as requested by the Company, the Customer will forfeit any compensation for that period, if any is due. In addition, the Customer shall be responsible for any and all costs and/or penalties incurred by the Company as result of the Customer’s failure to curtail. The duration and frequency of curtailments shall be at the sole discretion of the Company unless otherwise provided in the ESA between the Company and the Customer.

TRANSACTION COSTS: Where the Company gives its best efforts to arrange either a Marginal Capacity purchase or Released Capacity sale but is nonetheless unable to find a market for the Customer, the Company is entitled to its reasonable transaction costs.

NOTIFICATION REQUIRED BY THE CUSTOMER: In order to improve the possibility there will be a market for the Released Capacity or Marginal Capacity available, the Customer shall provide notice of its intent to sell Released Capacity or purchase Marginal Capacity no later than six



Section 14.03


Page 6 of 6






(6) months before the start date of the next applicable Winter Season or Summer Season, the six-month requirement to be waived at the Company’s discretion. COMMUNICATION REQUIREMENTS: The Customer agrees to use Company-specified communication requirements and procedures when submitting any offer for Released Capacity or Marginal Capacity. These requirements may include specific computer software and/or electronic communication procedures.

METERING REQUIREMENTS: Company approved metering equipment capable of providing load interval information is required for Rider participation. The Customer agrees to pay for the additional cost of such metering when not provided in conjunction with existing retail electric service.

LIABILITY: The Company and the Customer agree that the Company has no liability for indirect, special, incidental, or consequential loss or damages to the Customer, including but not limited to the Customer's operations, site, production output, or other claims by the Customer as a result of participation in this Rider.

ENERGY ADJUSTMENT RIDER: Energy consumed up to and including the Baseline Demand(s) is subject to the Energy Adjustment Rider as provided in Section 13.01, or any amendments or superseding provisions applicable thereto. Because Energy consumed above the Baseline Demand(s) is subject to the System Marginal Energy Price and calculated on a real-time basis, it is not subject to the Energy Adjustment Rider as provided for in Mandatory Riders – Applicability Matrix, Section 13.00.

CUSTOMER EQUIPMENT: Customers taking service under this Rider shall provide equipment to maintain a power factor at a level no less than the level in which penalties would be invoked under the Tariff, if applicable.



Section 14.04

ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load

CT Metering Rider (Large Dual Fuel) Page 1 of 4

Twenty-secondfirst Revision





CONTROLLED SERVICE - INTERRUPTIBLE LOAD

CT METERING RIDER

(Commonly identified as Large Dual Fuel)


CT Metering without ancillary load 31-170 N/A

CT Metering without ancillary load (with short-duration cycling) 31-165 N/A

Penalty 31-881 N/A

CT Metering with ancillary load

Uncontrolled period N/A 31-168

Controlled period N/A 31-268

CT Metering with ancillary load (with short-duration cycling)





AVAILABILITY: This rider is available for Customers with approved permanently connected

interruptible loads; such loads are primarily the electric heating portion of dual fuel heating systems.

Electric heating systems may include heat pumps. Domestic electric water heating, and/or other

permanently connected approved loads other than the exceptions noted below in Option 2, will be

interrupted during control periods.

When service to the electric space heating equipment on this rate is interrupted, the back-up heating

system cannot be electric.

Option 1: Electric fans, pumps, and other ancillary equipment used in the distribution of

conditioned air and/or water shall be wired for service through the Customer’s firm service

Tariff.

Option 2: The Company retains the authority to allow a portion of the load used to deliver

conditioned air and/or water to remain on during control periods in situations where 1) it is

functionally or financially unfeasible to separately serve the equipment’s control systems, or

other critical ancillary equipment associated with this load, or 2) if the separation would violate

the manufacturer’s Underwriters Laboratory (UL) approval or other industry recognized

operating standards.



Section 14.04








During the control period the amount of ancillary load shall not exceed 5% of the metered maximum

Demand measured during any period within the most recent 12 months. (For example, although a

minimal amount of fan and/or pump load may be allowed under this provision, it is not intended to

be applied to larger loads such as the non-conditioned fan load on low-temperature grain drying.)

If the Customer does not have a back-up heating system, it is not automatic, or it is inadequate, then

the Company requires a primary electric heating Customer served on an interruptible rate to

complete a Controlled Service Agreement acknowledging that the Customer is aware of the potential

for property damage.

RATE:

OPTION 1




Maximum kW per Month: $0.12

Summer Winter

Energy Charge per kWh: 3.4553.6

03 ¢/kWh

3.7453.

893 ¢/kWh

Penalty kWh: 15.230 ¢/kWh 15.530 ¢/kWh

During the Penalty Period, kWhs used will be measured and billed at the Energy Charge

and Penalty listed above.



Section 14.04








OPTION 2





Summer Winter

Energy Charge per kWh: 3.7253.873 ¢/kWh

4.0384.

186 ¢/kWh

Control Period Demand Charge

per kW: $7.22 /kW $6.07 /kW




Charge.



Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00 and 14.00 of the Minnesota

electric rates for the matrices of riders.




PENALTY PERIODS – OPTION 1 ONLY: Penalty periods are defined as periods when the

Company signals to interrupt the Customer’s load and the Customer’s equipment does not shed the

load. Installation of a dual register Meter will be at the option of the Company. When a dual register

Meter is installed, penalty usage will be recorded on the penalty register and the total register of the

dual register Meters.

The penalty provision is not intended as a buy-through option. Under no circumstances should the

penalty clause of this rider be interpreted as an approved buy-through option for service under this



Section 14.04








rider.

CONTROL CRITERIA: Service may be controlled up to a total of 24 hours during a 24-hour

period, as measured from midnight to midnight. Short-duration cycling is approximately 15-minutes

off / 15-minutes on of appropriate cooling equipment during the Summer Season (June 1-September

30). Domestic water heating may be controlled up to 14 hours in a 24-hour period, as measured from

midnight to midnight.

DETERMINATION OF FACILITIES CHARGE: The monthly measured Demand will be based

on the maximum 15 consecutive minute period measured by a Demand Meter for the month for

which the bill is rendered. The Facilities Charge Demand shall be based on the greatest of the current

and preceding 11 monthly measured Demands.

DETERMINATION OF CONTROL PERIOD DEMAND – OPTION 2 ONLY: The Billing

Demand measured during the control period for which the bill is rendered shall be the maximum

metered kW for any period of 15 consecutive minutes during the control period.


metering and control equipment.



Section 14.05


Self-Contained Metering Rider (Small Dual Fuel) Page 1 of 3






CONTROLLED SERVICE – INTERRUPTIBLE LOAD

SELF-CONTAINED METERING RIDER

(Commonly identified as Small Dual Fuel)

DESCRIPTION RATE

CODE

Self-Contained Metering 31-190

Self-Contained Metering (with short-duration cycling) 31-185

Penalty 31-882




interruptible load; such loads are primarily the electric heating portion of dual fuel heating systems.

Electric heating systems may include heat pumps. Domestic electric water heating and/or other

permanently connected approved loads other than the exceptions noted below, will be interrupted

during control periods. Electric fans, pumps and other ancillary equipment used in the distribution

of conditioned air and/or water shall be wired for service through the Customer's firm service Tariff.

The Company retains the authority to allow a portion of the load to remain on during control periods

in situations where 1) it is unfeasible to separately serve the equipment’s control systems, or other

critical ancillary equipment associated with this load, or 2) if the separation would violate the

manufacturer’s Underwriters Laboratory (UL) approval or other industry recognized operating

standards. Although a minimal amount of fan and pump load may be allowed under this provision,

it is not intended to be applied to larger loads such as the fan load on low temperature grain drying.





complete a Controlled Service Agreement acknowledging that the Customer is aware of the

potential for property damage.



Section 14.05








RATE:

CONTROLLED SERVICE - INTERRUPTIBLE LOAD – SELF-CONTAINED




Summer Winter

Energy Charge per kWh:

4.2914.439 ¢/kWh

4.6934.841 ¢/kWh

Penalty Charge per kWh: 15.702 ¢/kWh 16.930 ¢/kWh






Minimum Charge.



Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00 and 14.00 of the





PENALTY PERIODS: Penalty periods are defined as periods when the Company signals to

interrupt the Customer’s load and the Customer’s equipment does not shed the load. Installation of a

dual register Meter will be at the option of the Company. When a dual register Meter is installed,

penalty usage will be recorded on the penalty register, and the total register of the dual register

Meters.



Section 14.05










rider.




30). Domestic water heating may be controlled up to 14 hours in a 24-hour period, as measured

from midnight to midnight.





Section 14.06

ELECTRIC RATE SCHEDULE Controlled Service – Deferred Load Rider

(Thermal Storage) Page 1 of 3






CONTROLLED SERVICE

DEFERRED LOAD RIDER

(Commonly identified as Thermal Storage)

DESCRIPTION RATE

CODE

Deferred Loads 31-197

Deferred Loads (Short Duration Cycling) 31-195

Penalty 31-883




deferred loads that can be served under the limited conditions provided; such loads are primarily

electric water heating and thermal storage.

Deferred loads may include heat pumps, domestic electric water heating, and other permanently

connected loads that can be interrupted.

Electric fans, pumps, and other ancillary equipment used in the distribution of conditioned air and/or

water shall be wired through the Customer’s firm service Meter. The Company retains the authority

to allow a portion of the load to remain on during control periods in situations where 1) it is

unfeasible to separately serve the equipment’s control systems, or other critical ancillary equipment

associated with this load, or 2) if the separation would violate the manufacturer’s Underwriters

Laboratory (UL) approval or other industry recognized operating standards. Although a minimal

amount of fan and pump load may be allowed under this provision, it is not intended to be applied to

larger loads such as the fan load on low temperature grain drying.



Section 14.06








RATE:

CONTROLLED SERVICE - DEFERRED LOAD

Customer Charge per Month:

$2.00




All kWh

5.5885.736 ¢/kWh

5.9756.123 ¢/kWh

Penalty kWh 14.744 ¢/kWh 15.649 ¢/kWh

During the Penalty Period, kWhs used will be measured and billed at the Energy

Charge and Penalty listed above.




Minimum Charge.



Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00, and 14.00 of the









Meters.



rider.



Section 14.06










schedule recovery time following control periods that approach continuous 14 hours. Short-duration

cycling is 15-minutes off / 15-minutes on of appropriate cooling equipment during the Summer

Season (June 1-September 30). Domestic water heating may be controlled up to 14 hours in a 24-

hour period, as measured from midnight to midnight.





Section 14.07

ELECTRIC RATE SCHEDULE Fixed Time of Service Rider

(Fixed TOS) Page 1 of 4

SixthFifth Revision





FIXED TIME OF SERVICE RIDER

(Commonly identified as Fixed TOS)

DESCRIPTION RATE

CODES

Fixed Time of Service – Self-Contained Metering 31-301

Penalty 31-884

Fixed Time of Service – CT Metering 31-302

Penalty 31-885

Fixed Time of Service – Primary CT Metering 31-303

Penalty 31-886



AVAILABILITY: This rider is available to Customers with permanently connected thermal

storage space heating technologies that are designed and installed with the capability to be

operated under the limitations and terms of this rider.

Electric fans, pumps, and other ancillary equipment used in the distribution of heat shall be

wired through the Customer’s firm service Meter. The Company retains the authority to allow a

portion of the load to remain on during control periods in situations where 1) it is unfeasible to

separately serve the equipment’s control systems, or other critical ancillary equipment


Laboratory (UL) approval or other industry recognized operating standards. Although a

minimal amount of fan and pump load may be allowed under this provision, it is not intended to

be applied to larger loads such as the fan load on lowtemperature grain drying.



Section 14.07



SixthFifth Revision





RATE:

FIXED TIME OF SERVICE - Self-Contained Metering




Summer Winter

Energy Charge per kWh: 1.6261.774 ¢/kWh 3.3253.473 ¢/kWh

Penalty: 5.676 ¢/kWh 3.605 ¢/kWh

During the Penalty Period, kWhs used will be measured and billed at the Energy Charge and

Penalty listed above.

FIXED TIME OF SERVICE – CT Metering




Summer Winter







Section 14.07



SixthFifth Revision





FIXED TIME OF SERVICE – Primary CT Metering




Summer Winter

Energy Charge per kWh:

1.6201.7

68 ¢/kWh

3.3123.4

60 ¢/kWh







Minimum Charge.



Riders selected by the Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00

and 14.00 of the electric rates for the matrices of riders.





interrupt the Customer’s load and the Customer’s equipment does not shed the load. Installation

of a dual register Meter will be at the option of the Company. When a dual register Meter is

installed, penalty usage will be recorded on the penalty register, and the total register of the dual

register Meters.



Section 14.07



SixthFifth Revision





The penalty provision is not intended as a buy-through option. Under no circumstances should

the penalty clause of this rider be interpreted as an approved buy-through option for service

under this rider.

CONTROL CRITERIA: The Customer will receive electric service from 10:00 p.m. until

6:00 a.m. each day. During all other hours, the Customer's load will be controlled.





Section 14.12

ELECTRIC RATE SCHEDULE Off-Peak Electric Vehicle Rider

(Off-Peak EV) Page 1 of 3

First RevisionOriginal

MINNESOTA PUBLIC UTILITIES COMMISSION Approved: June 22, 2015 Docket No. E-017/GR-15-1033M-15-112


EFFECTIVE with bills rendered on and after July 1, 2015

in Minnesota

OFF-PEAK ELECTRIC VEHICLE RIDER

(Commonly identified as Off-Peak EV)

DESCRIPTION RATE

CODES

Off-Peak EV Service – Self-Contained Metering 31-781

Penalty/Unauthorized Use 31-887

Off-Peak EV Service – CT Metering 31-782


Off-Peak EV Service – Primary CT Metering 31-783




AVAILABILITY: This rider is available to Customers to purchase electricity solely for the

purpose of recharging an electric vehicle, as defined in Minnesota Statute § 216B.1614, Subd.1.

The Company reserves the right, at any time, to require from the Customer the State of

Minnesota vehicle registration and/or audit the interconnected facilities to verify customer

compliance with Minnesota Statute § 216B.1614 and eligibility for this rate.

RATE:

Off-Peak Electric Vehicle Service – Self-Contained Metering




Summer Winter







Section 14.12







in Minnesota

Off-Peak Electric Vehicle Service – CT Metering




Summer Winter





Off-Peak Electric Vehicle Service – Primary CT Metering




Summer Winter








Minimum Charge.







Section 14.12







in Minnesota

DEFINITIONS OF SEASONS: Summer: June 1 through September 30

Winter: October 1 through May 31

AUTHORIZED PERIODS OF ELECTRIC SERVICE: The Customer will only receive

electric service during the authorized periods from 10:00 p.m. until 6:00 a.m. each day. All

other hours of electric service are unauthorized and subject to Penalty Periods.

PENALTY PERIODS: Penalty periods are defined as periods when a) Customer utilizes

service during unauthorized periods and/or b) the Company signals to interrupt the Customer’s

load and the Customer’s equipment does not shed the load. Installation of a dual register Meter

will be at the option of the Company. When a dual register Meter is installed, penalty usage will

be recorded on the penalty register, and the total register of the dual register Meters.



under this rider.



1/3 tab

Volume 1

Interim Tariff Sheets – Non-Redlined


InterimMinnesota Public Utilities Commission

Section 9.01 ELECTRIC RATE SCHEDULE

Residential Service

Page 1 of 2 Twenty-sixth Revision

MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033


EFFECTIVE with bills renderedon and after

in Minnesota

RESIDENTIAL SERVICE

DESCRIPTION RATE CODE

Residential Service 31-101


APPLICATION OF SCHEDULE: This schedule is applicable to Residential Service as defined in the General Rules and Regulations.

RATE:

RESIDENTIAL SERVICE Customer Charge per Month: $8.50 Monthly Minimum Bill: Customer + Facilities Charges Facilities Charge per Month: $0.00

Energy Charge per kWh: Summer Winter 8.124 ¢/kWh 8.340 ¢/kWh

R

INTERIM RATE ADJUSTMENT: A 10.95 percent increase will be added to the sum of the following, as applicable: Customer Charge, Energy Charge, Demand Charge, Fixed Charge, Facilities Charge, and the monthly Minimum Charge.

N N N N

MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply and by any Voluntary Rate Riders selected by the Customer, unless otherwise noted in this schedule. See Sections 12.00, 13.00 and 14.00 of the Minnesota electric rates for the matrices of riders.

DEFINITIONS OF SEASONS: Summer: June 1 through September 30. Winter: October 1 through May 31.




Residential Service

Page 2 of 2 Twenty-sixth Revision




in Minnesota

SEASONAL RESIDENTIAL SERVICE:

1. These rates and regulations shall apply to Seasonal Residential Service without voluntary rate riders.

2. Seasonal Residential Customers will be billed at the same rate as Residential Customers,

except as follows:

A one-time seasonal fixed charge of $34.00 will be billed for each Meter in addition to the rate provided above. The fixed charge will be included on the first bill rendered for each season.

Each Seasonal Residential Customer will be billed for the number of months each season that the residence is in use, but not less than a minimum of four months, plus the seasonal fixed charge. At the option of the Company, Meters may be read during the off-season and a bill will be rendered if Energy recorded on the Meter exceeds 200 Kilowatt-Hours. If the first bill of the season exceeds an average usage of 200 Kilowatt-Hours per month during the off-season months, the Customer, at the option of the Company, may no longer be eligible for Seasonal Residential Service.

Bills may be rendered on a two-month basis at the Company’s discretion when the Energy used exceeds 200 Kilowatt-Hours and more than 55 days have elapsed since the previous Meter reading.

Seasonal Residential Customers also will be subject to a connection charge of $40.00 when the Account is established.



Section 9.02


(RDC) Page 1 of 2

Thirteenth Revision




in Minnesota


(Commonly identified as RDC)

DESCRIPTION RATE

CODE

Residential Demand Control 31-241



APPLICATION OF SCHEDULE: This schedule is applicable to Residential Customers with a

UL-approved Demand-control system.

RATE:






4.819 ¢/kWh 5.206 ¢/kWh


$6.08 /kW $5.11 /kW

R




Minimum Charge.

N

N

N

N



Section 9.02


(RDC) Page 2 of 2

Thirteenth Revision




in Minnesota








BILLING DEMAND DETERMINATION: The Demand will be determined based on the peak

one-hour Demand reading recorded during the Winter period for the most recent 12 months. An

estimated Demand of three kW will be used for Customers new to this rate until a Demand is

established.

DEMAND SIGNAL: Service may receive a Demand signal for up to a total of 14 hours during a

24-hour period, as measured from midnight to midnight. Water heaters served on this schedule also

will be included in the Company’s Summer water heater load control program.



Section 9.03


Page 1 of 2

Twenty-fifth Revision




in Minnesota

FARM SERVICE

DESCRIPTION RATE

CODE

Farm Service 31-361



APPLICATION OF SCHEDULE: This schedule is applicable to general Farm and home use.

The Customer may elect to have the following service offerings in the farm home (for residential

uses); Residential Service (Section 9.01) or Residential Demand Control Service Schedule

(Section 9.02) if all the requirements specified for the schedules are satisfied.

RATE:

FARM SERVICE



Facilities Charge per Month:

Single-phase $0.00

Three-phase: $8.00


7.814 ¢/kWh 8.021 ¢/kWh

R




Minimum Charge.

N

N

N

N



Section 9.03


Page 2 of 2

Twenty-fifth Revision




in Minnesota










Section 10.01


Page 1 of 4

Third Revision




in Minnesota

SMALL GENERAL SERVICE

Under 20 kW

DESCRIPTION Secondary Primary

Metered Service – under 20 kW 31-404 31-405

Non-metered Service - 1000 Watts or less – CLOSED TO

NEW INSTALLATIONS

31-408 Not Available



APPLICATION OF SCHEDULE: This schedule is applicable to Three-phase Residential

Customers, and both Single- and Three-phase nonresidential Customers. This schedule is not

applicable for outdoor lighting. Emergency and supplementary/standby service will be supplied only

as allowed by law.

RATE:



Monthly Minimum

Bill: Customer + Facilities Charges Customer + Facilities Charges

Facilities Charge per Month: $0.00 $0.00


7.727 ¢/kWh 7.932 ¢/kWh 7.479 ¢/kWh 7.632 ¢/kWh

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Section 10.01


Page 2 of 4

Third Revision




in Minnesota

NON-METERED SERVICE-SECONDARY ONLY-1000 WATTS OR LESS

***CLOSED TO NEW INSTALLATIONS***





All kWh 7.863 ¢/kWh 7.863 ¢/kWh

R




Charge.

N

N

N

N








TERMS AND CONDITIONS: The Customer may remain on the Small General Service schedule

as long as Customer's maximum Demand does not equal or exceed 20 kW for more than two of the

most recent 12 months. If the Customer achieves an actual Demand of 20 kW or greater for a third

time in the most recent 12 months, the Customer will be placed on the General Service schedule

(Section 10.02) in the next billing month.

SEASONAL SMALL GENERAL SERVICE:

1. These rates and regulations shall apply to Seasonal Small General Service without voluntary

rate riders.



Section 10.01


Page 3 of 4

Third Revision




in Minnesota

2. Seasonal Small General Service Customers will be billed at the same rate as Small General

Service Customers, except as follows:



season.

Each Seasonal Small General Service Customer will be billed for the number of months each

season that the property is in use, but not less than a minimum of four months, plus the

seasonal fixed charge. At the option of the Company, Meters may be read during the off-

season and a bill will be rendered if Energy recorded on the Meter exceeds 400 Kilowatt-

Hours. If the first bill of the season exceeds an average usage of 400 Kilowatt-Hours per

month during the off-season months, the Customer, at the option of the Company, may no

longer be eligible for Seasonal Small General Service.



Meter reading.

Seasonal Small General Service Customers also will be subject to a connection charge of

$40.00 when the Account is established.

NON-METERED 1000 WATTS AND UNDER SERVICE:

For applications where no metering is installed, the applicable lower monthly Customer

Charge shall apply. For purposes of applying the appropriate Customer service charge, one

Customer Charge shall be applied for every point of delivery. A point of delivery shall be any

location where a Meter would otherwise be required under this schedule.

For applications where Customer owns and operates multiple electronic devices such

electronic devices are: 1) individually located at each point of delivery, 2) rated at less than

1000 watts or as specified in contract, and 3) operated with a continuous and constant load

level year round. Each individual electronic device must not in any way interfere with

Company operations and service to adjacent Customers. This optional service is not

applicable to electric service for traffic lights, civil defense-fire sirens, or lighting. Company

reserves the right to evaluate Customer requests for this optional service to determine

eligibility.



Section 10.01


Page 4 of 4

Third Revision




in Minnesota

In place of metered usage for each device, Customer will be billed for the predetermined

Energy usage in kWh per device. The Energy Charge shall equal the sum of the

predetermined Energy usage for Customer’s approved devices in service for the billing month

multiplied by the Energy Charge applicable for the billing month.

DETERMINATION OF DEMAND: Unless otherwise established, the Billing Demand shall be the

maximum Demand in kW as measured by a Demand Meter, for the highest 15-minute period during

the month for which the bill is rendered.



Section 10.02


Page 1 of 2

Twenty-fourth Revision




in Minnesota

GENERAL SERVICE

20 kW or Greater

DESCRIPTION RATE

CODE

General Service – Secondary Service 31-401

General Service – Primary Service 31-403


Rules and Regulations govern use of this service.

APPLICATION OF SCHEDULE: This schedule is applicable to Three-phase Residential Customers,

and both Single and Three-phase nonresidential Customers with a measured Demand of at least 20 kW

within the most recent 12 months. This schedule is not applicable for outdoor lighting. Emergency and

supplementary/Standby service will be supplied only as allowed by law.

RATE:



Monthly

Minimum Bill: Customer + Facilities + Demand Charges Customer + Facilities + Demand Charges


per annual max. kW

(minimum 20 kW per Month): $0.60 /kW $0.40 /kW


6.939 ¢/kWh 7.501 ¢/kWh 6.731 ¢/kWh 7.238 ¢/kWh

Demand Charge per kW: Summer Winter Summer Winter

(minimum 20 kW) $1.22 /kW $1.02 /kW $1.17 /kW $0.97 /kW

R



Section 10.02


Page 2 of 2

Twenty-fourth Revision




in Minnesota




Charge.

N

N

N

N








TERMS AND CONDITIONS: A Customer with a Billing Demand of less than 20 kW for 12

consecutive months will be required to take service under the Small General Service schedule

(Section 10.01).




Demand may be increased by 1 kW for each whole 10 kVar of measured Reactive Demand in excess

of 50% of the Metered Demand in kW.







Section 10.03


Page 1 of 3

Seventeenth Revision




in Minnesota


DESCRIPTION RATE

CODE

Declared-Peak 31-708

Intermediate 31-709

Off-Peak 31-710



APPLICATION OF SCHEDULE: This schedule is applicable to nonresidential Customers with

one Meter providing electrical service.

RATE:





Per annual maximum kW

(minimum 20kW per Month): $0.60 /kW


Declared-Peak 20.480 ¢/kWh 21.772 ¢/kWh

Intermediate 5.310 ¢/kWh 4.851 ¢/kWh

Off-Peak 2.479 ¢/kWh 3.653 ¢/kWh


(minimum of 20 kW):

Summer Winter

Declared-Peak N/A /kW N/A /kW


Off-Peak $0.00 /kW $0.00 /kW

R

R

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Minimum Charge.

N

N

N

N



Section 10.03


Page 2 of 3





in Minnesota





METERED DEMANDS: The maximum kW as measured for one hour during each period of the

Declared-Peak, Intermediate and Off-Peak periods during the month for which the bill is rendered.


Demand may be increased by 1 kW for each whole 10 kVar of Reactive Demand in excess of 50%

of the Metered Demand in kW.


kW or the Metered demand during the Intermediate Period and adjusted for Excess Reactive

Demand.

DETERMINATION OF FACILITIES CHARGE: The Facilities Charge Demand will be the

greater of 1) 20 kW, or 2) the largest of the most recent 12 monthly Metered Demands adjusted for

Excess Reactive Demand.


WINTER SEASON - OCTOBER 1 THROUGH MAY 31 BILLINGS Declared-Peak: For all kW and kWh used during the hours declared (see Declared-Peak Notification)

Intermediate: For all kW and kWh used during the hours other than declared-peak and off-peak Off-Peak: For all kW and kWh used Monday through Saturday from10:00 p.m. to 6:00 a.m., and all day Sunday

SUMMER SEASON - JUNE 1 THROUGH SEPTEMBER 30 BILLINGS Declared-Peak: For all kW and kWh used during the hours declared (see Declared-Peak Notification)

Intermediate: For all kW and kWh used during the hours other than declared-peak and off-peak



Section 10.03


Page 3 of 3





in Minnesota

Off-Peak: For all kW and kWh used Monday through Saturday from10:00 p.m. to 6:00 a.m., and all day Sunday

DECLARED-PEAK NOTIFICATION: The Company shall make available to the Customers, no

later than 4:00 p.m. (Central Time) of the preceding day, "declared-peak" designations for the next

business day. Except for unusual periods, the Company will make "declared-peak" designations for

Saturday through Monday available to Customers on the previous Friday. More than one-day-ahead

"declared-peak" designations may also be used for the following holidays: New Year’s Day,

Memorial Day, Independence Day, Labor Day, Thanksgiving, and Christmas.

Because circumstances prevent the Company from projecting "declared-peak" designations more

than one day in advance, the Company reserves the right to revise and make available to Customers

"declared-peak" designations for Sunday, Monday, any of the holidays mentioned above, or for the

day following a holiday. Any revised "declared-peak" designations shall be made available by the

usual means no later than 4:00 p.m. of the day prior to the prices taking effect.

The Company is not responsible for the Customer's failure to receive or obtain and act upon the

"declared-peak" designations. If the Customer does not receive or obtain the "declared-peak"

designations made available the Company, it is the Customer's responsibility to notify the Company

by 4:30 p.m. (Central Time) of the business day preceding the day that the "declared-peak"

designations are to take effect. The Company will be responsible for notifying the Customer if

prices are revised.



Section 10.04


Page 1 of 3

Twentieth Revision




in Minnesota

LARGE GENERAL SERVICE

DESCRIPTION RATE

CODES






APPLICATION OF SCHEDULE: This schedule is applicable to nonresidential Customers. This

schedule is not applicable for outdoor lighting. Emergency and supplementary/Standby service will

be supplied only as allowed by law.

RATE:

SECONDARY SERVICE





Less than 1000 kW: $0.33 /kW

Greater than or equal to 1000 kW: $0.24 /kW


4.766 ¢/kWh 5.148 ¢/kWh


(minimum of 80 kW): Summer Winter

$7.22 /kW $6.07 /kW

R



Section 10.04


Page 2 of 3

Twentieth Revision




in Minnesota

PRIMARY SERVICE





All kW: $0.12 /kW


4.625 ¢/kWh 4.969 ¢/kWh



R






All kW: $0.00 /kW


4.392 ¢/kWh 4.681 ¢/kWh



R




Minimum Charge.

N

N

N

N



Section 10.04


Page 3 of 3

Twentieth Revision




in Minnesota








METERED DEMAND: The maximum kW as measured by a Demand Meter for any period of 15



Demand may be increased by 1 kW for each whole 10 kVar of measured Reactive Demand in

excess of 50% of the Metered Demand in kW.







Section 10.05


Page 1 of 4

Seventh Revision




in Minnesota

LARGE GENERAL SERVICE - TIME OF DAY

DESCRIPTION On-Peak Shoulder Off-Peak

Secondary Service 31-611 31-615 31-613

Primary Service 31-610 31-614 31-612

Transmission Service 31-639 31-637 31-640


APPLICATION OF SCHEDULE: This schedule is applicable to nonresidential Customers with a measured Demand of at least 80 kW within the most recent 12 months.

RATE:

SECONDARY SERVICE





Less than 1000 kW: $0.33/kW

Greater than or equal to 1000 kW:

$0.24/kW


On-Peak 7.467 ¢/kWh 6.655 ¢/kWh

Shoulder 5.545 ¢/kWh 5.065 ¢/kWh



On-Peak $5.54 /kW $5.13 /kW


Off-Peak $0.00 /kW $0.00 /kW

R

R

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Section 10.05


Page 2 of 4

Seventh Revision




in Minnesota

PRIMARY SERVICE




per annual max. kW (minimum 80 kW per Month): $0.12/kW


On-Peak 7.215 ¢/kWh 6.399 ¢/kWh




On-Peak $5.32 /kW $4.94 /kW


Off-Peak $0.00 /kW $0.00 /kW



Monthly Minimum Bill

per annual max. kW

(minimum 80 kW per Month): Customer + Facilities Charges



On-Peak 6.808 ¢/kWh 5.992 ¢/kWh




On-Peak $4.31 /kW $4.27 /kW


Off-Peak $0.00 /kW $0.00 /kW

R

R

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R

R



Section 10.05


Page 3 of 4

Seventh Revision




in Minnesota




Charge.

N

N

N

N








METERED DEMAND: The maximum kW as measured for one hour during each of the On-peak,

Shoulder and Off-Peak periods during the month for which the bill is rendered.

ADJUSTMENTS FOR EXCESS REACTIVE DEMANDS: For billing purposes, the Metered

Demands may be increased by one kW for each whole ten kVar of Reactive Demand in each period

in excess of 50% of the Metered Demand in kW.



DETERMINATION OF FACILITIES CHARGE: The Facilities Charge Demand will be based on

the greater of 1) 80 kW, or 2) the largest of the most recent 12 monthly Metered Demands adjusted

for Excess Reactive Demand.

DEFINITION OF ON-PEAK, SHOULDER AND OFF-PEAK PERIODS BY SEASON:

WINTER SEASON - OCTOBER 1 THROUGH MAY 31 BILLINGS On-Peak: For all kW and kWh used Monday through Friday between 7:00 a.m. and 12:00 noon, and between 5:00 p.m. and 9:00 p.m.



Section 10.05


Page 4 of 4

Seventh Revision




in Minnesota

Shoulder: For all kW and kWh used Monday through Friday hour 6:00 a.m. to 7:00 a.m., hours 12:00 noon to 5:00 p.m. and hour 9:00 p.m. to 10:00 p.m. and, Saturday through Sunday 6:00 p.m. to 10:00 p.m.

Off-Peak: For all kW and kWh used Monday through Friday hours 10:00 p.m. to 6:00 a.m. and , Saturday and Sunday all hours except 6:00 p.m. to 10:00 p.m..

SUMMER SEASON - JUNE 1 THROUGH SEPTEMBER 30 BILLINGS On-Peak: For all kW and kWh used Monday through Friday between 1:00 p.m. and 7:00 p.m.

Shoulder: For all kW and kWh used Monday through Friday 9:00 a.m. to 1:00 p.m., and 7:00 p.m. to 10:00 p.m., Saturday through Sunday 9:00 a.m. to 10:00 p.m.

Off-Peak: For all kW and kWh used Monday through Friday hours 10:00 p.m. to 9:00 a.m.

and, Saturday and Sunday all hours except 9:00 a.m. to 10:00 p.m.



Section 11.01


Page 1 of 8

Eighth Revision




in Minnesota

STANDBY SERVICE

OPTION A: FIRM OPTION B: NON-FIRM

On-Peak Shoulder Off-Peak On-Peak Shoulder Off-Peak

Transmission Service 31-941 31-942 31-943 31-950 31-951 31-952

Primary Service 31-944 31-945 31-946 31-953 31-954 31-955

Secondary Service 31-947 31-948 31-949 31-956 31-957 31-958



AVAILABILITY: This schedule, including Attachment 1 - Definitions and Useful Terms,

provides Backup, Scheduled Maintenance, and Supplemental Services, is applicable to any

Customer who has the following conditions:

1. Requests to become a Standby Service Customer of the Company. Otherwise, the

Company views the Customer as a Non-Standby Service Customer. For information about

the different categories of Non-Standby Service Customers, including exemptions from

Standby Service, please see Attachment No. 1 – Definitions.

2. Utilizes Extended Parallel Generation Systems to meet all or a portion of electrical

requirements, which is capable of greater than 100 kW. Customers with Extended Parallel

Generation Systems used to meet all or a portion of electrical requirements that are capable

of 100 kW or less are considered Non-Standby Service Customers and exempt from

paying standby charges. Please see Attachment No. 1-Definitions for more information

regarding Non-Standby Service Customers.

3. Enters into a contract for services related to its Generator. Contracts will be made for this

service provided the Company has sufficient Capacity available in production, transmission

and Distribution Facilities to provide such service at the location where the service is

requested.

The Company delivers alternating current service at transmission, primary or secondary voltage

under this rate schedule, supplied through one Meter.

Power production equipment at the Customer site shall not operate in parallel with the Company’s

system until the installation has been inspected by an authorized Company representative and final

written approval is received from the Company to commence parallel operation.



Section 11.01


Page 2 of 8

Seventh Revision




in Minnesota

STANDBY RATE OPTIONS - FIRM AND NON-FIRM

OPTION A: FIRM STANDBY



Firm Standby Fixed Charges



Customer +

Reservation +

Standby Facilities

Charges

Customer +

Reservation +

Standby Facilities

Charges

Customer +

Reservation +

Standby Facilities

Charges

Summer Reservation Charge per



Winter Reservation Charge per






Firm Standby On-Peak Demand Charge - Summer



Firm Standby On-Peak Demand Charge - Winter



Firm Standby Energy Charges - Summer


On-Peak Charge 6.808 ¢/kWh 7.215 ¢/kWh 7.467 ¢/kWh

Shoulder Charge 5.100 ¢/kWh 5.376 ¢/kWh 5.545 ¢/kWh

Off-Peak Charge 2.420 ¢/kWh 2.524 ¢/kWh 2.585 ¢/kWh

Firm Standby Energy Charges - Winter


On-Peak Charge 5.992 ¢/kWh 6.399 ¢/kWh 6.655 ¢/kWh



R

R

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R

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Section 11.01


Page 3 of 8

Seventh Revision




in Minnesota

OPTION B: NON-FIRM STANDBY



Non-Firm Standby Fixed Charges



Customer +

Reservation +

Standby Facilities

Charges

Customer +

Reservation +

Standby Facilities

Charges

Customer +

Reservation +

Standby Facilities

Charges

Reservation Charge per month

per kW of Contracted Backup

Demand Not Available Not Available Not Available




Non-Firm Standby On-Peak Demand Charge - Summer



Non-Firm Standby On-Peak Demand Charge - Winter



Non-Firm Standby Energy Charges - Summer





Non-Firm Standby Energy Charges - Winter





R

R

R

R




Minimum Charge.

N

N

N

N



Section 11.01


Page 4 of 8

Seventh Revision




in Minnesota





DETERMINATION OF METERED DEMAND: Metered Demand shall be based on the

maximum kW registered over any period of one hour during the month in which the bill is

rendered.


1. Company's Meter will be detented to measure power and Energy from Company to

Customer only. Any flow of power and Energy from Customer to Company will be

separately metered under one of Company's Purchase Power Rate Schedules, Distributive

Generation Rider, or by contract.

2. Option A - Firm Standby: Exclusive of any scheduled maintenance hours, if the number of

hours on which Backup Service is supplied exceeds 120 On-Peak hours in the Summer

season and 240 On-Peak hours in the Winter season, Customer may be required to take

service under a standard, non-standby, rate schedule.

3. Option B – Non-Firm Standby: Backup Service is not available during any on-peak season.

This service is only available in the Summer Shoulder and Summer Off-Peak and Winter

Shoulder and Winter Off-Peak hours on a non-firm basis. The Company makes no

guarantee that this service will be available, however, the Company will make reasonable

efforts to provide Backup Service under Option B whenever possible.

4. One year (12 months) written notice to Company is required to convert from this standby

service to regular firm service, unless authorized by the Company.

5. Any additional facilities, beyond normal transmission and Distribution Facilities, required

to furnish service will be provided at Customer's expense.

6. Customer shall indemnify Company against all liability which may result from any and all

claims for damages to property and injury or death to persons which may arise out of or be

caused by the erection, maintenance, presence, or operation of the Customer generation

facility or by any related act or omission of the Customer, its employees, agents, contractors

or subcontractors.



Section 11.01


Page 5 of 8

Seventh Revision




in Minnesota

7. During times of Customer generation, Customer will be expected to provide vars as needed

to serve their load. Customer will provide equipment to maintain a unity power factor + or –

10% for Supplemental Service, and when Customer is taking Backup Service from

Company.

CONTRACT PERIOD: Standby Service is applicable only by signed agreement, setting forth the

location and conditions applicable to the electric service, such as the Contracted Backup

Demand, type of standby service (Option A or B), excess facilities required for service and other

applicable terms and conditions, and providing for an initial minimum contract period of one year,

unless otherwise authorized by Company.



Section 11.01


Page 6 of 8

Seventh Revision




in Minnesota

ATTACHMENT NO. 1 DEFINITIONS AND USEFUL TERMS

Backup Demand (a component of Backup Service) is the Demand taken when on-peak

Demand provided by Company is used to make up for reduced output from Customer's generation.

Backup Demand Charge is the sum of the ten highest daily Backup Demands multiplied by

the applicable Backup Demand Charge for that season.

Backup Service is the Energy and Demand supplied by the utility during unscheduled

outages of the Customer’s Generator.

Billing Demand is the Customer’s Demand used by the Company for billing purposes.

Capacity is the ability to functionally serve a required load on a continuing basis.

Contracted Backup Demand is the amount of Capacity selected to backup the Customer’s

generation, not to exceed the capability of the Customer’s Generator.

Demand is the rate at which electric Energy is delivered to or by a system, part of a system,

or a piece of equipment and is expressed in Kilowatts (“kW”) or Megawatts;

Energy is the Customer’s electric consumption requirement, measured in Kilowatt-Hours

(“kWh”).

Extended Parallel Generation Systems are generation systems that are designed to remain

connected in parallel to and in phase to the utility Distribution system for an extended period of

time.

Excess Distribution Facility Investment are Distribution Facilities required to provide

service to the distributed generation system that are not provided in the Company retail service

schedules. The Customer is required to pay up-front for these facilities and pay maintenance costs

as long as the facilities are required.

MAPP is the Mid-Continent Area Power Pool or any successor agency assuming or

charged with similar responsibility.



Section 11.01


Page 7 of 8

Eighth Revision




in Minnesota

MISO is the Midcontinent Independent System Operator, Inc. assures industry consumers

of unbiased regional grid management and open access to the Transmission Facilities under

Midwest ISO's functional supervision.

Non-Standby Service Customer is a Customer that a) does not request and receive

approval of Standby Services from the Company or, b) is exempt from paying any standby charges

as allowed by law or Commission Order, or, c) in lieu of service under this Tariff, may provide

Physical Assurance, or d) will take service from any of the Company’s other approved base Tariffs.

Customers with Extended Parallel Generation Systems used to meet all or a portion of

electrical requirements that are capable of 100 kW or less are considered Non-Standby Service

Customers and exempt from paying standby charges.

Standby Service for Customers with Extended Parallel Generation Systems used to meet all

or a portion of electrical requirements that are capable of 100 kW or less is available under the

Customer’s base rate.

For more information regarding Extended Parallel Generation Systems, Physical

Assurance Customers, and Standby Service for Customers, please see these terms under

Definitions.

Physical Assurance Customer is a Customer who agrees not to require standby services

and has an approved mechanical device, inspected and approved by a Company representative, to

insure standby service is not taken. The cost of the mechanical device is to be paid by the

Customer.

Renewable Energy Attributes refers to the benefits of the Energy from being generated by

a renewable resource rather than a fossil-fueled resource.

Renewable Energy Credit is typically viewed as a certification that something was

generated by a renewable resource.

Renewable Resource Premium referred to the extra payment received on top of the regular

avoided costs. This extra payment is to reflect the value of the Renewable Energy Credit, which is

a certification of the Renewable Energy Attributes.

Scheduled Maintenance Service is defined as the Energy and Demand supplied by the

utility during scheduled outages. The daily on-peak backup Demand charge under Variable

Charges of the "Rate" section will be waived for a maximum continuous period of 30 days per

calendar year to allow for maintenance of Customer generation source. Waiver is only valid during

the months of April, May, October, and November, and with a minimum of five working days

(excludes weekend and holidays) written notice to Company. In certain cases, such as very large



Section 11.01


Page 8 of 8

Seventh Revision




in Minnesota

Customers, the Company and the Customer will mutually agree to different maintenance schedules

as listed above.

Standby Service Customer is a Customer who receives the following services from the

Company, Sections 11.01; backup power for non-Company generation, supplemental power, and

scheduled maintenance power. These services are not applicable for resale, municipal outdoor

lighting, or customers with emergency standby Generators.

Summer On-Peak: For all kW and kWh used Monday through Friday between 1:00 p.m.

and 7:00 p.m.

Summer Off-Peak: For all other kW and kWh not covered by either shoulder or off-peak.

Summer Season is the period from June 1 through September 30.

Summer Shoulder: For all kW and kWh used Monday through Friday 9:00 a.m. to 1:00

p.m., and 7:00 p.m. to 10:00 p.m., Saturday through Sunday 9:00 a.m. to 10:00 p.m.

Supplemental Service is the Energy and Demand supplied by the utility in addition to the

capability of the on-site Generator. Except for determination of Demand, Supplemental Service

shall be provided under Standard Rate Schedule 10.06.

Supplemental Demand (a component of Supplemental Service) is the metered Demand

measured on Company Meter during on-peak and off-peak periods, less Contracted Backup

Demand.

Winter Season is the period from October 1 through May 31.

Winter Off-Peak: All other kW and kWh’s not covered by either shoulder or off-peak.

Winter On-Peak: For all kW and kWh used Monday through Friday between 7:00 a.m.

and 12:00 noon, and between 5:00 p.m. and 9:00 p.m.

Winter Shoulder: For all kW and kWh used Monday through Friday hour 6:00 a.m. to 7:00

a.m., hours 12:00 noon to 5:00 p.m. and hour 9:00 pm to 10:00 p.m. and, Saturday through Sunday

6:00 p.m. to 10:00 p.m.



Section 11.02


Page 1 of 3

Twenty-third Revision




in Minnesota

IRRIGATION SERVICE

DESCRIPTIONESCRIPTION RATE

CODE

Option 1: Non-Time-of-Use 31-703

Option 2: Declared Peak 31-704

Option 2: Intermediate 31-705

Option 2: Off-Peak 31-706



APPLICATION OF SCHEDULE: This Irrigation Service is applicable to Customers for pumping

water for irrigation of land during the irrigation season, April 15 through November 1.

RATE:

OPTION 1





6.649 ¢/kWh 4.439 ¢/kWh

R



Section 11.02


Page 2 of 3





in Minnesota

OPTION 2





Declared-Peak 20.141 ¢/kWh 22.209 ¢/kWh

Intermediate 4.384 ¢/kWh 4.236 ¢/kWh



Declared-Peak $0.00 /kW $0.00 /kW


Off-Peak $0.00 /kW $0.00 /kW

R

R

R




Charge.

N

N

N

N

FIXED CHARGE: Customers served under this rate shall pay an annual fixed charge equal to 18%

of the investment of the Company in the extension of lines, including any rebuilding or cost of

Capacity increase in lines or apparatus, necessitated because of the irrigation pumping load.

Alternatively, Customers may prepay the installation and cost of the equipment and shall pay an

annual fixed charge equal to 3.5% of the investment of the Company, in lieu of the 18% annual

fixed charge.

In either option, equipment remains the property of Otter Tail Power Company. This charge shall be

reviewed if additional Customers are connected to the extension within five years. The annual fixed

charge will be billed in seven equal monthly installments, May through November of each year.



Customer, unless otherwise noted in this rate schedule. See Sections 12.00, 13.00, and 14.00 of the




Section 11.02


Page 3 of 3





in Minnesota

CHARACTER AND CONDITIONS OF SERVICE: The Company reserves the right to interrupt

this service. As a condition to receiving service at this rate, the Customer shall, when notified to do

so, abide by such restrictions.


WINTER SEASON – APRIL 15 THROUGH MAY 31, AND OCTOBER 1 THROUGH NOVEMBER 1

Declared-Peak: For all kW and kWh used during the hours declared.


Off-Peak: For all kW and kWh used Monday through Saturday from10:00 p.m. to 6:00 a.m., and all day Sunday.

SUMMER SEASON - JUNE 1 THROUGH SEPTEMBER 30 Declared-Peak: For all kW and kWh used during the hours declared.


Off-Peak: For all kW and kWh used Monday through Saturday from10:00 p.m. to 6:00 a.m., and all

day Sunday.

DETERMINATION OF DEMAND: The Billing Demand shall be the maximum Demand in kW

registered over any period of one hour during the month for which the bill is rendered.

CONTRACT PERIOD AND AGREEMENT: The minimum Contract Period shall be five years.

The Company shall enter into a written agreement with each Customer served at this rate and the

Customer shall agree to pay for service at this rate for a period of five years because of the

investment of the Customer in pumping and irrigation equipment, and of the Company in the

extension of lines.

If, during the terms of such agreement, the Company shall establish a superseding rate for this

service, the Customer shall be billed at the superseding rate for the balance of the term of the contract

and shall comply with all terms and conditions of the superseding rate. Unless there is additional

investment by the Company, there shall be no change in the amount of the fixed charge during the

term of such agreement regardless of the provisions of any superseding rate.

An agreement will be entered into with each Customer, specifying the investment necessary to supply

service and the fixed charge.



Section 11.03 ELECTRIC RATE SCHEDULEOutdoor Lighting – Energy Only


Fifth Revision




in Minnesota

OUTDOOR LIGHTING – ENERGY ONLY DUSK TO DAWN

DESCRIPTION RATE

CODE Outdoor Lighting – Metered – Energy Only 31-748 Outdoor Lighting - Non-Metered – Energy Only 31-749


APPLICATION OF SCHEDULE: This schedule is applicable to all Customers who choose to own, install, and maintain automatically operated dusk-to-dawn outdoor lighting equipment. Under this schedule, the Company will provide only the dusk to dawn electric Energy.

EQUIPMENT AND SERVICE OWNERSHIP: The Customer or other third party shall install and own all equipment necessary for service beyond the point of connection with Company’s electrical system. The point of connection shall be at the Meter or disconnect switch, for service provided either overhead or underground. The Customer will be responsible for furnishing and installing a master disconnect switch at the point of connection so as to isolate the Customer’s equipment from Company’s electrical system. The Customer’s disconnect switch must be UL-approved or meet National Electric Code standards.

The Customer is responsible for the cost of providing maintenance on the equipment it owns. The Company reserves the right to disconnect the Customer’s equipment from the Company’s electrical system should the Company determine the Customer’s lighting equipment is operated or maintained in an unsafe or improper manner.



Section 11.03 ELECTRIC RATE SCHEDULEOutdoor Lighting – Energy Only


Fifth Revision




in Minnesota

RATE – METERED:

OUTDOOR LIGHTING - ENERGY ONLY Metered Rate Customer Charge per Month: $2.50 Monthly Minimum Bill: Customer Charge Facilities Charge per Month: $0.00 Energy Charge per kWh: 7.666 ¢/kWh

R

RATE – NON-METERED:

OUTDOOR LIGHTING –NON-METERED RATE

Monthly charge = Connected kW x $26.19, where Connected kW is the rated power of the lighting fixture (including ballast)

R


N N N N

MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply and by any Voluntary Rate Riders selected by the Customer, unless otherwise noted in this rate schedule. See Sections 12.00, 13.00 and 14.00 of the Minnesota electric rates for the matrices of riders.

SERVICE CONDITIONS: Company-owned lights shall not be attached to Customer-owned property.

The Company shall have the right to periodically review the Customer’s lighting equipment to verify that the rated power (kW) of the non-metered fixtures is consistent with the Company’s records.



Section 11.04







in Minnesota

OUTDOOR LIGHTING

DUSK TO DAWN

DESCRIPTION RATE

CODE

Outdoor Lighting 31-745

Floodlighting 31-746



APPLICATION OF SCHEDULE: This schedule is applicable to any Customer for

automatically operated dusk to dawn outdoor lighting supplied and operated by the Company.

RATE:

Unit type Lumens Wattage

Monthly

Charge

MV-6* 6000 175 $7.20

MV-6PT* 6000 175 $9.37

MV-11* 11000 250 $13.43

MV-21* 21000 400 $17.40

MV-35* 35000 750 $26.25

MV-55* 55000 1000 $36.08

MH-8 8500 100 $8.14

MH-8PT 8500 100 $11.54

MH-14 14000 175 $15.49

MH-20 20500 250 $17.71

MH-36 36000 400 $17.47

MH-110 110000 1000 $37.35

HPS-9 9000 100 $7.96

HPS-9PT 9000 100 $9.60

HPS-14 14000 150 $12.34

HPS-14PT 14000 150 $12.32

HPS-19 19000 200 $14.31

HPS-23 23000 250 $16.18

HPS-44 44000 400 $20.09

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R



Section 11.04







in Minnesota

Fixture

Unit Type

Monthly

Charge

400 MV-Flood* Mercury Vapor $17.40

400 MA-Flood Metal Additive $20.37

400 HPS-Flood High Pressure Sodium $20.09

1000 MV-Flood* Mercury Vapor $34.30

1000 MA-Flood Metal Additive $37.87

R

R

R

R

R

*Due to the U.S. Government Energy Act of 2005, after August 1, 2008, the Company will no

longer install Mercury Vapor fixtures for new installations.




Minimum Charge.

N

N

N

N



Riders selected by the Customer, unless otherwise noted in this rate schedule. See Sections 12.00,


SEASONAL CUSTOMERS: Seasonal Customers will be billed at the same rate as year-around

Customers, except as follows:

A fixed charge of $27.59 will be billed each Seasonal Customer once per season per fixture in

addition to the rate provided above. The fixed charge will be included in the first bill rendered

for each season.

Each Seasonal Customer will be billed for the number of months each season that the outdoor

lighting fixture is in use, but not less than a minimum of four months, plus the seasonal fixed

charge.

UNDERGROUND SERVICE: If the Customer requests underground service to any outdoor

lighting unit, the Company will supply up to 200 feet of wire and add an additional $2.12 to the

monthly rate specified above. If overhead service is not available, there is no additional charge.

There is no additional charge for the MV-6 PT*, HPS-9 PT or the HPS-14 PT fixtures.



Section 11.04







in Minnesota

EQUIPMENT AND OVERHEAD SERVICE SUPPLIED BY THE COMPANY: The light

shall be mounted on a suitable new or existing Company-owned pole. Any extension beyond one

span of wire will be at the expense of the Customer.

The Company will install, own and operate, and have discretion to replace or upgrade a high

intensity discharge light including suitable reflector or a floodlight including a lamp, bracket for

mounting on wood poles with overhead wiring and photo-electric or other device to control

operating hours. Customers provided with pole top fixtures on fiberglass poles will not receive

overhead power supply. The light shall operate from dusk to dawn. The Company will supply the

necessary electricity and maintenance for the unit.

SERVICE CONDITIONS: Lighting will not be mounted on Customer-owned property. The

light shall be mounted upon a suitable new or existing Company-owned facility. The Company

shall own, operate, and maintain the lighting unit including the pole, fixture, lamp, ballast,

photoelectric control, mounting brackets, and all necessary wiring using the Company's standard

street lighting equipment. The Company shall furnish all electric Energy required for operation of

the unit.

In cases of vandalism or damages, the Company has the discretion to discontinue service and

remove Company equipment.



Section 11.05


Page 1 of 2

Fourteenth Revision




in Minnesota

MUNICIPAL PUMPING SERVICE

DESCRIPTION RATE

CODE





APPLICATION OF SCHEDULE: This schedule is applicable to nonseasonal municipal or other

governmental loads only. It shall apply to electric service for motor driven pumps for use at water

pumping, sewage disposal and treating plants, sewage lift stations and may extend to all lighting and

other electrical requirements incidental to the operation of such plants and lift stations at those

locations. Municipal buildings adjacent to, but not incidental to pumping operation, may not be

served on this rate.

The appropriate rate and monthly minimum shall apply to each Meter in service.

RATE:



Monthly Minimum Bill: Customer + Facilities Charges Customer + Facilities Charges


Maximum kW per Month: $0.14 /kW $0.09 /kW


6.446 ¢/kWh 6.616 ¢/kWh 6.239 ¢/kWh 6.367 ¢/kWh

R




Minimum Charge.

N

N

N

N



Section 11.05


Page 2 of 2

Fourteenth Revision




in Minnesota










ADJUSTMENT FOR EXCESS REACTIVE DEMAND: The Metered Demand may be increased

by 1 kW for each whole 10 kVar of measured Reactive Demand in excess of 50% of the Metered

Demand in kW.




on the largest of the most recent 12 monthly Billing Demands.




Civil Defense – Fire Sirens

Page 1 of 2 Seventh Revision




in Minnesota

CIVIL DEFENSE – FIRE SIRENS


Civil Defense – Fire Sirens 31-843


APPLICATION OF SCHEDULE: This schedule is applicable to separately served civil defense and municipal fire sirens.

RATE:

CIVIL DEFENSE - FIRE SIRENS


Monthly Minimum Bill: Customer Charge Facilities Charge per Month: $0.00

Charge per HP: Summer Winter 59.482 ¢/HP 59.482 ¢/HP


N N N N





Civil Defense – Fire Sirens

Page 2 of 2 Seventh Revision




in Minnesota

DEFINITIONS OF SEASONS: Summer: June 1 through September 30.


OTHER SIREN SERVICE: If the siren is served through a Tariff applicable to the City Hall, fire hall or other tariffed service, no separate billing shall be made for the siren.

SERVICE CONDITIONS: Service shall be provided off of standard Distribution Facilities typical of those in the general area. If it is necessary for the Company to install non-standard Distribution Facilities in order to provide service, the Customer shall be responsible for any additional costs associated with the non-standard facilities. As part of this rate schedule, the Company will provide an extension of up to one span of wire, not to exceed 150 feet. No additional transformer Capacity shall be provided without additional charges. The Company shall have the right to periodically review the Customer’s Civil Defense – Fire Siren rated horsepower (hp) to verify that the rated hp of the non-metered siren is consistent with the Company’s records.




Small Power Producer RiderNet Energy Billing Rate

Page 1 of 3 Thirty-sixth Revision




in Minnesota

SMALL POWER PRODUCER RIDER (Net Energy Billing Rate)


AVAILABILITY: This rider is available to any qualifying facility with generation Capacity not exceeding 40 kW.

CUSTOMER CHARGE: $3.70 per month INTERIM RATE ADJUSTMENT: A 10.95 percent increase will be added to the Customer Charge.

N N

PAYMENT SCHEDULE: Payment per kWh for energy delivered to utility in excess used.

DESCRIPTION ENERGY CREDIT

RATE CODE

Residential 9.55¢ per kWh 31-910 Farm 9.67¢ per kWh 31-930 General Service 9.58¢ per kWh 31-940 Large General Service 9.50¢ per kWh 31-960

SPECIAL CONDITIONS OF SERVICE: The Customer will be required to sign a contract, agreeing to terms and conditions specified for small power producers. The minimum term of the contract is 12 months.

TERMS AND CONDITIONS: The use of this rider requires that special precautions be taken in the design of associated metering and control systems. The following terms and conditions describe these precautions and shall be followed on all Customer-owned small qualifying facilities (SQF).



2. If the SQF is located at a site outside of the Company's service territory and energy is delivered to

the Company through facilities owned by another utility, energy payments will be adjusted downward reflecting losses occurring between the point of metering and the point of delivery.





Page 2 of 3 Thirty-third Revision




in Minnesota

3. A SQF must have a generation Capacity of at least 30 kW to qualify for wheeling by the Company of the SQF output. In the event that the SQF desires, and qualifies for, wheeling by the Company of the SQF output, arrangements will be made subject to special provisions to be determined by all utilities involved. This also applies to SQF's outside the Company's service territory.

4. If required, a separate Meter will be furnished, owned and maintained by the Company to measure

the energy to the Company.

5. The SQF shall make provisions for the installation of Company owned on-site metering. All energy received from and delivered to the Company shall be metered. On site use of the SQF output shall be unmetered for purposes of compensation.

6. The Customer shall pay for any increased Capacity of the Distribution equipment serving him and made necessary by the installation of his Generator.

7. Power and energy purchased by the SQF from the Company shall be billed under the available retail rates for the purchase of electricity.


Generator output must be at the voltage and phase relationship of the existing service or of one mutually agreeable to the Company and the Customer.




interferes with the operation of the Company's equipment or with the equipment of other Company Customers.

11. The Customer is required to follow the Company’s interconnection process, which requires that

prior to installation, a detailed electrical diagram of the Generator and related equipment must be furnished to the Company for its approval for connection to the Company's system. No warranties, express or implied, will be made as to the safety or fitness of the said equipment by the Company due to this approval.







Page 3 of 3 Thirty-second Revision




in Minnesota

13. Equipment shall be provided by the Customer that provides a means of preventing feedback to the Company during an outage or interruption of that system as well as a visible means to disconnect the Generator from the Utility that is readily accessible by Utility employees.

14. The Customer shall install, own, and maintain all equipment deemed necessary by the Company to

assure proper parallel operation of the system.





Small Power Producer RiderSimultaneous Purchase and Sale Billing Rate

Page 1 of 3 Thirty-sixth Revision


Thomas R. Brause



in Minnesota

SMALL POWER PRODUCER RIDER SIMULTANEOUS PURCHASE AND SALE BILLING RATE

DESCRIPTION RATE

CODE Firm Power 31-981 Nonfirm Power 31-984


AVAILABILITY: This rider is available to any qualifying facility with generation Capacity not exceeding 40 kW.

CUSTOMER CHARGE: Firm Power $8.87 per month Nonfirm Power $1.40 per month

INTERIM RATE ADJUSTMENT: A 10.95 percent increase will be added to the Customer Charge.

N N


DESCRIPTION SUMMER CAPACITY

CREDIT

WINTER CAPACITY

CREDIT

SUMMER ENERGY CREDIT

WINTER ENERGY CREDIT

Firm and Non-Firm Power 1.57¢ per kWh 1.57¢ per kWh 3.707¢ per kWh 3.657¢ per kWh

SPECIAL CONDITIONS OF SERVICE: 1. The Customer will sign a contract agreeing to terms and conditions specified for small power

producers. The minimum term of the contract is 12 months.

2. If the qualifying facility does not meet the 65% on-peak Capacity requirement in any month,

the compensation will be the energy portion only.







Thomas R. Brause



in Minnesota

DEFINITIONS: Firm Power: Energy delivered by the qualifying facility to the utility with at least a 65 percent on-peak Capacity factor in the month.

Capacity Factor: The number of Kilowatt-Hours delivered during a period divided by the product of (the maximum one hour delivered Capacity in Kilowatts in the period) times (the number of hours in the period). Summer: June 1 through September 30. Winter: October 1 through May 31.

TERMS AND CONDITIONS: The use of this rate requires that special precautions be taken in the design of associated metering and control systems. The following terms and conditions describe these precautions and shall be followed on all Customer-owned small qualifying facilities (SQF).



2. If the SQF is located at a site outside of the Company's service territory and energy is delivered to the Company through facilities owned by another utility, energy payments will be adjusted downward reflecting losses occurring between the point of metering and the point of delivery.


Company of the SQF output. In the event that the SQF desires, and qualifies for, wheeling by the Company of the SQF output, arrangements will be made subject to special provisions to be determined by all utilities involved. This also applies to SQF's outside the Company's service territory.




energy received from and delivered to the Company shall be metered. On-site use of the SQF output shall be unmetered for purposes of compensation.

6. The Customer shall pay for any increased Capacity of the Distribution equipment serving him

and made necessary by the installation of his Generator.







Thomas R. Brause



in Minnesota








interferes with the operation of the Company's equipment or with the equipment of other Company Customers.

11. The Customer is required to follow the Company’s interconnection process, which requires

that prior to installation, a detailed electrical diagram of the Generator and related equipment must be furnished to the Company for its approval for connection to the Company's system. No warranties, express or implied, will be made as to the safety or fitness of the said equipment by the Company due to this approval.



13. Equipment shall be provided by the Customer that provides a means of preventing feedback to

the Company during an outage or interruption of that system as well as a visible means to disconnect the Generator from the Utility that is readily accessible by Utility employees.







Small Power Producer RiderTime of Day Purchase Rates

Page 1 of 4 Thirty-seventh Revision




in Minnesota

SMALL POWER PRODUCER RIDER TIME OF DAY PURCHASE RATES

DESCRIPTION RATE

CODE Firm Power On-Peak Off- Peak

31-982 31-985

Nonfirm Power On-Peak Off-Peak

31-983 31-986


AVAILABILITY: This rider is available to any qualifying facility with generation Capacity of 100 kW or less, and available to qualifying facilities with Capacity of more than 100 kW if firm power is provided.



INTERIM RATE ADJUSTMENT: A 10.95 percent increase will be added to the Customer Charge.

N N


DESCRIPTION CAPACITY PAYMENT

(ON-PEAK ONLY)

ENERGY CREDIT

ON-PEAK

ENERGY CREDIT OFF-PEAK

Summer (Firm Power and Non-Firm Power) 3.45¢ per kWh 4.486¢ per kWh 3.093¢ per kWh Winter (Firm Power and Non-Firm Power) 3.45¢ per kWh 4.354¢ per kWh 3.058¢ per kWh

SPECIAL CONDITIONS OF SERVICE: 1. The Customer will sign a contract agreeing to terms and conditions specified for small

power producers. The minimum term of the contract is 12 months.









in Minnesota

2. If the qualifying facility does not meet the 65% on-peak Capacity requirement in any month, the compensation will be the energy portion only.

DEFINITIONS:

Firm Power: Energy delivered by the qualifying facility to the utility with at least a 65 percent on-peak Capacity factor in the month.

Capacity Factor: The number of Kilowatt-Hours delivered during a period divided by the product of (the maximum one hour delivered Capacity in Kilowatts in the period) times (the number of hours in the period).

Summer On-Peak: June 1 through September 30 including those hours from 8:00 a.m. to 10:00 p.m. Monday through Friday, excluding holidays.

Winter On-Peak: October 1 through May 31 including those hours from 7:00 a.m. to 10:00 p.m. Monday through Friday, excluding holidays.

Holidays: New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day.

TERMS AND CONDITIONS: The use of this rate requires that special precautions be taken in the design of associated metering and control systems. The following terms and conditions describe these precautions and shall be followed on all Customer-owned small qualifying facilities (SQF).




delivered to the Company through facilities owned by another utility, energy payments will be adjusted downward reflecting losses occurring between the point of metering and the point of delivery.


Company of the SQF output. In the event that the SQF desires, and qualifies for, wheeling by the Company of the SQF output, arrangements will be made subject to special provisions to be determined by all utilities involved. This also applies to SQF's outside the Company's service territory.









in Minnesota

4. If required, a separate Meter will be furnished, owned and maintained by the Company to measure the energy to the Company.

5. The SQF shall make provisions for the installation of Company owned on-site metering.

All energy received from and delivered to the Company shall be metered. On-site use of the SQF output shall be unmetered for purposes of compensation.

6. The Customer shall pay for any increased capacity of the distribution equipment serving

him and made necessary by the installation of his Generator.

7. Power and energy purchased by the SQF from the Company shall be billed under the

available retail rates for the purchase of electricity.





10. The Company reserves the right to disconnect the Customer's Generator from its system if

it interferes with the operation of the Company's equipment or with the equipment of other Company Customers.

11. The Customer is required to follow the Company’s interconnection process, which

requires that prior to installation, a detailed electrical diagram of the Generator and related equipment must be furnished to the Company for its approval for connection to the Company's system. No warranties, express or implied, will be made as to the safety or fitness of the said equipment by the Company due to this approval.



13. Equipment shall be provided by the Customer that provides a means of preventing

feedback to the Company during an outage or interruption of that system as well as a visible means to disconnect the Generator from the Utility that is readily accessible by Utility employees.









in Minnesota







Distributed Generation Service Rider

Page 1 of 6 Fifth Revision




in Minnesota

DISTRIBUTED GENERATION SERVICE RIDER


Distributed Generation Service Rider 31-931


AVAILABILITY: The rider for Distributed Generation is available between any Customer, who has entered into the “State of Minnesota Interconnection Agreement for the Interconnection of Extended Parallel Distributed Generation Systems with Electric Utilities,” and the Company for the interconnection and operation of on-site extended parallel distributed generation system, as follows.

1. The distributed generation system must be fueled by natural gas or a renewable fuel, or

another similarly clean fuel or combination of fuels of no more than 10 MW of interconnected Capacity at a point of common coupling to Company’s Distribution system. The distributed generation facility must be an operable, permanently installed or mobile generation facility serving the Customer receiving retail electric service at the same site.

2. The interconnection and operation of distributed generation systems at each point of

common coupling shall be considered as a separate application of the Rider.

3. Service hereunder is subject to Company’s ”Guidelines for Generation, Tie-Line, and

Substation Interconnections” and the “State of Minnesota Interconnection Process for Distributed Generation Systems,” copies of which are available at the Company’s web page at http://www.otpco.com. The requirements, terms and conditions contained in the “State of Minnesota Interconnection Process for Distributed Generation Systems” supersede the requirements, terms and conditions contained in the Company’s “Guidelines for Generation, Tie-Line, and Substation Interconnections” in the event of an inconsistency between the two documents.

4. All provisions of the applicable standard service schedule shall apply to distributed

generation service under this Rider except as noted below.









in Minnesota

In lieu of service under this Rider, Customer and Company may pursue reasonable transactions outside the Rider; or Customer may take service, as applicable, under Company’s Small Power Producer Riders as established under Minnesota Rules Chapter 7835 – Cogeneration and Small Power Production.

SERVICES: Services provided under this Rider may include services from the Company to Customer and from Customer to Company. The following rates, charges, credits and payments are applicable for such services in addition to all applicable charges for service being taken under Company’s rate schedules, as noted in the “Availability” section above.

Customer Charge: $11.57 per month for Customer Account expense Distribution Maintenance Charge ($/Month): This charge will be based upon Customer- specific Distribution Facilities required for operation of the distributed generation system.

Distribution Maintenance Charge ($/Month) = (Excess Distribution Facilities Investment x 0.344%)

Monthly Minimum Charge: The sum of the Customer Charge plus the Distribution Maintenance Charge.


N N N N

Services from Company to Customer

Interconnection Services

Interconnection services include services such as engineering/design studies, Company system upgrades and testing. The technical requirements, addressing the safe and reliable interconnection of the Customer’s equipment to the Company’s system are described in the State of Minnesota Interconnection Process for Distributed Generation Systems, a copy of which is available at the Company’s web page at http://www.otpco.com.

Supply Services Supply services include standby services such as Scheduled Maintenance, Backup and Supplemental service as provided under Company’s Standby Service, Section 11.01.

Transmission Services The Company will arrange the following services, as required, to the Customer without









in Minnesota

additional charge. The Company reserves the right to monitor the impacts of these costs and if found to be inequitable to other ratepayers, the Company will seek regulatory approval to develop appropriate charges for these services.

Transmission Services can include reservation and delivery of Capacity and energy on either a firm or non-firm basis and those ancillary services that are necessary to support the transmission of Capacity and energy from resources to loads while maintaining reliable operation over transmission providers’ transmission system. These ancillary services include services such as scheduling, system control and dispatch service, reactive supply and voltage control from generation sources service, regulation and frequency response service, Generator imbalance service, operating reserve – spinning reserve and operating reserve – supplemental reserve.

Distribution Services Distribution services include reservation and delivery of Capacity and energy and those indirect services that are necessary to support the delivery of Capacity and energy over Company’s Distribution system. These indirect services include allocated support services or expenses such as operation and maintenance, Customer accounting, Customer service and information, administrative and general costs, depreciation, interest and taxes. These costs are contained in the Company’s Standby Service, Section 11.01 and any of the other approved Company Tariffs. The Company reserves the right to monitor the impacts of these costs and if found to be inequitable to ratepayers, the Company will seek regulatory approval to develop appropriate charges for these services.

Services from Customer to Company

Capacity/Energy Customer may sell all of the energy produced by the distributed generation system to the Company, use all the distributed generation energy to meet its own electrical requirements, or use a portion of the energy from the distributed generation system to meet its own electrical needs and sell the remaining energy to the Company.

If the Customer offers to sell energy to the Company, then all such energy and/or Capacity offered will be purchased by the Company under the rates, terms and conditions for such purchases as established by the Company under this Rider or under other mutually agreeable arrangements between the Company and the Customer.

Capacity and/or energy payments shall be based on Company’s annual calculation of avoided energy and Capacity costs. The Capacity credits in effect at the time Customer enters into a power purchase agreement with Company shall remain in effect for the length









in Minnesota

of the agreement. Energy payments for use under the power purchase agreement shall reflect the current schedule. The Company’s avoided energy costs shall include consideration of the actual value to the Company or avoided costs associated with renewable energy credits or emissions credits. Customer may receive either renewable credits or tradable emission credits but not both. Upon written request by Customer and after signing a non-disclosure agreement, Company shall provide Customer the current schedule of Capacity and energy credits.

Distribution Payments Distribution payments to Customer equal the Company’s avoided Distribution costs resulting from the installation and operation of the distributed generation system. Upon written request by Customer and after signing a non-disclosure agreement a list of substation areas or feeders that could be likely candidates for Distribution credits as determined through the Company’s normal Distribution planning process. Upon receiving an application from Customer for the interconnection and operation of a distributed generation system, Company shall perform an initial screening study to determine if the project has the potential to receive Distribution payments. Customer shall be responsible for the cost of such screening study. If Company’s study shows that there exists potential for Distribution payments, Company shall, at its own expense, pursue further study to determine the Distribution payment.

Emission Payments Any emission payments shall be included in the development of the Company’s avoided energy costs and shall equal the value of any revenues received by the Company from the emissions credit. Customer may receive either renewable credits or tradable emission credits but not both.

Renewable Energy Credits Customer who installs a renewable DG facility shall be paid (1) the Company’s regular avoided cost and (2) for the transfer of the property rights to the Company of the renewable energy attributes (or renewable energy credits in the event of the development of a Commission-approved renewable energy tracking system) associated with the generation of renewable energy, a Renewable Resource Premium. Any renewable energy attributes (or renewable energy credits in the event of the development of a Commission-approved renewable energy tracking system) associated with Customer generated energy used on-site and not delivered to the Company will remain with the Customer who owns the generator. The Company has the option to negotiate with the Customer regarding purchases of the renewable energy attributes (or renewable energy credits in the event of the development of a Commission-approved renewable energy tracking system) associated with the Customer’s on-site usage.









in Minnesota

Line Loss Credits If Customer makes a written request to the Company to provide a specific line loss study, at the Customer’s expense regardless of the study’s outcome, Customer may be eligible for additional line loss credits if the study supports such credits.

DEFINITIONS: Definitions associated with Customer generation systems can be found in Attachment 1 of Standby Service, Section 11.01.

The following terms and conditions apply to this Rider (specific conditions are elaborated upon in Company’s Technical Handbook):


1. Company will install all metering equipment necessary to monitor services provided to ensure adequate measurements are obtained to support necessary application of rates, charges, credits and payments. Customer will be charged an up-front contribution in aid of construction for the installed cost of such metering equipment.

2. The Customer will be compensated monthly for all energy delivered to Company. The schedule for these payments is subject to annual review.

3. The Customer shall make provisions for the installation of Company owned on-site

metering. All energy received from and delivered to the Company shall be metered. On-site use of the distributed generation system output shall be unmetered for purposes of compensation. The Company may require metering of the generation output.

4. The Customer shall pay for all interconnection costs incurred by the Company, made

necessary by the installation of the distributed generation system. 5. Power and energy purchased by the Customer from the Company shall be billed under

the available retail rates for the purchase of electricity. 6. The Generator output must be compatible with the Utility system. The Customer's 60-

hertz Generator output must be at the voltage and phase relationship of the existing service or of one mutually agreeable to the Company and the Customer.











in Minnesota

8. The Company reserves the right to disconnect the Customer's Generator from its system if the Generator or related equipment interferes with the operation of the Company’s equipment or with the equipment of other Company Customers.

9. Prior to installation, a detailed electrical diagram of the Generator and related

equipment must be furnished to the Company for its approval for connection to the Company’s system. No warranties, express or implied, will be made as to the safety or fitness of the said equipment by the Company due to this approval.


include, among other provisions, a minimum term of service. 11. Equipment shall be provided by the Customer that provides a positive means of

preventing feedback to the Company during an outage or interruption of that system as well as a visible means to disconnect the Generator from the Utility that is readily accessible by Utility employees.






Section 14.01


Page 1 of 2

Twenty-first Revision




in Minnesota

WATER HEATING CONTROL RIDER

DESCRIPTION RATE

CODE

Separately Metered Water Heating Control Service 31-191

Water Heating Credit Control Service 31-192



AVAILABILITY: This rider is available for Customers with electric water heaters requesting

controlled service; refer to Section 14.00 for the Voluntary Riders – Availability Matrix.

RATE:

SEPARATELY METERED WATER HEATING CONTROL SERVICE - 191





6.067 ¢/kWh 6.476 ¢/kWh

R

WATER HEATING CREDIT CONTROL SERVICE - 192

Monthly Credit: $4.00




Minimum Charge. This Interim Rate Adjustment only applies to Separately Metered Water

Heating Control Service rate 191.

N

N

N

N

N



Section 14.01


Page 2 of 2

Twenty-first Revision




in Minnesota


modified by any Mandatory Rate Riders that must apply and by any Voluntary Rate Riders selected

by the Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00 and 14.00 of the


TERMS AND CONDITIONS FOR SEPARATELY METERED WATER HEATING

CONTROL SERVICE - RATE 191: Service under this rate shall be supplied through a separate

Meter.

TERMS AND CONDITIONS FOR WATER HEATING CREDIT CONTROL SERVICE -

RATE 192: The Customer will be compensated by receiving the water heating credit. The credit

will be applied on the Customer’s Account, except the credit shall not reduce the monthly billing to

less than the Monthly Minimum Bill.



schedule recovery time following control periods that approach 14 hours.





metering and/or control equipment.



Section 14.02


Page 1 of 5

Fifth Revision




in Minnesota

REAL TIME PRICING RIDER

N

N

DESCRIPTION RATE

CODE





General Rules and Regulations govern use under this rider.

AVAILABILITY: This rider is available on a voluntary basis and is limited to 20 Customers,

who have maintained a measured Demand of at least 200 kW during the historical period used

for Customer Baseline Load (“CBL”) development. Priority will be established based on the date

that an agreement is executed by both the Customer and the Company.





selected by the Customer, unless otherwise noted in this schedule. See Sections 12.00, 13.00 and

14.00 of the Minnesota electric rates for the matrices of riders.

ADMINISTRATIVE CHARGE: An Administrative Charge in the amount of $199 will be


associated with real-time pricing, plus any other applicable Tariff charges.

TERM OF SERVICE: Service under this rider shall be for a period not less than one year. The

Customer shall take service under this rider by either signing new electric service agreements

with the Company or by entering into amendments of existing electric service agreements. A

Customer who voluntarily cancels service under this rider is not eligible to receive service again

under this rider for a period of one year.

PRICING METHODOLOGY: Hourly prices are determined for each day based on

projections of the hourly system incremental costs, losses according to voltage level, hourly

outage costs (when applicable), and profit margin.



Section 14.02


Page 2 of 5

Fifth Revision




in Minnesota

CUSTOMER BASELINE LOAD: The Customer Baseline Load is specific to each Real Time

Pricing (“RTP”) Customer and is developed using a 12-month period of hourly (8,760) Energy

levels (kWh) as well as the corresponding twelve monthly Billing Demands based on the

Customer's rate schedule under which it was being billed immediately prior to taking service

under the RTP Rider. The Customer's CBL must be agreed to in writing by the Customer as a

precondition of receiving service under this rider.

The Customer's CBL is a representation of its typical pattern of electricity consumption and is

derived from historical usage data. The CBL is used to produce the Standard Bill and from

which to measure changes in consumption for purposes of billing under the RTP rider.

STANDARD BILL: The Standard Bill is calculated by applying the charges in the rate

schedule under which the Customer was being billed immediately prior to taking service under

the RTP rider to both the Customer's CBL Demand (adjusted for Reactive Demand) and the CBL

level of Energy usage for each month of the RTP service year. The Company will immediately

adjust a Customer’s Standard Bill to reflect any changes which are approved by the Minnesota

Public Utilities Commission to the applicable rate schedule or resource adjustment.

BILL DETERMINATION: A Real Time Pricing bill will be rendered after each monthly

billing period. The bill consists of an Administrative Charge, a Standard Bill, a charge (or

credit) for consumption changes from the CBL, and an excess Reactive Demand charge/credit.

The monthly bill is calculated using the following formula:

RTP Bill Mo = Adm. Charge + Std BillMo + Consumption Changes from

CBLHr + Excess Reactive Demand

Where:

RTP BillMo = Customer's monthly bill for service under this Rider

Adm. Chg. = See Administrative Charge section below

Std. BillMo = See Standard Bill section above

Consumption Changes From CBL = ∑ {PriceHr x {LoadHr - CBLHr}}

Excess Reactive Demand = See Excess Reactive Demand section below

∑ = Sum over all hours of the monthly billing period

PriceHr = Hourly RTP price as defined under Pricing Methodology

LoadHr = Customer's actual load for each hour of the billing period

CBLHr = Customer's CBL Energy usage for each hour of the billing period



Section 14.02


Page 3 of 5

Fifth Revision




in Minnesota

CONSUMPTION CHANGES FROM CBL: Hourly RTP prices are applied only to the

difference, determined in kWhs for each hour of the billing period, between the Customer's actual

Energy usage and its CBL Energy usage.

EXCESS REACTIVE DEMAND: The Reactive Demand shall be the maximum kVar

registered over any period of one hour during the month for which the bill is rendered. A

separate charge or credit will be made on the bill to reflect incremental changes from the Reactive

Demand used in the Standard Bill calculation.

DETERMINATION OF THE CBL:

1. Development of the Customer's CBL.

For a Customer who elects to take service under this RTP rider, the Company and the

Customer will develop a CBL using hourly load data from a representative 12-month

period. The representative hourly load data to be used will be historical data that

originates within two years (24 months) of the date that the Customer begins receiving

service under the RTP rider.

In situations where hourly data are not available for a particular Customer, a CBL will

be made by using available aggregate metered usage data and load shapes from

Customers with similar usage patterns along with engineering and operating data

provided by the Customer and which is verified by the Company.

2. Calendar Mapping of the Base-Year CBL to the RTP service year.

To provide the Customer with the appropriate CBL for each day of the RTP service

year, each day of the base-year CBL is calendar-mapped to the corresponding day of

the RTP service year. Calendar-mapping is a day-matching exercise performed to

assure that Mondays are matched to Mondays, Tuesdays are matched to Tuesdays,

holidays to holidays, and so forth. Calendar-mapping also reflects Customer

shutdown schedules. Calendar-mapping is performed prior to each year of RTP

service, after any necessary adjustments (as defined below) are made to the CBL.



Section 14.02


Page 4 of 5

Fifth Revision




in Minnesota

CBL ADJUSTMENTS: In order to assure that the CBL accurately reflects the Energy that the

Customer would consume on its otherwise applicable rate schedule, adjustments to the CBL shall

be made for:

1. The installation of permanent Energy efficiency measures as a result of

participation in the Company’s Conservation Improvement Project or other

verifiable conservation or technology efficiency improvement measures. At any

time during the RTP service year, Customers can request that CBL adjustments be

made to reflect efficiency improvements and that the adjustment coincide with the

time of the installation or change-out.

2. The permanent removal of Customer equipment or a change to operating

procedures that results in a significant and permanent reduction of electrical load.

At any time before or during the RTP service year, the Company will make

adjustments to the CBL to coincide with the time that the equipment is removed or

changes to operating procedures.

3. The permanent addition of Customer equipment that has been or will be made

prior to the initial RTP service year is based upon known changes in Customer

usage and/or Demand that are not directly related to the introduction of RTP.

4. One-time, extraordinary events such as a tornado or other natural causes or

disasters outside the control of the Customer or the Company. In these cases, the

Company will make adjustments to the CBL as warranted by the circumstance.

CBL RECONTRACTING: RTP Customers, at the time of initial subscription and during future

re-subscription periods, shall select a recontracting Adjustment Factor that will be used in the

CBL adjustment rule defined below for the next RTP service year. The Adjustment Factor shall

be a number between zero and one inclusive.

After taking service under the RTP rider for one full year, the CBL for the second (and

subsequent) year(s) of RTP service will be based on both the CBL and the actual load. CBLs will

be developed for subsequent years based upon the following general rule:

CBLt+1 = CBLt + {Adjustment Factor x ( Actual loadt - CBLt )}



Section 14.02


Page 5 of 5

Fifth Revision




in Minnesota

PRICE NOTIFICATION: The Company shall make available to Customers, no later than 4:00

p.m. (Central Time) of the preceding day, hourly RTP prices for the next business day. Except

for unusual periods where an outage is at high risk, the Company will make prices for Saturday

through Monday available to Customers on the previous Friday. More than one-day-ahead

pricing may also be used for the following holidays: New Year’s Day, Memorial Day,

Independence Day, Labor Day, Thanksgiving, and Christmas.

Because high-outage-risk circumstances prevent the Company from projecting prices more than

one day in advance, the Company reserves the right to revise and make available to Customers

prices for Sunday, Monday, any of the holidays mentioned above, or for the day following a

holiday. Any revised prices shall be made available by the usual means no later than 4:00 p.m. of

the day prior to the prices taking effect.

The Company is not responsible for a Customer's failure to receive or obtain and act upon the

hourly RTP prices. If a Customer does not receive or obtain the prices made available by the

Company, it is the Customer's responsibility to notify the Company by 4:30 p.m. (Central Time)

of the business day preceding the day that the prices are to take effect. The Company will be

responsible for notifying the Customer if prices are revised.

SPECIAL PROVISIONS:

1. If there is a change in the legal identity of the Customer receiving service under

this RTP rider, service shall be terminated unless the Company and the Customer make other

mutually agreeable arrangements.

2. All equipment to be served must be of such voltage and electrical characteristics so

that it can be served from the circuit provided for the main part of the load and so that the

electricity used can be properly measured by the Meter ordinarily installed on such a circuit. If

the equipment is such that it is impossible to serve from existing circuits, the Customer must

provide any necessary transformers, auto transformers, or any other devices so that connection

can be made to the circuit provided by the Company.

3. If the Customer's actual load exceeds the CBL by an amount that requires the

Company to install additional facilities to serve the Customer, the Customer will be responsible

for any and all costs incurred by the Company to install the facilities.



Section 14.03


Page 1 of 6

Seventh Revision




in Minnesota

LARGE GENERAL SERVICE RIDER


Fixed Rate Energy Pricing 31-648 31-649

System Marginal Energy Pricing 31-642 31-645

Short-term Marginal Capacity Purchases 31-643 31-646

Short-term Marginal Capacity Releases 31-644 31-647


AVAILABILITY: This rider is available at the request of Customers who take service under the rate schedules listed in the Application Section of this Tariff and have either (Option 1) a metered Demand of at least 1 MW, or (Option 2) a Total Coincident Demand of at least 10 MW for multiple, non-contiguous facilities that function in series.

ADMINISTRATIVE CHARGE: An Administrative Charge in the amount of $199.00 will be


associated with this rider.

INTERIM RATE ADJUSTMENT: A 10.95 percent increase will be added to the Administrative Charge, Demand Charge and Energy Charge for Fixed Rate Energy Pricing rates 648 and 649.

N N N

MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply and by any Voluntary Rate Riders selected by the Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00 and 14.00 of the Minnesota electric rates for the matrices of riders.

ELECTRIC SERVICE AGREEMENT: For service under this rider, the Company may, at its

discretion, require a written electric service agreement (“ESA”) between the Company and the

Customer that sets forth, among other things, the Customer’s Billing Demand, Firm Demand, and

Baseline Demands.

FIXED RATE ENERGY PRICING:

Background: Certain Company industrial and Commercial Customers have ESAs that designate, among other things, a Billing Demand, Baseline Demand(s) and a Firm Demand. With Baseline Demand(s), the Company agrees to provide and the Customer agrees to purchase all of its Energy requirements at rates set forth in the Customer’s applicable rate



Section 14.03


Page 2 of 6

Seventh Revision




in Minnesota

schedule and/or a negotiated rate subject to Commission approval. Setting Firm and Baseline Demands benefit both the Company and the Customer. With Firm Demands, the Company is able to curtail participating Customers’ load to predetermined levels which allows the Company to more accurately forecast its native load Capacity and Energy requirements. Baseline Demands assure the Customer a fixed price for Energy up to the Baseline Demand(s) and the ability to purchase Energy above the Baseline Demand(s) at rates set forth in the Customer’s applicable rate schedule and/or a negotiated Energy rate subject to

Commission approval.

Energy: The Customer’s monthly rate for Energy will be determined in two parts: (1)

Energy consumed up to and including the Baseline Demand(s), and (2) Energy consumed

above the Baseline Demand. The price (rate) for Energy consumed up to and including the

Baseline Demand(s) will be determined by multiplying the Customer’s metered Energy

consumption by the Energy rate provided in the rate schedule applicable to the Customer

and/or a negotiated rate subject to Commission approval. The monthly rate for Energy

consumed above the Baseline Demand(s) will be determined by multiplying the Customer’s

metered Energy consumption by the Energy rate provided in the rate schedule applicable to

the Customer and/or a negotiated Energy rate subject to Commission approval.

Demand: A Customer’s monthly rate for Demand shall be determined by multiplying the

Customer’s Billing Demand by the Demand rate provided in the rate schedule applicable to

the Customer and/or a negotiated Demand rate subject to Commission approval.

SYSTEM MARGINAL ENERGY PRICING:

Background: Certain Company industrial and Commercial Customers have ESAs that designate, among other things, a Billing Demand, Baseline Demands and a Firm Demand. With Baseline Demands, the Company agrees to provide and the Customer agrees to purchase its Energy requirements up to the Baseline Demand(s) at rates set forth in the Customer’s applicable rate schedule. Setting a Firm and Baseline Demands benefits both the Company and the Customer. With Firm Demands, the Company is able to curtail participating Customers’ load to predetermined levels which allows the Company to more accurately forecast its native load Capacity and Energy requirements. Baseline Demands assure the Customer a fixed price for Energy up to the Baseline Demand(s) and the ability to purchase Energy above the Baseline Demand(s) on a “real time” basis, which can be higher or lower than the rates set forth in the applicable rate schedule. Accordingly, a Customer can adjust its Energy consumption above the Baseline Demand(s) according to the value the Customer places on that Energy in real-time.

Energy: A Customer’s monthly rate for Energy will be determined in two parts: (1) Energy consumed up to and including the Baseline Demand(s), and (2) Energy consumed above the Baseline Demand(s). The price (rate) for Energy consumed up to and including the Baseline



Section 14.03


Page 3 of 6

Seventh Revision




in Minnesota

Demand(s) will be determined by multiplying the Customer’s metered Energy consumption by the Energy rate provided in the rate schedule applicable to the Customer. The monthly rate for Energy consumed above the Baseline Demand(s) will be determined by multiplying the Customer’s metered Energy consumption by the Company’s System Marginal Energy Price.

System Marginal Energy Price Notification: No later than 4:00 p.m. (Central Time) of the preceding day, the Company shall give its best efforts to make available to Customers the System Marginal Energy Price for the next business day. System Marginal Energy Prices for Saturday through Monday will be made available, whenever possible, the previous Friday. The Company may deviate from this procedure in abnormal operating conditions and for the following holidays: New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving, and Christmas.

The Company is not responsible for a Customer’s failure to receive or obtain and act upon the System Marginal Energy Prices. If a Customer does not receive or obtain the prices made available by the Company, it is the Customer’s responsibility to notify the Company by 4:30 p.m. of the business day preceding the day the prices are to take effect. The Company reserves the right to revise its System Marginal Energy Price at any time prior to Customer’s acceptance and will be responsible for notifying the Customer of such revised prices.

Demand: A Customer’s monthly rate for Demand shall be determined by multiplying the Customer’s Billing Demand by the Demand rate provided in the rate schedule applicable to the Customer.

SHORT-TERM MARGINAL CAPACITY PURCHASES:


Marginal Capacity: Where the Customer requests additional Capacity on a Short-term

basis, the Customer may reserve additional Capacity, to the extent available, from the

Company’s system, or request the Company to purchase available Capacity in the market

(the “Marginal Capacity”). Where the Company is unable to provide Marginal Capacity

within 60 days of the Customer’s notice under Section 4.3, the Customer may seek Marginal



Section 14.03


Page 4 of 6

Seventh Revision




in Minnesota

Capacity indirectly from a third party. The Company would work with the third party to

effectuate the purchase. In each case, the Company agrees to give to the Customer its best

effort in seeking the Marginal Capacity. The Marginal Capacity purchase must be for a

minimum of 1000 kW (1MW) and will include charges for Transmission Service, a Reserve

Margin and applicable administrative and other costs. The Company does not guarantee the

availability of Capacity or Transmission Service for the Marginal Capacity.

Compensation: The rate for the Marginal Capacity shall be as negotiated by the parties.

Where the Marginal Capacity is provided by a third party, the compensation for such

Marginal Capacity shall be as negotiated between the Customer, the Company and the third-

party, and the Company shall be compensated for its efforts in assisting the transaction.

Purchase Period: The Purchase Period shall be either a Summer Season(s) or Winter Season(s), or combination thereof, unless otherwise agreed to by the Company and Customer, but in no case will be less than one (1) month.

Effect of Marginal Capacity: By purchasing Marginal Capacity, the Customer agrees that its Firm Demand, as established in the ESA, will be increased throughout the Purchase Period by the amount of Marginal Capacity purchased. The Customer will continue to be billed for the Billing Demand established in the ESA. For all eligible Customers not taking service under Rate Schedule 14.02 (the Real Time Pricing Rider), Energy consumed above the Baseline Demand(s) will continue to be billed at the System Marginal Energy Price. Real Time Pricing Rider Customers will continue to be billed under the provisions of Rate Schedule 14.02.

SHORT-TERM MARGINAL CAPACITY RELEASES:


Released Capacity: Where the Customer requests to release Capacity on a short-term basis, the Customer may release some but not all of the Capacity (the “Released Capacity”), and the Company agrees to give its best effort in finding a purchaser of the Released Capacity. Where the Company is unable or unwilling to purchase the Released Capacity for its own



Section 14.03


Page 5 of 6

Seventh Revision




in Minnesota

use or to resell it off-system at wholesale, or otherwise find a purchaser, within 60 days of the Customer’s notice under Section 4.3, the Customer may have a third party market the Capacity. The Company would work with the third-party to effectuate the sale of the Released Capacity. The Released Capacity must be a minimum of 1000 KW (1MW).

Compensation: As compensation for the Released Capacity, the Customer shall receive a credit or payment during any billing month in which Customer and Company have cooperated to make a Released term Capacity sale, adjusted to take into account the Company’s applicable administrative and other costs. Where the Company purchases the Released Capacity, the rate will be as negotiated between the Company and the Customer. No credit will be given to the Customer for any Energy sold by the Company under the Released Capacity, and the Customer will have no cost responsibility associated with the sale of such Energy. Where the Released Capacity is marketed by a third party, the compensation for such Released Capacity shall be as negotiated between the Customer, the Company and the third-party, and the Company shall be compensated for its efforts in assisting the Released Capacity transaction.

Release Period: The Release Period shall be either a Summer Season(s) or Winter Season(s), or combination thereof, unless otherwise agreed to by the Company and Customer, but in no case will be less than one (1) month.

Effect of Release Capacity: By selling Released Capacity, the Customer agrees that its Firm Demand, as established in the ESA, will be reduced throughout the Release Period by the amount of Released Capacity. The Customer will continue to be billed for the Billing Demand established in the ESA.

PENALTY FOR INSUFFICIENT LOAD CONTROL: Upon notification from the Company, the Customer shall curtail its Demand to its Firm Demand, as adjusted to take into consideration any Marginal Capacity or Released Capacity. In the event the Customer fails to curtail its load as requested by the Company, the Customer will forfeit any compensation for that period, if any is due. In addition, the Customer shall be responsible for any and all costs and/or penalties incurred by the Company as result of the Customer’s failure to curtail. The duration and frequency of curtailments shall be at the sole discretion of the Company unless otherwise provided in the ESA between the Company and the Customer.

TRANSACTION COSTS: Where the Company gives its best efforts to arrange either a Marginal Capacity purchase or Released Capacity sale but is nonetheless unable to find a market for the Customer, the Company is entitled to its reasonable transaction costs.

NOTIFICATION REQUIRED BY THE CUSTOMER: In order to improve the possibility there will be a market for the Released Capacity or Marginal Capacity available, the Customer shall provide notice of its intent to sell Released Capacity or purchase Marginal Capacity no later than six



Section 14.03


Page 6 of 6

Seventh Revision




in Minnesota

(6) months before the start date of the next applicable Winter Season or Summer Season, the six-month requirement to be waived at the Company’s discretion. COMMUNICATION REQUIREMENTS: The Customer agrees to use Company-specified communication requirements and procedures when submitting any offer for Released Capacity or Marginal Capacity. These requirements may include specific computer software and/or electronic communication procedures.

METERING REQUIREMENTS: Company approved metering equipment capable of providing load interval information is required for Rider participation. The Customer agrees to pay for the additional cost of such metering when not provided in conjunction with existing retail electric service.

LIABILITY: The Company and the Customer agree that the Company has no liability for indirect, special, incidental, or consequential loss or damages to the Customer, including but not limited to the Customer's operations, site, production output, or other claims by the Customer as a result of participation in this Rider.

ENERGY ADJUSTMENT RIDER: Energy consumed up to and including the Baseline Demand(s) is subject to the Energy Adjustment Rider as provided in Section 13.01, or any amendments or superseding provisions applicable thereto. Because Energy consumed above the Baseline Demand(s) is subject to the System Marginal Energy Price and calculated on a real-time basis, it is not subject to the Energy Adjustment Rider as provided for in Mandatory Riders – Applicability Matrix, Section 13.00.

CUSTOMER EQUIPMENT: Customers taking service under this Rider shall provide equipment to maintain a power factor at a level no less than the level in which penalties would be invoked under the Tariff, if applicable.



Section 14.04



Twenty-second Revision




in Minnesota

CONTROLLED SERVICE - INTERRUPTIBLE LOAD

CT METERING RIDER

(Commonly identified as Large Dual Fuel)


CT Metering without ancillary load 31-170 N/A

CT Metering without ancillary load (with short-duration cycling) 31-165 N/A

Penalty 31-881 N/A

CT Metering with ancillary load



CT Metering with ancillary load (with short-duration cycling)






interruptible loads; such loads are primarily the electric heating portion of dual fuel heating systems.

Electric heating systems may include heat pumps. Domestic electric water heating, and/or other

permanently connected approved loads other than the exceptions noted below in Option 2, will be

interrupted during control periods.



Option 1: Electric fans, pumps, and other ancillary equipment used in the distribution of

conditioned air and/or water shall be wired for service through the Customer’s firm service

Tariff.

Option 2: The Company retains the authority to allow a portion of the load used to deliver

conditioned air and/or water to remain on during control periods in situations where 1) it is

functionally or financially unfeasible to separately serve the equipment’s control systems, or

other critical ancillary equipment associated with this load, or 2) if the separation would violate

the manufacturer’s Underwriters Laboratory (UL) approval or other industry recognized

operating standards.



Section 14.04







in Minnesota

During the control period the amount of ancillary load shall not exceed 5% of the metered maximum

Demand measured during any period within the most recent 12 months. (For example, although a

minimal amount of fan and/or pump load may be allowed under this provision, it is not intended to

be applied to larger loads such as the non-conditioned fan load on low-temperature grain drying.)



complete a Controlled Service Agreement acknowledging that the Customer is aware of the potential

for property damage.

RATE:

OPTION 1





Summer Winter

Energy Charge per kWh: 3.603 ¢/kWh 3.893 ¢/kWh

Penalty kWh: 15.230 ¢/kWh 15.530 ¢/kWh



R



Section 14.04







in Minnesota

OPTION 2





Summer Winter


Control Period Demand Charge

per kW: $7.22 /kW $6.07 /kW

R




Charge.

N

N

N

N



Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00 and 14.00 of the Minnesota

electric rates for the matrices of riders.




PENALTY PERIODS – OPTION 1 ONLY: Penalty periods are defined as periods when the

Company signals to interrupt the Customer’s load and the Customer’s equipment does not shed the

load. Installation of a dual register Meter will be at the option of the Company. When a dual register

Meter is installed, penalty usage will be recorded on the penalty register and the total register of the

dual register Meters.



rider.



Section 14.04







in Minnesota




30). Domestic water heating may be controlled up to 14 hours in a 24-hour period, as measured from

midnight to midnight.

DETERMINATION OF FACILITIES CHARGE: The monthly measured Demand will be based

on the maximum 15 consecutive minute period measured by a Demand Meter for the month for

which the bill is rendered. The Facilities Charge Demand shall be based on the greatest of the current

and preceding 11 monthly measured Demands.

DETERMINATION OF CONTROL PERIOD DEMAND – OPTION 2 ONLY: The Billing

Demand measured during the control period for which the bill is rendered shall be the maximum

metered kW for any period of 15 consecutive minutes during the control period.





Section 14.05







in Minnesota

CONTROLLED SERVICE – INTERRUPTIBLE LOAD

SELF-CONTAINED METERING RIDER

(Commonly identified as Small Dual Fuel)

DESCRIPTION RATE

CODE

Self-Contained Metering 31-190

Self-Contained Metering (with short-duration cycling) 31-185

Penalty 31-882




interruptible load; such loads are primarily the electric heating portion of dual fuel heating systems.

Electric heating systems may include heat pumps. Domestic electric water heating and/or other

permanently connected approved loads other than the exceptions noted below, will be interrupted

during control periods. Electric fans, pumps and other ancillary equipment used in the distribution

of conditioned air and/or water shall be wired for service through the Customer's firm service Tariff.

The Company retains the authority to allow a portion of the load to remain on during control periods

in situations where 1) it is unfeasible to separately serve the equipment’s control systems, or other

critical ancillary equipment associated with this load, or 2) if the separation would violate the

manufacturer’s Underwriters Laboratory (UL) approval or other industry recognized operating

standards. Although a minimal amount of fan and pump load may be allowed under this provision,

it is not intended to be applied to larger loads such as the fan load on low temperature grain drying.





complete a Controlled Service Agreement acknowledging that the Customer is aware of the

potential for property damage.



Section 14.05







in Minnesota

RATE:

CONTROLLED SERVICE - INTERRUPTIBLE LOAD – SELF-CONTAINED




Summer Winter


Penalty Charge per kWh: 15.702 ¢/kWh 16.930 ¢/kWh



R




Minimum Charge.

N

N

N

N



Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00 and 14.00 of the









Meters.



Section 14.05







in Minnesota



rider.




30). Domestic water heating may be controlled up to 14 hours in a 24-hour period, as measured

from midnight to midnight.





Section 14.06







in Minnesota

CONTROLLED SERVICE

DEFERRED LOAD RIDER

(Commonly identified as Thermal Storage)

DESCRIPTION RATE

CODE

Deferred Loads 31-197

Deferred Loads (Short Duration Cycling) 31-195

Penalty 31-883




deferred loads that can be served under the limited conditions provided; such loads are primarily

electric water heating and thermal storage.

Deferred loads may include heat pumps, domestic electric water heating, and other permanently

connected loads that can be interrupted.

Electric fans, pumps, and other ancillary equipment used in the distribution of conditioned air and/or

water shall be wired through the Customer’s firm service Meter. The Company retains the authority

to allow a portion of the load to remain on during control periods in situations where 1) it is

unfeasible to separately serve the equipment’s control systems, or other critical ancillary equipment


Laboratory (UL) approval or other industry recognized operating standards. Although a minimal

amount of fan and pump load may be allowed under this provision, it is not intended to be applied to

larger loads such as the fan load on low temperature grain drying.



Section 14.06







in Minnesota

RATE:

CONTROLLED SERVICE - DEFERRED LOAD

Customer Charge per Month:

$2.00




All kWh 5.736 ¢/kWh 6.123 ¢/kWh

Penalty kWh 14.744 ¢/kWh 15.649 ¢/kWh

During the Penalty Period, kWhs used will be measured and billed at the Energy

Charge and Penalty listed above.

R




Minimum Charge.

N

N

N

N



Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00, and 14.00 of the









Meters.



rider.



Section 14.06







in Minnesota



schedule recovery time following control periods that approach continuous 14 hours. Short-duration

cycling is 15-minutes off / 15-minutes on of appropriate cooling equipment during the Summer

Season (June 1-September 30). Domestic water heating may be controlled up to 14 hours in a 24-

hour period, as measured from midnight to midnight.





Section 14.07



Sixth Revision




in Minnesota

FIXED TIME OF SERVICE RIDER

(Commonly identified as Fixed TOS)

DESCRIPTION RATE

CODES

Fixed Time of Service – Self-Contained Metering 31-301

Penalty 31-884

Fixed Time of Service – CT Metering 31-302

Penalty 31-885

Fixed Time of Service – Primary CT Metering 31-303

Penalty 31-886



AVAILABILITY: This rider is available to Customers with permanently connected thermal

storage space heating technologies that are designed and installed with the capability to be

operated under the limitations and terms of this rider.

Electric fans, pumps, and other ancillary equipment used in the distribution of heat shall be

wired through the Customer’s firm service Meter. The Company retains the authority to allow a

portion of the load to remain on during control periods in situations where 1) it is unfeasible to

separately serve the equipment’s control systems, or other critical ancillary equipment


Laboratory (UL) approval or other industry recognized operating standards. Although a

minimal amount of fan and pump load may be allowed under this provision, it is not intended to

be applied to larger loads such as the fan load on lowtemperature grain drying.



Section 14.07



Sixth Revision




in Minnesota

RATE:

FIXED TIME OF SERVICE - Self-Contained Metering




Summer Winter





R

FIXED TIME OF SERVICE – CT Metering




Summer Winter





R



Section 14.07



Sixth Revision




in Minnesota

FIXED TIME OF SERVICE – Primary CT Metering




Summer Winter





R




Minimum Charge.

N

N

N

N









interrupt the Customer’s load and the Customer’s equipment does not shed the load. Installation

of a dual register Meter will be at the option of the Company. When a dual register Meter is

installed, penalty usage will be recorded on the penalty register, and the total register of the dual

register Meters.



Section 14.07



Sixth Revision




in Minnesota



under this rider.

CONTROL CRITERIA: The Customer will receive electric service from 10:00 p.m. until

6:00 a.m. each day. During all other hours, the Customer's load will be controlled.






Off-Peak Electric Vehicle Rider (Off-Peak EV)

Page 1 of 3 First Revision


Thomas R. Brause



in Minnesota

OFF-PEAK ELECTRIC VEHICLE RIDER (Commonly identified as Off-Peak EV)

DESCRIPTION RATE

CODES Off-Peak EV Service – Self-Contained Metering 31-781 Penalty/Unauthorized Use 31-887 Off-Peak EV Service – CT Metering 31-782 Penalty/Unauthorized Use 31-888 Off-Peak EV Service – Primary CT Metering 31-783 Penalty/Unauthorized Use 31-889


AVAILABILITY: This rider is available to Customers to purchase electricity solely for the purpose of recharging an electric vehicle, as defined in Minnesota Statute § 216B.1614, Subd.1. The Company reserves the right, at any time, to require from the Customer the State of Minnesota vehicle registration and/or audit the interconnected facilities to verify customer compliance with Minnesota Statute § 216B.1614 and eligibility for this rate.

RATE:

Off-Peak Electric Vehicle Service – Self-Contained Metering Customer Charge per Month: $1.50 Monthly Minimum Bill: Customer + Facilities Charges Facilities Charge per Month: $3.00 Summer Winter Energy Charge per kWh: 3.110 ¢/kWh 4.809 ¢/kWh Penalty: 5.676 ¢/kWh 3.605 ¢/kWh

During the Penalty Period, kWhs used will be measured and billed at the Energy Charge and Penalty listed above.

R







Thomas R. Brause



in Minnesota

Off-Peak Electric Vehicle Service – CT Metering

Customer Charge per Month: $2.00 Monthly Minimum Bill: Customer + Facilities Charges Facilities Charge per Month: $16.00 Summer Winter Energy Charge per kWh: 3.110 ¢/kWh 4.809 ¢/kWh Penalty: 5.676 ¢/kWh 3.605 ¢/kWh During the Penalty Period, kWhs used will be measured and billed at the Energy Charge and Penalty listed above.

R

Off-Peak Electric Vehicle Service – Primary CT Metering

Customer Charge per Month: $5.00 Monthly Minimum Bill: Customer + Facilities Charges Facilities Charge per Month: $8.00 Summer Winter Energy Charge per kWh: 3.104 ¢/kWh 4.796 ¢/kWh Penalty: 5.670 ¢/kWh 3.592 ¢/kWh During the Penalty Period, kWhs used will be measured and billed at the Energy Charge and Penalty listed above.

R


N N N N

MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply and by any Voluntary Rate Riders selected by the Customer, unless otherwise noted in this rider. See Sections 12.00, 13.00 and 14.00 of the electric rates for the matrices of riders.







Thomas R. Brause



in Minnesota


Summer: June 1 through September 30 Winter: October 1 through May 31

AUTHORIZED PERIODS OF ELECTRIC SERVICE: The Customer will only receive electric service during the authorized periods from 10:00 p.m. until 6:00 a.m. each day. All other hours of electric service are unauthorized and subject to Penalty Periods.

PENALTY PERIODS: Penalty periods are defined as periods when a) Customer utilizes service during unauthorized periods and/or b) the Company signals to interrupt the Customer’s load and the Customer’s equipment does not shed the load. Installation of a dual register Meter will be at the option of the Company. When a dual register Meter is installed, penalty usage will be recorded on the penalty register, and the total register of the dual register Meters.

The penalty provision is not intended as a buy-through option. Under no circumstances should the penalty clause of this rider be interpreted as an approved buy-through option for service under this rider.

EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard metering and control equipment.

1/3 tab

Volume 1

Proposed Notices

********BILL INSERT********

INTERIM CHANGE IN ELECTRIC RATES IN EFFECT APRIL 16, 2016

On February 16, 2016, Otter Tail Power Company asked the Minnesota Public Utilities

Commission (MPUC) for permission to increase its electric rates by approximately $19.3

million, or about 9.8 percent.

In accordance with Minnesota law, the MPUC has suspended our proposed final rates to

allow time to evaluate our request. The MPUC has authorized an interim rate increase of

approximately $19.25 million, or approximately 10.95 percent over current base rates.

This rate increase appears on your bill as “Interim Rate Adj” for service used on and after

April 16, 2016, and applies to the customer charge, energy charge, demand charge,

facilities charge, fixed charge, and the monthly minimum charge.

The MPUC will evaluate our request and make its decision regarding final rates by

December 16, 2016 unless the review period is extended by the MPUC. If final rates are

lower than interim rates, we’ll refund customers the difference with interest. If final rates

are higher than interim rates, we will not charge customers the difference.

The following table shows the average monthly impact of the approved interim and

proposed final rates for an average customer in each of our customer classes. The impact

on an individual customer may be higher or lower depending on the individual

customer’s actual electric consumption.

Average Monthly Electricity Costs

Customer Classification

Monthly Kilowatt-hour

Usage

Previous Monthly

Cost

Approved Interim Change

in Monthly Cost

Proposed Final Change

in Monthly Cost

Residential 810 $83 $9.07 $9.53

Farms 1,991 $193 $21.11 $17.35

General Service 2,618 $247 $27.02 $22.20

Large General Service 231,698 $14,503 $1,588.12 $1,305.30

Irrigation 1,521 $151 $16.56 $28.74

Outdoor Lighting 2,074 $2 $0.23 $0.27

Other Public Authority 3,366 $257 $28.17 $33.45

Controlled Service Water Heating

214 $17 $1.84 $1.93

Controlled Service Interruptible

2,041 $109 $11.95 $12.55

Controlled Service Deferred

2,237 $125 $13.64 $5.92

Why is Otter Tail Power Company asking for an increase at this time?

Our current rates were established in 2011. Since then, we’ve added environmental

technologies and strengthened the system that delivers electricity to you. It’s those

investments paired with an increase in general costs we incur to provide you with electric

service that we need to include in our rates.

What is the process for reviewing Otter Tail Power Company’s request?

In addition to the MPUC review, the Minnesota Department of Commerce – Division of

Energy Resources conducts an investigation of our books and records. The Office of the

Attorney General – Antitrust & Utilities Division may investigate this proposal as well.

Public hearings will be scheduled by the MPUC and overseen by an Administrative Law

Judge. Customers and the public are encouraged to attend the hearings and will have

opportunities to comment on our rate request. Notice of the hearing dates and locations

will be published in local newspapers in our service area, in a flyer enclosed with our

electric service statements, and on our website at: www.otpco.com/MNRateCase.

For more information Visit www.otpco.com/MNRateCase to view the proposed rate schedules and a

comparison of present and proposed rates or visit our General Office during normal

business hours at:




Phone: 800-257-4044

You may also contact the Minnesota Department of Commerce – Division of Energy

Resources at:

85 7th Place East, Suite 500

St. Paul, MN 55101

Telephone: 651-539-1886

FAX: 651-539-1549

You can also search e-dockets at the Department of Commerce website:

https://www.edockets.state.mn.us/EFiling/search.jsp

(Web address case sensitive)

Select 2015 in the year field, enter 1033 in the number field, click on Search, and

the list of documents will appear on the next page.

How to participate

Anyone who wishes to formally intervene in this case should contact:

Administrative Law Judge FIRST AND LAST NAME

Office of Administrative Hearings

600 North Robert Street

St. Paul, Minnesota 55164

Telephone: 651-361-7900

TDD: 651-361-7878


FAX: 651-539-0300

Web: http://mn.gov/oah

You do not need to contact the Administrative Law Judge if you simply want to attend

the public hearings, provide oral comments at the public hearings, or submit comment

letters.

You also may provide comments to the Minnesota Public Utilities Commission at:


St. Paul, MN 55101-2147

Telephone: 651-296-0406

Toll Free: 800-657-3782

FAX: 651-297-7073

Email: [email protected]

Written comments are most effective when the following three items are included:

1. The section of Otter Tail Power Company’s proposal you are addressing.

2. Your specific recommendation.

3. The reason for your recommendation.

Please be sure to reference Dockets No. OAH XX-XXXX-XXXX-X and

MPUC E017/GR-15-1033 in all correspondence or requests.

*********NEWSPAPER NOTICE*********

Rate increase notice Notice of public hearings for Otter Tail Power Company

On February 16, 2016, Otter Tail Power Company (the Company) asked the Minnesota Public

Utilities Commission (MPUC) for permission to increase its electric rates by approximately

$19.3 million, or 9.80 percent.

Some customers will see more than the overall increase and some will see less based on

customer class, rates applied, and energy use. The MPUC has until December 16, 2016, to make

its final decision, unless the review period is extended by the MPUC.

The Company’s last request for a rate increase in Minnesota was in 2010.

Public comment Administrative Law Judge FIRST AND LAST NAME has scheduled public hearings so that

customers and others have opportunities to present their views on the adequacy and quality of the

Company’s service, the level of rates, or other related matters. You do not need to be

represented by an attorney.

Public hearing schedule Date, Time and locations to be added

Accommodations If you need any reasonable accommodation to enable you to fully participate in these public

hearings (i.e., sign language or foreign language interpreter, or large-print materials) please

contact the MPUC at 651-296-0406 one week in advance of the hearing.

Evidentiary hearings Formal evidentiary hearings on Otter Tail Power Company’s proposal are scheduled to start on

MONTH DAY, YEAR at (TIME) in (Place).

The purpose of the evidentiary hearings is to allow Otter Tail Power Company, the Minnesota

Department of Commerce – Division of Energy Resources, the Minnesota Office of the Attorney

General – Antitrust & Utilities Division, and other formal parties to the proceeding to present

testimony and to cross-examine each other’s witnesses on the proposed rate increase.

Anyone who wishes to formally intervene in this case should contact the Administrative Law

Judge.

Written comments

Written comments are most effective when they include:

1. The section of Otter Tail Power Company’s proposal you’re addressing.

2. Your specific recommendations.

3. The reasons for your recommendations.

Please be sure to reference Docket No. OAH XX-XXXX-XXXX-X and MPUC E017/GR-15-

1033 in all correspondence or requests.

Comments may be sent to the following address:

Administrative Law Judge FIRST AND LAST NAME


600 North Robert St.

St. Paul, MN 55164

Web: http://mn.gov/oah

You also may provide comments to the Minnesota Public Utilities Commission at:



St. Paul, MN 55101-2147

Phone: 651-296-0406

Toll Free: 800-657-3782

FAX: 651-297-7073

Email: [email protected]

Effect of rate changes

The following table shows the average monthly impact of the approved interim and proposed

final rates for an average customer in each of our customer classes. The impact on an individual

customer may be higher or lower depending on the individual customer’s actual electric

consumption.




Usage

Previous Monthly

Cost


in Monthly Cost


in Monthly Cost

Residential 810 $83 $9.07 $9.53

Farms 1,991 $193 $21.11 $17.35

General Service 2,618 $247 $27.02 $22.20


Irrigation 1,521 $151 $16.56 $28.74




214 $17 $1.84 $1.93


2,041 $109 $11.95 $12.55


2,237 $125 $13.64 $5.92

Otter Tail Power Company has requested the rate changes described in this notice. The MPUC

may grant or deny the requested changes, in whole or in part, and may grant a lesser or greater

increase than that requested for any class or classes of service.

For more information The proposed rate schedules and a comparison of present and proposed rates are available at

www.otpco.com/MNRateCase and can also be examined during normal business hours at Otter

Tail Power Company’s General Office. Our offices are located at:




Phone: 800-257-4044

You may also contact the Minnesota Department of Commerce -- Division of Energy Resources

at:

Minnesota Department of Commerce -- Division of Energy Resources


St. Paul, MN 55101

Telephone: 651-539-1886

FAX: 651-539-1549

You can also search e-dockets at the Department of Commerce website:


(Web address case sensitive)

Select 2015 in the year field, enter 1033 in the number field, click on Search, and the list

of documents will appear on the next page.


NOTICE TO COUNTIES AND MUNICIPALITIES

Under Minn. Stat. § 216B.16, Subd. 1

MPUC Docket No. E017/GR-15-1033

OAH Docket No. #-####-#####-#

On February 16, 2016, Otter Tail Power Company (Otter Tail) asked the Minnesota Public

Utilities Commission (MPUC) for permission to increase its electric rates by approximately

$19.3 million, or about 9.8 percent.

In accordance with Minn. Stat. §216B.16, Subd. 2, the MPUC has suspended Otter Tail’s

proposed final rates to allow the MPUC time to evaluate the request. In accordance with Minn.

Stat. §216B.16, Subd. 3, the MPUC has authorized an interim rate increase of approximately

$19.25 million (10.95 percent on base rate components other than riders) to be effective April 16,

2016, subject to refund. These higher rates will remain in effect until the final rates are

determined by the MPUC.

The MPUC will determine the final rate increase by December 16, 2016, unless the review

period is extended by the MPUC. If the final rate increase is less than the interim rate increase,

Otter Tail will refund to customers any over-collection of interim rates, plus interest, in a method

determined by the MPUC. If the final rate increase authorized by the MPUC is higher than the

interim rate increase, the higher rates will only become effective as of the date of the MPUC

Order approving final rates.

Otter Tail is requesting this revenue increase to cover rising costs and to meet the growing

demand for electricity as we serve customers as reliably, economically and environmentally

responsible as possible.

The following table shows the average monthly impact of the approved interim and proposed

final rates for an average customer in each of our customer classes. The impact on an individual

customer may be higher or lower depending on the individual customer’s actual electric

consumption.




Usage

Previous Monthly

Cost


in Monthly Cost


in Monthly Cost

Residential 810 $83 $9.07 $9.53

Farms 1,991 $193 $21.11 $17.35

General Service 2,618 $247 $27.02 $22.20


Irrigation 1,521 $151 $16.56 $28.74




214 $17 $1.84 $1.93


2,041 $109 $11.95 $12.55


2,237 $125 $13.64 $5.92

The Minnesota Department of Commerce – Division of Energy Resources office is conducting

an investigation of Otter Tail’s books and records with respect to this requested rate increase.

Public hearings have been scheduled as follows:

Date, Time and locations to be added

Public notice of the hearing dates, times, and locations will also be published in local newspapers

in our service area.

The proposed rate schedules and a comparison of present and proposed rates may be reviewed at

Otter Tail’s General Office during normal business hours at:




Phone: 800-257-4044

You also may review our current and proposed rate schedules by contacting the Minnesota

Department of Commerce – Division of Energy Resources.

Minnesota Department of Commerce – Division of Energy Resources



Telephone: 651-539-1886

FAX: 651-539-1549

Web: http://mn.gov/commerce/energy/

Additional information about our proposed rate schedules and a comparison of present and

proposed rates is available at www.otpco.com/MNRateCase. Questions or comments about the

rate increase request may be directed to 800-257-4044 or e-mailed to [email protected].

Persons who wish to intervene or testify in the evidentiary hearing in this case should contact the

Administrative Law Judge.

Administrative Law Judge FIRST MIDDLE AND LAST


600 North Robert St


Telephone: 651-361-7900

FAX: 651-539-0300

TDD: 651-361-7878

Web http://mn.gov/oah

OTTER TAIL POWER COMPANY

COUNTIES IN SERVICE TERRITORY

County County Seat

Becker County Detroit Lakes

Beltrami County Bemidji

Big Stone County Ortonville

Cass County Walker

Chippewa County Montevideo

Clay County Moorhead

Clearwater County Bagley

Douglas County Alexandria

Grant County Elbow Lake

Hubbard County Park Rapids

Kandiyohi County Willmar

Kittson County Hallock

Lac qui Parle County Madison

Lincoln County Ivanhoe

Lyon County Marshall

Mahnomen County Mahnomen

Marshall County Warren

Norman County Ada

Otter Tail County Fergus Falls

Pennington County Thief River Falls

Polk County Crookston

Pope County Glenwood

Red Lake County Red Lake Falls

Redwood County Redwood Falls

Roseau County Roseau

Stevens County Morris

Swift County Benson

Todd County Long Prairie

Traverse County Wheaton

Wilkin County Breckenridge

Yellow Medicine County Granite Falls

OTTER TAIL POWER COMPANY

RETAIL ELECTRIC SERVICE TO COMMUNITIES

Alberta Deer Creek Holt Parkers Prairie

Amiret Degraff Humboldt Pelican Rapids

Angus Dent Ivanhoe Pennock

Appleton Donaldson Johnson Perham

Argyle Donnelly Karlstad Plummer

Ashby Doran Kennedy Porter

Audubon Dudley Kensington Red Lake Falls

Badger Dumont Kent Richville

Barrett Eldred Kerkhoven Rose City

Barry Elizabeth Lac Qui Parle Rothsay

Battle Lake Erdahl Lake Benton St. Hilaire

Beardsley Erhard Lake Bronson St. Leo

Bejou Erskine Lancaster St. Vincent

Bellingham Evansville Lockhart Shevlin

Beltrami Farwell Louisburg Solway

Bemidji Fergus Falls McIntosh Strandquist

Boyd Fertile Mahnomen Sunburg

Brandon Fisher Marietta Syre

Brooks Forada Melby Taunton

Browns Valley Foxhome Mentor Tenney

Burr Frazee Middle River Tintah

Callaway Garfield Milan Trail

Campbell Gary Millerville Twin Valley

Canby Gentilly Milroy Ulen

Carlisle Ghent Miltona Underwood

Carlos Gonvick Minneota Urbank

Cass Lake Graceville Morris Verdi

Chokio Greenbush Murdock Vergas

Clearbrook Green Valley Nashua Viking

Climax Gully Nassau Vining

Clinton Hallock New York Mills Waubun

Clitherall Halma Norcross Wendell

Clontarf Hancock Northcote Wheaton

Correll Hendricks Noyes White Earth

Crookston Herman Odessa Wilno

Cyrus Hitterdal Ogema Wilton

Dalton Hoffman Oklee Winger

Danvers Holloway Oslo

Dawson Holmes City Ottertail