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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
Docket No. E017/GR-15-1033
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
Docket No. E017/GR-15-1033
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
Otter Tail Power Company Minnesota General Rate Case Documents
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
Otter Tail Power Company Minnesota General Rate Case Documents
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
Minnesota Public Utilities Commission
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
Docket No. E017/GR-15-1033
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.
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
Otter Tail Power Company
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
Docket No. E017/GR-15-1033
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
Otter Tail Power Company
215 South Cascade Street
Fergus Falls, MN 56537
218-739-8200
Bruce Gerhardson
Associate General Counsel
Otter Tail Power Company
P.O. Box 496
215 South Cascade Street
Fergus Falls, MN 56538-0496
218-739-8475
Cary Stephenson
Associate General Counsel
Otter Tail Power Company
PO Box 496
215 South Cascade Street
Fergus Falls, MN 56538-0496
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.
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 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
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
Otter Tail Power Company
P.O. Box 496
215 South Cascade Street
Fergus Falls, MN 56538-0496
Bruce Gerhardson
Associate General Counsel
Otter Tail Power Company
P.O. Box 496
215 South Cascade Street
Fergus Falls, MN 56538-0496
Cary Stephenson
Associate General Counsel
Otter Tail Power Company
P.O. Box 496
215 South Cascade Street
Fergus Falls, MN 56538-0496
Richard J. Johnson
Moss & Barnett, A professional Association
Suite 1200
150 South Fifth Street
Minneapolis, MN 55402
Patrick T. Zomer
Moss & Barnett, A professional Association
Suite 1200
150 South Fifth Street
Minneapolis, MN 55402
7
XII. CONCLUSION
The Company respectfully requests consideration and acceptance of its Application.
Dated: February 16, 2016
Respectfully submitted,
/s/ THOMAS R. BRAUSE
Thomas R. Brause
Vice President, Administration
Otter Tail Power Company
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
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
Docket No. E017/GR-15-1033
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.
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 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.
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
Docket No. E017/GR-15-1033
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.
Otter Tail Power Company
Initial Filing
Dated this 16th
day of February 2016.
/s/ WENDI A. OLSON
Wendi A. Olson
Regulatory Filing Coordinator
Otter Tail Power Company
215 South Cascade Street
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
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Ryan Barlow [email protected]
Office of the AttorneyGeneral-RUD
445 Minnesota StreetBremer Tower, Suite 1400St. Paul,Minnesota55101
Electronic Service Yes SPL_SL_15-1033_Potentially InterestedParties - Harding
Peter Beithon [email protected] Otter Tail Power Company P.O. Box 496215 South Cascade StreetFergus Falls,MN565380496
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
William Black [email protected] MMUA Suite 4003025 Harbor Lane NorthPlymouth,MN554475142
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
William A. Blazar [email protected] Minnesota Chamber OfCommerce
Suite 1500400 Robert Street NorthSt. Paul,MN55101
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Thomas R Brause [email protected] Otter Tail Power Company PO Box 496215 S Cascade StFergus Falls,MN56538-0496
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Christina Brusven [email protected] Fredrikson Byron 200 S 6th St Ste 4000Minneapolis,MN554021425
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Michael J. Bull [email protected] Center for Energy andEnvironment
212 Third Ave N Ste 560Minneapolis,MN55401
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Tammie Carino [email protected] Great River Energy 12300 Elm Creek Blvd.Maple Grove,MN55369-4718
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
2
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Ray Choquette [email protected] Ag Processing Inc. 12700 West Dodge RoadPO Box 2047Omaha,NE68103-2047
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
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
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Derick O. Dahlen [email protected]
Avant Energy Services 220 S. Sixth St Ste 1300Minneapolis,MN55402
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
William T Davis N/A - 23456 Garland LnBattle Lake,MN56515-9665
Paper Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Ian Dobson [email protected]
Office of the AttorneyGeneral-RUD
Antitrust and UtilitiesDivision445 Minnesota Street, 1400BRM TowerSt. Paul,MN55101
Electronic Service Yes SPL_SL_15-1033_Potentially InterestedParties - Harding
Dennis R Eicher [email protected]
D.R. Eicher Consulting, Inc. 28947 River Ridge Rd NWIsanti,MN55040
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
James C. Erickson [email protected] Kelly Bay Consulting 17 Quechee StSuperior,WI54880-4421
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Emma Fazio [email protected] Stoel Rives LLP 33 South Sixth StreetSuite 4200Minneapolis,MN55402
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
3
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Sharon Ferguson [email protected]
Department of Commerce 85 7th Place E Ste 500Saint Paul,MN551012198
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Edward Garvey [email protected] Residence 32 Lawton StSaint Paul,MN55102
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
John R. Gasele [email protected] Fryberger Buchanan Smith& Frederick PA
700 Lonsdale Building302 West Superior StreetDuluth,MN55802
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Bruce Gerhardson [email protected] Otter Tail Power Company PO Box 496215 S Cascade StFergus Falls,MN565380496
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Jeffrey Haase [email protected] Great River Energy 12300 Elm Creek BlvdMaple Grove,MN55369
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Annete Henkel [email protected] Minnesota Utility Investors 413 Wacouta Street#230St.Paul,MN55101
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Jim Horan [email protected] Minnesota Rural ElectricAssociation
11640 73rd Ave NMaple Grove,MN55369
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Arshia Javaherian [email protected]
Enbridge Energy 26 East Superior StreetSuite 309Duluth,MN55802
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Linda Jensen [email protected]
Office of the AttorneyGeneral-DOC
1800 BRM Tower 445Minnesota StreetSt. Paul,MN551012134
Electronic Service Yes SPL_SL_15-1033_Potentially InterestedParties - Harding
Richard Johnson [email protected]
Moss & Barnett 150 S. 5th StreetSuite 1200Minneapolis,MN55402
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
4
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
J. Vincent Jones [email protected]
Woods, Fuller, Shultz &Smith P.C.
300 S Phillips Ave Ste 300PO Box 5027Sioux Falls,SD57117-5027
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Michael Krikava [email protected] Briggs And Morgan, P.A. 2200 IDS Center80 S 8th StMinneapolis,MN55402
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
James D. Larson [email protected]
Avant Energy Services 220 S 6th St Ste 1300Minneapolis,MN55402
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Elizabeth A. Lewis [email protected]
Woods, Fuller, Shultz &Smith P.C.
300 S Phillips Ave Ste 300PO Box 5027Sioux Falls,SD57117-5027
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
John Lindell [email protected] Office of the AttorneyGeneral-RUD
1400 BRM Tower445 Minnesota StSt. Paul,MN551012130
Electronic Service Yes SPL_SL_15-1033_Potentially InterestedParties - Harding
Peter Madsen [email protected]
Office of the AttorneyGeneral-DOC
Bremer Tower, Suite 1800445 Minnesota StreetSt. Paul,Minnesota55101
Electronic Service Yes SPL_SL_15-1033_Potentially InterestedParties - Harding
Kavita Maini [email protected] KM Energy Consulting LLC 961 N Lost Woods RdOconomowoc,WI53066
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Pam Marshall [email protected] Energy CENTS Coalition 823 7th St ESt. Paul,MN55106
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Patrick Mastel N/A Missouri River EnergyServices
3724 W. Avera DrivePO Box 88920Sioux Falls,SD57109-8920
Paper Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Sara G McGrane [email protected] Felhaber Larson 220 S 6th St Ste 2200Minneapolis,MN55420
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
5
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Brian Meloy [email protected] Stinson,Leonard, StreetLLP
150 S 5th St Ste 2300Minneapolis,MN55402
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Tim Miller_ N/A Missouri River EnergyServices
3724 W. Avera DrivePO Box 88920Sioux Falls,SD57109-8920
Paper Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Andrew Moratzka [email protected] Stoel Rives LLP 33 South Sixth StreetSuite 4200Minneapolis,MN55402
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Darrell Nitschke [email protected] North Dakota PublicService Commission
600 E. Boulevard AvenueState Capital, 12th Floor,Dept 408Bismarck,ND585050480
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Gary Oetken [email protected] Ag Processing, Inc. 12700 West Dodge RoadP.O. Box 2047Omaha,NE681032047
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Lisa Pickard [email protected] Minnkota PowerCooperative
1822 Mill RdPO Box 13200Grand Forks,ND582083200
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Marcia Podratz [email protected] Minnesota Power 30 W Superior SDuluth,MN55802
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Charles Riesen [email protected] PKM Electric Cooperative 406 North Minnesota Street PO Box 108Warren,MN567620108
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Steve Sanda 101 Park CircleOttertail City,MN565717003
Paper Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
6
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Richard Savelkoul [email protected]
Martin & Squires, P.A. 332 Minnesota Street SteW2750St. Paul,MN55101
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Larry L. Schedin [email protected] LLS Resources, LLC 12 S 6th St Ste 1137Minneapolis,MN55402
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Michael Schmidt [email protected] PKM Electric Coop Inc PO Box 108406 North Minnesota StWarren,MN56762
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Christopher Schoenherr [email protected]
SMMPA 500 First Ave SWRochester,MN55902-3303
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Robert H. Schulte [email protected]
Schulte Associates LLC 1742 Patriot RdNorthfield,MN55057
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Janet Shaddix Elling [email protected]
Shaddix And Associates Ste 1229100 W Bloomington FrwyBloomington,MN55431
Electronic Service Yes SPL_SL_15-1033_Potentially InterestedParties - Harding
Mrg Simon [email protected] Missouri River EnergyServices
3724 W. Avera DriveP.O. Box 88920Sioux Falls,SD571098920
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Cari Snaza [email protected] Office of AdministrativeHearings
PO Box 64620St. Paul,MN55155
Electronic Service Yes SPL_SL_15-1033_Potentially InterestedParties - Harding
Ron Spangler, Jr. [email protected] Otter Tail Power Company 215 So. Cascade St.PO Box 496Fergus Falls,MN565380496
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
SaGonna Thompson [email protected]
Xcel Energy 414 Nicollet Mall FL 7Minneapolis,MN554011993
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
7
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Stuart Tommerdahl [email protected] Otter Tail Power Company 215 S Cascade StPO Box 496Fergus Falls,MN56537
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Patricia Van Gerpen [email protected]
South Dakota PublicUtilities Commission
State Capitol Building500 E Capitol AvePierre,SD57501-5070
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Kevin Walli [email protected] Fryberger, Buchanan,Smith & Frederick
380 St. Peter St Ste 710St. Paul,MN55102
Electronic Service No SPL_SL_15-1033_Potentially InterestedParties - Harding
Daniel P Wolf [email protected] Public Utilities Commission 121 7th Place EastSuite 350St. Paul,MN551012147
Electronic Service Yes SPL_SL_15-1033_Potentially InterestedParties - Harding
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 OFF_SL_15-1033_GR-15-1033
Julia Anderson [email protected]
Office of the AttorneyGeneral-DOC
1800 BRM Tower445 Minnesota StSt. Paul,MN551012134
Electronic Service Yes OFF_SL_15-1033_GR-15-1033
Thomas Bailey [email protected] Briggs And Morgan 2200 IDS Center80 S 8th StMinneapolis,MN55402
Electronic Service No OFF_SL_15-1033_GR-15-1033
William A. Blazar [email protected] Minnesota Chamber OfCommerce
Suite 1500400 Robert Street NorthSt. Paul,MN55101
Electronic Service No 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
Electronic Service No OFF_SL_15-1033_GR-15-1033
Tammie Carino [email protected] Great River Energy 12300 Elm Creek Blvd.Maple Grove,MN55369-4718
Electronic Service No OFF_SL_15-1033_GR-15-1033
Ray Choquette [email protected] Ag Processing Inc. 12700 West Dodge RoadPO Box 2047Omaha,NE68103-2047
Electronic Service No OFF_SL_15-1033_GR-15-1033
Derick O. Dahlen [email protected]
Avant Energy Services 220 S. Sixth St Ste 1300Minneapolis,MN55402
Electronic Service No OFF_SL_15-1033_GR-15-1033
William T Davis N/A - 23456 Garland LnBattle Lake,MN56515-9665
Paper Service No OFF_SL_15-1033_GR-15-1033
Ian Dobson [email protected]
Office of the AttorneyGeneral-RUD
Antitrust and UtilitiesDivision445 Minnesota Street, 1400BRM TowerSt. Paul,MN55101
Electronic Service No OFF_SL_15-1033_GR-15-1033
2
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
James C. Erickson [email protected] Kelly Bay Consulting 17 Quechee StSuperior,WI54880-4421
Electronic Service No OFF_SL_15-1033_GR-15-1033
Emma Fazio [email protected] Stoel Rives LLP 33 South Sixth StreetSuite 4200Minneapolis,MN55402
Electronic Service No OFF_SL_15-1033_GR-15-1033
Thomas E. Ferguson N/A Ferguson Consulting, LLC 5740 Kehtel RdDuluth,MN55811
Paper Service No OFF_SL_15-1033_GR-15-1033
Sharon Ferguson [email protected]
Department of Commerce 85 7th Place E Ste 500Saint Paul,MN551012198
Electronic Service No OFF_SL_15-1033_GR-15-1033
Edward Garvey [email protected] Residence 32 Lawton StSaint Paul,MN55102
Electronic Service No OFF_SL_15-1033_GR-15-1033
Bruce Gerhardson [email protected] Otter Tail Power Company PO Box 496215 S Cascade StFergus Falls,MN565380496
Electronic Service Yes OFF_SL_15-1033_GR-15-1033
Annete Henkel [email protected] Minnesota Utility Investors 413 Wacouta Street#230St.Paul,MN55101
Electronic Service No OFF_SL_15-1033_GR-15-1033
Shane Henriksen [email protected]
Enbridge Energy Company,Inc.
1409 Hammond Ave FL 2Superior,WI54880
Electronic Service No OFF_SL_15-1033_GR-15-1033
Richard Johnson [email protected]
Moss & Barnett 150 S. 5th StreetSuite 1200Minneapolis,MN55402
Electronic Service No OFF_SL_15-1033_GR-15-1033
J. Vincent Jones [email protected]
Woods, Fuller, Shultz &Smith P.C.
300 S Phillips Ave Ste 300PO Box 5027Sioux Falls,SD57117-5027
Electronic Service No OFF_SL_15-1033_GR-15-1033
3
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Joel W. Kanvik [email protected] Enbridge Energy Company,Inc.
26 E Superior St Ste 309Duluth,MN55802
Electronic Service No OFF_SL_15-1033_GR-15-1033
Bill Lachowitzer [email protected]
IBEW Local Union 949 12908 Nicollet Ave SBurnsville,MN55337-3527
Electronic Service No OFF_SL_15-1033_GR-15-1033
Douglas Larson [email protected]
Dakota Electric Association 4300 220th St WFarmington,MN55024
Electronic Service No OFF_SL_15-1033_GR-15-1033
James D. Larson [email protected]
Avant Energy Services 220 S 6th St Ste 1300Minneapolis,MN55402
Electronic Service No OFF_SL_15-1033_GR-15-1033
Elizabeth A. Lewis [email protected]
Woods, Fuller, Shultz &Smith P.C.
300 S Phillips Ave Ste 300PO Box 5027Sioux Falls,SD57117-5027
Electronic Service No OFF_SL_15-1033_GR-15-1033
John Lindell [email protected] Office of the AttorneyGeneral-RUD
1400 BRM Tower445 Minnesota StSt. Paul,MN551012130
Electronic Service Yes OFF_SL_15-1033_GR-15-1033
Pam Marshall [email protected] Energy CENTS Coalition 823 7th St ESt. Paul,MN55106
Electronic Service No OFF_SL_15-1033_GR-15-1033
Tom Micheletti [email protected]
Excelsior Energy Inc. 225 S 6th St Ste 2560Minneapolis,MN55402-4638
Electronic Service No OFF_SL_15-1033_GR-15-1033
Andrew Moratzka [email protected] Stoel Rives LLP 33 South Sixth StreetSuite 4200Minneapolis,MN55402
Electronic Service No OFF_SL_15-1033_GR-15-1033
Jeffrey L. Nelson [email protected] East River Electric PowerCoop.
121 SE First StreetPO Box 227Madison,SD57042
Electronic Service No OFF_SL_15-1033_GR-15-1033
4
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Gary Oetken [email protected] Ag Processing, Inc. 12700 West Dodge RoadP.O. Box 2047Omaha,NE681032047
Electronic Service No OFF_SL_15-1033_GR-15-1033
David G. Prazak [email protected] Otter Tail Power Company P.O. Box 496215 South Cascade StreetFergus Falls,MN565380496
Electronic Service No OFF_SL_15-1033_GR-15-1033
Anna K Roberts [email protected] Otter Tail Power Company 215 S Cascade StPO Box 496Fergus Falls,MN56538-0496
Electronic Service No OFF_SL_15-1033_GR-15-1033
Tim Rogelstad [email protected] Otter Tail Power Company 215 South Cascade StreetFergus Falls,MN56538
Electronic Service Yes OFF_SL_15-1033_GR-15-1033
Richard Savelkoul [email protected]
Martin & Squires, P.A. 332 Minnesota Street SteW2750St. Paul,MN55101
Electronic Service No OFF_SL_15-1033_GR-15-1033
Larry L. Schedin [email protected] LLS Resources, LLC 12 S 6th St Ste 1137Minneapolis,MN55402
Electronic Service No OFF_SL_15-1033_GR-15-1033
Robert H. Schulte [email protected]
Schulte Associates LLC 1742 Patriot RdNorthfield,MN55057
Electronic Service No OFF_SL_15-1033_GR-15-1033
Mrg Simon [email protected] Missouri River EnergyServices
3724 W. Avera DriveP.O. Box 88920Sioux Falls,SD571098920
Electronic Service No OFF_SL_15-1033_GR-15-1033
Ron Spangler, Jr. [email protected] Otter Tail Power Company 215 So. Cascade St.PO Box 496Fergus Falls,MN565380496
Electronic Service Yes OFF_SL_15-1033_GR-15-1033
William Taylor [email protected]
Taylor Law Firm 2921 E 57th StPO Box 10,Sioux FallsSD
Electronic Service No OFF_SL_15-1033_GR-15-1033
5
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
SaGonna Thompson [email protected]
Xcel Energy 414 Nicollet Mall FL 7Minneapolis,MN554011993
Electronic Service No OFF_SL_15-1033_GR-15-1033
Pat Treseler [email protected] Paulson Law Office LTD Suite 3257301 Ohms LaneEdina,MN55439
Electronic Service No OFF_SL_15-1033_GR-15-1033
Cam Winton [email protected] Minnesota Chamber ofCommerce
400 Robert Street NorthSuite 1500St. Paul,Minnesota55101
Electronic Service No OFF_SL_15-1033_GR-15-1033
Daniel P Wolf [email protected] Public Utilities Commission 121 7th Place EastSuite 350St. Paul,MN551012147
Electronic Service Yes OFF_SL_15-1033_GR-15-1033
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 GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Ray Choquette [email protected] Ag Processing Inc. 12700 West Dodge RoadPO Box 2047Omaha,NE68103-2047
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
James C. Erickson [email protected] Kelly Bay Consulting 17 Quechee StSuperior,WI54880-4421
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Sharon Ferguson [email protected]
Department of Commerce 85 7th Place E Ste 500Saint Paul,MN551012198
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Bruce Gerhardson [email protected] Otter Tail Power Company PO Box 496215 S Cascade StFergus Falls,MN565380496
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Shane Henriksen [email protected]
Enbridge Energy Company,Inc.
1409 Hammond Ave FL 2Superior,WI54880
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Richard Johnson [email protected]
Moss & Barnett 150 S. 5th StreetSuite 1200Minneapolis,MN55402
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Douglas Larson [email protected]
Dakota Electric Association 4300 220th St WFarmington,MN55024
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
James D. Larson [email protected]
Avant Energy Services 220 S 6th St Ste 1300Minneapolis,MN55402
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
John Lindell [email protected] Office of the AttorneyGeneral-RUD
1400 BRM Tower445 Minnesota StSt. Paul,MN551012130
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Kavita Maini [email protected] KM Energy Consulting LLC 961 N Lost Woods RdOconomowoc,WI53066
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
2
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Andrew Moratzka [email protected] Stoel Rives LLP 33 South Sixth StreetSuite 4200Minneapolis,MN55402
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Gary Oetken [email protected] Ag Processing, Inc. 12700 West Dodge RoadP.O. Box 2047Omaha,NE681032047
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Matt Olsen [email protected] Otter Tail Power Company 215 South Cascade StreetFergus Falls,MN56537
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Larry L. Schedin [email protected] LLS Resources, LLC 12 S 6th St Ste 1137Minneapolis,MN55402
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Cary Stephenson [email protected] Otter Tail Power Company 215 South Cascade StreetFergus Falls,MN56537
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Stuart Tommerdahl [email protected] Otter Tail Power Company 215 S Cascade StPO Box 496Fergus Falls,MN56537
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Daniel P Wolf [email protected] Public Utilities Commission 121 7th Place EastSuite 350St. Paul,MN551012147
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
Patrick Zomer [email protected]
Moss & Barnett aProfessional Association
150 S. 5th Street, #1200Minneapolis,MN55402
Electronic Service No GEN_SL_Otter Tail PowerCompany_General ServiceList - Rate Case
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Julia Anderson [email protected]
Office of the AttorneyGeneral-DOC
1800 BRM Tower445 Minnesota StSt. Paul,MN551012134
Electronic Service Yes OFF_SL_10-239_Official
Christopher Anderson [email protected] Minnesota Power 30 W Superior StDuluth,MN558022191
Electronic Service No OFF_SL_10-239_Official
Thomas Bailey [email protected] Briggs And Morgan 2200 IDS Center80 S 8th StMinneapolis,MN55402
Electronic Service No OFF_SL_10-239_Official
William A. Blazar [email protected] Minnesota Chamber OfCommerce
Suite 1500400 Robert Street NorthSt. Paul,MN55101
Electronic Service No OFF_SL_10-239_Official
Tammie Carino [email protected] Great River Energy 12300 Elm Creek Blvd.Maple Grove,MN55369-4718
Electronic Service No OFF_SL_10-239_Official
Ray Choquette [email protected] Ag Processing Inc. 12700 West Dodge RoadPO Box 2047Omaha,NE68103-2047
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
Derick O. Dahlen [email protected]
Avant Energy Services 220 S. Sixth St Ste 1300Minneapolis,MN55402
Electronic Service No OFF_SL_10-239_Official
William T Davis N/A - 23456 Garland LnBattle Lake,MN56515-9665
Paper Service No OFF_SL_10-239_Official
Ian Dobson [email protected]
Office of the AttorneyGeneral-RUD
Antitrust and UtilitiesDivision445 Minnesota Street, 1400BRM TowerSt. Paul,MN55101
Electronic Service No OFF_SL_10-239_Official
2
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
James C. Erickson [email protected] Kelly Bay Consulting 17 Quechee StSuperior,WI54880-4421
Electronic Service No OFF_SL_10-239_Official
Emma Fazio [email protected] Stoel Rives LLP 33 South Sixth StreetSuite 4200Minneapolis,MN55402
Electronic Service No OFF_SL_10-239_Official
Thomas E. Ferguson N/A Ferguson Consulting, LLC 5740 Kehtel RdDuluth,MN55811
Paper Service No OFF_SL_10-239_Official
Sharon Ferguson [email protected]
Department of Commerce 85 7th Place E Ste 500Saint Paul,MN551012198
Electronic Service No OFF_SL_10-239_Official
Edward Garvey [email protected] Residence 32 Lawton StSaint Paul,MN55102
Electronic Service No OFF_SL_10-239_Official
Bruce Gerhardson [email protected] Otter Tail Power Company PO Box 496215 S Cascade StFergus Falls,MN565380496
Electronic Service Yes OFF_SL_10-239_Official
Annete Henkel [email protected] Minnesota Utility Investors 413 Wacouta Street#230St.Paul,MN55101
Electronic Service No OFF_SL_10-239_Official
Shane Henriksen [email protected]
Enbridge Energy Company,Inc.
1409 Hammond Ave FL 2Superior,WI54880
Electronic Service Yes OFF_SL_10-239_Official
Richard Johnson [email protected]
Moss & Barnett 150 S. 5th StreetSuite 1200Minneapolis,MN55402
Electronic Service No OFF_SL_10-239_Official
J. Vincent Jones [email protected]
Woods, Fuller, Shultz &Smith P.C.
300 S Phillips Ave Ste 300PO Box 5027Sioux Falls,SD57117-5027
Electronic Service No OFF_SL_10-239_Official
3
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Joel W. Kanvik [email protected] Enbridge Energy Company,Inc.
26 E Superior St Ste 309Duluth,MN55802
Electronic Service No OFF_SL_10-239_Official
Michael Krikava [email protected] Briggs And Morgan, P.A. 2200 IDS Center80 S 8th StMinneapolis,MN55402
Electronic Service No OFF_SL_10-239_Official
Bill Lachowitzer [email protected]
IBEW Local Union 949 12908 Nicollet Ave SBurnsville,MN55337-3527
Electronic Service No OFF_SL_10-239_Official
Douglas Larson [email protected]
Dakota Electric Association 4300 220th St WFarmington,MN55024
Electronic Service No OFF_SL_10-239_Official
James D. Larson [email protected]
Avant Energy Services 220 S 6th St Ste 1300Minneapolis,MN55402
Electronic Service No OFF_SL_10-239_Official
Elizabeth A. Lewis [email protected]
Woods, Fuller, Shultz &Smith P.C.
300 S Phillips Ave Ste 300PO Box 5027Sioux Falls,SD57117-5027
Electronic Service No OFF_SL_10-239_Official
John Lindell [email protected] Office of the AttorneyGeneral-RUD
1400 BRM Tower445 Minnesota StSt. Paul,MN551012130
Electronic Service Yes OFF_SL_10-239_Official
Kavita Maini [email protected] KM Energy Consulting LLC 961 N Lost Woods RdOconomowoc,WI53066
Electronic Service No OFF_SL_10-239_Official
Pam Marshall [email protected] Energy CENTS Coalition 823 7th St ESt. Paul,MN55106
Electronic Service No OFF_SL_10-239_Official
Patrick Mastel N/A Missouri River EnergyServices
3724 W. Avera DrivePO Box 88920Sioux Falls,SD57109-8920
Paper Service No OFF_SL_10-239_Official
4
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Tom Micheletti [email protected]
Excelsior Energy Inc. 225 S 6th St Ste 2560Minneapolis,MN55402-4638
Electronic Service No OFF_SL_10-239_Official
Tim Miller_ N/A Missouri River EnergyServices
3724 W. Avera DrivePO Box 88920Sioux Falls,SD57109-8920
Paper Service No OFF_SL_10-239_Official
Andrew Moratzka [email protected] Stoel Rives LLP 33 South Sixth StreetSuite 4200Minneapolis,MN55402
Electronic Service No OFF_SL_10-239_Official
Jeffrey L. Nelson [email protected] East River Electric PowerCoop.
121 SE First StreetPO Box 227Madison,SD57042
Electronic Service No OFF_SL_10-239_Official
Gary Oetken [email protected] Ag Processing, Inc. 12700 West Dodge RoadP.O. Box 2047Omaha,NE681032047
Electronic Service No OFF_SL_10-239_Official
Marcia Podratz [email protected] Minnesota Power 30 W Superior SDuluth,MN55802
Electronic Service No OFF_SL_10-239_Official
Michelle Rebholz [email protected]
Public Utilities Commission Suite 350121 SeventhPlace EastSt. Paul,MN55101
Electronic Service Yes OFF_SL_10-239_Official
Tim Rogelstad [email protected] Otter Tail Power Company 215 South Cascade StreetFergus Falls,MN56538
Electronic Service Yes OFF_SL_10-239_Official
Steve Sanda 101 Park CircleOttertail City,MN565717003
Paper Service No OFF_SL_10-239_Official
Richard Savelkoul [email protected]
Martin & Squires, P.A. 332 Minnesota Street SteW2750St. Paul,MN55101
Electronic Service No OFF_SL_10-239_Official
5
First Name Last Name Email Company Name Address Delivery Method View Trade Secret Service List Name
Larry L. Schedin [email protected] LLS Resources, LLC 12 S 6th St Ste 1137Minneapolis,MN55402
Electronic Service No OFF_SL_10-239_Official
Robert H. Schulte [email protected]
Schulte Associates LLC 1742 Patriot RdNorthfield,MN55057
Electronic Service No OFF_SL_10-239_Official
Mrg Simon [email protected] Missouri River EnergyServices
3724 W. Avera DriveP.O. Box 88920Sioux Falls,SD571098920
Electronic Service No OFF_SL_10-239_Official
Ron Spangler, Jr. [email protected] Otter Tail Power Company 215 So. Cascade St.PO Box 496Fergus Falls,MN565380496
Electronic Service Yes OFF_SL_10-239_Official
William Taylor [email protected]
Taylor Law Firm 2921 E 57th StPO Box 10,Sioux FallsSD
Electronic Service No OFF_SL_10-239_Official
SaGonna Thompson [email protected]
Xcel Energy 414 Nicollet Mall FL 7Minneapolis,MN554011993
Electronic Service No OFF_SL_10-239_Official
Pat Treseler [email protected] Paulson Law Office LTD Suite 3257301 Ohms LaneEdina,MN55439
Electronic Service No OFF_SL_10-239_Official
Cam Winton [email protected] Minnesota Chamber ofCommerce
400 Robert Street NorthSuite 1500St. Paul,Minnesota55101
Electronic Service No OFF_SL_10-239_Official
Daniel P Wolf [email protected] Public Utilities Commission 121 7th Place EastSuite 350St. Paul,MN551012147
Electronic Service Yes OFF_SL_10-239_Official
1/3 tab
Volume 1
Notice and Petition for Interim 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
Docket No. E017/GR-15-1033
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)
Otter Tail Power Company
PO Box 496
215 South Cascade Street
Fergus Falls, MN 56537
218-739-8200
Bruce Gerhardson
Associate General Counsel
Otter Tail Power Company
PO Box 496
215 South Cascade Street
Fergus Falls, MN 56538-0496
218-739-8475
2
Cary Stephenson
Associate General Counsel
Otter Tail Power Company
PO Box 496
215 South Cascade Street
Fergus Falls, MN 56538-0496
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 proposed interim rates are requested to become
effective
(Policy Statement, Item 2, page 2)
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
(Policy Statement, Item 3, page 2)
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
(Policy Statement, Item 4, page 2)
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
(Policy Statement, Item 5, page 2)
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
(Policy Statement, Item 6, page 2)
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.
Dated: February 16, 2016
Respectfully submitted,
/s/ THOMAS R. BRAUSE
Thomas R. Brause
Vice President, Administration
Otter Tail Power Company
Subscribed and sworn to before
me this 16th day of February, 2016.
/s/ WENDI A. OLSON
Notary Public
My Commission expires January 31, 2020.
1/3 tab
Volume 1
Agreement and Undertaking,
and Certification
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
Docket No. E017/GR-15-1033
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.
Dated: February 16, 2016
By: /s/ THOMAS R. BRAUSE
Thomas R. Brause
Vice President Administration
Otter Tail Power Company
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.
Dated: February 16, 2016
/s/ TIMOTHY ROGELSTAD
Timothy Rogelstad
President
Otter Tail Power Company
Subscribed and sworn to before
me this 16th day of February, 2016
/s/ WENDI A. OLSON
Notary Public
My Commission expires January 31, 2020.
1/3 tab
Volume 1
Interim Supporting Schedules
and Workpapers
Docket No. E017/GR-15-1033
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.
Detailed Rate Base Components 1
Description of Adjustments to Rate Base 2
Rate Base with Adjustments (Bridge Schedule) 3
Statement of Operating Income 4
Description of Adjustments to Operating Statement 5
Statement of Operating Income with Adjustments (Bridge Schedule) 6
Summary of Revenue Requirements 7
Schedule No.
Detailed Rate Base Components 1
Description of Changes to Rate Base 2
Statement of Operating Income 3
Description of Changes to Operating Statement 4
Summary of Revenue Requirements 5
Capital Structure and Rate of Return Calculations 6
Description of Changes to Capital Structure and Rate of Return Calculations 7
Schedule No.
Detailed Rate Base Components 1
Description of Changes to Rate Base 2
Statement of Operating Income 3
Description of Changes to Operating Statement 4
Summary of Revenue Requirements 5
Schedule No.
Detailed Rate Base Components 1
Description of Changes to Rate Base Components 2
Statement of Operating Income 3
Description of Changes to Operating Statement 4
Summary of Revenue Requirements 5
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%
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART A
INTERIM RATE SCHEDULE Schedule 2
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART A
INTERIM RATE SCHEDULE Schedule 3
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART A
INTERIM RATE SCHEDULE Schedule 4
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%
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART A
INTERIM RATE SCHEDULE Schedule 5
STATEMENT OF OPERATING INCOME Page 1 of 1
Line Proposed Interim
No. Description Test Year
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART A
INTERIM RATE SCHEDULE Schedule 6
DETAILED RATE BASE COMPONENTS Page 1 of 1
Line Proposed Interim
No. Description Test Year
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
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
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)
Utility Plant in Service:
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
13 NET Utility Plant in Service
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)
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART B
COMPARISON OF PROPOSED INTERIM RATES TO Schedule 2
DETAILED RATE BASE COMPONENTS Page 1 of 1
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART B
COMPARISON OF PROPOSED INTERIM RATES TO Schedule 3
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
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART B
COMPARISON OF PROPOSED INTERIM RATES TO Schedule 4
STATEMENT OF OPERATING INCOME Page 1 of 1
(A) (B) (C)
Proposed
Line Test Year Proposed Interim Change
No. Description 2016 Test Year (B) - (A)
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)
4 OPERATING EXPENSES
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)
17 INCOME TAX EXPENSE
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
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART B
COMPARISON OF PROPOSED INTERIM RATES TO Schedule 5
STATEMENT OF OPERATING INCOME Page 1 of 2
DESCRIPTION OF ADJUSTMENTS
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART B
COMPARISON OF PROPOSED INTERIM RATES TO Schedule 5
STATEMENT OF OPERATING INCOME Page 2 of 2
DESCRIPTION OF ADJUSTMENTS
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART B
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
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART B
COMPARISON OF PROPOSED INTERIM RATES TO Schedule 7
SUMMARY OF REVENUE REQUIREMENTS Page 1 of 1
(A) (B) (C)
Proposed
Line Test Year Proposed Interim Change
No. Description 2016 Test Year (B) - (A)
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)%
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART C
Schedule 1
DETAILED RATE BASE COMPONENTS Page 1 of 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)
Utility Plant in Service:
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
7 Accumulated Depreciation
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)
14 NET Utility Plant in Service
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
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART C
Schedule 2
DETAILED RATE BASE COMPONENTS Page 1 of 1
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART C
COMPARISON OF PROPOSED INTERIM RATES TO OTP'S MOST RECENT GENERAL RATE CASE Schedule 3
STATEMENT OF OPERATING INCOME Page 1 of 1
(A) (B) (C)
Results of MostRecent General
Line Rate Case Proposed Interim Change
No. Description E017/GR-10-239 Test Year (B) - (A)
OPERATING REVENUES
1 Retail $146,009,997 $175,833,397 $29,823,400
2 Other Operating Revenue 6,366,059 7,311,132 945,074
3 TOTAL OPERATING REVENUE $152,376,056 $183,144,530 $30,768,474
4 OPERATING EXPENSES
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
16 NET OPERATING INCOME BEFORE INCOME TAXES $25,625,930 $17,905,888 ($7,720,043)
17 INCOME TAX EXPENSE
17 Investment Tax Credit ($4,930,206) ($4,478,056) $452,150
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)
21 NET OPERATING INCOME $24,115,366 $17,279,172 ($6,836,195)
22 Allowance for Funds Used During Construction 421,564 671,443 249,879
23 TOTAL AVAILABLE FOR RETURN $24,536,930 $17,950,615 ($6,586,316)
Notes: Revenues reflect calendar month sales
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART C
COMPARISON OF PROPOSED INTERIM RATES TO OTP'S MOST RECENT GENERAL RATE CASE Schedule 4
STATEMENT OF OPERATING INCOME Page 1 of 1
DESCRIPTION OF CHANGES
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART C
COMPARISON OF PROPOSED INTERIM RATES TO OTP'S MOST RECENT GENERAL RATE CASE Schedule 5
SUMMARY OF REVENUE REQUIREMENTS Page 1 of 1
(A) (B) (C)
Results of MostRecent General
Line Rate Case Proposed Interim Change
No. Description E017/GR-10-239 Test Year (B) - (A)
1 Average Rate Base $292,716,226 $362,299,321 $69,583,095
2 Operating Income (Before AFUDC) $24,115,366 $17,279,172 ($6,836,194)
3 Allowance for Funds Used During Construction (AFUDC) $421,564 $671,443 $249,879
4 Total Available for Return (Line 2 + Line 3 + Rounding) $24,536,930 $17,950,615 ($6,586,315)
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
9 Gross Revenue Conversion Factor 1.705611 1.705611 0
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%
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART C
COMPARISON OF PROPOSED INTERIM RATES TO OTP'S MOST RECENT GENERAL RATE CASE Schedule 6
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
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART C
COMPARISON OF PROPOSED INTERIM RATES TO OTP'S MOST RECENT GENERAL RATE CASE Schedule 7
CAPITAL STRUCTURE AND RATE OF RETURN CALCULATIONS Page 1 of 1
DESCRIPTION OF CHANGES
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART D
COMPARISON OF PROPOSED INTERIM RATES TO UNADJUSTED PROJECTED FISCAL YEAR Schedule 1
DETAILED RATE BASE COMPONENTS Page 1 of 1
(A) (B) (C)Unadjusted
Line Projected Year Proposed Interim Change
No. Description 2016 Test Year (B) - (A)
Utility Plant in Service:
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)
7 Accumulated Depreciation
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
14 NET Utility Plant in Service
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
22 Utility Plant Held for Future Use $13,813 $13,813 $0
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)
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of MN PART D
Schedule 2
Page 1 of 1
DETAILED RATE BASE COMPONENTS
DESCRIPTION OF CHANGES
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of MN PART D
Schedule 3
Page 1 of 1
STATEMENT OF OPERATING INCOME
(A) (B) (C)Unadjusted
Projected
Line Fiscal Year Proposed Interim Change
No. Description 2016 Test Year (B) - (A)
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)
4 OPERATING EXPENSES
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)
16 NET OPERATING INCOME BEFORE INCOME TAXES $33,609,816 $17,905,888 ($15,703,928)
17 INCOME TAX EXPENSE
18 Investment Tax Credit ($4,508,451) ($4,478,056) $30,395
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)
22 NET OPERATING INCOME $27,586,395 $17,279,172 ($10,307,223)
23 Allowance for Funds Used During Construction 818,137 671,443 (146,694)
24 TOTAL AVAILABLE FOR RETURN $28,404,532 $17,950,615 ($10,453,917)
Notes: Revenues reflect calendar month sales
COMPARISON OF PROPOSED INTERIM RATES TO
UNADJUSTED PROJECTED FISCAL YEAR
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of MN PART D
Schedule 4
Page 1 of 1
STATEMENT OF OPERATING INCOME
DESCRIPTION OF CHANGES
COMPARISON OF PROPOSED INTERIM RATES TO UNADJUSTED
PROJECTED FISCAL YEAR
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of MN PART D
Schedule 5
Page 1 of 1
SUMMARY OF REVENUE REQUIREMENTS
(A) (B) (C)Unadjusted
Projected
Line Fiscal Year Proposed Interim Change
No. Description 2016 Test Year (B) - (A)
1 Average Rate Base $460,035,382 $362,299,321 ($97,736,061)
2 Operating Income (Before AFUDC) $27,586,395 $17,279,172 ($10,307,223)
3 Allowance for Funds Used During Construction (AFUDC) $818,137 $671,443 ($146,694)
4 Total Available for Return (Line 2 + Line 3 + Rounding) $28,404,532 $17,950,615 ($10,453,917)
5 Overall Rate of Return (Line 4 / Line 1) 6.17% 4.95% (1.22)%
6 Required Rate of Return 8.07% 8.07% (0.00)%
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
9 Gross Revenue Conversion Factor 1.705611 1.705611 0
10 Revenue Deficiency (Line 8 x Line 9) $14,873,480 $19,251,130 $4,377,649
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) 7.56% 10.95% 3.39%
COMPARISON OF PROPOSED INTERIM RATES TO UNADJUSTED
PROJECTED FISCAL YEAR
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART E
OTP'S MOST RECENT GENERAL RATE CASE TO PROPOSED TEST YEAR Schedule 1
DETAILED RATE BASE COMPONENTS Page 1 of 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)
Utility Plant in Service:
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
7 Accumulated Depreciation
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)
14 NET Utility Plant in Service
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
22 Utility Plant Held for Future Use $13,501 $13,813 $312
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
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART E
Schedule 2
DETAILED RATE BASE COMPONENTS Page 1 of 1
DESCRIPTION OF CHANGES
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART E
OTP'S MOST RECENT GENERAL RATE CASE TO PROPOSED TEST YEAR Schedule 3
STATEMENT OF OPERATING INCOME Page 1 of 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)
OPERATING REVENUES
1 Retail $146,009,997 $196,817,160 $50,807,163
2 Other Operating Revenue 6,366,059 7,177,664 811,606
3 TOTAL OPERATING REVENUE $152,376,056 $203,994,824 $51,618,768
4 OPERATING EXPENSES
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
17 INCOME TAX EXPENSE
18 Investment Tax Credit ($4,930,206) ($4,509,538) $420,668
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
Notes: Revenues reflect calendar month sales
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART E
Schedule 4
STATEMENT OF OPERATING INCOME Page 1 of 1
DESCRIPTION OF CHANGES
OTP'S MOST RECENT GENERAL RATE CASE TO PROPOSED TEST YEAR
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.
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
Electric Utility - State of Minnesota PART E
Schedule 5
SUMMARY OF REVENUE REQUIREMENTS Page 1 of 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 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
5 Overall Rate of Return (Line 4 / Line 1) 8.38% 5.73% (2.65)%
6 Required Rate of Return 8.61% 8.07% (0.54)%
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
10 Revenue Deficiency (Line 8 x Line 9) $1,150,851 $19,295,623 $18,144,772
11 Retail Related Revenues Under Present Rates $146,009,997 $196,817,160 $50,807,163
12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 0.79% 9.80% 9.02%
OTP'S MOST RECENT GENERAL RATE CASE TO PROPOSED TEST YEAR
1/3 tab
Volume 1
Summary of Present and Interim Revenue
OTTER TAIL POWER COMPANY Docket No. E017/GR-15-1033
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 9.01
ELECTRIC RATE SCHEDULE Residential Service
Page 2 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 9.02
ELECTRIC RATE SCHEDULE Residential Demand Control Service
(RDC) Page 1 of 2
ThirteenthTwelfth 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 DEMAND CONTROL SERVICE
(Commonly identified as RDC)
DESCRIPTION RATE
CODE
Residential Demand Control 31-241
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 Customers with a
UL-approved Demand-control system.
RATE:
RESIDENTIAL DEMAND CONTROL SERVICE
Customer Charge per Month: $11.00
Monthly Minimum Bill: Customer + Facilities + Demand Charges
Facilities Charge per Month: $5.00
Energy Charge per kWh: Summer Winter
4.6714.819 ¢/kWh 5.0585.206 ¢/kWh
Demand Charge per kW: Summer Winter
$6.08 /kW $5.11 /kW
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 9.02
ELECTRIC RATE SCHEDULE Residential Demand Control Service
(RDC) Page 2 of 2
ThirteenthTwelfth 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
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 9.03
ELECTRIC RATE SCHEDULE Farm Service
Page 1 of 2
Twenty-fifthfourth 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
FARM SERVICE
DESCRIPTION RATE
CODE
Farm Service 31-361
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 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
Customer Charge per Month: $12.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month:
Single-phase $0.00
Three-phase: $8.00
Energy Charge per kWh: Summer Winter
7.6667.814 ¢/kWh 7.8738.021 ¢/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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 9.03
ELECTRIC RATE SCHEDULE Farm Service
Page 2 of 2
Twenty-fifthfourth 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.01
ELECTRIC RATE SCHEDULE Small General Service
Page 1 of 4
ThirdSecond 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
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
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. 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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.01
ELECTRIC RATE SCHEDULE Small General Service
Page 2 of 4
ThirdSecond 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
NON-METERED SERVICE-SECONDARY ONLY-1000 WATTS OR LESS
***CLOSED TO NEW INSTALLATIONS***
Customer Charge per Month: $2.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month: $0.00
Energy Charge per kWh: Summer Winter
All kWh 7.715
7.863 ¢/kWh
7.715
7.863 ¢/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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.01
ELECTRIC RATE SCHEDULE Small General Service
Page 3 of 4
ThirdSecond 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
2. Seasonal Small General Service Customers will be billed at the same rate as Small General
Service Customers, except as follows:
A one-time seasonal fixed charge of $62.00 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 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.
Bills may be rendered on a two-month basis at the Company’s discretion when the Energy
used exceeds 400 Kilowatt-Hours and more than 55 days have elapsed since the previous
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.01
ELECTRIC RATE SCHEDULE Small General Service
Page 4 of 4
ThirdSecond 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.02
ELECTRIC RATE SCHEDULE General Service
Page 1 of 2
Twenty-fourththird 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
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:
SECONDARY SERVICE PRIMARY SERVICE
Customer Charge per Month: $19.00 $19.00
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
Energy Charge per kWh: Summer Winter Summer Winter
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.02
ELECTRIC RATE SCHEDULE General Service
Page 2 of 2
Twenty-fourththird 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
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.03
ELECTRIC RATE SCHEDULE General Service – Time of Use
Page 1 of 3
SeventeenthSixteenth 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
GENERAL SERVICE - TIME OF USE
DESCRIPTION RATE
CODE
Declared-Peak 31-708
Intermediate 31-709
Off-Peak 31-710
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
one Meter providing electrical service.
RATE:
GENERAL SERVICE - TIME OF USE
Customer Charge per Month: $19.00
Monthly Minimum Bill: Customer + Facilities + Demand Charges
Facilities Charge per Month
Per annual maximum kW
(minimum 20kW per Month): $0.60 /kW
Energy Charge per kWh: Summer Winter
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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.03
ELECTRIC RATE SCHEDULE General Service – Time of Use
Page 2 of 3
SeventeenthSixteenth 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
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.
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.
ADJUSTMENT FOR EXCESS REACTIVE DEMAND: For billing purposes, the Metered
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.
DETERMINATION OF BILLING DEMAND: The Billing Demand shall be the greater of 20
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.03
ELECTRIC RATE SCHEDULE General Service – Time of Use
Page 3 of 3
SeventeenthSixteenth 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.04
ELECTRIC RATE SCHEDULE Large General Service
Page 1 of 3
TwentiethNineteenth 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
LARGE GENERAL SERVICE
DESCRIPTION RATE
CODES
Secondary Service 31-603
Primary Service 31-602
Transmission Service 31-632
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. This
schedule is not applicable for outdoor lighting. Emergency and supplementary/Standby service will
be supplied only as allowed by law.
RATE:
SECONDARY SERVICE
Customer Charge per Month: $40.00
Monthly Minimum Bill: Customer + Facilities + Demand Charges
Facilities Charge per Month
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
Energy Charge per kWh: Summer Winter
4.6184.766 ¢/kWh 5.0005.148 ¢/kWh
Demand Charge per kW
(minimum of 80 kW): Summer Winter
$7.22 /kW $6.07 /kW
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.04
ELECTRIC RATE SCHEDULE Large General Service
Page 2 of 3
TwentiethNineteenth 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
PRIMARY SERVICE
Customer Charge per Month: $40.00
Monthly Minimum Bill: Customer + Facilities + Demand Charges
Facilities Charge per Month
per annual max. kW (minimum 80kW per Month)
All kW: $0.12 /kW
Energy Charge per kWh: Summer Winter
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
Customer Charge per Month: $40.00
Monthly Minimum Bill: Customer + Facilities + Demand Charges
Facilities Charge per Month
per annual max. kW (minimum 80kW per Month)
All kW: $0.00 /kW
Energy Charge per kWh: Summer Winter
4.2444.392 ¢/kWh 4.5334.681 ¢/kWh
Demand Charge per kW Summer Winter
(minimum of 80 kW): $5.37 /kW $4.97 /kW
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.04
ELECTRIC RATE SCHEDULE Large General Service
Page 3 of 3
TwentiethNineteenth 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
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.
METERED DEMAND: 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 80
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) 80 kW or 2) the largest of the most recent 12 monthly Billing Demands.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.05
ELECTRIC RATE SCHEDULE Large General Service – Time of Day
Page 1 of 4
SeventhSixth 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
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
Customer Charge per Month: $60.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month
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
Energy Charge per kWh: Summer Winter
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
Demand Charge per kW: Summer Winter
On-Peak $5.54 /kW $5.13 /kW
Shoulder $1.68 /kW $0.94 /kW
Off-Peak $0.00 /kW $0.00 /kW
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.05
ELECTRIC RATE SCHEDULE Large General Service – Time of Day
Page 2 of 4
SeventhSixth 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
PRIMARY SERVICE
Customer Charge per Month: $60.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month
per annual max. kW (minimum 80 kW per Month): $0.12/kW
Energy Charge per kWh: Summer Winter
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
Demand Charge per kW: Summer Winter
On-Peak $5.32 /kW $4.94 /kW
Shoulder $1.61 /kW $0.82 /kW
Off-Peak $0.00 /kW $0.00 /kW
TRANSMISSION SERVICE
Customer Charge per Month: $60.00
Monthly Minimum Bill
per annual max. kW
(minimum 80 kW per Month): Customer + Facilities Charges
Facilities Charge per Month: $0.00
Energy Charge per kWh: Summer Winter
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
Demand Charge per kW: Summer Winter
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.05
ELECTRIC RATE SCHEDULE Large General Service – Time of Day
Page 3 of 4
SeventhSixth 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
On-Peak $4.31 /kW $4.27 /kW
Shoulder $1.06 /kW $0.70 /kW
Off-Peak $0.00 /kW $0.00 /kW
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.05
ELECTRIC RATE SCHEDULE Large General Service – Time of Day
Page 4 of 4
SeventhSixth 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
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
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
RULES AND REGULATIONS: Terms and conditions of this electric rate schedule and the
General Rules and Regulations govern use of this service.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 2 of 8
SeventhSixth 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
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
month per kW of Contracted
Backup Demand 4.68 ¢/kW 5.10 ¢/kW 5.37 ¢/kW
Standby Facilities Charge per
month per kW of Contracted
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
Metered Demand per day per
kW On-Peak Backup Charge 64.33 ¢/kW 70.03 ¢/kW 73.73 ¢/kW
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
Energy Charges per kWh
On-Peak Charge 5.8445.992 ¢/kWh 6.2516.399 ¢/kWh 6.5076.655 ¢/kWh
Shoulder Charge 4.4604.608 ¢/kWh 4.7424.890 ¢/kWh 4.9175.065 ¢/kWh
Off-Peak Charge 3.3523.500 ¢/kWh 3.5463.694 ¢/kWh 3.6653.813 ¢/kWh
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 3 of 8
SeventhSixth 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
OPTION B: NON-FIRM STANDBY
Transmission Primary Secondary
Service Service Service
Non-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
Reservation Charge per month
per kW of Contracted Backup
Demand Not Available Not Available Not Available
Standby Facilities Charge per
month per kW of Contracted
Backup Demand Not Applicable 52.83 ¢/kW 72.26 ¢/kW
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
Metered Demand per day per kW
On-Peak Backup Charge Not Available Not Available Not Available
Non-Firm Standby Energy Charges - Summer
Energy Charges per kWh
On-Peak Charge Not Available Not Available Not Available
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
Non-Firm Standby Energy Charges - Winter
Energy Charges per kWh
On-Peak Charge Not Available Not Available Not Available
Shoulder Charge 4.4604.608 ¢/kWh 4.7424.890 ¢/kWh 4.9175.065 ¢/kWh
Off-Peak Charge 3.3523.500 ¢/kWh 3.5463.694 ¢/kWh 3.6653.813 ¢/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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 4 of 8
SeventhSixth 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
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 5 of 8
SeventhSixth 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 6 of 8
SeventhSixth 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 7 of 8
EighthSeventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: January 27, 2014 Docket No. E-017/GR-15-1033M-13-609
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 8 of 8
SeventhSixth 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.02
ELECTRIC RATE SCHEDULE Irrigation Service
Page 1 of 3
Twenty-thirdsecond 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
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
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 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
Customer Charge per Month: $2.00
Monthly Minimum Bill: Customer + Fixed Charges
Fixed Charge per Month: Customer-Specific see Tariff
Energy Charge per kWh: Summer Winter
6.5016.649 ¢/kWh
4.2914.439 ¢/kWh
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.02
ELECTRIC RATE SCHEDULE Irrigation Service
Page 2 of 3
Twenty-thirdsecond 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
OPTION 2
Customer Charge per Month: $6.00
Monthly Minimum Bill: Customer + Fixed Charges
Fixed Charge per Month: Customer-Specific see Tariff
Energy Charge per kWh: Summer Winter
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
Demand Charge per kW: Summer Winter
Declared-Peak $0.00 /kW $0.00 /kW
Intermediate $2.53 /kW $1.30 /kW
Off-Peak $0.00 /kW $0.00 /kW
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.
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.02
ELECTRIC RATE SCHEDULE Irrigation Service
Page 3 of 3
Twenty-thirdsecond 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
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.
DEFINITION OF DECLARED, INTERMEDIATE AND OFF-PEAK PERIODS BY SEASON:
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.
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.03
ELECTRIC RATE SCHEDULE Outdoor Lighting – Energy Only
Dusk to Dawn Page 1 of 2
FifthFourth 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
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
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 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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.03
ELECTRIC RATE SCHEDULE Outdoor Lighting – Energy Only
Dusk to Dawn Page 2 of 2
FifthFourth 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
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: 7.5187.666 ¢/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)
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 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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.04
ELECTRIC RATE SCHEDULE Outdoor Lighting
Dusk to Dawn Page 1 of 3
SeventeenthSixteenth 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
OUTDOOR LIGHTING
DUSK TO DAWN
DESCRIPTION RATE
CODE
Outdoor Lighting 31-745
Floodlighting 31-746
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 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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.04
ELECTRIC RATE SCHEDULE Outdoor Lighting
Dusk to Dawn Page 2 of 3
SeventeenthSixteenth 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
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.
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 rate schedule. See Sections 12.00,
13.00 and 14.00 of the Minnesota electric rates for the matrices of riders.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.04
ELECTRIC RATE SCHEDULE Outdoor Lighting
Dusk to Dawn Page 3 of 3
SeventeenthSixteenth 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.05
ELECTRIC RATE SCHEDULE Municipal Pumping Service
Page 1 of 2
FourteenthThirteenth 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
MUNICIPAL PUMPING SERVICE
DESCRIPTION RATE
CODE
Secondary Service 31-871
Primary Service 31-874
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 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:
SECONDARY SERVICE PRIMARY SERVICE
Customer Charge per Month: $4.00 $4.00
Monthly Minimum Bill: Customer + Facilities Charges Customer + Facilities Charges
Facilities Charge per Annual
Maximum kW per Month: $0.14 /kW $0.09 /kW
Energy Charge per kWh: Summer Winter Summer Winter
6.298
6.446 ¢/kWh
6.468
6.616 ¢/kWh
6.091
6.239 ¢/kWh
6.219
6.367 ¢/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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.05
ELECTRIC RATE SCHEDULE Municipal Pumping Service
Page 2 of 2
FourteenthThirteenth 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
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.
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: 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 Metered
Demand adjusted for Excess Reactive Demand.
DETERMINATION OF FACILITIES CHARGE: The Facilities Charge Demand will be based
on the largest of the most recent 12 monthly Billing Demands.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.06
ELECTRIC RATE SCHEDULE Civil Defense – Fire Sirens
Page 1 of 2
SeventhSixth 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
CIVIL DEFENSE – FIRE SIRENS
DESCRIPTION RATE
CODE
Civil Defense – Fire Sirens 31-843
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 separately served civil defense
and municipal fire sirens.
RATE:
CIVIL DEFENSE - FIRE SIRENS
Customer Charge per Month: $1.00
Monthly Minimum Bill: Customer Charge
Facilities Charge per Month: $0.00
Charge per HP: Summer Winter
59.482 ¢/HP 59.482 ¢/HP
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.06
ELECTRIC RATE SCHEDULE Civil Defense – Fire Sirens
Page 2 of 2
SeventhSixth 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
DEFINITIONS OF SEASONS:
Summer: June 1 through September 30.
Winter: October 1 through May 31.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
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
EFFECTIVE with bills rendered on and after
January 1, 2016 in Minnesota
SMALL POWER PRODUCER RIDER
(Net Energy Billing Rate)
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 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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.01
ELECTRIC RATE SCHEDULE Small Power Producer Rider
Net Energy Billing Rate Page 2 of 3
Thirty-thirdsecond Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: NA Docket No. E-017/GR-15-1033E999/PR-12-09
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
January 1, 2013 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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.01
ELECTRIC RATE SCHEDULE Small Power Producer Rider
Net Energy Billing Rate Page 3 of 3
Thirty-secondfirst Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: NA Docket No. E-017/GR-15-1033E999/PR-11-09
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
January 1, 2012 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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.02
ELECTRIC RATE SCHEDULE Small Power Producer Rider
Simultaneous Purchase and Sale 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
EFFECTIVE with bills rendered on and after
January 1, 2016 in Minnesota
SMALL POWER PRODUCER RIDER
SIMULTANEOUS PURCHASE AND SALE BILLING RATE
DESCRIPTION RATE
CODE
Firm Power 31-981
Nonfirm Power 31-984
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 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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.02
ELECTRIC RATE SCHEDULE Small Power Producer Rider
Simultaneous Purchase and Sale Billing Rate Page 2 of 3
Thirty-secondfirst Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: NA Docket No. E-017/GR-15-1033E999/PR-11-09
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
January 1, 2012 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).
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.02
ELECTRIC RATE SCHEDULE Small Power Producer Rider
Simultaneous Purchase and Sale Billing Rate Page 3 of 3
Thirty-secondfirst Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: NA Docket No. E-017/GR-15-1033E999/PR-11-09
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
January 1, 2012 in Minnesota
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.
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.03
ELECTRIC RATE SCHEDULE Small Power Producer Rider Time of Day Purchase Rates
Page 1 of 4 Thirty-seventhsixth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: NA Docket No. E-017/GR-15-1033E999/PR-16-09
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
January 1, 2016 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
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 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.
CUSTOMER CHARGE: Firm Power $8.87 per month
Nonfirm Power $3.25 per month
INTERIM RATE ADJUSTMENT:
A 10.95 percent increase will be added to the Customer Charge.
PAYMENT SCHEDULE: For energy delivered to the utility.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.03
ELECTRIC RATE SCHEDULE Small Power Producer Rider Time of Day Purchase Rates
Page 2 of 4 Thirty-secondfirst Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: NA Docket No. E-017/GR-15-1033E999/PR-11-09
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
January 1, 2012 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).
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.03
ELECTRIC RATE SCHEDULE Small Power Producer Rider Time of Day Purchase Rates
Page 3 of 4 Thirty-secondfirst Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: NA Docket No. E-017/GR-15-1033E999/PR-11-09
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
January 1, 2012 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.
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.03
ELECTRIC RATE SCHEDULE Small Power Producer Rider Time of Day Purchase Rates
Page 4 of 4 Thirty-secondfirst Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: NA Docket No. E-017/GR-15-1033E999/PR-11-09
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
January 1, 2012 in Minnesota
14. The Customer shall install, own and maintain all equipment deemed necessary by the
Company to assure proper parallel operation of the system.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.04
ELECTRIC RATE SCHEDULE Distributed Generation Service Rider
Page 1 of 6
FifthFourth 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
DISTRIBUTED GENERATION SERVICE RIDER
DESCRIPTION RATE
CODE
Distributed Generation Service Rider 31-931
RULES AND REGULATIONS: Terms and conditions of this electric rate schedule and the
General Rules and Regulations govern use of this rider.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.04
ELECTRIC RATE SCHEDULE Distributed Generation Service Rider
Page 2 of 6
FifthFourth 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
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.
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.
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.04
ELECTRIC RATE SCHEDULE Distributed Generation Service Rider
Page 3 of 6
FifthFourth 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
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.04
ELECTRIC RATE SCHEDULE Distributed Generation Service Rider
Page 4 of 6
FifthFourth 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.04
ELECTRIC RATE SCHEDULE Distributed Generation Service Rider
Page 5 of 6
FifthFourth 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
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):
TERMS AND CONDITIONS:
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.
7. The Customer will provide equipment to maintain a 100% power factor (+ or - 10%)
during periods of Generator operation.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 12.04
ELECTRIC RATE SCHEDULE Distributed Generation Service Rider
Page 6 of 6
FifthFourth 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
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.
10. The Customer shall execute an electric service contract with the Company which may
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.
12. The Customer shall install, own and maintain all equipment deemed necessary by the
Company to assure proper parallel operation of the system.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.01
ELECTRIC RATE SCHEDULE Water Heating Control Rider
Page 1 of 2
Twenty-firstTwentieth 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
WATER HEATING CONTROL RIDER
DESCRIPTION RATE
CODE
Separately Metered Water Heating Control Service 31-191
Water Heating Credit Control Service 31-192
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 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
Customer Charge per Month: $2.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month: $0.00
Energy Charge per kWh: Summer Winter
5.9196.067 ¢/kWh
6.3286.476 ¢/kWh
WATER HEATING CREDIT CONTROL SERVICE - 192
Monthly Credit: $4.00
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. This Interim Rate Adjustment only applies to Separately Metered Water
Heating Control Service rate 191.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.01
ELECTRIC RATE SCHEDULE Water Heating Control Rider
Page 2 of 2
Twenty-firstTwentieth 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
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.
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.
DEFINITIONS OF SEASONS:
Summer: June 1 through September 30.
Winter: October 1 through May 31.
EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard
metering and/or control equipment.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.02
ELECTRIC RATE SCHEDULE Real Time Pricing Rider
Page 1 of 5
FifthFourth 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
REAL TIME PRICING RIDER
DESCRIPTION RATE
CODE
Transmission Service 31-660
Primary Service 31-662
Secondary Service 31-664
RULES AND REGULATIONS: Terms and conditions of this electric rate schedule and the
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.
INTERIM RATE ADJUSTMENT:
A 10.95 percent increase will be added to the Customer 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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.02
ELECTRIC RATE SCHEDULE Real Time Pricing Rider
Page 2 of 5
FifthFourth 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
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.02
ELECTRIC RATE SCHEDULE Real Time Pricing Rider
Page 3 of 5
FifthFourth 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.02
ELECTRIC RATE SCHEDULE Real Time Pricing Rider
Page 4 of 5
FifthFourth 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
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 )}
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.02
ELECTRIC RATE SCHEDULE Real Time Pricing Rider
Page 5 of 5
FifthFourth 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
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 1 of 6
SeventhSixth 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
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
applied to each monthly bill to cover billing, administrative, metering, and communication costs
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 2 of 6
SeventhSixth 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
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 3 of 6
SeventhSixth 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
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 4 of 6
SeventhSixth 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
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:
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”).
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 5 of 6
SeventhSixth 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
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 6 of 6
SeventhSixth 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
(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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.04
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
CT Metering Rider (Large Dual Fuel) Page 1 of 4
Twenty-secondfirst 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
CONTROLLED SERVICE - INTERRUPTIBLE LOAD
CT METERING RIDER
(Commonly identified as Large Dual Fuel)
DESCRIPTION Option 1 Option 2
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)
Uncontrolled period N/A 31-169
Controlled period N/A 31-269
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 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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.04
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
CT Metering Rider (Large Dual Fuel) Page 2 of 4
Twenty-secondfirst 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
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
Customer Charge per Month: $5.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Annual
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.04
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
CT Metering Rider (Large Dual Fuel) Page 3 of 4
Twenty-secondfirst 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
OPTION 2
Customer Charge per Month: $6.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Annual
Maximum kW per Month: $0.12
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
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 rider. 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.
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.04
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
CT Metering Rider (Large Dual Fuel) Page 4 of 4
Twenty-secondfirst 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
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.
EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard
metering and control equipment.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.05
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
Self-Contained Metering Rider (Small Dual Fuel) Page 1 of 3
Twenty-secondfirst 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
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
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 for Customers with approved permanently connected
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.
When service to the electric space heating equipment on this rate is interrupted, the back-up heating
system cannot be electric.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.05
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
Self-Contained Metering Rider (Small Dual Fuel) Page 2 of 3
Twenty-secondfirst 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
RATE:
CONTROLLED SERVICE - INTERRUPTIBLE LOAD – SELF-CONTAINED
Customer Charge per Month: $2.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month: $5.00
Summer Winter
Energy Charge per kWh:
4.2914.439 ¢/kWh
4.6934.841 ¢/kWh
Penalty Charge per kWh: 15.702 ¢/kWh 16.930 ¢/kWh
During the Penalty Period, kWhs used will be measured and billed at the Energy Charge
and Penalty listed above.
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 rider. 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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.05
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
Self-Contained Metering Rider (Small Dual Fuel) Page 3 of 3
Twenty-secondfirst 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
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: 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.
EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard
metering and control equipment.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.06
ELECTRIC RATE SCHEDULE Controlled Service – Deferred Load Rider
(Thermal Storage) Page 1 of 3
Twenty-secondfirst 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
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
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 for Customers with approved permanently connected
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.06
ELECTRIC RATE SCHEDULE Controlled Service – Deferred Load Rider
(Thermal Storage) Page 2 of 3
Twenty-secondfirst 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
RATE:
CONTROLLED SERVICE - DEFERRED LOAD
Customer Charge per Month:
$2.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month: $4.00
Energy Charge per kWh: Summer Winter
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.
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 rider. 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.
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.06
ELECTRIC RATE SCHEDULE Controlled Service – Deferred Load Rider
(Thermal Storage) Page 3 of 3
Twenty-secondfirst 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
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 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.
EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard
metering and control equipment.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.07
ELECTRIC RATE SCHEDULE Fixed Time of Service Rider
(Fixed TOS) Page 1 of 4
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
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
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 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
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 lowtemperature grain drying.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.07
ELECTRIC RATE SCHEDULE Fixed Time of Service Rider
(Fixed TOS) Page 2 of 4
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
RATE:
FIXED TIME OF 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: 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
Customer Charge per Month: $2.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month: $16.00
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.07
ELECTRIC RATE SCHEDULE Fixed Time of Service Rider
(Fixed TOS) Page 3 of 4
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
FIXED TIME OF 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:
1.6201.7
68 ¢/kWh
3.3123.4
60 ¢/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.
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 rider. See Sections 12.00, 13.00
and 14.00 of the electric rates for the matrices of riders.
DEFINITIONS OF SEASONS:
Summer: June 1 through September 30.
Winter: October 1 through May 31.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.07
ELECTRIC RATE SCHEDULE Fixed Time of Service Rider
(Fixed TOS) Page 4 of 4
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
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.
EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard
metering and control equipment.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
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
Thomas R. Brause Vice President, Administration
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
Penalty/Unauthorized Use 31-888
Off-Peak EV Service – Primary CT Metering 31-783
Penalty/Unauthorized Use 31-889
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 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: 2.9623.110 ¢/kWh 4.6614.809 ¢/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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.12
ELECTRIC RATE SCHEDULE Off-Peak Electric Vehicle Rider
(Off-Peak EV) Page 2 of 3
First RevisionOriginal
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: June 22, 2015 Docket No. E-017/GR-15-1033M-15-112
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after July 1, 2015
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: 2.9623.110 ¢/kWh 4.6614.809 ¢/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.
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: 2.9563.104 ¢/kWh 4.6484.796 ¢/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.
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 rider. See Sections 12.00, 13.00
and 14.00 of the electric rates for the matrices of riders.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.12
ELECTRIC RATE SCHEDULE Off-Peak Electric Vehicle Rider
(Off-Peak EV) Page 3 of 3
First RevisionOriginal
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: June 22, 2015 Docket No. E-017/GR-15-1033M-15-112
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after July 1, 2015
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.
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
Interim Tariff Sheets – Non-Redlined
Fergus Falls, Minnesota
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
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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 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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 9.01 ELECTRIC RATE SCHEDULE
Residential Service
Page 2 of 2 Twenty-sixth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 9.02
ELECTRIC RATE SCHEDULE Residential Demand Control Service
(RDC) Page 1 of 2
Thirteenth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
RESIDENTIAL DEMAND CONTROL SERVICE
(Commonly identified as RDC)
DESCRIPTION RATE
CODE
Residential Demand Control 31-241
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 Customers with a
UL-approved Demand-control system.
RATE:
RESIDENTIAL DEMAND CONTROL SERVICE
Customer Charge per Month: $11.00
Monthly Minimum Bill: Customer + Facilities + Demand Charges
Facilities Charge per Month: $5.00
Energy Charge per kWh: Summer Winter
4.819 ¢/kWh 5.206 ¢/kWh
Demand Charge per kW: Summer Winter
$6.08 /kW $5.11 /kW
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 9.02
ELECTRIC RATE SCHEDULE Residential Demand Control Service
(RDC) Page 2 of 2
Thirteenth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 9.03
ELECTRIC RATE SCHEDULE Farm Service
Page 1 of 2
Twenty-fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
FARM SERVICE
DESCRIPTION RATE
CODE
Farm Service 31-361
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 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
Customer Charge per Month: $12.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month:
Single-phase $0.00
Three-phase: $8.00
Energy Charge per kWh: Summer Winter
7.814 ¢/kWh 8.021 ¢/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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 9.03
ELECTRIC RATE SCHEDULE Farm Service
Page 2 of 2
Twenty-fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.01
ELECTRIC RATE SCHEDULE Small General Service
Page 1 of 4
Third Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
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. 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
7.727 ¢/kWh 7.932 ¢/kWh 7.479 ¢/kWh 7.632 ¢/kWh
R
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.01
ELECTRIC RATE SCHEDULE Small General Service
Page 2 of 4
Third Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
NON-METERED SERVICE-SECONDARY ONLY-1000 WATTS OR LESS
***CLOSED TO NEW INSTALLATIONS***
Customer Charge per Month: $2.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month: $0.00
Energy Charge per kWh: Summer Winter
All kWh 7.863 ¢/kWh 7.863 ¢/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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.01
ELECTRIC RATE SCHEDULE Small General Service
Page 3 of 4
Third Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
2. Seasonal Small General Service Customers will be billed at the same rate as Small General
Service Customers, except as follows:
A one-time seasonal fixed charge of $62.00 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 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.
Bills may be rendered on a two-month basis at the Company’s discretion when the Energy
used exceeds 400 Kilowatt-Hours and more than 55 days have elapsed since the previous
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.01
ELECTRIC RATE SCHEDULE Small General Service
Page 4 of 4
Third Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.02
ELECTRIC RATE SCHEDULE General Service
Page 1 of 2
Twenty-fourth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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: 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:
SECONDARY SERVICE PRIMARY SERVICE
Customer Charge per Month: $19.00 $19.00
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
Energy Charge per kWh: Summer Winter Summer Winter
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
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.02
ELECTRIC RATE SCHEDULE General Service
Page 2 of 2
Twenty-fourth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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.
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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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.03
ELECTRIC RATE SCHEDULE General Service – Time of Use
Page 1 of 3
Seventeenth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
GENERAL SERVICE - TIME OF USE
DESCRIPTION RATE
CODE
Declared-Peak 31-708
Intermediate 31-709
Off-Peak 31-710
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
one Meter providing electrical service.
RATE:
GENERAL SERVICE - TIME OF USE
Customer Charge per Month: $19.00
Monthly Minimum Bill: Customer + Facilities + Demand Charges
Facilities Charge per Month
Per annual maximum kW
(minimum 20kW per Month): $0.60 /kW
Energy Charge per kWh: Summer Winter
Declared-Peak 20.480 ¢/kWh 21.772 ¢/kWh
Intermediate 5.310 ¢/kWh 4.851 ¢/kWh
Off-Peak 2.479 ¢/kWh 3.653 ¢/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
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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.
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.03
ELECTRIC RATE SCHEDULE General Service – Time of Use
Page 2 of 3
Seventeenth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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.
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.
ADJUSTMENT FOR EXCESS REACTIVE DEMAND: For billing purposes, the Metered
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.
DETERMINATION OF BILLING DEMAND: The Billing Demand shall be the greater of 20
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.03
ELECTRIC RATE SCHEDULE General Service – Time of Use
Page 3 of 3
Seventeenth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.04
ELECTRIC RATE SCHEDULE Large General Service
Page 1 of 3
Twentieth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
LARGE GENERAL SERVICE
DESCRIPTION RATE
CODES
Secondary Service 31-603
Primary Service 31-602
Transmission Service 31-632
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. This
schedule is not applicable for outdoor lighting. Emergency and supplementary/Standby service will
be supplied only as allowed by law.
RATE:
SECONDARY SERVICE
Customer Charge per Month: $40.00
Monthly Minimum Bill: Customer + Facilities + Demand Charges
Facilities Charge per Month
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
Energy Charge per kWh: Summer Winter
4.766 ¢/kWh 5.148 ¢/kWh
Demand Charge per kW
(minimum of 80 kW): Summer Winter
$7.22 /kW $6.07 /kW
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.04
ELECTRIC RATE SCHEDULE Large General Service
Page 2 of 3
Twentieth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
PRIMARY SERVICE
Customer Charge per Month: $40.00
Monthly Minimum Bill: Customer + Facilities + Demand Charges
Facilities Charge per Month
per annual max. kW (minimum 80kW per Month)
All kW: $0.12 /kW
Energy Charge per kWh: Summer Winter
4.625 ¢/kWh 4.969 ¢/kWh
Demand Charge per kW Summer Winter
(minimum of 80 kW): $6.93 /kW $5.76 /kW
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TRANSMISSION SERVICE
Customer Charge per Month: $40.00
Monthly Minimum Bill: Customer + Facilities + Demand Charges
Facilities Charge per Month
per annual max. kW (minimum 80kW per Month)
All kW: $0.00 /kW
Energy Charge per kWh: Summer Winter
4.392 ¢/kWh 4.681 ¢/kWh
Demand Charge per kW Summer Winter
(minimum of 80 kW): $5.37 /kW $4.97 /kW
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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.
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.04
ELECTRIC RATE SCHEDULE Large General Service
Page 3 of 3
Twentieth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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.
METERED DEMAND: 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 80
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) 80 kW or 2) the largest of the most recent 12 monthly Billing Demands.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.05
ELECTRIC RATE SCHEDULE Large General Service – Time of Day
Page 1 of 4
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
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
Customer Charge per Month: $60.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month
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
Energy Charge per kWh: Summer Winter
On-Peak 7.467 ¢/kWh 6.655 ¢/kWh
Shoulder 5.545 ¢/kWh 5.065 ¢/kWh
Off-Peak 2.585 ¢/kWh 3.813 ¢/kWh
Demand Charge per kW: Summer Winter
On-Peak $5.54 /kW $5.13 /kW
Shoulder $1.68 /kW $0.94 /kW
Off-Peak $0.00 /kW $0.00 /kW
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.05
ELECTRIC RATE SCHEDULE Large General Service – Time of Day
Page 2 of 4
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
PRIMARY SERVICE
Customer Charge per Month: $60.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month
per annual max. kW (minimum 80 kW per Month): $0.12/kW
Energy Charge per kWh: Summer Winter
On-Peak 7.215 ¢/kWh 6.399 ¢/kWh
Shoulder 5.376 ¢/kWh 4.890 ¢/kWh
Off-Peak 2.524 ¢/kWh 3.694 ¢/kWh
Demand Charge per kW: Summer Winter
On-Peak $5.32 /kW $4.94 /kW
Shoulder $1.61 /kW $0.82 /kW
Off-Peak $0.00 /kW $0.00 /kW
TRANSMISSION SERVICE
Customer Charge per Month: $60.00
Monthly Minimum Bill
per annual max. kW
(minimum 80 kW per Month): Customer + Facilities Charges
Facilities Charge per Month: $0.00
Energy Charge per kWh: Summer Winter
On-Peak 6.808 ¢/kWh 5.992 ¢/kWh
Shoulder 5.100 ¢/kWh 4.608 ¢/kWh
Off-Peak 2.420 ¢/kWh 3.500 ¢/kWh
Demand Charge per kW: Summer Winter
On-Peak $4.31 /kW $4.27 /kW
Shoulder $1.06 /kW $0.70 /kW
Off-Peak $0.00 /kW $0.00 /kW
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.05
ELECTRIC RATE SCHEDULE Large General Service – Time of Day
Page 3 of 4
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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.
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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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 10.05
ELECTRIC RATE SCHEDULE Large General Service – Time of Day
Page 4 of 4
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 1 of 8
Eighth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
RULES AND REGULATIONS: Terms and conditions of this electric rate schedule and the
General Rules and Regulations govern use of this service.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 2 of 8
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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
month per kW of Contracted
Backup Demand 4.68 ¢/kW 5.10 ¢/kW 5.37 ¢/kW
Standby Facilities Charge per
month per kW of Contracted
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
Metered Demand per day per
kW On-Peak Backup Charge 64.33 ¢/kW 70.03 ¢/kW 73.73 ¢/kW
Firm Standby Energy Charges - Summer
Energy Charges per kWh
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
Energy Charges per kWh
On-Peak Charge 5.992 ¢/kWh 6.399 ¢/kWh 6.655 ¢/kWh
Shoulder Charge 4.608 ¢/kWh 4.890 ¢/kWh 5.065 ¢/kWh
Off-Peak Charge 3.500 ¢/kWh 3.694 ¢/kWh 3.813 ¢/kWh
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 3 of 8
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
OPTION B: NON-FIRM STANDBY
Transmission Primary Secondary
Service Service Service
Non-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
Reservation Charge per month
per kW of Contracted Backup
Demand Not Available Not Available Not Available
Standby Facilities Charge per
month per kW of Contracted
Backup Demand Not Applicable 52.83 ¢/kW 72.26 ¢/kW
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
Metered Demand per day per kW
On-Peak Backup Charge Not Available Not Available Not Available
Non-Firm Standby Energy Charges - Summer
Energy Charges per kWh
On-Peak Charge Not Available Not Available Not Available
Shoulder Charge 5.100 ¢/kWh 5.376 ¢/kWh 5.545 ¢/kWh
Off-Peak Charge 2.420 ¢/kWh 2.524 ¢/kWh 2.585 ¢/kWh
Non-Firm Standby Energy Charges - Winter
Energy Charges per kWh
On-Peak Charge Not Available Not Available Not Available
Shoulder Charge 4.608 ¢/kWh 4.890 ¢/kWh 5.065 ¢/kWh
Off-Peak Charge 3.500 ¢/kWh 3.694 ¢/kWh 3.813 ¢/kWh
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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.
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 4 of 8
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 5 of 8
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 6 of 8
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 7 of 8
Eighth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.01
ELECTRIC RATE SCHEDULE Standby Service
Page 8 of 8
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.02
ELECTRIC RATE SCHEDULE Irrigation Service
Page 1 of 3
Twenty-third Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
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 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
Customer Charge per Month: $2.00
Monthly Minimum Bill: Customer + Fixed Charges
Fixed Charge per Month: Customer-Specific see Tariff
Energy Charge per kWh: Summer Winter
6.649 ¢/kWh 4.439 ¢/kWh
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.02
ELECTRIC RATE SCHEDULE Irrigation Service
Page 2 of 3
Twenty-third Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
OPTION 2
Customer Charge per Month: $6.00
Monthly Minimum Bill: Customer + Fixed Charges
Fixed Charge per Month: Customer-Specific see Tariff
Energy Charge per kWh: Summer Winter
Declared-Peak 20.141 ¢/kWh 22.209 ¢/kWh
Intermediate 4.384 ¢/kWh 4.236 ¢/kWh
Off-Peak 1.771 ¢/kWh 1.964 ¢/kWh
Demand Charge per kW: Summer Winter
Declared-Peak $0.00 /kW $0.00 /kW
Intermediate $2.53 /kW $1.30 /kW
Off-Peak $0.00 /kW $0.00 /kW
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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.
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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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.02
ELECTRIC RATE SCHEDULE Irrigation Service
Page 3 of 3
Twenty-third Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.
DEFINITION OF DECLARED, INTERMEDIATE AND OFF-PEAK PERIODS BY SEASON:
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.
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.
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 11.03 ELECTRIC RATE SCHEDULEOutdoor Lighting – Energy Only
Dusk to Dawn Page 1 of 2
Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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
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 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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 11.03 ELECTRIC RATE SCHEDULEOutdoor Lighting – Energy Only
Dusk to Dawn Page 2 of 2
Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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
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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)
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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.
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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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.04
ELECTRIC RATE SCHEDULE Outdoor Lighting
Dusk to Dawn Page 1 of 3
Seventeenth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
OUTDOOR LIGHTING
DUSK TO DAWN
DESCRIPTION RATE
CODE
Outdoor Lighting 31-745
Floodlighting 31-746
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 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
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.04
ELECTRIC RATE SCHEDULE Outdoor Lighting
Dusk to Dawn Page 2 of 3
Seventeenth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
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*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.
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.
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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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.04
ELECTRIC RATE SCHEDULE Outdoor Lighting
Dusk to Dawn Page 3 of 3
Seventeenth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.05
ELECTRIC RATE SCHEDULE Municipal Pumping Service
Page 1 of 2
Fourteenth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
MUNICIPAL PUMPING SERVICE
DESCRIPTION RATE
CODE
Secondary Service 31-871
Primary Service 31-874
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 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:
SECONDARY SERVICE PRIMARY SERVICE
Customer Charge per Month: $4.00 $4.00
Monthly Minimum Bill: Customer + Facilities Charges Customer + Facilities Charges
Facilities Charge per Annual
Maximum kW per Month: $0.14 /kW $0.09 /kW
Energy Charge per kWh: Summer Winter Summer Winter
6.446 ¢/kWh 6.616 ¢/kWh 6.239 ¢/kWh 6.367 ¢/kWh
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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.
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 11.05
ELECTRIC RATE SCHEDULE Municipal Pumping Service
Page 2 of 2
Fourteenth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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.
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: 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 Metered
Demand adjusted for Excess Reactive Demand.
DETERMINATION OF FACILITIES CHARGE: The Facilities Charge Demand will be based
on the largest of the most recent 12 monthly Billing Demands.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 11.06 ELECTRIC RATE SCHEDULE
Civil Defense – Fire Sirens
Page 1 of 2 Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
in Minnesota
CIVIL DEFENSE – FIRE SIRENS
DESCRIPTION RATE CODE
Civil Defense – Fire Sirens 31-843
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 separately served civil defense and municipal fire sirens.
RATE:
CIVIL DEFENSE - FIRE SIRENS
Customer Charge per Month: $1.00
Monthly Minimum Bill: Customer Charge Facilities Charge per Month: $0.00
Charge per HP: Summer Winter 59.482 ¢/HP 59.482 ¢/HP
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.
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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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 11.06 ELECTRIC RATE SCHEDULE
Civil Defense – Fire Sirens
Page 2 of 2 Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
in Minnesota
DEFINITIONS OF SEASONS: Summer: June 1 through September 30.
Winter: October 1 through May 31.
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.01 ELECTRIC RATE SCHEDULE
Small Power Producer RiderNet Energy Billing Rate
Page 1 of 3 Thirty-sixth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
in Minnesota
SMALL POWER PRODUCER RIDER (Net Energy Billing Rate)
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 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).
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.01 ELECTRIC RATE SCHEDULE
Small Power Producer RiderNet Energy Billing Rate
Page 2 of 3 Thirty-third Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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.
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.01 ELECTRIC RATE SCHEDULE
Small Power Producer RiderNet Energy Billing Rate
Page 3 of 3 Thirty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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.
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.02 ELECTRIC RATE SCHEDULE
Small Power Producer RiderSimultaneous Purchase and Sale Billing Rate
Page 1 of 3 Thirty-sixth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause
Vice President, Administration
EFFECTIVE with bills renderedon and after
in Minnesota
SMALL POWER PRODUCER RIDER SIMULTANEOUS PURCHASE AND SALE BILLING RATE
DESCRIPTION RATE
CODE Firm Power 31-981 Nonfirm Power 31-984
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 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
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.02 ELECTRIC RATE SCHEDULE
Small Power Producer RiderSimultaneous Purchase and Sale Billing Rate
Page 2 of 3 Thirty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause
Vice President, Administration
EFFECTIVE with bills renderedon and after
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).
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.
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.02 ELECTRIC RATE SCHEDULE
Small Power Producer RiderSimultaneous Purchase and Sale Billing Rate
Page 3 of 3 Thirty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause
Vice President, Administration
EFFECTIVE with bills renderedon and after
in Minnesota
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.
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.
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.03 ELECTRIC RATE SCHEDULE
Small Power Producer RiderTime of Day Purchase Rates
Page 1 of 4 Thirty-seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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
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 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.
CUSTOMER CHARGE: Firm Power $8.87 per month
Nonfirm Power $3.25 per month
INTERIM RATE ADJUSTMENT: A 10.95 percent increase will be added to the Customer Charge.
N N
PAYMENT SCHEDULE: For energy delivered to the utility.
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.03 ELECTRIC RATE SCHEDULE
Small Power Producer RiderTime of Day Purchase Rates
Page 2 of 4 Thirty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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).
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.
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.03 ELECTRIC RATE SCHEDULE
Small Power Producer RiderTime of Day Purchase Rates
Page 3 of 4 Thirty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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.
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.
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.03 ELECTRIC RATE SCHEDULE
Small Power Producer RiderTime of Day Purchase Rates
Page 4 of 4 Thirty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
in Minnesota
14. The Customer shall install, own and maintain all equipment deemed necessary by the
Company to assure proper parallel operation of the system.
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.04 ELECTRIC RATE SCHEDULE
Distributed Generation Service Rider
Page 1 of 6 Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
in Minnesota
DISTRIBUTED GENERATION SERVICE RIDER
DESCRIPTION RATE CODE
Distributed Generation Service Rider 31-931
RULES AND REGULATIONS: Terms and conditions of this electric rate schedule and the General Rules and Regulations govern use of this rider.
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.04 ELECTRIC RATE SCHEDULE
Distributed Generation Service Rider
Page 2 of 6 Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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.
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
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
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.04 ELECTRIC RATE SCHEDULE
Distributed Generation Service Rider
Page 3 of 6 Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.04 ELECTRIC RATE SCHEDULE
Distributed Generation Service Rider
Page 4 of 6 Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.04 ELECTRIC RATE SCHEDULE
Distributed Generation Service Rider
Page 5 of 6 Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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):
TERMS AND CONDITIONS:
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.
7. The Customer will provide equipment to maintain a 100% power factor (+ or - 10%)
during periods of Generator operation.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 12.04 ELECTRIC RATE SCHEDULE
Distributed Generation Service Rider
Page 6 of 6 Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills renderedon and after
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.
10. The Customer shall execute an electric service contract with the Company which may
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.
12. The Customer shall install, own and maintain all equipment deemed necessary by the
Company to assure proper parallel operation of the system.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.01
ELECTRIC RATE SCHEDULE Water Heating Control Rider
Page 1 of 2
Twenty-first Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
WATER HEATING CONTROL RIDER
DESCRIPTION RATE
CODE
Separately Metered Water Heating Control Service 31-191
Water Heating Credit Control Service 31-192
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 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
Customer Charge per Month: $2.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month: $0.00
Energy Charge per kWh: Summer Winter
6.067 ¢/kWh 6.476 ¢/kWh
R
WATER HEATING CREDIT CONTROL SERVICE - 192
Monthly Credit: $4.00
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. This Interim Rate Adjustment only applies to Separately Metered Water
Heating Control Service rate 191.
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Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.01
ELECTRIC RATE SCHEDULE Water Heating Control Rider
Page 2 of 2
Twenty-first Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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.
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.
DEFINITIONS OF SEASONS:
Summer: June 1 through September 30.
Winter: October 1 through May 31.
EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard
metering and/or control equipment.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.02
ELECTRIC RATE SCHEDULE Real Time Pricing Rider
Page 1 of 5
Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
REAL TIME PRICING RIDER
N
N
DESCRIPTION RATE
CODE
Transmission Service 31-660
Primary Service 31-662
Secondary Service 31-664
RULES AND REGULATIONS: Terms and conditions of this electric rate schedule and the
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.
INTERIM RATE ADJUSTMENT:
A 10.95 percent increase will be added to the Customer 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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.02
ELECTRIC RATE SCHEDULE Real Time Pricing Rider
Page 2 of 5
Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.02
ELECTRIC RATE SCHEDULE Real Time Pricing Rider
Page 3 of 5
Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.02
ELECTRIC RATE SCHEDULE Real Time Pricing Rider
Page 4 of 5
Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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 )}
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.02
ELECTRIC RATE SCHEDULE Real Time Pricing Rider
Page 5 of 5
Fifth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 1 of 6
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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
applied to each monthly bill to cover billing, administrative, metering, and communication costs
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.
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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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 2 of 6
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 3 of 6
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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:
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 4 of 6
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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:
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”).
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 5 of 6
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.03
ELECTRIC RATE SCHEDULE Large General Service Rider
Page 6 of 6
Seventh Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.04
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
CT Metering Rider (Large Dual Fuel) Page 1 of 4
Twenty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
CONTROLLED SERVICE - INTERRUPTIBLE LOAD
CT METERING RIDER
(Commonly identified as Large Dual Fuel)
DESCRIPTION Option 1 Option 2
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)
Uncontrolled period N/A 31-169
Controlled period N/A 31-269
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 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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.04
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
CT Metering Rider (Large Dual Fuel) Page 2 of 4
Twenty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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.)
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
Customer Charge per Month: $5.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Annual
Maximum kW per Month: $0.12
Summer Winter
Energy Charge per kWh: 3.603 ¢/kWh 3.893 ¢/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.
R
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.04
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
CT Metering Rider (Large Dual Fuel) Page 3 of 4
Twenty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
OPTION 2
Customer Charge per Month: $6.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Annual
Maximum kW per Month: $0.12
Summer Winter
Energy Charge per kWh: 3.873 ¢/kWh 4.186 ¢/kWh
Control Period Demand Charge
per kW: $7.22 /kW $6.07 /kW
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 rider. 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.
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
rider.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.04
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
CT Metering Rider (Large Dual Fuel) Page 4 of 4
Twenty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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.
EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard
metering and control equipment.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.05
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
Self-Contained Metering Rider (Small Dual Fuel) Page 1 of 3
Twenty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
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 for Customers with approved permanently connected
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.
When service to the electric space heating equipment on this rate is interrupted, the back-up heating
system cannot be electric.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.05
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
Self-Contained Metering Rider (Small Dual Fuel) Page 2 of 3
Twenty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
RATE:
CONTROLLED SERVICE - INTERRUPTIBLE LOAD – SELF-CONTAINED
Customer Charge per Month: $2.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month: $5.00
Summer Winter
Energy Charge per kWh: 4.439 ¢/kWh 4.841 ¢/kWh
Penalty Charge per kWh: 15.702 ¢/kWh 16.930 ¢/kWh
During the Penalty Period, kWhs used will be measured and billed at the Energy Charge
and Penalty listed above.
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 rider. 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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.05
ELECTRIC RATE SCHEDULE Controlled Service – Interruptible Load
Self-Contained Metering Rider (Small Dual Fuel) Page 3 of 3
Twenty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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: 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.
EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard
metering and control equipment.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.06
ELECTRIC RATE SCHEDULE Controlled Service – Deferred Load Rider
(Thermal Storage) Page 1 of 3
Twenty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
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 for Customers with approved permanently connected
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.06
ELECTRIC RATE SCHEDULE Controlled Service – Deferred Load Rider
(Thermal Storage) Page 2 of 3
Twenty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
RATE:
CONTROLLED SERVICE - DEFERRED LOAD
Customer Charge per Month:
$2.00
Monthly Minimum Bill: Customer + Facilities Charges
Facilities Charge per Month: $4.00
Energy Charge per kWh: Summer Winter
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
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 rider. 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.
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.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.06
ELECTRIC RATE SCHEDULE Controlled Service – Deferred Load Rider
(Thermal Storage) Page 3 of 3
Twenty-second Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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 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.
EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard
metering and control equipment.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.07
ELECTRIC RATE SCHEDULE Fixed Time of Service Rider
(Fixed TOS) Page 1 of 4
Sixth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
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
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 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
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 lowtemperature grain drying.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.07
ELECTRIC RATE SCHEDULE Fixed Time of Service Rider
(Fixed TOS) Page 2 of 4
Sixth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
RATE:
FIXED TIME OF 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: 1.774 ¢/kWh 3.473 ¢/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.
R
FIXED TIME OF 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: 1.774 ¢/kWh 3.473 ¢/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.
R
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.07
ELECTRIC RATE SCHEDULE Fixed Time of Service Rider
(Fixed TOS) Page 3 of 4
Sixth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
FIXED TIME OF 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: 1.768 ¢/kWh 3.460 ¢/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
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 rider. See Sections 12.00, 13.00
and 14.00 of the electric rates for the matrices of riders.
DEFINITIONS OF SEASONS:
Summer: June 1 through September 30.
Winter: October 1 through May 31.
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.
Fergus Falls, Minnesota
Interim Minnesota Public Utilities Commission
Section 14.07
ELECTRIC RATE SCHEDULE Fixed Time of Service Rider
(Fixed TOS) Page 4 of 4
Sixth Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause Vice President, Administration
EFFECTIVE with bills rendered on and after
in Minnesota
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.
EQUIPMENT SUPPLIED: The Company will supply and maintain the necessary standard
metering and control equipment.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 14.12 ELECTRIC RATE SCHEDULE
Off-Peak Electric Vehicle Rider (Off-Peak EV)
Page 1 of 3 First Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause
Vice President, Administration
EFFECTIVE with bills renderedon and after
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
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 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
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 14.12 ELECTRIC RATE SCHEDULE
Off-Peak Electric Vehicle Rider (Off-Peak EV)
Page 2 of 3 First Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause
Vice President, Administration
EFFECTIVE with bills renderedon and after
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
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 rider. See Sections 12.00, 13.00 and 14.00 of the electric rates for the matrices of riders.
Fergus Falls, Minnesota
InterimMinnesota Public Utilities Commission
Section 14.12 ELECTRIC RATE SCHEDULE
Off-Peak Electric Vehicle Rider (Off-Peak EV)
Page 3 of 3 First Revision
MINNESOTA PUBLIC UTILITIES COMMISSION Approved: Docket No. E-017/GR-15-1033
Thomas R. Brause
Vice President, Administration
EFFECTIVE with bills renderedon and after
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.
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:
Otter Tail Power Company
215 South Cascade Street
Fergus Falls, MN 56537
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:
121 7th Place East, Suite 350
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
Office of Administrative Hearings
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:
Minnesota Public Utilities Commission
121 7th Place East, Suite 350
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.
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
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:
Otter Tail Power Company
215 South Cascade Street
Fergus Falls, MN 56537
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
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.
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.
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
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:
Otter Tail Power Company
215 South Cascade Street
Fergus Falls, MN 56537
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
85 7th Place East, Suite 500
St. Paul, Minnesota 55101
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
Office of Administrative Hearings
600 North Robert St
St. Paul, Minnesota 55164
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