Otter Tail Power Company Before the Minnesota Public Utilities Commission

Otter Tail Power Company Before the Minnesota Public Utilities Commission Application for Authority to Increase Electric Rates in Minnesota Docket No. E-017/GR-10-239 Volume 1 Notice of Change in Rates Interim Rate Petition

Otter Tail Power Company Minnesota General Rate Case Documents Docket No. E-017/GR-10-239 Volume 1 Notice of Change in Rates Interim Rate Petition 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 Thomas R. Brause Policy Peter J. Beithon Jurisdictional Cost of Service Operating Statement Class Cost of Service Kyle Sem Rate Base Kevin G. Moug Financial Soundness Capital Structure Cost of Capital 2B 2C Direct Testimony and Supporting Schedules Robert B. Hevert Return on Equity Peter Wasberg Employee Compensation Timothy J. Rogelstad Boundary Guidelines Study David G. Prazak Rate Design Proposed Redlined and Non-Redlined Tariff Sheets Proposed Tariff Sheets Redlined Proposed Tariff Sheets Non-Redlined 3 Required Financial Information Index Required Financial Information A. Jurisdictional Financial Summary Schedules (Rule 7825.3900) Definitions Summary of Revenue Requirements Test Year 2009 Jurisdictional Financial Summary Schedule i

Otter Tail Power Company Minnesota General Rate Case Documents Docket No. E-017/GR-10-239 Volume 3 Required Financial Information (Continued) B. Rate Base Schedules (Rule 7825.4000) Definitions 1. Rate Base Summary a. Removes Wind From Actual Year 2009 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 a. Removes Wind From Actual Year 2009 2. Statement of Operating Income Jurisdictional 3. Statement of Operating Income Test Year 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. Composite Cost of Preferred Stock 4. Average Short-Term Debt 5. Average Common-Equity E. Rate Structure and Design Information (Rule 7825.4300) 1. Test Year Operating Revenue Summary Comparison 2. Test Year Operating Revenue Detailed Comparison 3A. Class Cost of Service Study 3B. Component Class Cost of Service Study F. Other Supplemental Information 1. Annual Report and Statistical Supplement 2. Gross Revenue Conversion Factor ii

Otter Tail Power Company Minnesota General Rate Case Documents Docket No. E-017/GR-10-239 Volume 3 Required Financial Information (Continued) G. Commission Policy Information 1. Schedule Detailing Advertising Expenses 1A. Advertising Copy by Category 2. Charitable Contributions 3. Organization Dues 4. Research Expense 4A Workpapers Section 1 2009 Test Year Workpapers Jurisdictional Cost of Service Study (JCOSS) Class Cost of Service Study (CCOSS) Functionalization Input Summary Test Year Adjustments TY-01- Normalized Plant in Service TY-02 - BSP II Deferred Recovery TY-03 - Transmission Distribution transfer TY-04 - Depreciation Expense to Reflect 2009 Rates TY-05 - Special Deposits TY-06 - Weather Normalization TY-07 - FCA True-up Normalization TY-08 - Asset-Based Margins TY-09 - Non-Asset Wholesale Expenses TY-10 - Annual Labor Increases, KPA TY-11 - Employee Medical, Dental, Postemployment (FAS 106 & 112) and Pension (FAS 87) TY-12 - Holding Company Formation Expense TY-13 - Rate Case Expenses TY-14 - Remove Amortization of MISO Schedule 16 & 17 Costs TY-15 - Vegetative Maintenance TY-16 - Storm Damages TY-17 - High Voltage Test Lab TY-18 - Reduction in Capacity Costs TY-19 - Normalize MISO Congestion and Losses TY-20 - MISO Schedule 26 TY-21 - Capital Structure TY-22 - E8760 Adjustment Section 2 2009 Actual Year Workpapers Jurisdictional Cost of Service Study (JCOSS) Functionalization Input Summary Workpapers A-D Section 3 Interim Jurisdictional Cost of Service Study Section 4 Hevert Cost of Capital Workpapers Provided separately on a CD 4B Lead Lag Study Boundary Guideline Study Lead Lag Study Boundary Guideline Study iii

Volume 1 Filing Letter 1/3 Tab

215 South Cascade Street PO Box 496 Fergus Falls, Minnesota 56538-0496 218 739-8200 www.otpco.com (web site) April 2, 2010 Dr. Burl W. Haar 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. E-017/GR-10-239 Dear Dr. Haar: Enclosed is the Application for a Proposed Increase in Electric Rates (the Application ) for Otter Tail Power Company ( OTP or the Company ). This Application is being filed with the Minnesota Public Utilities Commission (the Commission ) pursuant to Minn. Stat. 216B.16, subd. 1. OTP seeks authority to increase base rates by $10,632,383 or 8.01 percent to recover the current cost of providing electric service to our customers, including an appropriate return on common equity. OTP requests final rates be effective June 1, 2010. If the Commission suspends the proposed rate increase pursuant to Minn. Stat. 216B.16, subd. 2, OTP requests that interim rates be effective on June 1, 2010, pursuant to Minn. Stat. 216B.16, subd. 3, with final rates effective within 10 months of the date of the Application. OTP also requests an interim rate increase of $5,051,076, resulting in a 3.80 percent interim increase to be applied to base rate components other than riders. An Equal Opportunity Employer

Dr. Burl W. Harr April 2, 2010 Page 2 OTP s Application for Proposed Increase in Electric Rates is presented in seven volumes as described below: Application/Interim Rates Volume 1 Volumes 2A, 2B, 2C Volume 3 Volumes 4A, 4B Notice of Change in Rates Interim Rate Petition Testimony and Schedules Proposed Rates and Tariffs Required Information Test Year Workpapers 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. Also included in Volume 1 is the Notice and Petition for Interim Rates (the Petition ) that 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. 7825.2600, subpt. 2, OTP is also submitting a separate miscellaneous rate change filing seeking to restate the Base Energy Adjustment Charge for interim rates (Docket No. E- 017/MR-10-240). A copy of the Application has been served on the Department of Commerce Office of Energy Security and the Office of the Attorney General Residential Utilities Division, and the Summary of Filing has been served on all intervenors from the Company s most recent electric rate case, 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 of 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 jwf Enclosures By electronic filing c: Service List

CERTIFICATE OF SERVICE I, Jennifer M. Winningham-Floden, hereby certify that I have this day served a copy of the Application, on Dr. Burl W. Haar and Sharon Ferguson by e-filing, and a copy of the Application on the Office of Attorney General by First Class mail, and all other persons on the attached service list were served by electronic service or by First Class mail with either a copy of the Application or the Summary of the Filing in the following matter. In the Matter of the Application of Otter Tail Power Company for Authority to Increase Rates for Electric Utility Service in Minnesota MPUC Docket No. E-017/GR-10-239 Dated this 2 nd day of April, 2010. /s/ Jennifer M. Winningham-Floden Jennifer M. Winningham-Floden Rate Case Coordinator

Otter Tail Power Company Docket No. E-017/GR-10-239 Burl W. Haar (2) MN Public Utilities Commission Suite 350 121 7 th Place East St. Paul, MN 55101-2147 Ronald M. Giteck (1) Office of Attorney General Residential Utilities Division 445 Minnesota Street 900 BRM Tower St. Paul, MN 55101-2130 Michael Bradley (1) Moss & Barnett 4800 Wells Fargo Center 90 South Seventh Street Minneapolis, MN 55402-4129 Larry L. Schedin (1) LLS Resources, LLC Suite 1137 12 South Sixth Street Minneapolis, MN 55402 Christopher Anderson* Minnesota Power 30 W. Superior Street Duluth, MN 55802-2191 Gary Chesnut* AG Processing, Inc. 12700 West Dodge Road P. O. Box 2047 Omaha, NE 68103-2047 William T. Davis* 24524 West Rivers Bend Road Fergus Falls, MN 56537-8101 Sharon Ferguson (4) State of Minnesota Department of Commerce 85 7 th Place E., Ste. 500 St. Paul, MN 55101-2198 Richard Savelkoul (1) Felhaber, Larson, Fenlon & Vogt, P.A. 444 Cedar St., Ste. 2100 St. Paul, MN 55101-2136 Richard Johnson (1) Moss & Barnett 4800 Wells Fargo Center 90 South Seventh Street Minneapolis, MN 55402-4129 Bruce Gerhardson (1) Otter Tail Power Company 215 South Cascade Street P. O. Box 496 Fergus Falls, MN 56538-0496 Thomas Erik Bailey* Briggs and Morgan 2200 IDS Center 80 South 8 th Street Minneapolis, MN 55402 Christopher Clark* Xcel Energy 5 th Floor 414 Nicollet Mall Minneapolis, MN 55401-1993 Jonathan M. Drews* Utility Research P. O. Box 230 Fergus Falls, MN 56538 John Lindell (1) Office of Attorney General Residential Utilities Division 445 Minnesota Street 900 BRM Tower St. Paul, MN 55101-2130 Andrew Moratzka (1) Mackall Crounse & Moore Law Offices 1400 AT&T Tower 901 Marquette Avenue Minneapolis, MN 55402-2859 Mike Franklin (1) Minnesota Chamber of Commerce Suite 1500 400 Robert Street North St. Paul, MN 55101 Ron Spangler, Jr. (1) Otter Tail Power Company 215 South Cascade Street P. O. Box 496 Fergus Falls, MN 56538-0496 Michele Beck* Great River Energy 12300 Elm Creek Boulevard Maple Grove, MN 55369-4718 Derick O. Dahlen* Avant Energy Services Suite 300 200 South Sixth Street Minneapolis, MN 55402 James C. Erickson* Kelly Bay Consulting 17 Quechee Superior, WI 54880 *Sent Summary Notice

Otter Tail Power Company Docket No. E-017/GR-10-239 Edward Garvey* 32 Lawton Street St. Paul, MN 55102 Elizabeth Goodpaster* MN Center for Environmental Advocacy Suite 206 26 East Exchange Street St. Paul, MN 55101-1667 Shane Henriksen* Enbridge Energy Company, Inc. Second Floor 1409 Hammond Avenue Superior, WI 54880-1674 James D. Larson* Avant Energy Services 200 South Sixth Street, Suite 300 Minneapolis, MN 55402-1423 Patrick J. Mastel* Missouri River Energy Services 3724 W. Avera Drive P. O. Box 88920 Sioux Falls, SD 57109-8920 Jeffrey L. Nelson* East River Electric Power Coop. 121 SE First Street P. O. Box 227 Madison, SD 57042 Sherry Gaugler* Jeffrey C. Paulson & Associates, Ltd. Suite 325 7301 Ohms Lane Edina, MN 55439 William Harrington* Excelsior Energy, Inc. Suite 305 11100 Wayzata Boulevard Minnetonka, MN 55305 Michael C. Krikava* Briggs and Morgan, P.A. 2200 IDS Center 80 South 8th Street Minneapolis, MN 55402 Kavita Maini* KM Energy Consulting LLC 961 North Lost Woods Road Oconomowoc, WI 53066 Tim Miller* Missouri River Energy Services 3724 W. Avera Drive P. O. Box 88920 Sioux Falls, SD 57109-8920 James Nessa* Utility Research P. O. Box 230 Fergus Falls, MN 56538 Piedmont Consulting, Inc.* 701 4th Avenue South, Suite 500 Minneapolis, MN 55402 Annete Henkel* Minnesota Utility Investors 413 Wacouta St., #230 St. Paul, MN 55101 Douglas Larson* Dakota Electric Association 4300 220th St. W. Farmington, MN 55024 Pam Marshall* Energy CENTS Coalition 823 7th St. E. St. Paul, MN 55106 Jenny L. Myers* Izaak Walton League of America Suite 202 1619 Dayton Ave. St. Paul, MN 55104 Marcia Podratz* Minnesota Power 30 West Superior Street Duluth, MN 55802 *Sent Summary Notice

Otter Tail Power Company Docket No. E-017/GR-10-239 Steve Sanda* 101 Park Circle Ottertail City, MN 56571-7003 SaGonna Thompson* Xcel Energy 414 Nicollet Mall FL 7 Minneapolis, MN 55401-1993 Robert H. Schulte* Schulte Associates LLC 15347 Boulder Pointe Road Eden Prairie, MN 55347 Curt Walvatne* 210 ½ N. Cascade St., Apt. 6 Fergus Falls, MN 56537 William Stamets* Office of the Attorney General Suite 900 445 Minnesota Street St. Paul, MN 55101-2127 *Sent Summary Notice

Volume 1 Notice of Change in Rates 1/3 Tab

STATE OF MINNESOTA BEFORE THE David Boyd Chair J. Dennis O'Brien Commissioner Thomas Pugh Commissioner Phyllis Reha Commissioner Betsy Wergin Commissioner In the Matter of the Application of Otter Tail Power Company For Authority to Increase Rates for Electric Utility Service in Minnesota MPUC Docket No.: E-017/GR-10-239 Notice of Change in Rates A. Introduction Otter Tail Power Company ( OTP or the Company ) hereby applies for authority from the Minnesota Public Utilities Commission (the Commission ) to increase retail electric rates in Minnesota pursuant to Minn. Stat. 216B.16 and Minn. R. 7825.3100-7825.4600 and 7829.2400 (the Application ). This Application is for an increase in base rates of $10,632,383 million or 8.01 percent to be effective June 1, 2010, without suspension, pursuant to Minn. Stat. 216B.16, subd 1. If the Commission elects to suspend the proposed rate increase under Minn. Stat. 216B.16, subd. 2, the Company requests, pursuant to Minn. Stat. 216B.16, subd. 3, an interim rate increase of $5,051,076 or 3.80 percent to be effective on June 1, 2010, with final rates becoming effective within 10 months of the date of the Application. The typical residential electric customer uses 9,528 kilowatt-hours per year. On average, the proposed rate change would increase the bill for a typical residential electric customer by $7.28 per month or $87.36 annually. The interim increase, if the requested rates are suspended, for that same annual amount of usage, on average, would be $2.54 per month or $30.48 per year. OTP s total revenue deficiency in this case is $10,632,383 or 8.01 percent and the Company s proposal includes the following proposed change in how asset-based wholesale margins are credited. OTP proposes to move the asset-based wholesale margins from providing a credit to base rates to providing a credit to the Energy Adjustment Rider revenue requirement. Based on the level of asset-based margins received by the Company in 2009, this proposed change results in a $1,518,119 increase in base rates and a $1,518,119 decrease in the Energy Adjustment Rider. The actual amount of the credit to the Energy Adjustment Rider will vary each year and may be higher or lower than $1,518,119. OTP is also proposing a few changes to rate designs and terms of service. This Application includes the following information in accordance with Minnesota Statutes and the Commission s rules:

B. Notice and Proposal Regarding General Rate Change. (Minn. R. 7825.3200A(1) and 7825.3500) 1. Name, address and telephone number of utility. Otter Tail Power Company 215 South Cascade Street Fergus Falls, MN 56537 218-739-8200 2. Name, address and telephone number of attorneys for the utility. Bruce Gerhardson Associate General Counsel Otter Tail Power Company P.O. Box 496 215 South Cascade Street Fergus Falls, MN 56538-0496 218-998-7108 and Michael J. Bradley Richard J. Johnson Moss & Barnett 4800 Wells Fargo Center 90 South Seventh Street Minneapolis, MN 55402 612-877-5000 3. Date of filing and date modified rates are to be effective. The date of this filing is April 2, 2010. Pursuant to Minn. Stat. 216B.16, subd. 1, OTP proposes and requests that the overall requested electric rates increase become effective June 1, 2010, 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. If the Commission suspends the proposed electric rates pursuant to Minn. Stat. 216B.16, subd. 2, then, pursuant to Minn. Stat. 216B.16, subd. 3, the Company requests that the Commission approve the interim electric rates proposed in the Petition for Interim Rates, which is filed as a part of this Application, effective on June 1, 2010, with final rates effective within 10 months of the date of this Application. 4. 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, 2009. 2

This filing complies with the provisions of Minn. Stat. 216B.16 and the Commission s rules governing rate changes. 5. Effect of the change in rates. The overall increase in base rates is $10,632,383 and 8.01 percent. The typical residential electric customer uses 9,528 kilowatt-hours per year. On average, the proposed rate change would increase the overall bill for a typical residential electric customer by $7.28 per month or $87.36 annually. The interim increase, if the requested rates are suspended, for that same annual amount of usage, on average, would be $2.54 per month or $30.48 per year. 6. 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. C. Modified rates. (Minn. R. 7825.3200(A)(2) and 7825.3600) Attached to this Application are rate schedules containing the proposed changed rates and tariffs. These schedules and tariffs are included in Volume 2C of the Application and are supported by the pre-filed Direct Testimony of David G. Prazak. D. 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. E. Information requirements. (Minn. R. 7825.3200(A)(4) and 7825.3800-7825.4400) Included in this Application in Volumes 2A and 2B are the Direct Testimonies of the Company s witnesses, Volume 2C contains our proposed tariffs, which along with Volume 3, Required Information, and Volumes 4A and 4B, Test Year Workpapers, represents 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. The data for the most recent fiscal year is 2009. The projected fiscal year is 2010. The proposed test year is a historic test year ending December 31, 2009, with known and measurable changes. 3

F. 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. G. 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. H. Customer notice. (Minn. R. 7829.2400, subpt. 3) OTP will notify customers through a bill insert of its Application to increase retail electric rates and explain the proposed general 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). I. 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. 1. Summary. A summary of the Application is attached to this notice. 2. Service; proof of service. OTP has served copies of the Application on the Department of Commerce - Office of Energy Security and the Office of the Attorney General Residential Utilities Division. OTP will serve a copy of the Summary of Filing on the other parties on the general service list for OTP electric filings and on the parties in the Company s last electric rate case proceedings (Docket No. E- 017/GR-07-1178). The combined service list for these proceedings and a certificate of service are attached. 4

3. Notice to public and governing bodies. See Sections G. and H., 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. 4. 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. J. 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: Ron L. Spangler, Jr. Rate Case Manager 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 Michael J. Bradley Richard J. Johnson Moss & Barnett 4800 Wells Fargo Center 90 South 7th Street Minneapolis, MN 55402 5

K. Conclusion. The Company respectfully requests consideration and acceptance of its Application. Dated: April 2, 2010 Respectfully submitted, /s/ THOMAS R. BRAUSE Thomas R. Brause Vice President, Administration Otter Tail Power Company Subscribed and sworn to before me this 2 nd day of April, 2010 /s/ JENNIFER M. WINNINGHAM-FLODEN Notary Public My Commission expires January 31, 2013. 6

STATE OF MINNESOTA BEFORE THE David Boyd Chair J. Dennis O'Brien Commissioner Thomas Pugh Commissioner Phyllis Reha Commissioner Betsy Wergin Commissioner In the Matter of the Application of Otter Tail Power Company For Authority to Increase Rates for Electric Utility Service in Minnesota MPUC Docket No.: E-017/GR-10-239 SUMMARY OF FILING On April 2, 2010, Otter Tail Power Company ( OTP ) filed with the Minnesota Public Utilities Commission (the Commission ) an application to increase base retail electric rates in the State of Minnesota (the Application ). OTP requests an increase in base rates of $10,632,383 or 8.01 percent. OTP proposes to move the asset-based wholesale margins from providing a credit to base rates to providing a credit to the Energy Adjustment Rider revenue requirement. Based on the level of asset-based margins received by the Company in 2009, this proposed change results in a $1,518,119 increase in base rates and a $1,518,119 decrease in the Energy Adjustment Rider. The actual amount of the credit to the Energy Adjustment Rider will vary each year and may be higher or lower than $1,518,119. If the Commission elects to suspend the proposed rate increase under Minn. Stat. 216B.16, subd. 2, the Company requests, pursuant to Minn. Stat. 216B.16, subd. 3, that an interim rate increase of $5,051,076 or 3.80 percent be effective on June 1, 2010, with final rates becoming effective within 10 months of the date of the Application. The typical residential electric customer uses 9,528 kilowatt-hours per year. On average, the proposed rate change would increase the bill for a typical residential electric customer by $7.28 per month or $87.36 annually. The interim increase, if the requested rates are suspended, for that same annual amount of usage, on average, would be $2.54 per month or $30.48 per year. OTP is also proposing a few changes to rate designs and terms of service. The proposed rate schedules and a comparison of present and proposed rates are available at http://www.otpco.com/electricrates/mnratecase.asp 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.

Volume 1 Notice and Petition for Interim Rates 1/3 Tab

2. 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 April 2, 2010. This Petition is submitted as part of the Company s Application for a general electric rate increase (the 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 June 1, 2010, 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. 3. 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 Supporting Schedules accompanying this Petition set forth the calculation of the interim revenue deficiency of $5,051,076 or 3.80 percent for OTP s electric utility operations. As required by Minn. Stat. 216B.16, subd. 3, and the Commission s Statement of Policy on Interim Rates, OTP has removed from the interim rate request the recovery of costs that are not of the same nature and kind as allowed in the most recent rate proceeding. Those adjustments are described in Schedule B, Part 2, Description of Changes to the Operating Income. The return on equity requested for interim rates for OTP is 10.43 percent, which is the percent approved by the Commission in OTP s last electric rate case (Docket No. E-017/GR-07-1178). An adjustment has been made to credit asset-based margins to base rates for interim rate purposes. In addition, OTP proposes to recover the transmission revenue requirement through the Transmission Cost Recovery Rider ( TCRR ) during the period interim rates are in effect, and therefore an adjustment has been made to reflect this continuation of TCRR recovery through the interim rate period. 4. 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 most recently approved electric rate case (Docket No. E-017/GR-07-1178) is contained in Schedule E of this filing. 2

5. 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 test year for OTP s general electric rate increase filing is the calendar year ending 2009, with known and measurable changes. The revenue requirement study supporting the necessity for interim rate relief shows a deficiency in revenue of $5,051,076 under present rates. Present rates, as referred to in this Petition, are the rates authorized by the Commission in its final order in Docket No. E-017/GR-07-1178. OTP is requesting an interim rate adjustment which will increase OTP s test year revenues, exclusive of separately collected revenues related to franchise fees or gross earnings taxes imposed by local governmental units, by $5,051,076 or 3.80 percent increase above present rates. 6. Certification by chief executive officer of the utility. (Policy Statement, Item 6, page 2) This Petition contains a certificate signed by Thomas R. Brause, Vice President Administration, Otter Tail Power Company, affirming that this interim rate Petition complies with Minnesota Statutes. 7. Methods and procedures for refunding. Pursuant to Minn. Stat. 216B.16, subd. 3, another section of this filing contains the Company s Agreement and Undertaking of Refund by OTP. 8. Signature and title of the utility officer authorizing the proposed interim rates. (Policy Statement, Item 7, page 2) See signature page at the end of this Petition. 9. 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 a separate section. 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. E-017/GR-07-1178; 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. 10. 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 3.80 percent to all base rate categories, which would 3

provide an additional $5,051,076 of base rate revenues on an annualized basis. The Company also filed a petition in Docket E-017/MR-10-240 to reset the base cost of energy from 2.5711 cents to 2.3122 cents (a reduction of 0.2589 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, which is a reduction of 0.2589 cents. Also included is a schedule of interim revenue impacts under the tab Summary of Present and Interim Revenue. 11. 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. 12. 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. 4

C. Conclusion OTP hereby submits this 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 Petition for Interim Rates be promptly considered and accepted by the Commission, and that the interim rate schedules be approved and made effective on June 1, 2010, pursuant to Minn. Stat. 216B.16, subd. 3, subject to refund pending final Commission action on the general rate increase Application. Dated: April 2, 2010 Respectfully submitted, /s/ THOMAS R. BRAUSE Thomas R. Brause Vice President, Administration Otter Tail Power Company Subscribed and sworn to before me this 2 nd day of April, 2010 /s/ JENNIFER M. WINNINGHAM-FLODEN Notary Public My Commission expires January 31, 2013. 5

Volume 1 Agreement and Undertaking, and Certification 1/3 Tab

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: April 2, 2010 /s/ THOMAS R. BRAUSE Thomas R. Brause Vice President, Administration Otter Tail Power Company Subscribed and sworn to before me this 2 nd day of April, 2010 /s/ JENNIFER M. WINNINGHAM-FLODEN Notary Public My Commission expires January 31, 2013.

Volume 1 Interim Supporting Schedules and Workpapers 1/3 Tab

INTERIM RATE SCHEDULES INDEX Docket No. E017/GR-10-239 PART A: Interim Rate Summary 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 PART B: Comparison of Proposed Interim Rates to 2009 Test Year 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 PART C: Comparison of Proposed Interim Rates to Most Recent General Rate Case (2006) 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 PART D: Comparison of Proposed Interim Rates to 2009 Actual Year 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 PART E: Most Recent General Rate Case (2006) to 2009 Actual Rates 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

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 INTERIM RATE INCREASE PART A REVENUES & PERCENT INCREASE Schedule 1 Page 1 of 1 Total Interim Retail Revenues $132,806,609 Interim Deficiency $5,051,076 Total Interim Revenue % Increase 3.80%

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART A INTERIM RATE SCHEDULE Schedule 2 SUMMARY OF REVENUE REQUIREMENTS Page 1 of 2 DESCRIPTION OF INTERIM RATE PETITION REQUIREMENTS, SUPPORTING SCHEDULES AND WORKPAPERS The Minnesota Public Utilities Commission (the 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 equivalent operating income statement corresponding with the most recent actual year for which audited data is available and corresponding with the same period in months as the test year, if the test year is a projected 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 most recent actual year for which audited data is available with the income statement for the 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 most recent actual year for which audited data is available, including a description of all changes and corresponding dollar amounts. Although the Commission s Statement of Policy does not require regulated companies to do so, OTP has included as Part B, Schedule 3, a comparison of the operating income statement for this general rate case filing with the income statement for the proposed interim test year, as well as Part B, Schedule 4, a bridge schedule of the operating income statement for this general rate case filing 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-10-239 Electric Utility - State of Minnesota PART A INTERIM RATE SCHEDULE Schedule 2 SUMMARY OF REVENUE REQUIREMENTS 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 equivalent average rate base corresponding with the most recent actual year for which audited data is available and corresponding with the same period in months as the test year, if the test year is a projected test 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 most recent actual year for which audited data is available 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 most recent actual year for which audited data is available, including a description of all changes and corresponding dollar amounts. Although not required by the Commission s Policy Statement, OTP has included as Part B, Schedule 1, comparison of the average rate base for this general rate case filing with the average rate base for the proposed interim test year, as well as Part B, Schedule 2, a bridge schedule of the average rate base for this general rate case filing 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 4 of this filing. 4) 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 3, shows the revenue deficiency calculations for the most recent general rate case and for the proposed interim rates. Part D, Schedule 3, shows the revenue deficiency calculations for the most recent actual year for which audited data is available and for the proposed interim rates. Part E, Schedule 3, shows the revenue deficiency calculations for the most recent general rate case and the most recent actual year for which audited data is available. Although not required by the Commission s Policy Statement, OTP has included as Schedule B, Part 5 of 5 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-10-239 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 Year The proposed interim test year information is for the calendar year ending December 31, 2009 and includes the effect of rate making adjustments for interim rates. General Rate Case Filing The general rate case filing information represents the financial information for the 2009 calendar year and includes the effects of rate making adjustments for final rates. Most Recent General Rate Case This information represents the financial data for the 12 months test year ending December 31, 2006, from Otter Tail Power Company s last Minnesota electric rate case (Docket No. E-017/GR- 07-1178), as approved by the Commission. Most Recent Actual Year This information represents actual unadjusted financial information for the calendar year ended December 31, 2009. Note on Rounding The 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-10-239 Electric Utility - State of Minnesota PART A INTERIM RATE SCHEDULE Schedule 4 SUMMARY OF REVENUE REQUIREMENTS Page 1 of 1 Interim Rate Line Petition No. Description Present Rates 1 Average Rate Base $215,053,382 2 Operating Income (Before AFUDC) 14,697,846 3 Allowance for Funds Used During Construction (AFUDC) 577,235 4 Total Available for Return (Line 2 + Line 3 + Rounding) 15,275,081 5 Overall Rate of Return (Line 4 / Line 1) 7.10% 6 Required Rate of Return 8.48% 7 Operating Income Requirement (Line 1 x Line 6) 18,236,527 8 Income Deficiency (Line 7 - Line 4) 2,961,447 9 Gross Revenue Conversion Factor 1.705611 10 Revenue Deficiency (Line 8 x Line 9) 5,051,076 11 Retail Related Revenues Under Present Rates 132,806,609 12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 3.80%

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART A INTERIM RATE SCHEDULE Schedule 5 STATEMENT OF OPERATING INCOME Page 1 of 1 Line No. Description OPERATING REVENUES Interim Rate Petition Present Rates 1 Retail $132,806,609 2 Other Operating Revenue 12,379,999 3 TOTAL OPERATING REVENUE $145,186,608 4 OPERATING EXPENSES 5 Production Expenses $69,631,772 6 Transmission Expenses 5,463,954 7 Distribution Expenses 6,911,957 8 Customer Accounting Expenses 5,577,131 9 Customer Service & Information Expenses 3,879,658 10 Sales Expenses 254,585 11 Administration & General Expenses 16,593,260 12 Charitable Contributions 96,752 13 Depreciation Expense 13,451,817 14 General Taxes 3,864,391 15 TOTAL OPERATING EXPENSES $125,725,277 16 NET OPERATING INCOME BEFORE INCOME TAXES $19,461,331 17 INCOME TAX EXPENSE 18 Investment Tax Credit ($475,324) 19 Deferred Income Taxes 9,876,833 20 Income Taxes (4,638,024) 21 TOTAL INCOME TAX EXPENSE $4,763,485 22 NET OPERATING INCOME $14,697,846 23 Allowance for Funds Used During Construction 577,235 24 TOTAL AVAILABLE FOR RETURN $15,275,081 Note: Revenues reflect calendar month sales.

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART A INTERIM RATE SCHEDULE Schedule 6 DETAILED RATE BASE COMPONENTS Page 1 of 1 Line No. Description Interim Rate Petition Present Rates Utility Plant in Service: 1 Production $198,167,284 2 Transmission 99,556,918 3 Distribution 156,578,523 4 General 36,203,368 5 Intangible 1,849,317 6 TOTAL Utility Plant in Service $492,355,410 7 Accumulated Depreciation 8 Production ($115,240,453) 9 Transmission (38,853,474) 10 Distribution (65,548,292) 11 General (14,960,351) 12 Intangible (524,017) 13 TOTAL Accumulated Depreciation ($235,126,588) 14 NET Utility Plant in Service 15 Production $82,926,831 16 Transmission 60,703,444 17 Distribution 91,030,231 18 General 21,243,017 19 Intangible 1,325,300 20 NET Utility Plant in Service $257,228,822 21 Big Stone Plant capitalized items $0 22 Utility Plant Held for Future Use 13,553 23 Construction Work in Progress 10,753,544 24 Materials and Supplies 7,418,264 25 Fuel Stocks 4,388,966 26 Prepayments (16,660,756) 27 Customer Advances & Deposits (480,160) 28 Cash Working Capital 2,750,394 29 Accumulated Deferred Income Taxes (50,359,245) 30 Total Average Rate Base $215,053,382

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART B COMPARISON OF PROPOSED INTERIM RATES TO 2009 TEST YEAR Schedule 1 DETAILED RATE BASE COMPONENTS Page 1 of 1 (A) (B) (C) = (B) - (A) Interim Rate Line 2009 Test Petition No. Description Year Present Rates Change Utility Plant in Service: 1 Production $203,323,264 $198,167,284 ($5,155,980) 2 Transmission 102,098,558 99,556,918 (2,541,640) 3 Distribution 156,578,523 156,578,523 0 4 General 36,203,373 36,203,368 (5) 5 Intangible 1,849,318 1,849,317 (0) 6 TOTAL Utility Plant in Service $500,053,035 $492,355,410 ($7,697,625) 7 Accumulated Depreciation 8 Production ($115,240,453) ($115,240,453) $0 9 Transmission (38,885,215) (38,853,474) 31,741 10 Distribution (65,548,292) (65,548,292) 0 11 General (14,960,353) (14,960,351) 2 12 Intangible (524,017) (524,017) 0 13 TOTAL Accumulated Depreciation ($235,158,331) ($235,126,588) $31,743 14 NET Utility Plant in Service 15 Production $88,082,812 $82,926,831 ($5,155,980) 16 Transmission 63,213,342 60,703,444 (2,509,899) 17 Distribution 91,030,231 91,030,231 0 18 General 21,243,019 21,243,017 (3) 19 Intangible 1,325,300 1,325,300 (0) 20 NET Utility Plant in Service $264,894,704 $257,228,822 ($7,665,882) 21 Big Stone Plant capitalized items 0 0 $0 22 Utility Plant Held for Future Use 13,553 13,553 $0 23 Construction Work in Progress 6,598,890 10,753,544 4,154,654 24 Materials and Supplies 7,418,264 7,418,264 (0) 25 Fuel Stocks 4,388,966 4,388,966 0 26 Prepayments (16,682,186) (16,660,756) 21,431 27 Customer Advances & Deposits (480,778) (480,160) 618 28 Cash Working Capital 2,575,586 2,750,394 174,808 29 Accumulated Deferred Income Taxes (50,580,653) (50,359,245) 221,407 30 Total Average Rate Base $218,146,346 $215,053,382 ($3,092,964)

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART B COMPARISON OF PROPOSED INTERIM RATES TO 2009 TEST YEAR Schedule 2 DETAILED RATE BASE COMPONENTS Page 1 of 1 DESCRIPTION OF ADJUSTMENTS There are a total of four adjustments that convert the Rate Base of the General Rate Petition to the Rate Base Proposed for Interim Rates. A bridge from the General Rate Petition rate base to the Interim Rate Petition rate base is provided in Part B, Schedule 3. Net Electric Plant in Service (2 related adjustments) OTP s General Rate Application requests approval to include costs currently included in the transmission cost recovery rider to be included in base rates. An adjustment is being made to the Interim Rate Application to remove the costs associated with the transmission rider as the rider will remain in effect during the interim period. In addition, the General Rate Application requests approval to include recovery of the Big Stone II costs. These investments have not been approved for recovery at the time of this filing so an adjustment is being made to the Interim Rate Application to remove those costs. There are numerous components to rate base that are impacted as a result of these two adjustments that will be discussed below. Construction Work in Progress An adjustment is being made to the Interim Rate Application to remove the costs associated with the transmission rider and recovery of Big Stone II costs discussed earlier that are included in construction work in progress in the General Rate Application. Cash Working Capital A negative adjustment was made to Cash Working Capital for interim rates that slightly reduced the amount of positive Cash Working Capital from the level included in the General Rate Application. The Cash Working Capital amount is determined by applying the various components of the lead/lag study to the test year revenue and expense amounts. Certain adjustments made to the income statement for interim rate purposes produced reduced expense dollar leads and increased revenue dollar lag to which the lead/lag study factors were applied. Accumulated Deferred Income Taxes An adjustment is being made to the Interim Rate Application to remove the costs associated with the transmission rider and recovery of Big Stone II costs discussed earlier that are included in accumulated deferred income taxes in the General Rate Application. Changes in Allocations due to Interim Rate Adjustments OTP uses its jurisdictional cost of service (JCOS) 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 JCOS 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-10-239 Electric Utility - State of Minnesota PART B COMPARISON OF PROPOSED INTERIM RATES TO 2009 TEST YEAR Schedule 3 RATE BASE WITH ADJUSTMENTS (BRIDGE SCHEDULE) Page 1 of 1 (A) (B) (C) (D) (E) (F) Remove BSP II Impact of Operating Changes in Deferred Recovery Transmission Statement Allocations Due to Interim Rate Line 2009 Test Test Year Rider Amounts Adjustments on Cash Effect of Interim Petition No. Description Year Adjustment Removed Working Capital Adjustments Present Rates (1) 1 Electric Plant in Service * $500,053,035 ($5,155,980) ($2,541,640) $0 ($5) $492,355,410 2 Less: Accumulated Depreciation* (235,158,331) 0 31,741 0 $2 (235,126,588) 3 Net Electric Plant in Service $264,894,704 ($5,155,980) ($2,509,899) $0 ($3) $257,228,822 4 Other Rate Base Components: 5 Plant Held for Future Use $13,553 $0 $0 $0 $0 $13,553 6 Construction Work in Progress 6,598,890 4,154,654 0 0 0 10,753,545 7 Materials and Supplies 7,418,264 0 0 0 0 7,418,264 8 Fuel Stocks 4,388,966 0 0 0 0 4,388,966 9 Prepayments (16,682,186) 0 0 0 21,431 (16,660,755) 10 Customer Advances (480,778) 0 0 0 618 (480,160) 11 Cash Working Capital 2,575,586 0 0 174,808 0 2,750,394 12 Accumulated Deferred Income Taxes (50,580,653) 0 171,340 0 50,068 (50,359,245) 13 Unamortized Balance - Spiritwood 0 0 0 0 0 0 14 TOTAL $218,146,346 ($1,001,326) ($2,338,559) $174,808 $72,114 $215,053,382 (1) Electric Utility - Minnesota Jurisdiction

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART B COMPARISON OF PROPOSED INTERIM RATES TO 2009 TEST YEAR Schedule 4 STATEMENT OF OPERATING INCOME Page 1 of 1 (A) (B) (C) = (B) - (A) Interim Rate Line 2009 Test Petition No. Description Year Present Rates Change OPERATING REVENUES 1 Retail $132,806,609 $132,806,609 $0 2 Other Operating Revenue 6,112,618 12,379,999 6,267,381 3 TOTAL OPERATING REVENUE $138,919,227 $145,186,608 $6,267,381 4 OPERATING EXPENSES 5 Production Expenses $64,876,750 $69,631,772 $4,755,022 6 Transmission Expenses 5,500,044 5,463,954 (36,090) 7 Distribution Expenses 6,965,971 6,911,957 (54,014) 8 Customer Accounting Expenses 5,620,119 5,577,131 (42,989) 9 Customer Service & Information Expenses 3,902,863 3,879,658 (23,204) 10 Sales Expenses 254,585 254,585 0 11 Administration & General Expenses 16,738,839 16,593,260 (145,580) 12 Charitable Contributions 96,752 96,752 0 13 Depreciation Expense 14,791,595 13,451,817 (1,339,779) 14 General Taxes 3,906,312 3,864,391 (41,920) 15 TOTAL OPERATING EXPENSES $122,653,830 $125,725,277 $3,071,447 16 NET OPERATING INCOME BEFORE INCOME TAXES $16,265,397 $19,461,331 $3,195,934 17 INCOME TAX EXPENSE 18 Investment Tax Credit ($475,598) ($475,324) $274 19 Deferred Income Taxes 10,181,518 9,876,833 (304,685) 20 Income Taxes (6,319,486) (4,638,024) 1,681,462 21 TOTAL INCOME TAX EXPENSE $3,386,433 $4,763,485 $1,377,052 22 NET OPERATING INCOME $12,878,964 $14,697,846 $1,818,882 23 Allowance for Funds Used During Construction 324,110 577,235 253,126 24 TOTAL AVAILABLE FOR RETURN $13,203,073 $15,275,081 $2,072,008 Notes: Revenues reflect calendar month sales

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART B COMPARISON OF PROPOSED INTERIM RATES TO 2009 TEST YEAR Schedule 5 STATEMENT OF OPERATING INCOME Page 1 of 2 DESCRIPTION OF ADJUSTMENTS Part B, Schedule 3, contains a bridge schedule itemizing the changes from the General Rate Petition operating income statement to the Interim Rate Petition operating income statement. Nine adjustments have been made to bridge the General Petition operating income statement to the Proposed Interim operating income statement. Adjustment to Remove Costs Associated with Big Stone II Deferred Recovery An adjustment has been made to remove OTP s proposal for recovery associated with the costs on Big Stone II similar to what was discussed in Part B Schedule 2. These investments have not been approved for recovery at the time of this filing so an adjustment is being made to the Interim Rate Application to remove those costs. This adjustment simply reverses the adjustment made to the Test Year. Adjustment to Remove Transmission Rider Costs An 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 General Rate Petition. 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 FAS 106 Amortization Expense An adjustment has been made to remove the current year FAS 106 amortization expense as Ordered in OTP s most recent General Rate Petition, Docket No. E017/GR-07-1178. OTP is proposing recovery of the amortization expense in this General Rate Petition so an adjustment is needed for interim purposes to match the most recent Order. Adjust Revenues to Include Asset-Based Wholesale Margins An adjustment has been made to add back the asset-based wholesale margins. In the Application for final rates, OTP proposes moving the wholesale margins from providing a credit to base rates to providing a credit to the fuel clause revenue requirement. Included in that proposal is a request for Commission authorization to apply the wholesale margin credit to fuel costs effective with the implementation of final rates. Adjustment to Remove Non Asset-Based Expense Adjustment Related to Incremental Cost Study An adjustment was made in the General Rate Petition for final rates to determine the expenses associated with Non Asset-Based trading activity based on actual incremental costs as opposed to a volumetric method which has been used in the past. An expense adjustment was made to remove costs associated with non asset-based activity to below-the-line activity in the Order in Docket E017/GR-07-1178. That method was based on a volumetric calculation and the adjustment needed in the Interim Petition in this case is to convert back to a volumetric calculation. This adjustment is simply the reversal of the adjustment made in the Test Year to convert to an incremental expense calculation. Adjustment to Reverse Test Year Adjustment for Holding Company Costs An adjustment was made in the Test Year for OTP s proposal to recover deferred costs associated with the Holding Company formation that occurred during the Actual Year. The adjustment proposal is to recover the annual amortization expense associated with the unamortized balance of costs over a three year period. This adjustment is simply a reversal of the Test Year adjustment.

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART B COMPARISON OF PROPOSED INTERIM RATES TO 2009 TEST YEAR Schedule 5 STATEMENT OF OPERATING INCOME Page 2 of 2 DESCRIPTION OF ADJUSTMENTS Adjustment to Reverse Test Year Adjustment for Removal of High Voltage Test Lab Revenue An adjustment was made in the Test Year for OTP s proposal to remove the annual revenue addition that is made related to the Settlement Stipulation dated September 18, 1997 and by Commission Order dated October 17, 1997 in Docket No. E017/PA-97-697. That settlement 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. At the time, the Commission wanted compensation for rate payers for the loss of profit from the Test Lab. OTP s proposal in this General Rate Petition is to remove the adjustment as it had been ten years from the date of that Order to the time OTP filed its last case in 2007. At the time of the Order in Docket No. E017/PA-97-697 it wasn t known that it would be ten years until OTP filed its next rate case and as a result it is OTP s position that this adjustment wasn t intended to last indefinitely. This adjustment simply removes that Test Year adjustment from the interim petition to match the Order in Docket No. E017/GR-07-1178. Adjustment to Remove Test Year adjustment for MISO Schedule 16 & 17 Deferred Amortization An adjustment was made in the Test Year to remove the deferred amortization associated with the recovery of MISO Schedule 16 & 17 costs over a three year period as Ordered in OTP s most recent General Rate Case, Docket No. E017/GR-07-1178. The adjustment was made in the Test Year because the three year amortization period will be up at the time final rates go into effect. The adjustment in this interim petition is to reverse the Test Year adjustment as the Ordered amortization period will remain in effect during the interim rate period. Changes in Allocations due to Interim Rate Adjustments OTP uses its jurisdictional cost of service (JCOS) 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 JCOS 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-10-239 Electric Utility - State of Minnesota PART B COMPARISON OF PROPOSED INTERIM RATES TO 2009 TEST YEAR Schedule 6 STATEMENT OF OPERATING INCOME WITH ADJUSTMENTS (BRIDGE SCHEDULE) Page 1 of 1 (A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) Remove BSP II Remove Remove Remove Remove Changes in Deferred Recovery Transmission FAS 106 Adj Asset-Based Non-Asset Holding Co. Amortization of Allocations Due Interim Rate Line 2009 Test Test Year Rider Amounts as Ordered in Margins Wholesale Exp Formation High Voltage Deferred MISO to Effect of Interim Petition No. Description Year Adjustment Removed Docket #07-1178 Adjustment Adjustment Expenses Test Lab Sched 16 & 17 Adjustments Present Rates OPERATING REVENUES 1 Retail $132,806,609 $0 $0 $0 $0 $0 $0 $0 $0 $0 $132,806,609 2 Other Operating Revenue 6,112,618 0 0 0 6,177,837 0 0 96,768 0 (7,224) 12,379,999 3 TOTAL OPERATING REVENUE $138,919,227 $0 $0 $0 $6,177,837 $0 $0 $96,768 $0 ($7,224) $145,186,608 OPERATING EXPENSES 4 Production Expenses $64,876,750 $0 $0 ($95,158) $4,659,718 ($102,432) $0 $0 $292,895 $0 $69,631,772 5 Transmission Expenses 5,500,044 0 0 (36,090) 0 0 0 0 0 0 5,463,954 6 Distribution Expenses 6,965,971 0 0 (54,014) 0 0 0 0 0 0 6,911,957 7 Customer Accounting Expenses 5,620,119 0 0 (42,989) 0 0 0 0 0 0 5,577,131 8 Customer Service & Information Expenses 3,902,863 0 0 (23,204) 0 0 0 0 0 0 3,879,658 9 Sales Expenses 254,585 0 0 0 0 0 0 0 0 0 254,585 10 Administration & General Expenses 16,738,839 0 0 (117,594) 0 0 (25,824) 0 0 (2,162) 16,593,260 11 Charitable Contributions 96,752 0 0 0 0 0 0 0 0 96,752 12 Depreciation Expense 14,791,595 (1,288,995) (50,784) 0 0 0 0 0 0 0 13,451,817 13 Spiritwood Amortization 0 0 0 0 0 0 0 0 0 0 0 14 General Taxes 3,906,312 0 (36,950) 0 0 0 0 0 0 (4,971) 3,864,391 15 TOTAL OPERATING EXPENSES $122,653,830 ($1,288,995) ($87,733) ($369,048) $4,659,718 ($102,432) ($25,824) $0 $292,895 ($7,133) $125,725,277 16 NET OPERATING INCOME BEFORE INCOME TAXES $16,265,397 $1,288,995 $87,733 $369,048 $1,518,119 $102,432 $25,824 $96,768 ($292,895) ($91) $19,461,331 INCOME TAX EXPENSE 17 Investment Tax Credit ($475,598) $0 $0 $0 $0 $0 $0 $0 $0 $274 ($475,324) 18 Deferred Income Taxes 10,181,518 0 (294,876) 0 0 0 0 0 0 (9,809) 9,876,833 19 Income Taxes (6,319,486) 633,331 373,254 152,675 628,046 42,376 10,683 40,033 (121,170) (77,765) (4,638,024) 20 TOTAL INCOME TAX EXPENSE $3,386,433 $633,331 $78,378 $152,675 $628,046 $42,376 $10,683 $40,033 ($121,170) ($87,300) $4,763,485 21 NET OPERATING INCOME $12,878,964 $655,664 $9,355 $216,373 $890,073 $60,056 $15,141 $56,735 ($171,724) $87,209 $14,697,846 22 Allowance for Funds Used During Construction 324,110 241,899 0 0 0 0 0 0 0 11,227 577,235 23 TOTAL AVAILABLE FOR RETURN $13,203,073 073 $897,563 $9,355 $216,373 $890,073 073 $60,056 056 $15,141 141 $56,735 ($171,724) 724) $98,436 $15,275,081 Notes: (1) Electric Utility - Minnesota Jurisdiction

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART B COMPARISON OF PROPOSED INTERIM RATES TO 2009 TEST YEAR Schedule 7 SUMMARY OF REVENUE REQUIREMENTS Page 1 of 1 (A) (B) (C) = (B) - (A) Interim Rate Line 2009 Test Petition No. Description Year Present Rates Change 1 Average Rate Base $218,146,346 $215,053,382 ($3,092,964) 2 Operating Income (Before AFUDC) 12,878,964 14,697,846 1,818,882 3 Allowance for Funds Used During Construction (AFUDC) 324,110 577,235 253,126 4 Total Available for Return (Line 2 + Line 3 + Rounding) 13,203,073 15,275,081 2,072,008 5 Overall Rate of Return (Line 4 / Line 1) 6.05% 7.10% 1.05% 6 Required Rate of Return 8.91% 8.48% -0.43% 7 Operating Income Requirement (Line 1 x Line 6) 19,436,839 18,236,527 (1,200,313) 8 Income Deficiency (Line 7 - Line 4) 6,233,766 2,961,446 (3,272,320) 9 Gross Revenue Conversion Factor 1.705611 1.705611 0 10 Revenue Deficiency (Line 8 x Line 9) 10,632,383 5,051,076 (5,581,307) 11 Retail Related Revenues Under Present Rates 132,806,609 132,806,609 0 12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 8.01% 3.80% (4.20)%

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART C COMPARISON OF PROPOSED INTERIM RATES TO MOST RECENT GENERAL RATE CASE Schedule 1 DETAILED RATE BASE COMPONENTS Page 1 of 1 (A) (B) (C) = (B) - (A) Most Recent General Rate Interim Rate Line Case Filing Petition No. Description E-017/GR-07-1178 Present Rates Change Utility Plant in Service: 1 Production $192,937,033 $198,167,284 $5,230,251 2 Transmission 94,485,320 99,556,918 5,071,598 3 Distribution 137,737,940 156,578,523 18,840,583 4 General 35,864,975 36,203,368 338,393 5 Intangible 1,952,229 1,849,317 (102,912) 6 TOTAL Utility Plant in Service $462,977,496 $492,355,410 $29,377,913 7 Accumulated Depreciation 8 Production ($112,437,194) ($115,240,453) ($2,803,259) 9 Transmission (36,670,765) (38,853,474) (2,182,709) 10 Distribution (57,222,144) (65,548,292) (8,326,148) 11 General (14,284,827) (14,960,351) (675,524) 12 Intangible (748,615) (524,017) 224,598 13 TOTAL Accumulated Depreciation ($221,363,544) ($235,126,588) ($13,763,043) 14 NET Utility Plant in Service 15 Production $80,499,839 $82,926,831 2,426,992 16 Transmission 57,814,555 60,703,444 2,888,889 17 Distribution 80,515,796 91,030,231 10,514,435 18 General 21,580,148 21,243,017 (337,131) 19 Intangible 1,203,614 1,325,300 121,686 20 NET Utility Plant in Service $241,613,952 $257,228,822 $15,614,870 21 Big Stone Plant capitalized items 0 0 0 22 Utility Plant Held for Future Use 14,157 13,553 ($604) 23 Construction Work in Progress 7,602,461 10,753,544 3,151,083 24 Materials and Supplies 5,722,799 7,418,264 1,695,465 25 Fuel Stocks 3,203,404 4,388,966 1,185,562 26 Prepayments (14,816,072) (16,660,756) (1,844,684) 27 Customer Advances & Deposits (292,220) (480,160) (187,940) 28 Cash Working Capital 1,934,122 2,750,394 816,272 29 Accumulated Deferred Income Taxes (40,094,522) (50,359,245) (10,264,723) 30 Total Average Rate Base $204,888,081 $215,053,382 $10,165,301

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART C COMPARISON OF PROPOSED INTERIM RATES TO MOST RECENT GENERAL RATE CASE Schedule 2 DETAILED RATE BASE COMPONENTS Page 1 of 1 DESCRIPTION OF CHANGES Total Average Rate Base proposed by OTP for interim rates has increased by approximately $10.2 million since the last approved electric rate case in Docket No. E017/GR-07-1178. 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) and Accumulated Deferred Income Taxes. Total Net Plant in Service increased approximately $15.6 million. Gross Plant in Service increased by $29.4 million and Reserve for Depreciation and Amortization increased by $13.8 million. In addition, Construction Work in Progress increased approximately $3.2 million. The increases in Utility Plant in Service and CWIP were offset by an increase in Accumulated Deferred Income Taxes, which is a reduction to rate base, of approximately $10.3 million. These three components account for $8.5 million of the $10.2 million increase to rate base. Distribution Plant now comprises 35 percent of Net Plant compared to 33 percent for the 2006 Test Year in the last General Rate Order increasing distribution plant by $10.5 million, (capital additions of $18.8 million offset by increases in depreciation reserves of $8.3 million). Transmission Plant has increased by $2.9 million (capital additions of $5.7 million offset by increases in depreciation reserves of $2.2 million), and remains very consistent as a percentage of Net Plant when compared to the 2006 Test Year at 24 percent. The value of Production Plant as a percent of Net Plant in Service also has remained very consistent when compared to the 2006 Test Year comprising 32 percent and an increase $2.4 million (capital additions of $5.2 million offset by increases in depreciation reserves of $2.8 million) compared to 33 percent in the 2006 Test Year. As mentioned earlier, Accumulated Deferred Income Taxes, a reduction to average Rate Base, increased by $10.3 million. This increase is mainly caused by timing differences between book and tax depreciation on plant in service investment. Cash Working Capital increased approximately $800,000, Materials and Supplies comprised an increase of $1.7 million, Fuel Inventory increased by $1.2 million, Prepayments decreased by $1.8 million and Customer Advances and Deposits decreased by $200,000 since the 2006 Test Year in the last General Rate Order. The net effect of the $15.6 million increase in Net Plant in Service, the $3.2 million increase in CWIP, the $1.8 million decrease in Prepayments (which results in a deduction from Average Rate Base), the $10.3 million increase in Accumulated Deferred Income Taxes (also a reduction to average Rate Base), the $800,000 increase in Cash Working Capital, the $2.9 million increase in Materials and Supplies and Fuel Inventory along with the $200,000 decrease in Customer Advances and Deposits account for the $10.2 million increase in Total Average Rate Base for the interim rate period.

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART C COMPARISON OF PROPOSED INTERIM RATES TO MOST RECENT GENERAL RATE CASE (1986) Schedule 3 STATEMENT OF OPERATING INCOME Page 1 of 1 (A) (B) (C) = (B) - (A) Most Recent General Rate Interim Rate Line Case Filing Petition No. Description E-017/GR-07-1178 Present Rates Change OPERATING REVENUES 1 Retail $131,338,179 $132,806,609 $1,468,430 2 Other Operating Revenue 17,656,555 12,379,999 (5,276,556) 3 TOTAL OPERATING REVENUE $148,994,734 $145,186,608 ($3,808,126) 4 OPERATING EXPENSES 5 Production Expenses $74,533,381 $69,631,772 ($4,901,609) 6 Transmission Expenses 5,330,005 5,463,954 133,949 7 Distribution Expenses 6,283,425 6,911,957 628,532 8 Customer Accounting Expenses 4,680,629 5,577,131 896,502 9 Customer Service & Information Expenses 4,022,888 3,879,658 (143,230) 10 Sales Expenses 361,258 254,585 (106,673) 11 Administration & General Expenses 16,803,612 16,593,260 (210,352) 12 Charitable Contributions 92,377 96,752 4,375 13 Depreciation Expense 13,015,289 13,451,817 436,528 14 General Taxes 4,748,410 3,864,391 (884,019) 15 TOTAL OPERATING EXPENSES $129,871,275 $125,725,277 ($4,145,997) 16 NET OPERATING INCOME BEFORE INCOME TAXES $19,123,459 $19,461,331 $337,871 17 INCOME TAX EXPENSE 17 Investment Tax Credit ($572,102) ($475,324) $96,778 18 Deferred Income Taxes (1,616,131) 9,876,833 11,492,964 19 Income Taxes 6,968,995 (4,638,024) (11,607,019) 20 TOTAL INCOME TAX EXPENSE $4,780,762 $4,763,485 ($17,277) 21 NET OPERATING INCOME $14,342,697 $14,697,846 $355,148 22 Allowance for Funds Used During Construction 488,851 577,235 88,384 23 TOTAL AVAILABLE FOR RETURN $14,831,548 $15,275,081 $443,532 Notes: Revenues reflect calendar month sales

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART C COMPARISON OF PROPOSED INTERIM RATES TO MOST RECENT GENERAL RATE CASE (1986) Schedule 4 STATEMENT OF OPERATING INCOME Page 1 of 1 DESCRIPTION OF CHANGES Comparing OTP s 2006 Test Year utility available for return approved by the Commission in Docket No. E-017/GR-07-1178 with the 2009 available for return proposed in the Company s 2009 Interim Rate petition shows a small change, an increase of approximately $445,000. Major components of the change in utility available for return include the following: Retail Electric Revenues increased by $1.5 million or just over 1%. Other Revenue decreased by $5.3 million. OTP s asset-based revenue dropped from $11.6 million in the 2006 Test Year to $6.2 million in the 2009 Interim Petition due to the drop in wholesale electric energy prices since 2008. Fuel, Purchased Energy and Power Production costs have decreased by approximately $4.9 million compared to the 2006 Test Year General Rate Order. Approximately $4.5 million of this decrease is in Purchased Energy costs. Other Operating Expenses increased by approximately $1.2 million. The changes that occurred in the various cost functions are: Transmission expense, an increase of $134,000; Distribution expense, an increase of $629,000; Customer Accounting, an increase of $897,000; Customer Services combined with Information and Sales, a decrease of $250,000; and Administrative and General expense, a decrease of $210,000. Depreciation expense increased by approximately $437,000 which represents a 3 percent increase over the 2006 Test Year General Rate Order. General Taxes decreased approximately $884,000 since the 2006 Test Year. 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 the Investment Tax Credit have increased by $11.6 million while Current Tax Expense has decreased by approximately $11.6 million resulting in virtually no change in Total Income Taxes since the last General Rate Order. Compared to the last electric General Rate Order, Allowance for Funds Used During Construction (AFUDC) increased by $88,000 reflecting an increase in projects with long development lead times carried in CWIP.

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART C COMPARISON OF PROPOSED INTERIM RATES TO MOST RECENT GENERAL RATE CASE (1986) Schedule 5 SUMMARY OF REVENUE REQUIREMENTS Page 1 of 1 (A) (B) (C) = (B) - (A) Most Recent General Rate Interim Rate Line Case Filing Petition No. Description E-017/GR-07-1178 Present Rates Change 1 Average Rate Base $204,888,081 $215,053,382 $10,165,301 2 Operating Income (Before AFUDC) 14,342,697 14,697,846 355,149 3 Allowance for Funds Used During Construction (AFUDC) 488,851 577,235 88,384 4 Total Available for Return (Line 2 + Line 3 + Rounding) 14,831,548 15,275,081 443,533 5 Overall Rate of Return (Line 4 / Line 1) 7.24% 7.10% (0.14)% 6 Required Rate of Return 8.33% 8.48% -(0.15)% 7 Operating Income Requirement (Line 1 x Line 6) 17,067,177 18,236,527 1,169,350 8 Income Deficiency (Line 7 - Line 4) 2,235,629 2,961,446 725,816 9 Gross Revenue Conversion Factor 1.705611 1.705611 0 10 Revenue Deficiency (Line 8 x Line 9) 3,813,114 5,051,076 1,237,963 11 Retail Related Revenues Under Present Rates 131,338,179 132,806,609 1,468,430 12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 2.90% 3.80% 0.90%

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART C COMPARISON OF PROPOSED INTERIM RATES TO MOST RECENT GENERAL RATE CASE (2006) 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 I. Capital Structure and Rate of Return Calculation Approved by the Commission in the Most Recent General Rate Case (Docket E-017/GR-07-1178) 1 Long-Term Debt $184,736,587 42.30% 6.32% 2.67% 2 Short-Term Debt $18,119,160 4.15% 6.52% 0.27% 3 Long-Term and Short-Term Debt $202,855,747 46.45% 6.34% 2.94% 4 Preferred Stock 15,500,000 3.55% 4.75% 0.17% 5 Net Common Equity 218,355,747 50.00% 10.43% 5.22% 6 Total Equity $233,855,747 53.55% 5.38% 7 Total Capitalization $436,711,493 100.00% 8.33% II. Capital Structure and Rate of Return Calculation for Proposed Interim Rates 8 Long-Term Debt $288,367,295 45.5% 6.71% 3.06% 9 Short-Term Debt 17,149,175 2.7% 0.92% 0.02% 10 Long-Term and Short-Term Debt $305,516,471 48.2% 6.38% 3.08% 11 Preferred Stock 0 0.0% 0.00% 0.00% 12 Net Common Equity 328,112,867 51.8% 10.43% 5.40% 13 Total Equity $328,112,867 51.8% 5.40% 14 Total Capitalization $633,629,338 100.0% 8.48% III. Amount of Changes Between I and II Amount Fiscal Year Most Recent General Rate Case Filing Proposed Interim Rate Change (A) (B) (C) = (B) - (A) 15 Long-Term Debt $184,736,587 $288,367,295 $103,630,708 16 Short-Term Debt 18,119,160 $17,149,175 ($969,984) 17 Long-Term and Short-Term Debt $202,855,747 $305,516,471 $102,660,724 18 Preferred Stock 15,500,000 0 ($15,500,000) 19 Net Common Equity 218,355,747 328,112,867 109,757,121 20 Total Equity $233,855,747 $328,112,867 $94,257,121 21 Total Capitalization $436,711,493 $633,629,338 $196,917,845

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART C COMPARISON OF PROPOSED INTERIM RATES TO MOST RECENT GENERAL RATE CASE (2006 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 $103.6 million, compared to the last electric general rate case order in Docket No. E017/GR-07-1178. Some of this debt is the result of the restructuring that took place with the formation of the Holding Company in 2009 including the addition of some debt and the replacement of Preferred Stock with equivalent amounts of debt at the same cost as the preferred stock cost, net of income tax impacts. The capital structure for Interim Rates includes $17.1 million of Short-Term Debt as compared to $18 million in the last electric General Rate Order. As mentioned above, with the formation of the Holding Company in 2009, all of the Preferred Stock was transferred to the Parent Company, Otter Tail Corporation, and has been replaced by equivalent amounts of debt on OTP s balance sheet. Common Equity has increased by approximately $109.8 million primarily due to contributions to capital over the last three years as retained earnings have remained relatively unchanged. The overall cost of capital has increased from the order in the Most Recent General Rate Case. The increase has been driven primarily by an increase in the cost of debt. In addition, even though Preferred Stock has been eliminated from the cost of capital, it was replaced with equivalent amounts of debt, as mentioned previously. The 10.43% cost of common equity is the same as the Commission Ordered in the Most Recent General Rate Case.

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART D COMPARISON OF PROPOSED INTERIM RATES TO 2009 ACTUAL YEAR Schedule 1 DETAILED RATE BASE COMPONENTS Page 1 of 1 (A) (B) (C) = (B) - (A) Interim Rate Line 2009 Actual Petition No. Description Year Present Rates Change Utility Plant in Service: 1 Production $193,275,422 $198,167,284 $4,891,862 2 Transmission 101,298,696 99,556,918 (1,741,778) 3 Distribution 154,816,672 156,578,523 1,761,851 4 General 36,206,717 36,203,368 (3,349) 5 Intangible 1,849,488 1,849,317 (171) 6 TOTAL Utility Plant in Service $487,446,995 $492,355,410 $4,908,415 7 Accumulated Depreciation 8 Production ($114,605,473) ($115,240,453) ($634,979) 9 Transmission (39,475,353) (38,853,474) 621,879 10 Distribution (65,080,417) (65,548,292) (467,875) 11 General (14,967,189) (14,960,351) 6,837 12 Intangible (524,066) (524,017) 48 13 TOTAL Accumulated Depreciation ($234,652,498) ($235,126,588) ($474,090) 14 NET Utility Plant in Service 15 Production $78,669,948 $82,926,831 4,256,883 16 Transmission 61,823,343 60,703,444 (1,119,899) 17 Distribution 89,736,255 91,030,231 1,293,976 18 General 21,239,528 21,243,017 3,488 19 Intangible 1,325,423 1,325,300 (123) 20 NET Utility Plant in Service $252,794,497 $257,228,822 $4,434,325 21 Big Stone Plant capitalized items 0 0 0 22 Utility Plant Held for Future Use 13,556 13,553 (4) 23 Construction Work in Progress 15,242,161 10,753,544 (4,488,617) 24 Materials and Supplies 7,419,519 7,418,264 (1,255) 25 Fuel Stocks 4,388,966 4,388,966 0 26 Prepayments (16,651,548) (16,660,756) (9,208) 27 Customer Advances & Deposits (479,895) (480,160) (265) 28 Cash Working Capital 12,737,181 2,750,394 (9,986,786) 29 Accumulated Deferred Income Taxes (50,507,609) (50,359,245) 148,363 30 Total Average Rate Base $224,956,829 $215,053,382 ($9,903,447)

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of MN PART D COMPARISON OF PROPOSED INTERIM RATES TO 2009 ACTUAL YEAR Schedule 2 DETAILED RATE BASE COMPONENTS Page 1 of 1 DESCRIPTION OF CHANGES Total Average Rate Base for the Company s Interim Rate Petition decreased by approximately $9.9 million from 2009, the most recent actual fiscal year. The decrease is primarily the net result of a $4.4 million increase in Net Plant in Service, a $4.5 million reduction in Construction Work in Progress and a $10 million reduction in Cash Working Capital. Net Plant in Service A majority of the increase in Net Plant in Service is explained in Test Year Adjustment MN TY- 01 located in Volume 4A, Tab Test Year Work Papers. MN TY-01 details out the adjustments needed to annualize Net Plant for projects that were capitalized during 2009 or will be capitalized during 2010 (the Known and Measurable period). Each of these additions is explained in more detail in the testimony of Mr. Kyle A. Sem. In addition, any amounts related to the Transmission Cost Recovery Rider have been removed from the Interim Petition as the rider mechanism will remain in effect during the interim period. Cash Working Capital In addition to explaining the changes related to Net Plant in Service, Test Year Adjustment Work Paper MN TY-01 also details out the change in Cash Working Capital (CWIP) for the Interim Petition. The reduction is related to annualizing projects that were capitalized in 2009 or 2010 (Known and Measurable period) that were in CWIP during the Actual Year. In order to capitalize a full year s worth of Gross Plant an offsetting adjustment was needed to reduce the associated amount sitting in CWIP. Cash Working Capital A negative adjustment was made to Cash Working Capital (CWC) for interim rates that reduced the amount of positive Cash Working Capital from the level included in the 2009 most recent fiscal year. The Cash Working Capital amount is determined by applying the various components of the lead/lag study to the most recent actual and interim year revenue and expense amounts. Certain adjustments made to the income statement for interim rate purposes produced reduced expense dollar leads and increased revenue dollar lag to which the lead/lag study factors were applied. In addition, an adjustment was made to Special Deposits, a component of the Cash Working Capital calculation, (see Test Year Adjustment MN TY-05) to normalize the Test Year which carried to the Interim Rate Petition. Since Special Deposits is a component of Cash Working Capital the adjustment had a direct impact on the CWC calculation for interim purposes. Other Rate Base Items resulted in a collective increase in average rate base of approximately $140,000 driven primarily by a decrease in Accumulated Deferred Income Taxes, (a decrease to rate base), of approximately $150,000. In summary, the net effect of the $4.4 million increase in Net Plant in Service, $4.5 million decrease in CWIP, the $10 million decrease in CWC, and the $150,000 increase in Accumulated Deferred Income Taxes accounts for the most significant changes in Total Average Rate Base for the proposed interim rate period.

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of MN PART D COMPARISON OF PROPOSED INTERIM RATES TO 2009 ACTUAL YEAR Schedule 3 STATEMENT OF OPERATING INCOME Page 1 of 1 (A) (B) (C) = (B) - (A) Interim Rate Line 2009 Actual Petition No. Description Year Present Rates Change OPERATING REVENUES 1 Retail $131,666,762 $132,806,609 $1,139,847 2 Other Operating Revenue 12,376,895 12,379,999 3,104 3 TOTAL OPERATING REVENUE $144,043,657 $145,186,608 $1,142,951 4 OPERATING EXPENSES 5 Production Expenses $69,479,006 $69,631,772 $152,766 6 Transmission Expenses 5,117,762 5,463,954 346,192 7 Distribution Expenses 6,512,734 6,911,957 399,223 8 Customer Accounting Expenses 5,306,251 5,577,131 270,880 9 Customer Service & Information Expenses 3,754,226 3,879,658 125,432 10 Sales Expenses 254,585 254,585 0 11 Administration & General Expenses 15,052,401 16,593,260 1,540,859 12 Charitable Contributions 96,752 96,752 0 13 Depreciation Expense 12,942,029 13,451,817 509,788 14 General Taxes 3,899,137 3,864,391 (34,746) 15 TOTAL OPERATING EXPENSES $122,414,883 $125,725,277 $3,310,394 16 NET OPERATING INCOME BEFORE INCOME TAXES $21,628,775 $19,461,331 ($2,167,443) 17 INCOME TAX EXPENSE 18 Investment Tax Credit ($475,243) ($475,324) ($82) 19 Deferred Income Taxes 10,166,772 9,876,833 (289,938) 20 Income Taxes (4,131,273) (4,638,024) (506,751) 21 TOTAL INCOME TAX EXPENSE $5,560,256 $4,763,485 ($796,771) 22 NET OPERATING INCOME $16,068,518 $14,697,846 ($1,370,672) 23 Allowance for Funds Used During Construction 805,597 577,235 (228,361) 24 TOTAL AVAILABLE FOR RETURN $16,874,115 $15,275,081 ($1,599,034) Notes: Revenues reflect calendar month sales

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of MN PART D COMPARISON OF PROPOSED INTERIM RATES TO 2009 ACTUAL YEAR Schedule 4 STATEMENT OF OPERATING INCOME Page 1 of 1 DESCRIPTION OF CHANGES Total Retail Electric revenues increased by $1.1 million from the most recent Actual Year (2009) compared to the Interim Petition in this filing. The increase is driven by the adjustments to the Test Year for weather normalization of $272,000 and $867,000 in FCA True-up revenue that is passed through the fuel clause recovery mechanism for the Interim Year. Other Operating Revenue had little change from the most recent Actual Year to the Interim Year, due to small changes in the iterative factors in the cost of service model. In comparing the cost of Fuel, Purchased Energy and Power Production Expenses in the 2009 Actual Year to the Interim Petition there was an increase of $153,000 in the Interim Year or less than 1 percent. Excluding the cost of Fuel, Purchased Energy and Power Production, other operating expenses increased approximately $2.7 million in total. Transmission expenses increased approximately $350,000; Distribution expenses increased by $400,000; Customer Accounting expenses increased by $270,000; Customer Service, Information and Sales expenses increased by $125,000; and Administrative and General (A&G) expenses increased by $1.54 million primarily driven by increases in employee labor and benefit costs. Depreciation expense is higher by $510,000 driven primarily by an adjustment to reflect the annualization of new plant additions as detailed in Test Year Adjustment Work Paper MN TY- 01 located in Volume 4A, Tab Test Year Adjustment Work Papers as well as an adjustment to reflect the new 2009 depreciation rates found on Test Year Work Paper MN TY-04. Current Federal and State Income Taxes decreased by approximately $510,000 because taxable income is lower in the Interim Year than in the 2009 Actual Year. Deferred Income Taxes decreased by approximately $290,000 as a result of eliminating the costs associated with the Transmission Cost Recovery Rider projects which cause book and tax depreciation changes impacting the deferred tax calculation. The changes described above help to account for the $1.4 million reduction in utility operating income for the proposed interim rate period compared to the most recent fiscal year.

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of MN PART D COMPARISON OF PROPOSED INTERIM RATES TO 2009 ACTUAL YEAR Schedule 5 SUMMARY OF REVENUE REQUIREMENTS Page 1 of 1 (A) (B) (C) = (B) - (A) Interim Rate Line 2009 Petition No. Description Actual Year Present Rates Change 1 Average Rate Base $224,956,829 $215,053,382 ($9,903,447) 2 Operating Income (Before AFUDC) 16,068,518 14,697,846 (1,370,672) 3 Allowance for Funds Used During Construction (AFUDC) 805,597 577,235 (228,361) 4 Total Available for Return (Line 2 + Line 3 + Rounding) 16,874,115 15,275,081 (1,599,034) 5 Overall Rate of Return (Line 4 / Line 1) 7.50% 7.10% (0.40)% 6 Required Rate of Return 8.21% 8.48% -(0.27)% 7 Operating Income Requirement (Line 1 x Line 6) 18,468,956 18,236,527 (232,429) 8 Income Deficiency (Line 7 - Line 4) 1,594,841 2,961,446 1,366,605 9 Gross Revenue Conversion Factor 1.705611 1.705611 0 10 Revenue Deficiency (Line 8 x Line 9) 2,720,179 5,051,076 2,330,897 11 Retail Related Revenues Under Present Rates 131,666,762 132,806,609 1,139,847 12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 2.07% 3.80% 1.74%

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART E MOST RECENT GENERAL RATE CASE (2006) TO 2009 ACTUAL YEAR Schedule 1 DETAILED RATE BASE COMPONENTS Page 1 of 1 (A) (B) (C) = (B) - (A) Most Recent General Rate Line Case Filing 2009 Actual No. Description E-017/GR-07-1178 Year Change Utility Plant in Service: 1 Production $192,937,033 $193,275,422 $338,389 2 Transmission 94,485,320 101,298,696 6,813,376 3 Distribution 137,737,940 154,816,672 17,078,731 4 General 35,864,975 36,206,717 341,742 5 Intangible 1,952,229 1,849,488 (102,740) 6 TOTAL Utility Plant in Service $462,977,496 $487,446,995 $24,469,498 7 Accumulated Depreciation 8 Production ($112,437,194) ($114,605,473) ($2,168,279) 9 Transmission (36,670,765) (39,475,353) (2,804,588) 10 Distribution (57,222,144) (65,080,417) (7,858,273) 11 General (14,284,827) (14,967,189) (682,362) 12 Intangible (748,615) (524,066) 224,549 13 TOTAL Accumulated Depreciation ($221,363,544) ($234,652,498) ($13,288,953) 14 NET Utility Plant in Service 15 Production $80,499,839 $78,669,948 ($1,829,891) 16 Transmission 57,814,555 61,823,343 4,008,788 17 Distribution 80,515,796 89,736,255 9,220,458 18 General 21,580,148 21,239,528 (340,619) 19 Intangible 1,203,614 1,325,423 121,808 20 NET Utility Plant in Service $241,613,952 $252,794,497 $11,180,545 21 Big Stone Plant capitalized items 0 0 $0 22 Utility Plant Held for Future Use 14,157 13,556 ($600) 23 Construction Work in Progress 7,602,461 15,242,161 7,639,699 24 Materials and Supplies 5,722,799 7,419,519 1,696,721 25 Fuel Stocks 3,203,404 4,388,966 1,185,562 26 Prepayments (14,816,072) (16,651,548) (1,835,476) 27 Customer Advances & Deposits (292,220) (479,895) (187,675) 28 Cash Working Capital 1,934,122 12,737,181 10,803,059 29 Accumulated Deferred Income Taxes (40,094,522) (50,507,609) (10,413,087) 30 Total Average Rate Base $204,888,082 $224,956,829 $20,068,747

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART E MOST RECENT GENERAL RATE CASE (2006) TO 2009 ACTUAL YEAR Schedule 2 DETAILED RATE BASE COMPONENTS Page 1 of 2 DESCRIPTION OF CHANGES Total Average Rate Base of the Company for the Minnesota jurisdiction in the most recent fiscal year ended 2009 has increased by approximately $20.1 million since the last approved electric rate case in Docket No. E-017/GR-07-1178. A majority of the increase in Average Rate Base was related to the net effect of the increase in Net Utility Plant in Service, the increase in Construction Work in Progress (CWIP), the increase in Cash Working Capital (CWC) and the offsetting increase in Accumulated Deferred Income Taxes (ADIT), a reduction to rate base. Total Net Plant in Service increased approximately $11.2 million which is the result of Gross Plant in Service increasing by $24.5 million and the Reserve for Depreciation and Amortization increasing by $13.3 million. In addition, CWIP and CWC increased by approximately $7.6 million and $10.8 million, respectively. Alternatively, ADIT increased by $10.4 million, which actually reduced rate base. Distribution Plant in 2009 comprises 35.5 percent of Net Plant compared to 33 percent in the last General Rate Order, increasing by $9.2 million, (capital additions of $17.1 million offset by increases in depreciation reserves of $7.9 million). Transmission Plant has remained very stable as a percentage of Total Plant since the last General Rate Order. It represents just over 24 percent of total Net Plant in this Interim Petition versus just fewer than 24 percent in the last General Rate Order. The value of Transmission Plant has increased by $4 million (capital additions of $6.8 million offset by increases in depreciation reserves of $2.8 million). The value of Production Plant as a percent of Net Plant in Service has decreased from 33 percent of Net Plant in the last General Rate case to 31 percent in the 2009 Actual Year. Net Transmission Plant decreased by $1.8 million, (capital additions of $340,000 offset by increases in depreciation reserves of $2.17 million) Construction Work in Progress ( CWIP ) increased by approximately $7.6 million driven in large part by significant investment in on-going transmission related projects. Accumulated Deferred Income Taxes, a reduction to average Rate Base, increased by $10.4 million which reduces the overall calculation to Average Rate Base. ADIT balances are impacted in large part by differences in book and tax depreciation. Since the last approved rate case, Cash Working Capital requirements increased by approximately $10.8 million. This increase is largely caused by an increase in Special Deposits which is a component of the Cash Working Capital calculation. Please refer to Test Year Adjustment Work Paper MN TY-05 located in Volume 4A, Tab Test Year Adjustment Work Papers for detail on the adjustment to normalize the 2009 Actual Year for Special Deposit balances. Materials and Supplies comprised an increase of $1.7 million and Fuel Inventory increased by $1.2 million while Prepayments decreased by $1.8 million and Customer Advances and Deposits decreased by $200,000 since the last General Rate Order.

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART E Schedule 1 Schedule 2 DETAILED RATE BASE COMPONENTS Page 2 of 2 DESCRIPTION OF CHANGES The net effect of the $11.2 million increase in Net Plant in Service, the $7.6 million increase in CWIP, the $2.9 million increase in materials, supplies and fuel stocks, and the $10.8 million increase to CWC are offset by the $1.8 million decrease in Prepayments, the $200,000 decrease in Customer Advances and Deposits, the $10.4 million increase in Accumulated Deferred Income Taxes (a deduction from Average Rate Base) which all account for the $20.1 million increase in Total Average Rate Base from the last approved rate case to the 2009 Actual Year.

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART E MOST RECENT GENERAL RATE CASE (2006) TO 2009 ACTUAL YEAR Schedule 3 STATEMENT OF OPERATING INCOME Page 1 of 1 (A) (B) (C) = (B) - (A) Most Recent General Rate Line Case Filing 2009 Actual No. Description E-017/GR-07-1178 Year Change OPERATING REVENUES 1 Retail $131,338,179 $131,666,762 $328,583 2 Other Operating Revenue 17,656,555 12,376,895 (5,279,660) 3 TOTAL OPERATING REVENUE $148,994,734 $144,043,657 ($4,951,076) 4 OPERATING EXPENSES 5 Production Expenses $74,533,381 $69,479,006 ($5,054,375) 6 Transmission Expenses 5,330,005 5,117,762 (212,243) 7 Distribution Expenses 6,283,425 6,512,734 229,310 8 Customer Accounting Expenses 4,680,629 5,306,251 625,621 9 Customer Service & Information Expenses 4,022,888 3,754,226 (268,662) 10 Sales Expenses 361,258 254,585 (106,673) 11 Administration & General Expenses 16,803,612 15,052,401 (1,751,211) 12 Charitable Contributions 92,377 96,752 4,375 13 Depreciation Expense 13,015,289 12,942,029 (73,260) 14 General Taxes 4,748,410 3,899,137 (849,273) 15 TOTAL OPERATING EXPENSES $129,871,275 $122,414,883 ($7,456,392) 16 NET OPERATING INCOME BEFORE INCOME TAXES $19,123,459 $21,628,775 $2,505,316 17 INCOME TAX EXPENSE 18 Investment Tax Credit ($572,102) ($475,243) $96,859 18 Deferred Income Taxes (1,616,131) 10,166,772 11,782,903 19 Income Taxes 6,968,995 (4,131,273) (11,100,268) 20 TOTAL INCOME TAX EXPENSE $4,780,762 $5,560,256 $779,494 21 NET OPERATING INCOME $14,342,697 $16,068,518 $1,725,821 22 Allowance for Funds Used During Construction 488,851 805,597 316,746 23 TOTAL AVAILABLE FOR RETURN $14,831,548 $16,874,115 $2,042,567 Notes: Revenues reflect calendar month sales

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART E MOST RECENT GENERAL RATE CASE (2006) TO 2009 ACTUAL YEAR Schedule 4 STATEMENT OF OPERATING INCOME Page 1 of 1 DESCRIPTION OF CHANGES Comparing OTP s 2006 utility operating income approved by the Commission in Docket No. E-017/GR-07-1178, to operating income for the 2009 most recent fiscal year, shows an increase of approximately $1.7 million. Major components of the change in utility operating income include the following: Retail Electric Revenues increased by $330,000, representing a minimal increase of less than one percent. Other Revenue decreased by $5.3 million. OTP s asset-based revenue dropped from $11.6 million in the 2006 Test Year to $6.2 million in the 2009 Interim Petition due to the drop in wholesale electric energy prices since 2008. Fuel, Purchased Energy and Power Production costs have decreased by $5.1 million compared to the last General Rate Order in Docket No. E-017/GR-07-1178. Approximately $4.5 million of this decrease is in Purchased Energy costs. Other Operating Expenses decreased by approximately $1.5 million. The changes that occurred in the various cost functions are: Transmission expense, a decrease of $210,000; Distribution expense, an increase of $230,000; Customer Accounting expense, an increase of $625,000; Customer Services and Information and Sales, a decrease of $380,000; and Administrative and General expense, a decrease of $1.75 million. Depreciation expense remained relatively flat showing a decrease of less than one percent. General Taxes in the Actual Year decreased approximately $850,000 since the most recent General Rate Order. 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 the Investment Tax Credit have increased by $11.9 million while Income Tax Expense has decreased by approximately $11.1 million resulting in an increase of approximately $800,000 in Total Income Taxes since the last General Rate Order due to an increase in net operating income of $2.5 million. Compared to the last electric General Rate Order, Allowance for Funds Used During Construction (AFUDC) increased by approximately $300,000 reflecting an increase in projects with long development lead times carried in CWIP.

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 Electric Utility - State of Minnesota PART E MOST RECENT GENERAL RATE CASE (2006) TO 2009 ACTUAL YEAR Schedule 5 SUMMARY OF REVENUE REQUIREMENTS Page 1 of 1 (A) (B) (C) = (B) - (A) Most Recent General Rate Line Case Filing 2009 Actual No. Description E-017/GR-07-1178 Year Change 1 Average Rate Base $204,888,081 $224,956,829 $20,068,748 2 Operating Income (Before AFUDC) 14,342,697 16,068,518 1,725,821 3 Allowance for Funds Used During Construction (AFUDC) 488,851 805,597 316,746 4 Total Available for Return (Line 2 + Line 3 + Rounding) 14,831,548 16,874,115 2,042,567 5 Overall Rate of Return (Line 4 / Line 1) 7.24% 7.50% -(0.26)% 6 Required Rate of Return 8.33% 8.21% (0.12)% 7 Operating Income Requirement (Line 1 x Line 6) 17,067,177 18,468,956 1,401,779 8 Income Deficiency (Line 7 - Line 4) 2,235,629 1,594,841 (640,788) 9 Gross Revenue Conversion Factor 1.705611 1.705611 0.000000 10 Revenue Deficiency (Line 8 x Line 9) 3,813,114 2,720,179 (1,092,935) 11 Retail Related Revenues Under Present Rates 131,338,179 131,666,762 328,583 12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 2.90% 2.07% -0.84%

Volume 1 Summary of Present and Interim Revenue 1/3 Tab

OTTER TAIL POWER COMPANY Docket No. E017/GR-10-239 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 Operating Revenue Percent Rate Schedule Present 2009 Interim Increase Change Residential Service $34,778,849 $36,101,604 $1,322,755 3.80% Residential Demand Control $3,685,578 $3,825,753 $140,175 3.80% Total Residential Class Revenue $38,464,427 $39,927,357 $1,462,930 3.80% Farm Service $2,546,057 $2,642,892 $96,835 3.80% General Service < 20 kw $8,148,164 $8,458,066 $309,902 3.80% General Service >= 20 kw $17,291,921 $17,949,590 $657,669 3.80% Commercial Time of Use $976,659 $1,013,805 $37,146 Total GS Class Revenue $26,416,744 $27,421,460 $1,004,716 3.80% Large General Service $22,540,736 $23,398,035 $857,299 3.80% Large General Service Time of Day $29,698,084 $30,827,601 $1,129,517 3.80% Real Time Pricing $0 $0 $0 0.00% Large General Service Rider $2,147,732 $2,229,417 $81,685 3.80% Standby Service $0 $0 $0 0.00% Total LGS Class Revenue $54,386,552 $56,455,053 $2,068,501 3.80% Irrigation Services $230,607 $239,378 $8,771 3.80% Outdoor Lighting - Energy Only $244,639 $253,944 $9,304 3.80% Outdoor Lighting $2,158,181 $2,240,264 $82,083 3.80% Total Lighting Class Revenue $2,402,820 $2,494,207 $91,387 3.80% Municipal Pumping Service $1,139,654 $1,182,999 $43,345 3.80% Civil Defense - Fire Sirens $5,442 $5,649 $207 3.80% Total OPA Class Revenue $1,145,096 $1,188,648 $43,552 3.80% Water Heating, Controlled $1,326,879 $1,377,345 $50,466 3.80% Interruptible Load >= 80 kw $1,244,033 $1,291,348 $47,315 3.80% Interruptible Load < 80 kw $3,541,884 $3,676,594 $134,710 3.80% Total Interruptible Class Revenue $4,785,917 $4,967,941 $182,024 3.80% Deferred Load Controlled Service $701,452 $728,131 $26,679 3.80% Fix Time of Delivery Service $400,056 $415,272 $15,215 3.80% Total Def. Ld. Class Revenue $1,101,508 $1,143,402 $41,894 3.80% Total $132,806,608 $137,857,684 $5,051,076 3.80%

Volume 1 Interim Tariff Sheets Redlined 1/3 Tab

Section Rate Schedule Description 9.01 Residential Service 9.02 Residential Service Controlled Demand 9.03 Farm Service 10.01 Small General Service (less than 20 kw) 10.02 General Service (20 kw or greater) 10.03 Large General Service 10.04 General Service Time of Use 10.05 Large General Service Time of Day 11.01 Standby Service 11.02 Irrigation Service 11.03 Outdoor Lighting Energy Only 11.04 Outdoor Lighting 11.05 Municipal Pumping Service 11.06 Civil Defense - Fire Sirens 12.01 Small Power Producer Rider (Net Energy Billing Rate) Residential Farm General Service Large General Service 12.02 Small Power Producer Rider (Simultaneous Purchase & Sale Billing Rate) Firm Power Nonfirm Power 12.03 Small Power Producer Rider (Time-of-Day Purchase Rates) Firm Power Nonfirm Power 12.04 Distributed Generation Service Rider 14.01 Water Heating Controlled Service 14.02 Real Time Pricing Rider 14.03 Large General Service Rider 14.04 Controlled Service Interruptible Load (CT Metering) Rider 14.05 Controlled Service Interruptible Load (Self-Contained Metering) Rider 14.06 Controlled Service Deferred Load Rider 14.07 Fixed Time of Delivery Rider Docket No. E-017/GR-10-239 Interim Rate Schedules

Interim Otter Tail Corporation d/b/a Minnesota, Section 9.01 Residential Service Fergus Falls, Minnesota Page 1 of 2 Twenty-third fourth Revision DESCRIPTION RESIDENTIAL SERVICE RATE CODE Residential Service 30-101 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. AVAILABILITY: This schedule is applicable for residential service as defined in the General Rules and Regulations. RATES: RESIDENTIAL SERVICE Customer Charge per Month: $8.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter 7.9017.642 /kwh 7.1626.903 /kwh INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 9.01 Residential Service Fergus Falls, Minnesota Page 2 of 2 Twenty-third fourth Revision SEASONAL RESIDENTIAL SERVICE: 1. These rates and regulations shall apply to seasonal and lake cottage service and to rural residential service only. Resorts, stores, farms and other commercial establishments will be billed at the rates provided for such classes of service. 2. Seasonal customers will be billed at the same rate as year-around customers, except as follows: A one-time seasonal fixed charge of $32.00 will be billed each seasonal customer in addition to the rate provided above. The fixed charge will be included on the first bill rendered for each season. Each seasonal customer will be billed for the number of months each season that the residence or cottage is in use, but not less than a minimum of four months, plus the seasonal fixed charge. The Company will normally read meters and render a bill during the months of June, July, August and September. At the option of the Company, meters may be read at other times during the year and a bill will be rendered if energy recorded on the meter exceeds 100 kilowatt-hours. Billing may be rendered on a two-month basis at the discretion of the Company; when the energy used exceeds 100 kilowatt-hours and more than 55 days have elapsed since the previous meter reading, the bill will be rendered on a two-month basis. Seasonal customers will also be subject to a connection charge of $40.00 when the account is established. and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 9.02 Residential Demand Control Fergus Falls, Minnesota Page 1 of 2 Tenth Eleventh Revision DESCRIPTION RESIDENTIAL DEMAND CONTROL (Commonly identified as RDC) RATE CODE Residential Demand Control 30-241 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. APPLICATION OF SCHEDULE: This schedule is available to residential and farm customers with approved demand control systems. RATES: RESIDENTIAL DEMAND CONTROL SERVICE Customer Charge per Month: $10.35 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: Below 5,000 kwh per month during year $4.00 At or above 5,000 kwh per month during year $15.00 Energy Charge per kwh: Summer Winter 4.2634.00 4.6024.343 /kwh 4 /kwh Demand Charge per kw: Summer Winter $6.31 /kw $3.81 /kw INTERIM RATE ADJUSTMENT A 3.8 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. and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 9.02 Residential Demand Control Fergus Falls, Minnesota Page 2 of 2 Tenth Eleventh Revision MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. 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 (3) kw will be used for customers new to this rate until a demand is established. FACILITES CHARGES: The Facilities Charge will be $4.00 per month, unless the usage is at or above 5000 kwh per month which will establish the Facilities Charge at $15.00 per month for a 12 month period. The Facilities Charge is based on 30 days per month in a billing period. An adjustment of 167 kwh a day will be added for each day that a billing period exceeds 30 days. DEMAND SIGNAL: Service may receive a demand signal for up to a total of 14 hours during any 24-hour period, as measured from midnight to midnight. Water heaters served on this Tariff will also be included in the Company s summer water heater load control program. and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 9.03 Farm Service Fergus Falls, Minnesota Page 1 of 2 Twenty-second third Revision FARM SERVICE DESCRIPTION RATE CODE Farm Service 30-361 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. AVAILABILITY: Available for 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 of the requirements specified for that schedule are satisfied. RATES: FARM SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $20.00 Facilities Charge per Month: Single Phase $0.00 Three Phase: Overhead <25kVA $4.67 Three Phase: Overhead >=25kVA $5.45 Three Phase: Underground <25kVA $13.03 Three Phase: Underground >=25kVA $20.93 Energy Charge per kwh: Summer Winter 7.6037.344 /kwh 6.8326.573 /kwh INTERIM RATE ADJUSTMENT A 3.8 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 9.03 Farm Service Fergus Falls, Minnesota Page 2 of 2 Twenty-second third Revision MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.01 Small General Service Fergus Falls, Minnesota Page 1 of 3 OriginalFirst Revision SMALL GENERAL SERVICE Under 20 kw DESCRIPTION Secondary Primary Metered Service under 20 kw 30-404 30-405 Non-metered Service Under 20 kw 30-406 30-407 Non-metered Service - 1000 Watts or less 30-408 Not Available REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION: This schedule is applicable to non-residential customers. This rate is not applicable for emergency, supplementary/standby service, energy for resale, nor municipal outdoor lighting. RATES: SECONDARY SERVICE PRIMARY SERVICE Customer Charge per Month: $15.00 $15.00 Monthly Minimum Bill: Customer + Facilities Charge Customer + Facilities Charge Facilities Charge per Month: $0.00 $0.00 Energy Charge per kwh: Summer Winter Summer Winter 8.250 7.4137. 8.2137 7.3817 7.991 /kwh 154 /kwh.954 /kwh.122 /kwh NON-METERED SERVICE- 20 kw OR LESS SECONDARY SERVICE PRIMARY SERVICE Customer Charge per Month: $12.63 $12.63 Monthly Minimum Bill: Customer + Facilities Charge Customer + Facilities Charge Facilities Charge per Month: $0.00 $0.00 Energy Charge per kwh: Summer Winter Summer Winter 7.692 7.6927. 7.6587 7.6587 /kwh /kwh /kwh /kwh 7.433 433.399.399 and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.01 Small General Service Fergus Falls, Minnesota Page 2 of 3 OriginalFirst Revision NON-METERED SERVICE-SECONDARY ONLY-1000 WATTS OR LESS Customer Charge per Month: $1.97 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter 7.4907. 7.4907. All kwh 231 /kwh 231 /kwh INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. NON-METERED & 1000 WATTS AND UNDER SERVICE: NON-METERED 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. 1000 WATTS AND UNDER NON-METERED SERVICE: 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 and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.01 Small General Service Fergus Falls, Minnesota Page 3 of 3 OriginalFirst Revision 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. 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. Customer shall contract for this optional metering service through an electric service agreement with Company. TERMS AND CONDITIONS: The customer may remain on the Small General Service schedule as long as customer's maximum demand is less than 20 kw. When the customer achieves an actual demand of 20 kw or greater, the customer will be placed on the General Service schedule (section 10.02) in the next billing month. A customer with a billing demand of less than 20 kw for 12 consecutive months will be given the option of returning to the Small General Service schedule. 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. and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.02 General Service Fergus Falls, Minnesota Page 1 of 2 Twenty-first second Revision GENERAL SERVICE 20 kw or Greater DESCRIPTION RATE CODE General Service Secondary Service 30-401 General Service Primary Service 30-403 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION: This schedule is applicable to three-phase residential customers, and both single and three-phase non-residential customers. This rate is not applicable for emergency, supplementary/standby service, unless allowed by law, energy for resale, nor municipal street lighting. RATES: SECONDARY SERVICE PRIMARY SERVICE Customer Charge per Month: $18.50 $18.50 Monthly Minimum Bill: Customer + Facilities Charge Customer + Facilities Charge Facilities Charge per Month: $0.46 /kw $0.31 /kw Energy Charge per kwh: Summer Winter Summer Winter 7.9087.649 /kwh 7.1076.848 /kwh 7.8737.614 /kwh 7.0756.816 /kwh INTERIM RATE ADJUSTMENT A 3.8 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. and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.02 General Service Fergus Falls, Minnesota Page 2 of 2 Twenty-first second Revision MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. TERMS AND CONDITIONS: A customer with a billing demand of less than 20 kw for 12 consecutive months will be given the option of returning to the Small General Service schedule (Section 10.01). DETERMINATION OF DEMAND: 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. The billing demand may be estimated for Customer locations where no demand meter has been installed, but in no event will the billing demand be considered less than 20 kw. DETERMINATION OF FACILITIES CHARGE: The monthly measured demand will be based on the maximum 15 consecutive minute period measured by a suitable demand meter for the month for which the bill is rendered. The Facilities charge demand will be based on the largest of the most recent 12 monthly measured demands. and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) Regulatory Services Manager

Otter Tail Corporation d/b/a Fergus Falls, Minnesota Interim Minnesota, Section 10.03 Large General Service Page 1 of 3 Seventeenth Eighteenth Revision LARGE GENERAL SERVICE DESCRIPTION RATE CODES Secondary Service 30-603 Primary Service 30-602 Transmission Service 30-632 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This schedule is applicable to non-residential customers. This rate is not applicable for energy for resale, nor for municipal outdoor lighting. Standby Service will be supplied only as allowed by law. RATES: SECONDARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $350.00 + Facilities Charge Facilities Charge per Month: per annual max. kw (minimum 80kW per Month) 80 kw to under 1000 kw: $0.32 /kw >= 1000 kw: $0.19 /kw Energy Charge per kwh: Summer Winter 4.7504.491 /kwh 4.5134.254 /kwh Demand Charge per kw: $6.51 /kw $4.03 /kw and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/M-09-1463GR-10-239 Approved: October 31, 2008(DATE) Manager, Regulatory Services

Otter Tail Corporation d/b/a Fergus Falls, Minnesota Interim Minnesota, Section 10.03 Large General Service Page 2 of 3 Seventeenth Eighteenth Revision PRIMARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $350.00 + Facilities Charge Facilities Charge per Month: per annual max. kw (minimum 80kW per Month) All kw: $0.14 /kw Energy Charge per kwh: Summer Winter 4.7314.472 /kwh 4.4934.234 /kwh Demand Charge per kw: $6.46 /kw $4.02 /kw TRANSMISSION SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $350.00 + Facilities Charge Facilities Charge per Month: per annual max. kw (minimum 80kW per Month) All kw: $0.00 /kw Energy Charge per kwh: Summer Winter 4.6184.359 /kwh 4.3714.112 /kwh Demand Charge per kw: $4.85 /kw $3.75 /kw INTERIM RATE ADJUSTMENT A 3.8 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. and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/M-09-1463GR-10-239 Approved: October 31, 2008(DATE) Manager, Regulatory Services

Otter Tail Corporation d/b/a Fergus Falls, Minnesota Interim Minnesota, Section 10.03 Large General Service Page 3 of 3 Seventeenth Eighteenth Revision MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. DETERMINATION OF BILLING DEMAND: The billing demand shall be the greater of 80 kw or the maximum kw as measured by a suitable demand meter for any period of 15 consecutive minutes during the period for which the bill is rendered adjusted for Excess Reactive Demand. DETERMINATION OF FACILITIES CHARGE: The monthly measured demand will be based on the maximum 15 consecutive minute period measured by a suitable demand meter for the month for which the bill is rendered. The Facilities charge demand will be based on the largest of the most recent 12 monthly measured demands. ADJUSTMENT FOR EXCESS REACTIVE DEMAND: The billing demand shall be increased by 1 kw for each whole 10 kvar of measured reactive demand in excess of 50% of the measured demand in kw. SPECIAL BILLING DEMAND: By customer request, Otter Tail Power may calculate the demand used for billing as the average of the previous twelve billing demands. The use of a special billing demand shall not exceed a period of six consecutive months. Otter Tail Power may agree to the use of the special billing demand upon conditions where customers have incurred, or can take advantage of, increased demand levels and the increased demand levels did not, or will not, increase Otter Tail Power s peak load. During the period under which the customer s billing demand is calculated in accordance to the provision of the Special Billing Demand, Otter Tail Power reserves the right to curtail the customer s additional demand (i.e., any demand over the special billing demand level) back to the customer s special billing demand in order to maintain the integrity of Otter Tail Power s generation and transmission systems. and after February 1, 2009June 1, 2010, in Minnesota Docket No. E-017/M-09-1463GR-10-239 Approved: October 31, 2008(DATE) Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.04 Commercial Service Time of Use Fergus Falls, Minnesota Page 1 of 4 Fourteenth Fifteenth Revision DESCRIPTION COMMERCIAL SERVICE - TIME OF USE RATE CODE Declared-Peak 30-708 Intermediate 30-709 Off-Peak 30-710 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF SCHEDULE: This schedule is applicable to nonresidential customers with one meter providing electrical service. RATES: COMMERCIAL SERVICE - TIME OF USE Customer Charge per Month: $5.00 Monthly Minimum Bill: Facilities Charge per Month: Customer + Facilities Charge Customer specific - see tariff Energy Charge per kwh: Summer Winter Declared-Peak 18.60018.341 /kwh 17.03416.775 /kwh Intermediate 4.8264.567 /kwh 4.6074.348 /kwh Off-Peak 1.143.884 /kwh 1.2911.032 /kwh Demand Charge per kw: Summer Winter Declared-Peak N/A /kw N/A /kw Intermediate $2.96 /kw $2.74 /kw Off-Peak $0.00 /kw $0.00 /kw INTERIM RATE ADJUSTMENT A 3.8 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 Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.04 Commercial Service Time of Use Fergus Falls, Minnesota Page 2 of 4 Fourteenth Fifteenth Revision Charge. FACILITIES CHARGE: Customers served under this tariff shall pay an annual fixed charge equal to 18% of the dedicated investment of the Company in the extension of lines, including any rebuilding or cost of capacity increase in lines or apparatus and other annual expenses necessitated to receive service at this rate. Alternatively, customer 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. An agreement will be entered into with each customer, specifying the investment necessary to supply service and the fixed charge. The annual fixed charge will be billed in 12 equal monthly installments, plus all other charges. MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. CONTRACT PERIOD & AGREEMENT: The Contract Period shall be 5 years. Because of the investment needed to provide service 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. 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 his 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. DEFINITION OF DECLARED, INTERMEDIATE AND OFF-PEAK PERIODS BY SEASON: WINTER SEASON - OCTOBER THROUGH MAY BILLINGS Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.04 Commercial Service Time of Use Fergus Falls, Minnesota Page 3 of 4 Fourteenth Fifteenth Revision Declared-Peak: Hours declared (see Declared-Peak Notification). Intermediate: All hours other than Declared-peak and off-peak Off-Peak: For all kw and kwh used Weekdays or Saturdays from10:00 p.m. to 6:00 a.m., all day Sunday SUMMER SEASON - JUNE THROUGH SEPTEMBER BILLINGS Declared-Peak: Hours declared (see Declared-Peak Notification). Intermediate: All hours other than Declared-peak and off-peak Off-Peak: For all kw and kwh used Weekdays or Saturdays from10:00 p.m. to 6:00 a.m., all day Sunday DECLARED-PEAK NOTIFICATION: Otter Tail Power shall make available to 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, Otter Tail 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 unusual circumstances prevent Otter Tail from projecting "declared-peak" designations more than one day in advance, Otter Tail 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. Otter Tail is not responsible for a customer's failure to receive or obtain and act upon the "declaredpeak" designations. If a customer does not receive or obtain the "declared-peak" designations made available by Otter Tail, it is the customer's responsibility to notify Otter Tail by 4:30 p.m. (Central Time) of the business day preceding the day that the "declared-peak" designations are to take effect. Otter Tail will be responsible for notifying the customer if prices are revised. 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.04 Commercial Service Time of Use Fergus Falls, Minnesota Page 4 of 4 Fourteenth Fifteenth Revision Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.05 Large General Service Time of Day Fergus Falls, Minnesota Page 1 of 5 Fourth Fifth Revision LARGE GENERAL SERVICE - TIME OF DAY DESCRIPTION On-Peak Shoulder Off-Peak Secondary Service 30-611 30-615 30-613 Primary Service 30-610 30-614 30-612 Transmission Service 30-639 30-637 30-640 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This schedule is applicable to non-residential customers with an existing load of at least 80 kw. RATES: SECONDARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $380.00 + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter On-Peak 8.7078.448 /kwh 7.0436.784 /kwh Shoulder 5.5935.334 /kwh 4.9564.697 /kwh Off-Peak 1.9861.727 /kwh 2.2461.987 /kwh Demand Charge per kw: Summer Winter On-Peak $4.28 /kw $3.03 /kw Shoulder $1.76 /kw $0.98 /kw Off-Peak $0.00 /kw $0.00 /kw Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.05 Large General Service Time of Day Fergus Falls, Minnesota Page 2 of 5 Fourth Fifth Revision PRIMARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $380.00 + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter On-Peak 8.6708.411 /kwh 7.0096.750 /kwh Shoulder 5.5705.311 /kwh 4.9334.674 /kwh Off-Peak 1.9801.721 /kwh 2.2371.978 /kwh Demand Charge per kw: Summer Winter On-Peak $4.25 /kw $3.01 /kw Shoulder $1.74 /kw $0.98 /kw Off-Peak $0.00 /kw $0.00 /kw TRANSMISSION SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $380.00 + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter On-Peak 8.4438.184 /kwh 6.8056.546 /kwh Shoulder 5.4325.173 /kwh 4.7984.539 /kwh Off-Peak 1.9411.682 /kwh 2.1811.922 /kwh Demand Charge per kw: Summer Winter On-Peak $3.14 /kw $2.87 /kw Shoulder $1.30 /kw $0.91 /kw Off-Peak $0.00 /kw $0.00 /kw Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.05 Large General Service Time of Day Fergus Falls, Minnesota Page 3 of 5 Fourth Fifth Revision INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. METERED AND ESTABLISHED DEMAND: The Metered Demand shall be the maximum kw registered over any period of one hour during the month for which the bill is rendered. The Established Demand shall be the Metered Demand adjusted for excess reactive demand. ADJUSTMENT FOR EXCESS REACTIVE DEMAND: The Metered Demand shall be increased by 1 kw for each whole 10 kvar of reactive demand in excess of 50% of the measured demand in kw. SPECIAL BILLING DEMAND: By customer request, Otter Tail Power may calculate the demand used for billing as the average of the previous twelve on-peak and off-peak Established Demands. The use of the special billing demand shall not exceed a period of six consecutive months. Otter Tail Power may agree to the use of the special billing demand upon conditions where customers have incurred, or can take advantage of, increased demand levels and the increased demand levels did not, or will not, increase Otter Tail Power s peak load. During the period under which the customer s billing demand is calculated in accordance to the provision of the Special Billing Demand, Otter Tail Power reserves the right to curtail the customer s additional demand (i.e., any demand over the special billing demand level) back to the customer s special billing demand in order to maintain the integrity of Otter Tail Power s generation and transmission systems. DEFINITION OF ON, SHOULDER AND OFF-PEAK PERIODS BY SEASON: WINTER SEASON - OCTOBER THROUGH MAY 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.05 Large General Service Time of Day Fergus Falls, Minnesota Page 4 of 5 Fourth Fifth Revision 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. Off-Peak: For all other kw and kwh not covered by either shoulder or on-peak Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 10.05 Large General Service Time of Day Fergus Falls, Minnesota Page 5 of 5 Fourth Fifth Revision SUMMER SEASON - JUNE THROUGH SEPTEMBER 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 not covered by either shoulder or on-peak CONTRACT PERIOD & AGREEMENT: Contract period will be outlined in agreement. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.01 Standby Service Fergus Falls, Minnesota Page 1 of 8 Fourth Fifth Revision STANDBY SERVICE OPTION A: FIRM OPTION B: NON-FIRM On-Peak Shoulder Off-Peak On-Peak Shoulder Off-Peak Transmission Service 30-941 30-942 30-943 30-950 30-951 30-952 Primary Service 30-944 30-945 30-946 30-953 30-954 30-955 Secondary Service 30-947 30-948 30-949 30-956 30-957 30-958 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. 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 60 kw. Customers with Extended Parallel Generation Systems used to meet all or a portion of electrical requirements that are capable of 60 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.01 Standby Service Fergus Falls, Minnesota Page 2 of 8 Fourth Fifth Revision STANDBY RATE OPTIONS - FIRM AND NON-FIRM OPTION A: FIRM STANDBY Transmission Primary Secondary Service Service Service Firm Standby Fixed Charges Customer Charge $0.00/month $0.00/month $0.00/month Minimum Monthly Bill Customer + Standby Facilities Charges Customer + Standby Facilities Charges Customer + Standby Facilities Charges Standby Facilities charge per month per kw of Contracted Backup Demand Not Applicable 14 /kw 19 /kw Firm Standby On-Peak Demand Charge - Summer Metered Demand per day per kw On-Peak Backup Charge 41.78 /kw 43.11 /kw 43.33 /kw Firm Standby On-Peak Demand Charge - Winter Metered Demand per day per kw On-Peak Backup Charge 38.231 /kw 39.526 /kw 39.74 /kw Firm Standby Energy Charges - Summer Energy Charges per kwh On-Peak Charge 8.4438.184 /kwh 8.6708.411 /kwh 5.5705.311 Shoulder Charge 5.4325.173 /kwh /kwh 1.9801.721 Off-Peak Charge 1.9411.682 /kwh /kwh Firm Standby Energy Charges - Winter Energy Charges per kwh 7.0096.750 On-Peak Charge 6.8056.546 /kwh /kwh 4.9334.674 Shoulder Charge 4.7984.539 /kwh /kwh 2.2371.978 Off-Peak Charge 2.1811.922 /kwh /kwh 8.7078.448 /kwh 5.5935.334 /kwh 1.9861.727 /kwh 7.0436.784 /kwh 4.9564.697 /kwh 2.2461.987 /kwh Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.01 Standby Service Fergus Falls, Minnesota Page 3 of 8 Fourth Fifth Revision OPTION B: NON-FIRM STANDBY Transmission Primary Secondary Service Service Service Non-Firm Standby Fixed Charges Customer Charge $0.00/month $0.00/month $0.00/month Minimum Monthly Bill Customer + Reservation + Standby Facilities Charge Customer + Reservation + Standby Facilities Charge Customer + Reservation + Standby Facilities Charge Standby Facilities charge per month per kw of Contracted Backup Demand Not Applicable 14 /kw 19 /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 5.4325.173 /kwh 5.5705.311 /kwh 5.5935.334 /kwh Off-Peak Charge 1.9411.682 /kwh 1.9801.721 /kwh 1.9861.727 /kwh Non-Firm Standby Energy Charges - Winter Energy Charges per kwh On-Peak Charge Not Available Not Available Not Available Shoulder Charge 4.7984.539 /kwh 4.9334.674 /kwh 4.9564.697 /kwh Off-Peak Charge 2.1811.922 /kwh 2.2371.978 /kwh 2.2461.987 /kwh INTERIM RATE ADJUSTMENT Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.01 Standby Service Fergus Falls, Minnesota Page 4 of 8 Fourth Fifth Revision A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability 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 Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.01 Standby Service Fergus Falls, Minnesota Page 5 of 8 Fourth Fifth Revision 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. 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.01 Standby Service Fergus Falls, Minnesota Page 6 of 8 Fourth Fifth Revision 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. The total monthly backup charge will not exceed the sum of the ten highest daily charges for Backup Demand, if any. 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. MISO is the Midwest Independent Transmission System Operator 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.01 Standby Service Fergus Falls, Minnesota Page 7 of 8 Fourth Fifth Revision Customers with Extended Parallel Generation Systems used to meet all or a portion of electrical requirements that are capable of 60 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 60 kw or less is available under the Customer s base rate. For Large General Service or Large General Service-Time of Use Customers, a Special Minimum Demand may apply. For more information regarding Extended Parallel Generation Systems, Physical Assurance Customers, Special Minimum Demand, 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 customers, the Company and the customer will mutually agree to different maintenance schedules as listed above. Special Minimum Demand is a special demand calculation that the Company may use at its option for Large General Service or Large General Service-Time of Use Customers. The terms are outlined in Sections 10.03 and 10.05. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.01 Standby Service Fergus Falls, Minnesota Page 8 of 8 Fourth Fifth Revision 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.02 Irrigation Service Fergus Falls, Minnesota Page 1 of 4 Twentieth Twenty-first Revision IRRIGATION SERVICE DESCRIPTIONESCRIPTION RATE CODE Option 1: Non-Time-of-Use 30-703 Option 2: Declared-Peak 30-704 Option 2: Intermediate 30-705 Option 2: Off-Peak 30-706 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF SCHEDULE: This service is available to customers legally entitled to use water for irrigation during the irrigation season, April 15 through November 1. RATES: OPTION 1 Customer Charge per Month: $1.00 Monthly Minimum Bill: Facilities Charge per Month: Customer + Facilities Charge Customer-Specific see Tariff Energy Charge per kwh: Summer Winter 5.874 /kwh 4.623 /kwh Minnesota Docket No. E-017/M-09-214GR-10-239 Approved: May 12, 2009(DATE) and after May 12, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.02 Irrigation Service Fergus Falls, Minnesota Page 2 of 4 Twentieth Twenty-first Revision OPTION 2 Customer Charge per Month: $5.00 Monthly Minimum Bill: Facilities Charge per Month: Customer + Facilities Charge Customer-Specific see Tariff Energy Charge per kwh: Summer Winter Declared-Peak 15.38015.121 /kwh 14.73914.480 /kwh Intermediate 3.0292.770 /kwh 2.5942.335 /kwh Off-Peak 1.4591.200 /kwh 1.3511.092 /kwh Demand Charge per kw: Summer Winter Declared-Peak 0.00 /kw 0.00 /kw Intermediate $1.52 /kw $2.21 /kw Off-Peak 0.00 /kw 0.00 /kw INTERIM RATE ADJUSTMENT A 3.8 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. FACILITIES 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. MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Voluntary Rate Riders selected by the Customer or Mandatory Rate Riders that must apply. See sections 12 through 14 of the Minnesota electric rates for the applicability matrices of riders. 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 Minnesota Docket No. E-017/M-09-214GR-10-239 Approved: May 12, 2009(DATE) and after May 12, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.02 Irrigation Service Fergus Falls, Minnesota Page 3 of 4 Twentieth Twenty-first Revision so, abide by such restrictions. DEFINITION OF DECLARED, INTERMEDIATE AND OFF-PEAK PERIODS BY SEASON: WINTER SEASON APRIL 15 THROUGH MAY, AND OCTOBER THROUGH NOVEMBER 1 Declared-Peak: Hours declared. Intermediate: All hours other than declared-peak and off-peak. Off-Peak: For all kw and kwh used Weekdays or Saturdays from10:00 p.m. to 6:00 a.m., all day Sunday. SUMMER SEASON - JUNE THROUGH SEPTEMBER Declared-Peak: Hours declared. Intermediate: All hours other than declared-peak and off-peak. Off-Peak: For all kw and kwh used Weekdays or Saturdays from10:00 p.m. to 6:00 a.m., 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 Contract Period shall be 5 years. Because of the investment of the customer in pumping and irrigation equipment, and of the Company in the extension of lines, 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. 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 his 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. The annual fixed charge will be billed in seven equal monthly installments May through November of each year. Minnesota Docket No. E-017/M-09-214GR-10-239 Approved: May 12, 2009(DATE) and after May 12, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.02 Irrigation Service Fergus Falls, Minnesota Page 4 of 4 Twentieth Twenty-first Revision Minnesota Docket No. E-017/M-09-214GR-10-239 Approved: May 12, 2009(DATE) and after May 12, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.03 Outdoor Lighting Energy Only Fergus Falls, Minnesota Page 1 of 3 Second Third Revision OUTDOOR LIGHTING ENERGY ONLY DUSK TO DAWN DESCRIPTION RATE CODE Sign Lighting 30-747 Street and Area Lighting - Metered 30-748 Street and Area Lighting - Non-Metered 30-749 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This tariff is available to both private and governmental entities. The tariff will allow the Company to sell automatically operated dusk to dawn outdoor lighting electric energy to municipal and other outdoor area lighting customers who choose to own, install, and maintain the lighting equipment. Under the tariff, Otter Tail 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 meet the Company s specifications. 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 if, in the Company s determination, the customer s lighting equipment is operated or maintained in an unsafe or improper manner. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.03 Outdoor Lighting Energy Only Fergus Falls, Minnesota Page 2 of 3 Second Third Revision RATE METERED: OUTDOOR LIGHTING - ENERGY ONLY Metered Rate Customer Charge per Month: $1.60 Monthly Minimum Bill: Customer Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: 6.8356.576 /kwh RATE NON-METERED: OUTDOOR LIGHTING SIGN LIGHTING AND NON-METERED RATE Monthly charge = Connected kw x $23.3522.47, where Connected kw is the rated power of the lighting fixture (including ballast) INTERIM RATE ADJUSTMENT A 3.8 percent increase will be added to the sum of the following, as applicable: Customer Charge, Energy Charge, Demand Charge, Fixed Charge, Facilities Charge, Monthly Charge, and the monthly Minimum Charge. MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Voluntary Rate Riders selected by the Customer or Mandatory Rate Riders that must apply. See sections 12 through 14 of the Minnesota electric rates for the applicability matrices of riders. SERVICE CONDITIONS: Company-owned lights shall not be attached to customer-owned property. Company shall have the right to periodically review the customer s lighting equipment to verify Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.03 Outdoor Lighting Energy Only Fergus Falls, Minnesota Page 3 of 3 Second Third Revision that the rated power (kw) of the non-metered fixtures is consistent with the Company s records. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.04 Outdoor Lighting Fergus Falls, Minnesota Page 1 of 3 Fourteenth Fifteenth Revision DESCRIPTION OUTDOOR LIGHTING DUSK TO DAWN RATE CODE Street and Area Lighting 29-745 Floodlighting 29-746 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This schedule is available to any customer, including a village, town or city, for automatically operated dusk to dawn outdoor lighting supplied and operated by the Company. RATES[dlm1]: Unit type Lumens Wattage Monthly Charge MV-6 6000 175 $6.436.25 MV-6PT 6000 175 $8.408.22 MV-11 11000 250 $12.0311.77 MV-21 21000 400 $15.5615.16 MV-35 35000 750 $23.4422.77 MV-55 55000 1000 $32.2031.25 MH-8 8500 100 $7.327.21 MH-14 14000 175 $13.9413.76 MH-20 20500 250 $15.9215.67 MH-36 36000 400 $15.6215.22 MH-110 110000 1000 $33.3432.38 HPS-9 9000 100 $7.167.05 HPS-9PT 9000 100 $8.648.53 HPS-14 14000 150 $11.1010.93 HPS-14PT 14000 150 $11.0810.91 HPS-19 19000 200 $12.8612.65 HPS-23 23000 250 $14.5214.26 HPS-44 44000 400 $17.9917.59 Fixture Unit Type Monthly Charge 400 MV-Flood Mercury Vapor $15.5615.16 400 MA-Flood Metal Additive Mercury $18.2517.85 400 HPS-Flood High Pressure Sodium $17.9917.59 1000 MV-Flood Mercury Vapor $30.5929.64 1000 MA-Flood Metal Additive Mercury $33.8132.85 Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.04 Outdoor Lighting Fergus Falls, Minnesota Page 2 of 3 Fourteenth Fifteenth Revision 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 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability 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 $25.00 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 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 or sign, the Company will supply the equivalent of one span of underground and add an additional $1.92 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. EQUIPMENT AND SERVICE SUPPLIED BY THE COMPANY: 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. Other than customers provided with pole top fixtures on fiberglass poles, the service will provide pole top lights. The light shall operate from dusk to dawn. The Company will supply the necessary electricity and maintenance for the unit. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.04 Outdoor Lighting Fergus Falls, Minnesota Page 3 of 3 Fourteenth Fifteenth Revision SERVICE CONDITIONS: Lighting will not be mounted on customer-owned property. The light shall be mounted upon a suitable new or existing Company-owned facilities. Company shall own, operate, and maintain the lighting unit including the pole, fixture, lamp, ballast, photoelectric control, mounting brackets, and all necessary wiring using Company's standard street lighting equipment. Company shall furnish all electric energy required for operation of the unit. In cases of vandalism or damages, Otter Tail Power Company has the discretion to discontinue service. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.05 Municipal Pumping Service Fergus Falls, Minnesota Page 1 of 2 Eleventh Twelfth Revision DESCRIPTION MUNICIPAL PUMPING SERVICE RATE CODE Secondary Service 30-871 Primary Service 30-874 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This rate schedule is available to non-seasonal municipal or other governmental loads only. It shall apply to electric service for motor driven pumps for use at water pumping and treating plants, sewage disposal and treating plants, sewage lift stations and may be extended 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 the pumping operation, may not be served at this rate, however the Company reserves the authority to extend service under this tariff in cases where it is not practical to separately meter small loads adjacent to this service. The rate schedule and monthly minimum shall apply to each meter in service except that where service through a meter is for electric space heating only the energy on this meter shall be added to the pumping meter for billing purposes. Seasonal service is not permitted. RATES: The Company retains the authority to allow combined billing at locations where an approved single phase electric space heating load is metered separately from the three phase pumping load. In all other cases the monthly minimum shall apply to each meter providing service under this tariff. SECONDARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $8.00 Facilities Charge per Month: Maximum Monthly kwh <1150 $1.00 Maximum Monthly kwh 1150-7500 $5.00 Maximum Monthly kwh >7500 $15.00 Energy Charge per kwh: Summer Winter 6.0805.821 /kwh 5.6375.378 /kwh Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.05 Municipal Pumping Service Fergus Falls, Minnesota Page 2 of 2 Eleventh Twelfth Revision PRIMARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $8.00 Facilities Charge per Month: Maximum Monthly kwh <1150 $0.48 Maximum Monthly kwh 1150-7500 $2.41 Maximum Monthly kwh >7500 $7.24 Energy Charge per kwh: Summer Winter 6.2445.985 /kwh 5.6125.353 /kwh INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.06 Civil Defense - Fire Sirens Fergus Falls, Minnesota Page 1 of 2 Fourth Fifth Revision DESCRIPTION CIVIL DEFENSE-FIRE SIRENS RATE CODE Civil Defense Fire Sirens 30-843 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF SCHEDULE: This schedule is applicable to separately served civil defense and municipal fire sirens. RATES: CIVIL DEFENSE - FIRE SIRENS Customer Charge per Month: $0.00 Monthly Minimum Bill: $2.75 per siren + Facilities Charge Facilities Charge per Month: $0.00 Charge per HP: Summer Winter 61.077 /HP 61.077 /HP INTERIM RATE ADJUSTMENT A 3.8 percent increase will be added to the sum of the following, as applicable: Customer Charge, Energy Charge, Demand Charge, Fixed Charge, Facilities Charge, Charge per HP, 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 11.06 Civil Defense - Fire Sirens Fergus Falls, Minnesota Page 2 of 2 Fourth Fifth Revision 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 tariff, the Company will provide an extension of up to one span of wire, not to exceed 300 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 12.01 Small Power Producer Rider Net Energy Billing Rate Page 1 of 3 Twenty-sixth seventh Revision SMALL POWER PRODUCER RIDER (Net Energy Billing Rate) REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: Available to any qualifying facility with generation capacity not exceeding 40 kw. CUSTOMER CHARGE: $1.40 per month INTERIM RATE ADJUSTMENT A 3.8 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 7.066 per kwh 30-910 Farm 6.398 per kwh 30-930 General Service 7.990 per kwh 30-940 Large General Service 5.715 per kwh 30-960 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. EFFECTIVE for services rendered on and after April June 1, 2010, in Minnesota Docket No. E-017/M-09-1057GR-10-239 Approved: March 25, 2010(DATE) Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.01 Small Power Producer Rider Net Energy Billing Rate Page 2 of 3 Twenty-sixth seventh Revision 3. A SQF must have a generation capacity of at least 30 kw to qualify for wheeling by the Company of the SQF output. In the event that the SQF desires, and qualifies for, wheeling by the Company of the SQF output, arrangements will be made subject to special provisions to be determined by all utilities involved. This also applies to SQF's outside the Company's service territory. 4. If required, a separate meter will be furnished, owned and maintained by the Company to measure the energy to the Company. 5. The SQF shall make provisions for the installation of Company owned on-site metering. All energy received from and delivered to the Company shall be metered. On site use of the SQF output shall be unmetered for purposes of compensation. 6. The customer shall pay for any increased capacity of the distribution equipment serving him and made necessary by the installation of his generator. 7. Power and energy purchased by the SQF from the Company shall be billed under the available retail rates for the purchase of electricity. 8. The generator output must be compatible with the Utility system. The customer's 60 hertz generator output must be at the voltage and phase relationship of the existing service or of one mutually agreeable to the Company and the customer. 9. The customer will provide equipment to maintain a 100% power factor (+ or - 10%) during periods of generator operation. 10. The Company reserves the right to disconnect the customer's generator from its system if it interferes with the operation of the Company's equipment or with the equipment of other company customers. 11. The Customer is required to follow the Company s interconnection process which requires that prior to installation, a detailed electrical diagram of the generator and related equipment must be furnished to the Company for its approval for connection to the Company's system. No warranties, express or implied, will be made as to the safety or fitness of the said equipment by the Company due to this approval. 12. The customer shall execute an electric service contract with the Company which may include, EFFECTIVE for services rendered on and after April June 1, 2010, in Minnesota Docket No. E-017/M-09-1057GR-10-239 Approved: March 25, 2010(DATE) Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.01 Small Power Producer Rider Net Energy Billing Rate Page 3 of 3 Twenty-sixth seventh Revision 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. EFFECTIVE for services rendered on and after April June 1, 2010, in Minnesota Docket No. E-017/M-09-1057GR-10-239 Approved: March 25, 2010(DATE) Regulatory Services Manager

Interim Minnesota, Section 12.02 Small Power Producer Rider Simultaneous Purchase and Sale Billing Rate Fergus Falls, Minnesota Page 1 of 3 Twenty-sixth seventh Revision SMALL POWER PRODUCER RIDER SIMULTANEOUS PURCHASE AND SALE BILLING RATE DESCRIPTION RATE CODE Firm Power 30-981 Nonfirm Power 30-984 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under of this schedule. AVAILABILITY: 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 3.8 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 0.446 per kwh 0.445 per kwh 3.569 per kwh 2.909 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. DEFINITIONS: Firm Power: Energy delivered by the qualifying facility to the utility with at least a 65percent on-peak capacity factor in the month. Capacity Factor: The number of kilowatt-hours delivered during a period divided by the product and after April June 1, 2010, in Minnesota Docket No. E-017/M-09-1057GR-10-239 Approved: March 25, 2010(DATE) Regulatory Services Manager

Interim Minnesota, Section 12.02 Small Power Producer Rider Simultaneous Purchase and Sale Billing Rate Fergus Falls, Minnesota Page 2 of 3 Twenty-sixth seventh Revision of (the maximum one hour delivered capacity in kilowatts in the period) times (the number of hours in the period). Summer: June through September. Winter: October through May. 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. 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. and after April June 1, 2010, in Minnesota Docket No. E-017/M-09-1057GR-10-239 Approved: March 25, 2010(DATE) Regulatory Services Manager

Interim Minnesota, Section 12.02 Small Power Producer Rider Simultaneous Purchase and Sale Billing Rate Fergus Falls, Minnesota Page 3 of 3 Twenty-sixth seventh Revision 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. and after April June 1, 2010, in Minnesota Docket No. E-017/M-09-1057GR-10-239 Approved: March 25, 2010(DATE) Regulatory Services Manager

Interim Minnesota, Section 12.03 Small Power Producer Rider Time of Day Purchase Rates Fergus Falls, Minnesota Page 1 of 3 Twenty-sixth seventh Revision DESCRIPTION SMALL POWER PRODUCER RIDER TIME OF DAY PURCHASE RATES RATE CODE Firm Power 30-982 Nonfirm Power 30-983 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. AVAILABILITY: 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 3.8 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) 1.090 per kwh 4.748 per kwh 2.773 per kwh Winter (Firm Power and Non-Firm Power) 1.016 per kwh 3.941 per kwh 2.103 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. DEFINITIONS: and after April June 1, 2010 in Minnesota Docket No. E-017/M-09-1057GR-10-239 Approved: March 25, 2010(DATE) Regulatory Services Manager

Interim Minnesota, Section 12.03 Small Power Producer Rider Time of Day Purchase Rates Fergus Falls, Minnesota Page 2 of 3 Twenty-sixth seventh Revision 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 through September including those hours from 8:00 a.m. to 10:00 p.m. Monday through Friday, excluding holidays. Winter On-Peak: October through May 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. 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. and after April June 1, 2010 in Minnesota Docket No. E-017/M-09-1057GR-10-239 Approved: March 25, 2010(DATE) Regulatory Services Manager

Interim Minnesota, Section 12.03 Small Power Producer Rider Time of Day Purchase Rates Fergus Falls, Minnesota Page 3 of 3 Twenty-sixth seventh Revision 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. 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. and after April June 1, 2010 in Minnesota Docket No. E-017/M-09-1057GR-10-239 Approved: March 25, 2010(DATE) Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 1 of 6 Second Third Revision DESCRIPTION DISTRIBUTED GENERATION SERVICE RIDER RATE CODE Distributed Generation Service Rider 30-931 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. AVAILABILITY: The Rider for Distributed Generation is available between any Customer, who has entered into the State of Minnesota Interconnection Agreement for the Interconnection of Extended Parallel Distributed Generation Systems with Electric Utilities, and the Company for the interconnection and operation of on-site extended parallel distributed generation system, as follows. 1. The distributed generation system must be fueled by natural gas or a renewable fuel, or another similarly clean fuel or combination of fuels of no more than 10 MW of interconnected capacity at a point of common coupling to Company s distribution system. The distributed generation facility must be an operable, permanently installed or mobile generation facility serving the Customer receiving retail electric service at the same site. 2. The interconnection and operation of distributed generation systems at each point of common coupling shall be considered as a separate application of the Rider. 3. Service hereunder is subject to Company s Guidelines for Generation, Tie-Line, and Substation Interconnections and the State of Minnesota Interconnection Process for Distributed Generation Systems, copies of which are available at the Company s web page at http://www.otpco.com. The requirements, terms and conditions contained in the State of Minnesota Interconnection Process for Distributed Generation Systems supersede the requirements, terms and conditions contained in the Company s Guidelines for Generation, Tie-Line, and Substation Interconnections in the event of an inconsistency between the two documents. 4. All provisions of the applicable standard service schedule shall apply to distributed generation service under this Rider except as noted below. In lieu of service under this Rider, Customer and Company may pursue reasonable transactions Minnesota Docket No. E017/M-09-109GR-10-239 Approved: January 27, 2010(DATE) EFFECTIVE for services rendered on and after January 27, 2010June 1, 2010, in Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 2 of 6 Second Third Revision 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 Application of Schedule section above. Customer Charge: $11.57 per month for customer account expense Distribution Maintenance Charge ($/Month): This charge will be based upon customerspecific 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 Services Charge and the Distribution Maintenance Charge. Interim Rate Adjustment: A 3.8 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 Minnesota Docket No. E017/M-09-109GR-10-239 Approved: January 27, 2010(DATE) EFFECTIVE for services rendered on and after January 27, 2010June 1, 2010, in Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 3 of 6 Second Third Revision 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 tariff or under other mutually agreeable arrangement 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 Minnesota Docket No. E017/M-09-109GR-10-239 Approved: January 27, 2010(DATE) EFFECTIVE for services rendered on and after January 27, 2010June 1, 2010, in Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 4 of 6 Second Third Revision enters into a power purchase agreement with Company shall remain in effect for the length 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 Commissionapproved 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 Minnesota Docket No. E017/M-09-109GR-10-239 Approved: January 27, 2010(DATE) EFFECTIVE for services rendered on and after January 27, 2010June 1, 2010, in Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 5 of 6 Second Third Revision the development of a Commission-approved renewable energy tracking system) associated with the Customer s on-site usage. 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%) Minnesota Docket No. E017/M-09-109GR-10-239 Approved: January 27, 2010(DATE) EFFECTIVE for services rendered on and after January 27, 2010June 1, 2010, in Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 6 of 6 Second Third Revision during periods of generator operation. 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. Minnesota Docket No. E017/M-09-109GR-10-239 Approved: January 27, 2010(DATE) EFFECTIVE for services rendered on and after January 27, 2010June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.01 Water Heating Control Rider Fergus Falls, Minnesota Page 1 of 2 Eighteenth Nineteenth Revision DESCRIPTION WATER HEATING CONTROL RIDER RATE CODE Metered Water Heating Control Service 30-191 Water Heating Control Service Credit 30-192 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF SCHEDULE: This schedule is applicable for residential or non-residential purposes. RATES: WATER HEATING - CONTROLLED SERVICE 191 Customer Charge per Month: $1.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter 5.6835.424 /kwh 5.0844.825 /kwh WATER HEATING CREDIT 192 A $4.00 credit per month shall be applied to all bills having direct control water heating, except the credit shall not reduce the monthly billing to less than the Monthly minimum Charge. INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.01 Water Heating Control Rider Fergus Falls, Minnesota Page 2 of 2 Eighteenth Nineteenth Revision Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. TERM AND CONDITIONS FOR RATE 191: Service under rate 191 shall be supplied on a separate meter. TERMS AND CONDITIONS FOR RATE 192: The Customer will be compensated for taking service on this Rider by receiving a $4.00 per month bill credit. The credit will be applied on the customer s account. CONTROL CRITERIA: Service may be controlled for up to a total of 14 hours during any 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 through September. Winter: October through May. EQUIPMENT SUPPLIED: Otter Tail will supply and maintain the necessary metering and/or control equipment. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.02 Real Time Pricing Rider Fergus Falls, Minnesota Page 1 of 5 Second Third Revision DESCRIPTION OF SERVICE REAL TIME PRICING RIDER RATE CODES Transmission Service 30-660 Primary Service 30-662 Secondary Service 30-664 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This rider is available on a voluntary basis and is limited to twenty 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 Otter Tail Power Company. INTERIM RATE ADJUSTMENT A 3.8 percent increase will be added to the Administrative Charge. MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Voluntary Rate Riders selected by the Customer or Mandatory Rate Riders that must apply. See sections 12 through 14 of the Minnesota electric rates for the applicability 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 Otter Tail Power 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.02 Real Time Pricing Rider Fergus Falls, Minnesota Page 2 of 5 Second Third Revision 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. Otter Tail Power 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 Bill Mo + Consumption Changes from CBL Hr + Excess Reactive Demand Where: RTP Bill Mo = Customer's monthly bill for service under this Rider Adm. Chg. = See Administrative Charge section below Std. Bill Mo = See Standard Bill section above Consumption Changes From CBL = {Price Hr x {Load Hr - CBL Hr }} Excess Reactive Demand = See Excess Reactive Demand section below = Sum over all hours of the monthly billing period Price Hr = Hourly RTP price as defined under Pricing Methodology Load Hr = Customer's actual load for each hour of the billing period CBL Hr = Customer's CBL energy usage for each hour of the billing period Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.02 Real Time Pricing Rider Fergus Falls, Minnesota Page 3 of 5 Second Third Revision 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, Otter Tail Power 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 Otter Tail. 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. 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 Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.02 Real Time Pricing Rider Fergus Falls, Minnesota Page 4 of 5 Second Third Revision in Otter Tail'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, Otter Tail 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 Otter Tail. In these cases, Otter Tail 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: CBL t+1 = CBL t + {Adjustment Factor x ( Actual load t - CBL t )} PRICE NOTIFICATION: Otter Tail Power 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, Otter Tail 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 Otter Tail from projecting prices more than one Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.02 Real Time Pricing Rider Fergus Falls, Minnesota Page 5 of 5 Second Third Revision day in advance, Otter Tail 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. Otter Tail 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 Otter Tail, it is the customer's responsibility to notify Otter Tail by 4:30 p.m. (Central Time) of the business day preceding the day that the prices are to take effect. Otter Tail 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 Otter Tail 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 Otter Tail. 3. If the customer's actual load exceeds the CBL by an amount that requires Otter Tail to install additional facilities to serve the customer, the customer will be responsible for any and all costs incurred by Otter Tail to install the facilities. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.03 Large General Service Rider Fergus Falls, Minnesota Page 1 of 6 Fourth Fifth Revision LARGE GENERAL SERVICE RIDER DESCRIPTION Option 1 Option 2 Fixed Rate Energy Pricing 30-648 30-649 System Marginal Energy Pricing 30-642 30-645 Short-term Marginal Capacity Purchases 30-643 30-646 Short-term Marginal Capacity Releases 30-644 30-647 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. INTERIM RATE ADJUSTMENT A 3.8 percent increase will be added to the sum of the following, as applicable: Customer Charge, Energy Charge, Demand Charge, Fixed Charge, Facilities Charge, the monthly Minimum Charge, and Administrative Charge. MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Voluntary Rate Riders selected by the Customer or Mandatory Rate Riders that must apply, unless otherwise noted in this rider. See sections 12 through 14 of the Minnesota electric rates for the applicability matrices of riders. 1. Availability. 1.1 Large General Service Customers. 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. 1.2 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, On-Peak Baseline Demand and Off-Peak Baseline Demand. 2. Fixed Rate Energy Pricing. 2.1 Background. Certain of Otter Tail's industrial and commercial Customers have ESAs that designate, among other things, a Billing Demand, On-Peak and Off-Peak Baseline Demands and a Firm Demand. With On-Peak and Off-Peak Baseline Demands, 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 schedule and/or a negotiated rate subject to Commission approval. Setting a Firm and Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.03 Large General Service Rider Fergus Falls, Minnesota Page 2 of 6 Fourth Fifth Revision 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 and the ability to purchase Energy above the Baseline Demand at rates set forth in the Customer s applicable rate schedule and/or a negotiated Energy rate subject to Commission approval. 2.2 Energy. The Customer s monthly rate for Energy will be determined in two parts: (1) Energy consumed up to and including the On-Peak Baseline Demand and Off-Peak Baseline Demand, and (2) Energy consumed above the On-Peak Baseline Demand and Off-Peak Baseline Demand. The price (rate) for Energy consumed up to and including the On-Peak Baseline Demand and Off-Peak Baseline Demand 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 On- Peak Baseline Demand and Off-Peak Baseline Demand 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. 2.3 Demand. The 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. 3. System Marginal Energy Pricing. 3.1 Background. Certain of Otter Tail's industrial and commercial Customers have ESAs that designate, among other things, a Billing Demand, On-Peak and Off-Peak Baseline Demands and a Firm Demand. With On-Peak and Off-Peak Baseline Demands, the Company agrees to provide and the Customer agrees to purchase its Energy requirements up to the Baseline Demand 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 and the ability to purchase Energy above the Baseline Demand 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 according to the value the Customer places on that Energy in real-time. 3.2 Energy. The Customer s monthly rate for Energy will be determined in two parts: (1) Energy consumed up to and including the On-Peak Baseline Demand and Off-Peak Baseline Demand, and (2) Energy consumed above the On-Peak Baseline Demand and Off-Peak Baseline Demand. The price (rate) for Energy consumed up to and including the On-Peak Baseline Demand and Off-Peak Baseline Demand will be determined by multiplying the Customer s metered Energy Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.03 Large General Service Rider Fergus Falls, Minnesota Page 3 of 6 Fourth Fifth Revision consumption by the Energy rate provided in the rate schedule applicable to the Customer. The monthly rate for Energy consumed above the On-Peak Baseline Demand and Off-Peak Baseline Demand will be determined by multiplying the Customer s metered Energy consumption by the Company s System Marginal Energy Price. 3.2.1 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. 3.2.2 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 System Marginal Energy Pricing. 3.3 Demand. The 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. 4. Short-term Marginal Capacity Purchases and Releases. 4.1 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. This Section 3 provides 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 ). 4.2 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 Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.03 Large General Service Rider Fergus Falls, Minnesota Page 4 of 6 Fourth Fifth Revision the Customer s notice under Section 4.3, the Customer may seek Marginal Capacity indirectly from a third party. The Company would work with the third party to effectuate the purchase. In each case, Otter Tail 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. 4.2.1 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. 4.2.2 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. 4.2.3 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 Designation C-03M (the RTP Rider), Energy consumed above the On-Peak Baseline Demand and Off- Peak Baseline Demand will continue to be billed at the System Marginal Energy Price. RTP Rider Customers will continue to be billed under the provisions of Rate Designation C-03M. 4.3 Released Capacity. Where the Customer requests to release Capacity on a shortterm 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 use or to resell it offsystem 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). Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.03 Large General Service Rider Fergus Falls, Minnesota Page 5 of 6 Fourth Fifth Revision 4.3.1 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. 4.3.2 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. 4.3.3 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. 5. Miscellaneous Provisions. 5.1 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. 5.2 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. 5.3 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 (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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.03 Large General Service Rider Fergus Falls, Minnesota Page 6 of 6 Fourth Fifth Revision 5.4 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. 5.5 Metering Requirements. Company approved metering equipment capable of providing load interval information is required for Rider participation. Customer agrees to pay for the additional cost of such metering when not provided in conjunction with existing retail electric service. 5.6 Liability. The Company and Customer agree that Company has no liability for indirect, special, incidental, or consequential loss or damages to Customer, including but not limited to Customer's operations, site, production output, or other claims by the Customer as a result of participation in this Rider. 5.7 Energy Adjustment Rider. Energy consumed up to and including the On-Peak Baseline Demand and Off-Peak Baseline Demand is subject to the Energy Adjustment Rider as provided in Section 13, or any amendments or superseding provisions applicable thereto. Because Energy consumed above the On-Peak Baseline Demand and Off-Peak Baseline Demand 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, Section 13. 5.8 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Services

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.04 Controlled Service Interruptible Load Rider (CT Metering) Fergus Falls, Minnesota Page 1 of 3 Nineteenth Twentieth Revision CONTROLLED SERVICE - INTERRUPTIBLE LOAD CT METERING RIDER (Commonly identified as LARGE DUAL FUEL) DESCRIPTION RATE CODES CT Metering 29-170 CT Metering (with short-duration cycling) 29-165 Penalty 29-881 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. APPLICATION OF RIDER: This rider is applicable for residential or non-residential service to any 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 used for both heating and cooling. Domestic electric water heating, and/or other permanently connected approved loads that can be interrupted during control periods. Electric fans, pumps, and other ancillary, equipment used in the distribution of heat 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 manufacturers 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.04 Controlled Service Interruptible Load Rider (CT Metering) Fergus Falls, Minnesota Page 2 of 3 Nineteenth Twentieth Revision RATES: CONTROLLED SERVICE - INTERRUPTIBLE LOAD - CT METERING Customer Charge per Month: $5.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter All kwh 3.0042.745 /kwh 2.6902.431 /kwh Penalty kwh 15.000 /kwh 11.000 /kwh MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. INTERIM RATE ADJUSTMENT A 3.8 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. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. 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. Penalty usage will be recorded on the peak register, and the total register of the dual register meters. Installation of a dual register meter will be at the option of the Company. 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.04 Controlled Service Interruptible Load Rider (CT Metering) Fergus Falls, Minnesota Page 3 of 3 Nineteenth Twentieth Revision CONTROL CRITERIA: Service may be controlled 0 hours up to a total of 24 hours during any 24-hour period, as measured from midnight to midnight. Short-duration cycling is 15-minutes off / 15-minutes on of appropriate cooling equipment during the summer season (June 1-September 30). Approved deferred loads will receive 10 or more hours service per day. EQUIPMENT SUPPLIED: Otter Tail will supply and maintain the necessary metering and control equipment. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.05 Controlled Service Interruptible Load Self-Contained Metering Rider (Small Dual Fuel) Fergus Falls, Minnesota Page 1 of 3 Nineteenth Twentieth Revision CONTROLLED SERVICE - INTERRUPTIBLE LOAD SELF-CONTAINED METERING RIDER (Commonly identified as Small Dual Fuel) DESCRIPTION RATE CODE Self-Contained Metering 29-190 Self-Contained Metering (with short-duration cycling) 29-185 Penalty 29-882 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF RIDER: This rider is applicable for residential or non-residential service to any 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 used for both heating and cooling. Domestic electric water heating and/or other permanently connected approved loads that can be interrupted during control periods. Electric fans, pumps and other ancillary equipment used in the distribution of heat shall be wired for service through the customer's firm 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 manufacturers 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.05 Controlled Service Interruptible Load Self-Contained Metering Rider (Small Dual Fuel) Fergus Falls, Minnesota Page 2 of 3 Nineteenth Twentieth Revision RATES: CONTROLLED SERVICE - INTERR LOAD SELF-CONTAINED Customer Charge per Month: $5.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter All kwh 4.0553.796 /kwh 3.6253.366 /kwh Penalty kwh 15.000 /kwh 11.000 /kwh INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. 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. Penalty usage will be recorded on the peak register, and the total register of the dual register meters. Installation of a dual register meter will be at the option of the Company. The penalty provision is not intended as buy-through option. Under no circumstances should the penalty clause of this rider be interpreted as an approved buy-thru option for service under this rider. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.05 Controlled Service Interruptible Load Self-Contained Metering Rider (Small Dual Fuel) Fergus Falls, Minnesota Page 3 of 3 Nineteenth Twentieth Revision CONTROL CRITERIA: Service may be controlled 0 hours up to a total of 24 hours during any 24-hour period, as measured from midnight to midnight. Short-duration cycling is 15-minutes off / 15-minutes on of appropriate cooling equipment during the summer season (June 1-September 30). Approved deferred loads will receive 10 or more hours service per day. EQUIPMENT SUPPLIED: Otter Tail will supply and maintain the necessary metering and control equipment. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.06 Controlled Service Deferred Load Rider (Thermal Storage) Fergus Falls, Minnesota Page 1 of 3 Nineteenth Twentieth Revision CONTROLLED SERVICE DEFERRED LOAD RIDER (Commonly identified as Thermal Storage) DESCRIPTION RATE CODE Deferred Loads 30-197 Deferred Loads ( with short-duration cycling) 30-195 Penalty 30-883 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF RIDER: This rider is applicable for both residential and non-residential service to any 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 used for both heating and cooling, 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 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 manufacturers 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. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.06 Controlled Service Deferred Load Rider (Thermal Storage) Fergus Falls, Minnesota Page 2 of 3 Nineteenth Twentieth Revision RATES: CONTROLLED SERVICE - DEFERRED LOAD Customer Charge per Month: $1.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: Below 5000 kwh per month in all months $3.00 At or above 5000 kwh in any month $10.00 Energy Charge per kwh: Summer Winter All kwh 5.4555.196 /kwh 4.8814.622 /kwh Penalty kwh 15.000 /kwh 11.000 /kwh INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. 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. Penalty usage will be recorded on the peak register, and the total register of the dual register meters. Installation of a dual register meter will be at the option of the Company. The penalty provision is not intended as buy-through option. Under no circumstances should the Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.06 Controlled Service Deferred Load Rider (Thermal Storage) Fergus Falls, Minnesota Page 3 of 3 Nineteenth Twentieth Revision penalty clause of this rider be interpreted as an approved buy-thru option for service under this rider. FACILITIES CHARGES: The Facilities Charge will be $3.00 per month, unless the usage is at or above 5000 kwh per month which will establish the Facilities Charge at $10.00 per month for a 12 month period. The Facilities Charge is based on 30 days per month in a billing period. An adjustment of 167 kwh a day will be added for each day that a billing period exceeds 30 days. CONTROL CRITERIA: Service may be controlled for up to a total of 14 hours during any 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. Shortduration cycling is 15-minutes off / 15-minutes on of appropriate cooling equipment during the summer season (June 1-September 30). EQUIPMENT SUPPLIED: Otter Tail will supply and maintain the necessary metering and control equipment. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Regulatory Services Manager

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.07 Fixed Time of Delivery Rider (Fixed TOD) Page 1 of 3 Fergus Falls, Minnesota Third Fourth Revision FIXED TIME OF DELIVERY RIDER (Commonly identified as FIXED TOD) DESCRIPTION RATE CODES Fixed Time of Delivery Service Self-Contained Metering 29-301 Fixed Time of Delivery Service CT Metering 29-302 Fixed Time of Delivery Service Primary CT Metering 29-303 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. APPLICATION OF SCHEDULE: This rider is applicable to customers requesting service to permanently connected thermal storage space heating technologies that are designed and installed with the capability to operated under the limitations and terms of this rider. Rider threshold determinations will be made based on connected load and service level and will be independent of actual registered demand or energy usage. RATES: SECONDARY SERVICE - Self-Contained Metering Customer Charge per Month: $1.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $3.00 Energy Charge per kwh: Summer Winter 2.6532.394 /kwh 2.9202.661 /kwh Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Service

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.07 Fixed Time of Delivery Rider (Fixed TOD) Page 2 of 3 Fergus Falls, Minnesota Third Fourth Revision SECONDARY SERVICE CT Metering Customer Charge per Month: $2.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $14.00 Energy Charge per kwh: Summer Winter 2.6532. 394 /kwh 2.9202.66 1 /kwh PRIMARY SERVICE - CT Metering Customer Charge per Month: $3.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $9.00 Energy Charge per kwh: Summer Winter 2.6452.3 2.9132.6 86 /kwh 54 /kwh INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Service

Interim Otter Tail Corporation d/b/a Minnesota, Section 14.07 Fixed Time of Delivery Rider (Fixed TOD) Page 3 of 3 Fergus Falls, Minnesota Third Fourth Revision CONTROL CRITERIA: The customer will receive electric service from 10:00 p.m. until 6:00 a.m. each day. In all other hours, the customer's load will be controlled. EQUIPMENT SUPPLIED: Otter Tail Power Company will supply and maintain the necessary metering and control equipment. Minnesota Docket No. E-017/GR-07-117810-239 Approved: October 31, 2008(DATE) and after February 1, 2009June 1, 2010, in Manager, Regulatory Service

Volume 1 Interim Tariff Sheets Non-Redlined 1/3 Tab

Fergus Falls, Minnesota Interim Minnesota, Section 9.01 Residential Service Page 1 of 2 Twenty-fourth Revision DESCRIPTION RESIDENTIAL SERVICE RATE CODE Residential Service 30-101 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. AVAILABILITY: This schedule is applicable for residential service as defined in the General Rules and Regulations. RATES: RESIDENTIAL SERVICE Customer Charge per Month: $8.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter 7.642 /kwh 6.903 /kwh R INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. and after June 1, 2010, in Minnesota Docket No. E-017/GR-10-239 Approved: (DATE) Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 9.01 Residential Service Page 2 of 2 Twenty-fourth Revision SEASONAL RESIDENTIAL SERVICE: 1. These rates and regulations shall apply to seasonal and lake cottage service and to rural residential service only. Resorts, stores, farms and other commercial establishments will be billed at the rates provided for such classes of service. 2. Seasonal customers will be billed at the same rate as year-around customers, except as follows: A one-time seasonal fixed charge of $32.00 will be billed each seasonal customer in addition to the rate provided above. The fixed charge will be included on the first bill rendered for each season. Each seasonal customer will be billed for the number of months each season that the residence or cottage is in use, but not less than a minimum of four months, plus the seasonal fixed charge. The Company will normally read meters and render a bill during the months of June, July, August and September. At the option of the Company, meters may be read at other times during the year and a bill will be rendered if energy recorded on the meter exceeds 100 kilowatt-hours. Billing may be rendered on a two-month basis at the discretion of the Company; when the energy used exceeds 100 kilowatt-hours and more than 55 days have elapsed since the previous meter reading, the bill will be rendered on a two-month basis. Seasonal customers will also be subject to a connection charge of $40.00 when the account is established. and after June 1, 2010, in Minnesota Docket No. E-017/GR-10-239 Approved: (DATE) Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 9.02 Residential Demand Control Page 1 of 2 Eleventh Revision DESCRIPTION RESIDENTIAL DEMAND CONTROL (Commonly identified as RDC) RATE CODE Residential Demand Control 30-241 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. APPLICATION OF SCHEDULE: This schedule is available to residential and farm customers with approved demand control systems. RATES: RESIDENTIAL DEMAND CONTROL SERVICE Customer Charge per Month: $10.35 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: Below 5,000 kwh per month during year $4.00 At or above 5,000 kwh per month during year $15.00 Energy Charge per kwh: Summer Winter 4.343 /kwh 4.004 /kwh R Demand Charge per kw: Summer Winter $6.31 /kw $3.81 /kw INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. and after June 1, 2010, in Minnesota Docket No. E-017/GR-10-239 Approved: (DATE) Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 9.02 Residential Demand Control Page 2 of 2 Eleventh Revision DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. 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 (3) kw will be used for customers new to this rate until a demand is established. FACILITES CHARGES: The Facilities Charge will be $4.00 per month, unless the usage is at or above 5000 kwh per month which will establish the Facilities Charge at $15.00 per month for a 12 month period. The Facilities Charge is based on 30 days per month in a billing period. An adjustment of 167 kwh a day will be added for each day that a billing period exceeds 30 days. DEMAND SIGNAL: Service may receive a demand signal for up to a total of 14 hours during any 24-hour period, as measured from midnight to midnight. Water heaters served on this Tariff will also be included in the Company s summer water heater load control program. and after June 1, 2010, in Minnesota Docket No. E-017/GR-10-239 Approved: (DATE) Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 9.03 Farm Service Page 1 of 2 Twenty-third Revision FARM SERVICE DESCRIPTION RATE CODE Farm Service 30-361 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. AVAILABILITY: Available for 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 of the requirements specified for that schedule are satisfied. RATES: FARM SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $20.00 Facilities Charge per Month: Single Phase $0.00 Three Phase: Overhead <25kVA $4.67 Three Phase: Overhead >=25kVA $5.45 Three Phase: Underground <25kVA $13.03 Three Phase: Underground >=25kVA $20.93 Energy Charge per kwh: Summer Winter 7.344 /kwh 6.573 /kwh R INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 9.03 Farm Service Page 2 of 2 Twenty-third Revision DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 10.01 Small General Service Page 1 of 3 First Revision SMALL GENERAL SERVICE Under 20 kw DESCRIPTION Secondary Primary Metered Service under 20 kw 30-404 30-405 Non-metered Service Under 20 kw 30-406 30-407 Non-metered Service - 1000 Watts or less 30-408 Not Available REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION: This schedule is applicable to non-residential customers. This rate is not applicable for emergency, supplementary/standby service, energy for resale, nor municipal outdoor lighting. RATES: SECONDARY SERVICE PRIMARY SERVICE Customer Charge per Month: $15.00 $15.00 Monthly Minimum Bill: Customer + Facilities Charge Customer + Facilities Charge Facilities Charge per Month: $0.00 $0.00 Energy Charge per kwh: Summer Winter Summer Winter 7.991 /kwh 7.154 /kwh 7.954 /kwh 7.122 /kwh R NON-METERED SERVICE- 20 kw OR LESS SECONDARY SERVICE PRIMARY SERVICE Customer Charge per Month: $12.63 $12.63 Monthly Minimum Bill: Customer + Facilities Charge Customer + Facilities Charge Facilities Charge per Month: $0.00 $0.00 Energy Charge per kwh: Summer Winter Summer Winter 7.433 /kwh 7.433 /kwh 7.399 /kwh 7.399 /kwh R and after June 1, 2010, in Minnesota Docket No. E-017/GR-10-239 Approved: (DATE) Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 10.01 Small General Service Page 2 of 3 First Revision NON-METERED SERVICE-SECONDARY ONLY-1000 WATTS OR LESS Customer Charge per Month: $1.97 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter All kwh 7.231 /kwh 7.231 /kwh R INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. N N N DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. NON-METERED & 1000 WATTS AND UNDER SERVICE: NON-METERED 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. 1000 WATTS AND UNDER NON-METERED SERVICE: 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. and after June 1, 2010, in Minnesota Docket No. E-017/GR-10-239 Approved: (DATE) Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 10.01 Small General Service Page 3 of 3 First Revision 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. Customer shall contract for this optional metering service through an electric service agreement with Company. TERMS AND CONDITIONS: The customer may remain on the Small General Service schedule as long as customer's maximum demand is less than 20 kw. When the customer achieves an actual demand of 20 kw or greater, the customer will be placed on the General Service schedule (section 10.02) in the next billing month. A customer with a billing demand of less than 20 kw for 12 consecutive months will be given the option of returning to the Small General Service schedule. 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. and after June 1, 2010, in Minnesota Docket No. E-017/GR-10-239 Approved: (DATE) Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 10.02 General Service Page 1 of 2 Twenty-second Revision GENERAL SERVICE 20 kw or Greater DESCRIPTION RATE CODE General Service Secondary Service 30-401 General Service Primary Service 30-403 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION: This schedule is applicable to three-phase residential customers, and both single and three-phase non-residential customers. This rate is not applicable for emergency, supplementary/standby service, unless allowed by law, energy for resale, nor municipal street lighting. RATES: SECONDARY SERVICE PRIMARY SERVICE Customer Charge per Month: $18.50 $18.50 Monthly Minimum Bill: Customer + Facilities Charge Customer + Facilities Charge Facilities Charge per Month: $0.46 /kw $0.31 /kw Energy Charge per kwh: Summer Winter Summer Winter 7.649 /kwh 6.848 /kwh 7.614 /kwh 6.816 /kwh R INTERIM RATE ADJUSTMENT A 3.8 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 Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 10.02 General Service Page 2 of 2 Twenty-second Revision MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. TERMS AND CONDITIONS: A customer with a billing demand of less than 20 kw for 12 consecutive months will be given the option of returning to the Small General Service schedule (Section 10.01). DETERMINATION OF DEMAND: 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. The billing demand may be estimated for Customer locations where no demand meter has been installed, but in no event will the billing demand be considered less than 20 kw. DETERMINATION OF FACILITIES CHARGE: The monthly measured demand will be based on the maximum 15 consecutive minute period measured by a suitable demand meter for the month for which the bill is rendered. The Facilities charge demand will be based on the largest of the most recent 12 monthly measured demands. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 10.03 Large General Service Page 1 of 3 Eighteenth Revision LARGE GENERAL SERVICE DESCRIPTION RATE CODES Secondary Service 30-603 Primary Service 30-602 Transmission Service 30-632 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This schedule is applicable to non-residential customers. This rate is not applicable for energy for resale, nor for municipal outdoor lighting. Standby Service will be supplied only as allowed by law. RATES: SECONDARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $350.00 + Facilities Charge Facilities Charge per Month: per annual max. kw (minimum 80kW per Month) 80 kw to under 1000 kw: $0.32 /kw >= 1000 kw: $0.19 /kw Energy Charge per kwh: Summer Winter 4.491 /kwh 4.254 /kwh R Demand Charge per kw: $6.51 /kw $4.03 /kw and after June 1, 2010, in Minnesota Docket No. E-017/GR-10-239 Approved: (DATE) Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 10.03 Large General Service Page 2 of 3 Eighteenth Revision PRIMARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $350.00 + Facilities Charge Facilities Charge per Month: per annual max. kw (minimum 80kW per Month) All kw: $0.14 /kw Energy Charge per kwh: Summer Winter 4.472 /kwh 4.234 /kwh R Demand Charge per kw: $6.46 /kw $4.02 /kw TRANSMISSION SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $350.00 + Facilities Charge Facilities Charge per Month: per annual max. kw (minimum 80kW per Month) All kw: $0.00 /kw Energy Charge per kwh: Summer Winter 4.359 /kwh 4.112 /kwh R Demand Charge per kw: $4.85 /kw $3.75 /kw INTERIM RATE ADJUSTMENT A 3.8 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 and after June 1, 2010, in Minnesota Docket No. E-017/GR-10-239 Approved: (DATE) Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 10.03 Large General Service Page 3 of 3 Eighteenth Revision MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. DETERMINATION OF BILLING DEMAND: The billing demand shall be the greater of 80 kw or the maximum kw as measured by a suitable demand meter for any period of 15 consecutive minutes during the period for which the bill is rendered adjusted for Excess Reactive Demand. DETERMINATION OF FACILITIES CHARGE: The monthly measured demand will be based on the maximum 15 consecutive minute period measured by a suitable demand meter for the month for which the bill is rendered. The Facilities charge demand will be based on the largest of the most recent 12 monthly measured demands. ADJUSTMENT FOR EXCESS REACTIVE DEMAND: The billing demand shall be increased by 1 kw for each whole 10 kvar of measured reactive demand in excess of 50% of the measured demand in kw. SPECIAL BILLING DEMAND: By customer request, Otter Tail Power may calculate the demand used for billing as the average of the previous twelve billing demands. The use of a special billing demand shall not exceed a period of six consecutive months. Otter Tail Power may agree to the use of the special billing demand upon conditions where customers have incurred, or can take advantage of, increased demand levels and the increased demand levels did not, or will not, increase Otter Tail Power s peak load. During the period under which the customer s billing demand is calculated in accordance to the provision of the Special Billing Demand, Otter Tail Power reserves the right to curtail the customer s additional demand (i.e., any demand over the special billing demand level) back to the customer s special billing demand in order to maintain the integrity of Otter Tail Power s generation and transmission systems. and after June 1, 2010, in Minnesota Docket No. E-017/GR-10-239 Approved: (DATE) Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 10.04 Commercial Service Time of Use Page 1 of 3 Fifteenth Revision DESCRIPTION COMMERCIAL SERVICE - TIME OF USE RATE CODE Declared-Peak 30-708 Intermediate 30-709 Off-Peak 30-710 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF SCHEDULE: This schedule is applicable to nonresidential customers with one meter providing electrical service. RATES: COMMERCIAL SERVICE - TIME OF USE Customer Charge per Month: $5.00 Monthly Minimum Bill: Facilities Charge per Month: Customer + Facilities Charge Customer specific - see tariff Energy Charge per kwh: Summer Winter Declared-Peak 18.341 /kwh 16.775 /kwh Intermediate 4.567 /kwh 4.348 /kwh Off-Peak.884 /kwh 1.032 /kwh R R R Demand Charge per kw: Summer Winter Declared-Peak N/A /kw N/A /kw Intermediate $2.96 /kw $2.74 /kw Off-Peak $0.00 /kw $0.00 /kw INTERIM RATE ADJUSTMENT A 3.8 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 Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 10.04 Commercial Service Time of Use Page 2 of 3 Fifteenth Revision FACILITIES CHARGE: Customers served under this tariff shall pay an annual fixed charge equal to 18% of the dedicated investment of the Company in the extension of lines, including any rebuilding or cost of capacity increase in lines or apparatus and other annual expenses necessitated to receive service at this rate. Alternatively, customer 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. An agreement will be entered into with each customer, specifying the investment necessary to supply service and the fixed charge. The annual fixed charge will be billed in 12 equal monthly installments, plus all other charges. MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. CONTRACT PERIOD & AGREEMENT: The Contract Period shall be 5 years. Because of the investment needed to provide service 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. 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 his 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. DEFINITION OF DECLARED, INTERMEDIATE AND OFF-PEAK PERIODS BY SEASON: WINTER SEASON - OCTOBER THROUGH MAY BILLINGS Declared-Peak: Hours declared (see Declared-Peak Notification). Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 10.04 Commercial Service Time of Use Page 3 of 3 Fifteenth Revision Intermediate: All hours other than Declared-peak and off-peak Off-Peak: For all kw and kwh used Weekdays or Saturdays from10:00 p.m. to 6:00 a.m., all day Sunday SUMMER SEASON - JUNE THROUGH SEPTEMBER BILLINGS Declared-Peak: Hours declared (see Declared-Peak Notification). Intermediate: All hours other than Declared-peak and off-peak Off-Peak: For all kw and kwh used Weekdays or Saturdays from10:00 p.m. to 6:00 a.m., all day Sunday DECLARED-PEAK NOTIFICATION: Otter Tail Power shall make available to 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, Otter Tail 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 unusual circumstances prevent Otter Tail from projecting "declared-peak" designations more than one day in advance, Otter Tail 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. Otter Tail is not responsible for a customer's failure to receive or obtain and act upon the "declaredpeak" designations. If a customer does not receive or obtain the "declared-peak" designations made available by Otter Tail, it is the customer's responsibility to notify Otter Tail by 4:30 p.m. (Central Time) of the business day preceding the day that the "declared-peak" designations are to take effect. Otter Tail will be responsible for notifying the customer if prices are revised. 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 10.05 Large General Service Time of Day Page 1 of 4 Fifth Revision LARGE GENERAL SERVICE - TIME OF DAY DESCRIPTION On-Peak Shoulder Off-Peak Secondary Service 30-611 30-615 30-613 Primary Service 30-610 30-614 30-612 Transmission Service 30-639 30-637 30-640 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This schedule is applicable to non-residential customers with an existing load of at least 80 kw. RATES: SECONDARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $380.00 + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter On-Peak 8.448 /kwh 6.784 /kwh Shoulder 5.334 /kwh 4.697 /kwh Off-Peak 1.727 /kwh 1.987 /kwh R R R Demand Charge per kw: Summer Winter On-Peak $4.28 /kw $3.03 /kw Shoulder $1.76 /kw $0.98 /kw Off-Peak $0.00 /kw $0.00 /kw Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 10.05 Large General Service Time of Day Page 2 of 4 Fifth Revision PRIMARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $380.00 + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter On-Peak 8.411 /kwh 6.750 /kwh Shoulder 5.311 /kwh 4.674 /kwh Off-Peak 1.721 /kwh 1.978 /kwh R R R Demand Charge per kw: Summer Winter On-Peak $4.25 /kw $3.01 /kw Shoulder $1.74 /kw $0.98 /kw Off-Peak $0.00 /kw $0.00 /kw TRANSMISSION SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $380.00 + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter On-Peak 8.184 /kwh 6.546 /kwh Shoulder 5.173 /kwh 4.539 /kwh Off-Peak 1.682 /kwh 1.922 /kwh R R R Demand Charge per kw: Summer Winter On-Peak $3.14 /kw $2.87 /kw Shoulder $1.30 /kw $0.91 /kw Off-Peak $0.00 /kw $0.00 /kw Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 10.05 Large General Service Time of Day Page 3 of 4 Fifth Revision INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. METERED AND ESTABLISHED DEMAND: The Metered Demand shall be the maximum kw registered over any period of one hour during the month for which the bill is rendered. The Established Demand shall be the Metered Demand adjusted for excess reactive demand. ADJUSTMENT FOR EXCESS REACTIVE DEMAND: The Metered Demand shall be increased by 1 kw for each whole 10 kvar of reactive demand in excess of 50% of the measured demand in kw. SPECIAL BILLING DEMAND: By customer request, Otter Tail Power may calculate the demand used for billing as the average of the previous twelve on-peak and off-peak Established Demands. The use of the special billing demand shall not exceed a period of six consecutive months. Otter Tail Power may agree to the use of the special billing demand upon conditions where customers have incurred, or can take advantage of, increased demand levels and the increased demand levels did not, or will not, increase Otter Tail Power s peak load. During the period under which the customer s billing demand is calculated in accordance to the provision of the Special Billing Demand, Otter Tail Power reserves the right to curtail the customer s additional demand (i.e., any demand over the special billing demand level) back to the customer s special billing demand in order to maintain the integrity of Otter Tail Power s generation and transmission systems. DEFINITION OF ON, SHOULDER AND OFF-PEAK PERIODS BY SEASON: WINTER SEASON - OCTOBER THROUGH MAY 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. 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 Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 10.05 Large General Service Time of Day Page 4 of 4 Fifth Revision 6:00 p.m. to 10:00 p.m. Off-Peak: For all other kw and kwh not covered by either shoulder or on-peak SUMMER SEASON - JUNE THROUGH SEPTEMBER 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 not covered by either shoulder or on-peak CONTRACT PERIOD & AGREEMENT: Contract period will be outlined in agreement. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.01 Standby Service Page 1 of 8 Fifth Revision STANDBY SERVICE OPTION A: FIRM OPTION B: NON-FIRM On-Peak Shoulder Off-Peak On-Peak Shoulder Off-Peak Transmission Service 30-941 30-942 30-943 30-950 30-951 30-952 Primary Service 30-944 30-945 30-946 30-953 30-954 30-955 Secondary Service 30-947 30-948 30-949 30-956 30-957 30-958 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. 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 60 kw. Customers with Extended Parallel Generation Systems used to meet all or a portion of electrical requirements that are capable of 60 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.01 Standby Service Page 2 of 8 Fifth Revision STANDBY RATE OPTIONS - FIRM AND NON-FIRM OPTION A: FIRM STANDBY Transmission Primary Secondary Service Service Service Firm Standby Fixed Charges Customer Charge $0.00/month $0.00/month $0.00/month Minimum Monthly Bill Customer + Standby Facilities Charges Customer + Standby Facilities Charges Customer + Standby Facilities Charges Standby Facilities charge per month per kw of Contracted Backup Demand Not Applicable 14 /kw 19 /kw Firm Standby On-Peak Demand Charge - Summer Metered Demand per day per kw On-Peak Backup Charge 41.78 /kw 43.11 /kw 43.33 /kw Firm Standby On-Peak Demand Charge - Winter Metered Demand per day per kw On-Peak Backup Charge 38.231 /kw 39.526 /kw 39.74 /kw Firm Standby Energy Charges - Summer Energy Charges per kwh On-Peak Charge 8.184 /kwh 8.411 /kwh 8.448 /kwh Shoulder Charge 5.173 /kwh 5.311 /kwh 5.334 /kwh Off-Peak Charge 1.682 /kwh 1.721 /kwh 1.727 /kwh Firm Standby Energy Charges - Winter Energy Charges per kwh On-Peak Charge 6.546 /kwh 6.750 /kwh 6.784 /kwh Shoulder Charge 4.539 /kwh 4.674 /kwh 4.697 /kwh Off-Peak Charge 1.922 /kwh 1.978 /kwh 1.987 /kwh R R R R R R Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.01 Standby Service Page 3 of 8 Fifth Revision OPTION B: NON-FIRM STANDBY Transmission Primary Secondary Service Service Service Non-Firm Standby Fixed Charges Customer Charge $0.00/month $0.00/month $0.00/month Minimum Monthly Bill Customer + Reservation + Standby Facilities Charge Customer + Reservation + Standby Facilities Charge Customer + Reservation + Standby Facilities Charge Standby Facilities charge per month per kw of Contracted Backup Demand Not Applicable 14 /kw 19 /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 5.173 /kwh 5.311 /kwh 5.334 /kwh Off-Peak Charge 1.682 /kwh 1.721 /kwh 1.727 /kwh Non-Firm Standby Energy Charges - Winter Energy Charges per kwh On-Peak Charge Not Available Not Available Not Available Shoulder Charge 4.539 /kwh 4.674 /kwh 4.697 /kwh Off-Peak Charge 1.922 /kwh 1.978 /kwh 1.987 /kwh R R R R INTERIM RATE ADJUSTMENT A 3.8 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 Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.01 Standby Service Page 4 of 8 Fifth Revision MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability 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. 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 - Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.01 Standby Service Page 5 of 8 Fifth Revision 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.01 Standby Service Page 6 of 8 Fifth Revision 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. The total monthly backup charge will not exceed the sum of the ten highest daily charges for Backup Demand, if any. 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. MISO is the Midwest Independent Transmission System Operator 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.01 Standby Service Page 7 of 8 Fifth Revision Customers with Extended Parallel Generation Systems used to meet all or a portion of electrical requirements that are capable of 60 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 60 kw or less is available under the Customer s base rate. For Large General Service or Large General Service-Time of Use Customers, a Special Minimum Demand may apply. For more information regarding Extended Parallel Generation Systems, Physical Assurance Customers, Special Minimum Demand, 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 customers, the Company and the customer will mutually agree to different maintenance schedules as listed above. Special Minimum Demand is a special demand calculation that the Company may use at its option for Large General Service or Large General Service-Time of Use Customers. The terms are outlined in Sections 10.03 and 10.05. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.01 Standby Service Page 8 of 8 Fifth Revision 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.02 Irrigation Service Page 1 of 3 Twenty-first Revision IRRIGATION SERVICE DESCRIPTIONESCRIPTION RATE CODE Option 1: Non-Time-of-Use 30-703 Option 2: Declared-Peak 30-704 Option 2: Intermediate 30-705 Option 2: Off-Peak 30-706 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF SCHEDULE: This service is available to customers legally entitled to use water for irrigation during the irrigation season, April 15 through November 1. RATES: OPTION 1 Customer Charge per Month: $1.00 Monthly Minimum Bill: Facilities Charge per Month: Customer + Facilities Charge Customer-Specific see Tariff Energy Charge per kwh: Summer Winter 5.874 /kwh 4.623 /kwh R Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 11.02 Irrigation Service Page 2 of 3 Twenty-first Revision OPTION 2 Customer Charge per Month: $5.00 Monthly Minimum Bill: Facilities Charge per Month: Customer + Facilities Charge Customer-Specific see Tariff Energy Charge per kwh: Summer Winter Declared-Peak 15.121 /kwh 14.480 /kwh Intermediate 2.770 /kwh 2.335 /kwh Off-Peak 1.200 /kwh 1.092 /kwh R R R Demand Charge per kw: Summer Winter Declared-Peak 0.00 /kw 0.00 /kw Intermediate $1.52 /kw $2.21 /kw Off-Peak 0.00 /kw 0.00 /kw INTERIM RATE ADJUSTMENT A 3.8 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 FACILITIES 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. MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Voluntary Rate Riders selected by the Customer or Mandatory Rate Riders that must apply. See sections 12 through 14 of the Minnesota electric rates for the applicability matrices of riders. 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 11.02 Irrigation Service Page 3 of 3 Twenty-first Revision DEFINITION OF DECLARED, INTERMEDIATE AND OFF-PEAK PERIODS BY SEASON: WINTER SEASON APRIL 15 THROUGH MAY, AND OCTOBER THROUGH NOVEMBER 1 Declared-Peak: Hours declared. Intermediate: All hours other than declared-peak and off-peak. Off-Peak: For all kw and kwh used Weekdays or Saturdays from10:00 p.m. to 6:00 a.m., all day Sunday. SUMMER SEASON - JUNE THROUGH SEPTEMBER Declared-Peak: Hours declared. Intermediate: All hours other than declared-peak and off-peak. Off-Peak: For all kw and kwh used Weekdays or Saturdays from10:00 p.m. to 6:00 a.m., 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 Contract Period shall be 5 years. Because of the investment of the customer in pumping and irrigation equipment, and of the Company in the extension of lines, 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. 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 his 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. The annual fixed charge will be billed in seven equal monthly installments May through November of each year. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 11.03 Outdoor Lighting Energy Only Page 1 of 2 Third Revision OUTDOOR LIGHTING ENERGY ONLY DUSK TO DAWN DESCRIPTION RATE CODE Sign Lighting 30-747 Street and Area Lighting - Metered 30-748 Street and Area Lighting - Non-Metered 30-749 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This tariff is available to both private and governmental entities. The tariff will allow the Company to sell automatically operated dusk to dawn outdoor lighting electric energy to municipal and other outdoor area lighting customers who choose to own, install, and maintain the lighting equipment. Under the tariff, Otter Tail 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 meet the Company s specifications. 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 if, in the Company s determination, the customer s lighting equipment is operated or maintained in an unsafe or improper manner. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 11.03 Outdoor Lighting Energy Only Page 2 of 2 Third Revision RATE METERED: OUTDOOR LIGHTING - ENERGY ONLY Metered Rate Customer Charge per Month: $1.60 Monthly Minimum Bill: Customer Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: 6.576 /kwh R RATE NON-METERED: OUTDOOR LIGHTING SIGN LIGHTING AND NON-METERED RATE Monthly charge = Connected kw x $22.47, where Connected kw is the rated power of the lighting fixture (including ballast) R INTERIM RATE ADJUSTMENT A 3.8 percent increase will be added to the sum of the following, as applicable: Customer Charge, Energy Charge, Demand Charge, Fixed Charge, Facilities Charge, Monthly 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 Voluntary Rate Riders selected by the Customer or Mandatory Rate Riders that must apply. See sections 12 through 14 of the Minnesota electric rates for the applicability matrices of riders. SERVICE CONDITIONS: Company-owned lights shall not be attached to customer-owned property. 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 11.04 Outdoor Lighting Page 1 of 2 Fifteenth Revision DESCRIPTION OUTDOOR LIGHTING DUSK TO DAWN RATE CODE Street and Area Lighting 29-745 Floodlighting 29-746 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This schedule is available to any customer, including a village, town or city, for automatically operated dusk to dawn outdoor lighting supplied and operated by the Company. RATES: Unit type Lumens Wattage Monthly Charge MV-6 6000 175 $6.25 MV-6PT 6000 175 $8.22 MV-11 11000 250 $11.77 MV-21 21000 400 $15.16 MV-35 35000 750 $22.77 MV-55 55000 1000 $31.25 MH-8 8500 100 $7.21 MH-14 14000 175 $13.76 MH-20 20500 250 $15.67 MH-36 36000 400 $15.22 MH-110 110000 1000 $32.38 HPS-9 9000 100 $7.05 HPS-9PT 9000 100 $8.53 HPS-14 14000 150 $10.93 HPS-14PT 14000 150 $10.91 HPS-19 19000 200 $12.65 HPS-23 23000 250 $14.26 HPS-44 44000 400 $17.59 Fixture Unit Type Monthly Charge 400 MV-Flood Mercury Vapor $15.16 400 MA-Flood Metal Additive Mercury $17.85 400 HPS-Flood High Pressure Sodium $17.59 1000 MV-Flood Mercury Vapor $29.64 1000 MA-Flood Metal Additive Mercury $32.85 Due to the U.S. Government Energy Act of 2005, after August 1, 2008, the Company will no longer R R R R R R R R R R R R R R R R R R R R R R R Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.04 Outdoor Lighting Page 2 of 2 Fifteenth Revision install Mercury Vapor fixtures for new installations. INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability 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 $25.00 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 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 or sign, the Company will supply the equivalent of one span of underground and add an additional $1.92 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. EQUIPMENT AND SERVICE SUPPLIED BY THE COMPANY: 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. Other than customers provided with pole top fixtures on fiberglass poles, the service will provide pole top lights. 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 facilities. Company shall own, operate, and maintain the lighting unit including the pole, fixture, lamp, ballast, photoelectric control, mounting brackets, and all necessary wiring using Company's standard street lighting equipment. Company shall furnish all electric energy required for operation of the unit. N N N N In cases of vandalism or damages, Otter Tail Power Company has the discretion to discontinue service. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.05 Municipal Pumping Service Page 1 of 2 Twelfth Revision DESCRIPTION MUNICIPAL PUMPING SERVICE RATE CODE Secondary Service 30-871 Primary Service 30-874 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This rate schedule is available to non-seasonal municipal or other governmental loads only. It shall apply to electric service for motor driven pumps for use at water pumping and treating plants, sewage disposal and treating plants, sewage lift stations and may be extended 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 the pumping operation, may not be served at this rate, however the Company reserves the authority to extend service under this tariff in cases where it is not practical to separately meter small loads adjacent to this service. The rate schedule and monthly minimum shall apply to each meter in service except that where service through a meter is for electric space heating only the energy on this meter shall be added to the pumping meter for billing purposes. Seasonal service is not permitted. RATES: The Company retains the authority to allow combined billing at locations where an approved single phase electric space heating load is metered separately from the three phase pumping load. In all other cases the monthly minimum shall apply to each meter providing service under this tariff. SECONDARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $8.00 Facilities Charge per Month: Maximum Monthly kwh <1150 $1.00 Maximum Monthly kwh 1150-7500 $5.00 Maximum Monthly kwh >7500 $15.00 Energy Charge per kwh: Summer Winter 5.821 /kwh 5.378 /kwh R Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 11.05 Municipal Pumping Service Page 2 of 2 Twelfth Revision PRIMARY SERVICE Customer Charge per Month: $0.00 Monthly Minimum Bill: $8.00 Facilities Charge per Month: Maximum Monthly kwh <1150 $0.48 Maximum Monthly kwh 1150-7500 $2.41 Maximum Monthly kwh >7500 $7.24 Energy Charge per kwh: Summer Winter 5.985 /kwh 5.353 /kwh R INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 11.06 Civil Defense - Fire Sirens Page 1 of 2 Fifth Revision DESCRIPTION CIVIL DEFENSE-FIRE SIRENS RATE CODE Civil Defense Fire Sirens 30-843 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF SCHEDULE: This schedule is applicable to separately served civil defense and municipal fire sirens. RATES: CIVIL DEFENSE - FIRE SIRENS Customer Charge per Month: $0.00 Monthly Minimum Bill: $2.75 per siren + Facilities Charge Facilities Charge per Month: $0.00 Charge per HP: Summer Winter 61.077 /HP 61.077 /HP INTERIM RATE ADJUSTMENT A 3.8 percent increase will be added to the sum of the following, as applicable: Customer Charge, Energy Charge, Demand Charge, Fixed Charge, Facilities Charge, Charge per HP, 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 11.06 Civil Defense - Fire Sirens Page 2 of 2 Fifth Revision 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 tariff, the Company will provide an extension of up to one span of wire, not to exceed 300 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 12.01 Small Power Producer Rider Net Energy Billing Rate Page 1 of 3 Twenty-seventh Revision SMALL POWER PRODUCER RIDER (Net Energy Billing Rate) REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: Available to any qualifying facility with generation capacity not exceeding 40 kw. CUSTOMER CHARGE: $1.40 per month INTERIM RATE ADJUSTMENT A 3.8 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 7.066 per kwh 30-910 Farm 6.398 per kwh 30-930 General Service 7.990 per kwh 30-940 Large General Service 5.715 per kwh 30-960 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. Docket No. E-017/GR-10-239 Approved: (DATE) EFFECTIVE for services rendered on and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.01 Small Power Producer Rider Net Energy Billing Rate Page 2 of 3 Twenty-seventh Revision 3. A SQF must have a generation capacity of at least 30 kw to qualify for wheeling by the Company of the SQF output. In the event that the SQF desires, and qualifies for, wheeling by the Company of the SQF output, arrangements will be made subject to special provisions to be determined by all utilities involved. This also applies to SQF's outside the Company's service territory. 4. If required, a separate meter will be furnished, owned and maintained by the Company to measure the energy to the Company. 5. The SQF shall make provisions for the installation of Company owned on-site metering. All energy received from and delivered to the Company shall be metered. On site use of the SQF output shall be unmetered for purposes of compensation. 6. The customer shall pay for any increased capacity of the distribution equipment serving him and made necessary by the installation of his generator. 7. Power and energy purchased by the SQF from the Company shall be billed under the available retail rates for the purchase of electricity. 8. The generator output must be compatible with the Utility system. The customer's 60 hertz generator output must be at the voltage and phase relationship of the existing service or of one mutually agreeable to the Company and the customer. 9. The customer will provide equipment to maintain a 100% power factor (+ or - 10%) during periods of generator operation. 10. The Company reserves the right to disconnect the customer's generator from its system if it interferes with the operation of the Company's equipment or with the equipment of other company customers. 11. The Customer is required to follow the Company s interconnection process which requires that prior to installation, a detailed electrical diagram of the generator and related equipment must be furnished to the Company for its approval for connection to the Company's system. No warranties, express or implied, will be made as to the safety or fitness of the said equipment by the Company due to this approval. 12. The customer shall execute an electric service contract with the Company which may include, Docket No. E-017/GR-10-239 Approved: (DATE) EFFECTIVE for services rendered on and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.01 Small Power Producer Rider Net Energy Billing Rate Page 3 of 3 Twenty-seventh Revision 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. Docket No. E-017/GR-10-239 Approved: (DATE) EFFECTIVE for services rendered on and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 12.02 Small Power Producer Rider Simultaneous Purchase and Sale Billing Rate Fergus Falls, Minnesota Page 1 of 3 Twenty-seventh Revision SMALL POWER PRODUCER RIDER SIMULTANEOUS PURCHASE AND SALE BILLING RATE DESCRIPTION RATE CODE Firm Power 30-981 Nonfirm Power 30-984 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under of this schedule. AVAILABILITY: 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 3.8 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 0.446 per kwh 0.445 per kwh 3.569 per kwh 2.909 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. DEFINITIONS: Firm Power: Energy delivered by the qualifying facility to the utility with at least a 65percent on-peak capacity factor in the month. Capacity Factor: The number of kilowatt-hours delivered during a period divided by the product Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 12.02 Small Power Producer Rider Simultaneous Purchase and Sale Billing Rate Fergus Falls, Minnesota Page 2 of 3 Twenty-seventh Revision of (the maximum one hour delivered capacity in kilowatts in the period) times (the number of hours in the period). Summer: June through September. Winter: October through May. 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. 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 12.02 Small Power Producer Rider Simultaneous Purchase and Sale Billing Rate Fergus Falls, Minnesota Page 3 of 3 Twenty-seventh Revision 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 12.03 Small Power Producer Rider Time of Day Purchase Rates Fergus Falls, Minnesota Page 1 of 3 Twenty-seventh Revision DESCRIPTION SMALL POWER PRODUCER RIDER TIME OF DAY PURCHASE RATES RATE CODE Firm Power 30-982 Nonfirm Power 30-983 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. AVAILABILITY: 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 3.8 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) 1.090 per kwh 4.748 per kwh 2.773 per kwh Winter (Firm Power and Non-Firm Power) 1.016 per kwh 3.941 per kwh 2.103 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. DEFINITIONS: Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010 in Minnesota Regulatory Services Manager

Interim Minnesota, Section 12.03 Small Power Producer Rider Time of Day Purchase Rates Fergus Falls, Minnesota Page 2 of 3 Twenty-seventh Revision 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 through September including those hours from 8:00 a.m. to 10:00 p.m. Monday through Friday, excluding holidays. Winter On-Peak: October through May 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. 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010 in Minnesota Regulatory Services Manager

Interim Minnesota, Section 12.03 Small Power Producer Rider Time of Day Purchase Rates Fergus Falls, Minnesota Page 3 of 3 Twenty-seventh Revision 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. 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010 in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 1 of 6 Third Revision DESCRIPTION DISTRIBUTED GENERATION SERVICE RIDER RATE CODE Distributed Generation Service Rider 30-931 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. AVAILABILITY: The Rider for Distributed Generation is available between any Customer, who has entered into the State of Minnesota Interconnection Agreement for the Interconnection of Extended Parallel Distributed Generation Systems with Electric Utilities, and the Company for the interconnection and operation of on-site extended parallel distributed generation system, as follows. 1. The distributed generation system must be fueled by natural gas or a renewable fuel, or another similarly clean fuel or combination of fuels of no more than 10 MW of interconnected capacity at a point of common coupling to Company s distribution system. The distributed generation facility must be an operable, permanently installed or mobile generation facility serving the Customer receiving retail electric service at the same site. 2. The interconnection and operation of distributed generation systems at each point of common coupling shall be considered as a separate application of the Rider. 3. Service hereunder is subject to Company s Guidelines for Generation, Tie-Line, and Substation Interconnections and the State of Minnesota Interconnection Process for Distributed Generation Systems, copies of which are available at the Company s web page at http://www.otpco.com. The requirements, terms and conditions contained in the State of Minnesota Interconnection Process for Distributed Generation Systems supersede the requirements, terms and conditions contained in the Company s Guidelines for Generation, Tie-Line, and Substation Interconnections in the event of an inconsistency between the two documents. 4. All provisions of the applicable standard service schedule shall apply to distributed generation service under this Rider except as noted below. In 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 Docket No. E017/GR-10-239 Approved: (DATE) EFFECTIVE for services rendered on and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 2 of 6 Third Revision 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 Application of Schedule section above. Customer Charge: $11.57 per month for customer account expense Distribution Maintenance Charge ($/Month): This charge will be based upon customerspecific 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 Services Charge and the Distribution Maintenance Charge. Interim Rate Adjustment: A 3.8 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 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 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 Docket No. E017/GR-10-239 Approved: (DATE) EFFECTIVE for services rendered on and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 3 of 6 Third Revision 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 tariff or under other mutually agreeable arrangement 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 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 Docket No. E017/GR-10-239 Approved: (DATE) EFFECTIVE for services rendered on and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 4 of 6 Third Revision 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 Commissionapproved 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. Line Loss Credits Docket No. E017/GR-10-239 Approved: (DATE) EFFECTIVE for services rendered on and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 5 of 6 Third Revision 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. 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. Docket No. E017/GR-10-239 Approved: (DATE) EFFECTIVE for services rendered on and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 12.04 Distributed Generation Service Rider Page 6 of 6 Third Revision 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. Docket No. E017/GR-10-239 Approved: (DATE) EFFECTIVE for services rendered on and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 14.01 Water Heating Control Rider Page 1 of 2 Nineteenth Revision DESCRIPTION WATER HEATING CONTROL RIDER RATE CODE Metered Water Heating Control Service 30-191 Water Heating Control Service Credit 30-192 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF SCHEDULE: This schedule is applicable for residential or non-residential purposes. RATES: WATER HEATING - CONTROLLED SERVICE 191 Customer Charge per Month: $1.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter 5.424 /kwh 4.825 /kwh R WATER HEATING CREDIT 192 A $4.00 credit per month shall be applied to all bills having direct control water heating, except the credit shall not reduce the monthly billing to less than the Monthly minimum Charge. INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.01 Water Heating Control Rider Page 2 of 2 Nineteenth Revision TERM AND CONDITIONS FOR RATE 191: Service under rate 191 shall be supplied on a separate meter. TERMS AND CONDITIONS FOR RATE 192: The Customer will be compensated for taking service on this Rider by receiving a $4.00 per month bill credit. The credit will be applied on the customer s account. CONTROL CRITERIA: Service may be controlled for up to a total of 14 hours during any 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 through September. Winter: October through May. EQUIPMENT SUPPLIED: Otter Tail will supply and maintain the necessary metering and/or control equipment. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.02 Real Time Pricing Rider Page 1 of 5 Third Revision DESCRIPTION OF SERVICE REAL TIME PRICING RIDER RATE CODES Transmission Service 30-660 Primary Service 30-662 Secondary Service 30-664 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. AVAILABILITY: This rider is available on a voluntary basis and is limited to twenty 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 Otter Tail Power Company. INTERIM RATE ADJUSTMENT A 3.8 percent increase will be added to the Administrative Charge. N N MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Voluntary Rate Riders selected by the Customer or Mandatory Rate Riders that must apply. See sections 12 through 14 of the Minnesota electric rates for the applicability 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 Otter Tail Power 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.02 Real Time Pricing Rider Page 2 of 5 Third Revision 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. Otter Tail Power 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 Bill Mo + Consumption Changes from CBL Hr + Excess Reactive Demand Where: RTP Bill Mo = Customer's monthly bill for service under this Rider Adm. Chg. = See Administrative Charge section below Std. Bill Mo = See Standard Bill section above Consumption Changes From CBL = {Price Hr x {Load Hr - CBL Hr }} Excess Reactive Demand = See Excess Reactive Demand section below = Sum over all hours of the monthly billing period Price Hr = Hourly RTP price as defined under Pricing Methodology Load Hr = Customer's actual load for each hour of the billing period CBL Hr = Customer's CBL energy usage for each hour of the billing period Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.02 Real Time Pricing Rider Page 3 of 5 Third Revision 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, Otter Tail Power 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 Otter Tail. 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. 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 Otter Tail'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 Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.02 Real Time Pricing Rider Page 4 of 5 Third Revision 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, Otter Tail 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 Otter Tail. In these cases, Otter Tail 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: CBL t+1 = CBL t + {Adjustment Factor x ( Actual load t - CBL t )} PRICE NOTIFICATION: Otter Tail Power 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, Otter Tail 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 Otter Tail from projecting prices more than one day in advance, Otter Tail 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.02 Real Time Pricing Rider Page 5 of 5 Third Revision Otter Tail 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 Otter Tail, it is the customer's responsibility to notify Otter Tail by 4:30 p.m. (Central Time) of the business day preceding the day that the prices are to take effect. Otter Tail 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 Otter Tail 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 Otter Tail. 3. If the customer's actual load exceeds the CBL by an amount that requires Otter Tail to install additional facilities to serve the customer, the customer will be responsible for any and all costs incurred by Otter Tail to install the facilities. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.03 Large General Service Rider Page 1 of 6 Fifth Revision LARGE GENERAL SERVICE RIDER DESCRIPTION Option 1 Option 2 Fixed Rate Energy Pricing 30-648 30-649 System Marginal Energy Pricing 30-642 30-645 Short-term Marginal Capacity Purchases 30-643 30-646 Short-term Marginal Capacity Releases 30-644 30-647 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. INTERIM RATE ADJUSTMENT A 3.8 percent increase will be added to the sum of the following, as applicable: Customer Charge, Energy Charge, Demand Charge, Fixed Charge, Facilities Charge, the monthly Minimum Charge, and Administrative Charge. N N N N MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Voluntary Rate Riders selected by the Customer or Mandatory Rate Riders that must apply, unless otherwise noted in this rider. See sections 12 through 14 of the Minnesota electric rates for the applicability matrices of riders. 1. Availability. 1.1 Large General Service Customers. 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. 1.2 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, On-Peak Baseline Demand and Off-Peak Baseline Demand. 2. Fixed Rate Energy Pricing. 2.1 Background. Certain of Otter Tail's industrial and commercial Customers have ESAs that designate, among other things, a Billing Demand, On-Peak and Off-Peak Baseline Demands and a Firm Demand. With On-Peak and Off-Peak Baseline Demands, 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 schedule and/or a negotiated rate subject to Commission approval. Setting a Firm and Baseline Demands benefits both the Company and the Customer. With Firm Demands, the Company is Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.03 Large General Service Rider Page 2 of 6 Fifth Revision 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 and the ability to purchase Energy above the Baseline Demand at rates set forth in the Customer s applicable rate schedule and/or a negotiated Energy rate subject to Commission approval. 2.2 Energy. The Customer s monthly rate for Energy will be determined in two parts: (1) Energy consumed up to and including the On-Peak Baseline Demand and Off-Peak Baseline Demand, and (2) Energy consumed above the On-Peak Baseline Demand and Off-Peak Baseline Demand. The price (rate) for Energy consumed up to and including the On-Peak Baseline Demand and Off-Peak Baseline Demand 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 On- Peak Baseline Demand and Off-Peak Baseline Demand 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. 2.3 Demand. The 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. 3. System Marginal Energy Pricing. 3.1 Background. Certain of Otter Tail's industrial and commercial Customers have ESAs that designate, among other things, a Billing Demand, On-Peak and Off-Peak Baseline Demands and a Firm Demand. With On-Peak and Off-Peak Baseline Demands, the Company agrees to provide and the Customer agrees to purchase its Energy requirements up to the Baseline Demand 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 and the ability to purchase Energy above the Baseline Demand 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 according to the value the Customer places on that Energy in real-time. 3.2 Energy. The Customer s monthly rate for Energy will be determined in two parts: (1) Energy consumed up to and including the On-Peak Baseline Demand and Off-Peak Baseline Demand, and (2) Energy consumed above the On-Peak Baseline Demand and Off-Peak Baseline Demand. The price (rate) for Energy consumed up to and including the On-Peak Baseline Demand and Off-Peak Baseline Demand 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 On-Peak Baseline Demand and Off-Peak Baseline Demand will Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.03 Large General Service Rider Page 3 of 6 Fifth Revision be determined by multiplying the Customer s metered Energy consumption by the Company s System Marginal Energy Price. 3.2.1 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. 3.2.2 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 System Marginal Energy Pricing. 3.3 Demand. The 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. 4. Short-term Marginal Capacity Purchases and Releases. 4.1 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. This Section 3 provides 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 ). 4.2 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 Capacity indirectly from a third party. The Company would work with the third party to effectuate the purchase. In each case, Otter Tail agrees to give to the Customer its best effort in seeking the Marginal Capacity. The Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.03 Large General Service Rider Page 4 of 6 Fifth Revision 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. 4.2.1 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. 4.2.2 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. 4.2.3 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 Designation C-03M (the RTP Rider), Energy consumed above the On-Peak Baseline Demand and Off- Peak Baseline Demand will continue to be billed at the System Marginal Energy Price. RTP Rider Customers will continue to be billed under the provisions of Rate Designation C-03M. 4.3 Released Capacity. Where the Customer requests to release Capacity on a shortterm 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 use or to resell it offsystem 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). 4.3.1 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.03 Large General Service Rider Page 5 of 6 Fifth Revision 4.3.2 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. 4.3.3 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. 5. Miscellaneous Provisions. 5.1 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. 5.2 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. 5.3 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 (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. 5.4 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. 5.5 Metering Requirements. Company approved metering equipment capable of providing load interval information is required for Rider participation. Customer agrees to pay for the additional cost of such metering when not provided in conjunction with existing retail electric service. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Fergus Falls, Minnesota Interim Minnesota, Section 14.03 Large General Service Rider Page 6 of 6 Fifth Revision 5.6 Liability. The Company and Customer agree that Company has no liability for indirect, special, incidental, or consequential loss or damages to Customer, including but not limited to Customer's operations, site, production output, or other claims by the Customer as a result of participation in this Rider. 5.7 Energy Adjustment Rider. Energy consumed up to and including the On-Peak Baseline Demand and Off-Peak Baseline Demand is subject to the Energy Adjustment Rider as provided in Section 13, or any amendments or superseding provisions applicable thereto. Because Energy consumed above the On-Peak Baseline Demand and Off-Peak Baseline Demand 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, Section 13. 5.8 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Services

Interim Minnesota, Section 14.04 Controlled Service Interruptible Load Rider (CT Metering) Fergus Falls, Minnesota Page 1 of 3 Twentieth Revision CONTROLLED SERVICE - INTERRUPTIBLE LOAD CT METERING RIDER (Commonly identified as LARGE DUAL FUEL) DESCRIPTION RATE CODES CT Metering 29-170 CT Metering (with short-duration cycling) 29-165 Penalty 29-881 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. APPLICATION OF RIDER: This rider is applicable for residential or non-residential service to any 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 used for both heating and cooling. Domestic electric water heating, and/or other permanently connected approved loads that can be interrupted during control periods. Electric fans, pumps, and other ancillary, equipment used in the distribution of heat 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 manufacturers 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 14.04 Controlled Service Interruptible Load Rider (CT Metering) Fergus Falls, Minnesota Page 2 of 3 Twentieth Revision RATES: CONTROLLED SERVICE - INTERRUPTIBLE LOAD - CT METERING Customer Charge per Month: $5.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter All kwh 2.745 /kwh 2.431 /kwh Penalty kwh 15.000 /kwh 11.000 /kwh R MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. INTERIM RATE ADJUSTMENT A 3.8 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 DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. 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. Penalty usage will be recorded on the peak register, and the total register of the dual register meters. Installation of a dual register meter will be at the option of the Company. 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 0 hours up to a total of 24 hours during any Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 14.04 Controlled Service Interruptible Load Rider (CT Metering) Fergus Falls, Minnesota Page 3 of 3 Twentieth Revision 24-hour period, as measured from midnight to midnight. Short-duration cycling is 15-minutes off / 15-minutes on of appropriate cooling equipment during the summer season (June 1-September 30). Approved deferred loads will receive 10 or more hours service per day. EQUIPMENT SUPPLIED: Otter Tail will supply and maintain the necessary metering and control equipment. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 14.05 Controlled Service Interruptible Load Self-Contained Metering Rider (Small Dual Fuel) Fergus Falls, Minnesota Page 1 of 3 Twentieth Revision CONTROLLED SERVICE - INTERRUPTIBLE LOAD SELF-CONTAINED METERING RIDER (Commonly identified as Small Dual Fuel) DESCRIPTION RATE CODE Self-Contained Metering 29-190 Self-Contained Metering (with short-duration cycling) 29-185 Penalty 29-882 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF RIDER: This rider is applicable for residential or non-residential service to any 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 used for both heating and cooling. Domestic electric water heating and/or other permanently connected approved loads that can be interrupted during control periods. Electric fans, pumps and other ancillary equipment used in the distribution of heat shall be wired for service through the customer's firm 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 manufacturers 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 14.05 Controlled Service Interruptible Load Self-Contained Metering Rider (Small Dual Fuel) Fergus Falls, Minnesota Page 2 of 3 Twentieth Revision RATES: CONTROLLED SERVICE - INTERR LOAD SELF-CONTAINED Customer Charge per Month: $5.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $0.00 Energy Charge per kwh: Summer Winter All kwh 3.796 /kwh 3.366 /kwh Penalty kwh 15.000 /kwh 11.000 /kwh R INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. 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. Penalty usage will be recorded on the peak register, and the total register of the dual register meters. Installation of a dual register meter will be at the option of the Company. The penalty provision is not intended as buy-through option. Under no circumstances should the penalty clause of this rider be interpreted as an approved buy-thru option for service under this rider. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 14.05 Controlled Service Interruptible Load Self-Contained Metering Rider (Small Dual Fuel) Fergus Falls, Minnesota Page 3 of 3 Twentieth Revision CONTROL CRITERIA: Service may be controlled 0 hours up to a total of 24 hours during any 24-hour period, as measured from midnight to midnight. Short-duration cycling is 15-minutes off / 15-minutes on of appropriate cooling equipment during the summer season (June 1-September 30). Approved deferred loads will receive 10 or more hours service per day. EQUIPMENT SUPPLIED: Otter Tail will supply and maintain the necessary metering and control equipment. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 14.06 Controlled Service Deferred Load Rider (Thermal Storage) Fergus Falls, Minnesota Page 1 of 3 Twentieth Revision CONTROLLED SERVICE DEFERRED LOAD RIDER (Commonly identified as Thermal Storage) DESCRIPTION RATE CODE Deferred Loads 30-197 Deferred Loads ( with short-duration cycling) 30-195 Penalty 30-883 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use under this schedule. APPLICATION OF RIDER: This rider is applicable for both residential and non-residential service to any 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 used for both heating and cooling, 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 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 manufacturers 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. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 14.06 Controlled Service Deferred Load Rider (Thermal Storage) Fergus Falls, Minnesota Page 2 of 3 Twentieth Revision RATES: CONTROLLED SERVICE - DEFERRED LOAD Customer Charge per Month: $1.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: Below 5000 kwh per month in all months $3.00 At or above 5000 kwh in any month $10.00 Energy Charge per kwh: Summer Winter All kwh 5.196 /kwh 4.622 /kwh Penalty kwh 15.000 /kwh 11.000 /kwh R INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. N N N N DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. 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. Penalty usage will be recorded on the peak register, and the total register of the dual register meters. Installation of a dual register meter will be at the option of the Company. The penalty provision is not intended as buy-through option. Under no circumstances should the penalty clause of this rider be interpreted as an approved buy-thru option for service under this rider. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Interim Minnesota, Section 14.06 Controlled Service Deferred Load Rider (Thermal Storage) Fergus Falls, Minnesota Page 3 of 3 Twentieth Revision FACILITIES CHARGES: The Facilities Charge will be $3.00 per month, unless the usage is at or above 5000 kwh per month which will establish the Facilities Charge at $10.00 per month for a 12 month period. The Facilities Charge is based on 30 days per month in a billing period. An adjustment of 167 kwh a day will be added for each day that a billing period exceeds 30 days. CONTROL CRITERIA: Service may be controlled for up to a total of 14 hours during any 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. Shortduration cycling is 15-minutes off / 15-minutes on of appropriate cooling equipment during the summer season (June 1-September 30). EQUIPMENT SUPPLIED: Otter Tail will supply and maintain the necessary metering and control equipment. Docket No. E-017/GR-10-239 Approved: (DATE) and after June 1, 2010, in Minnesota Regulatory Services Manager

Fergus Falls, Minnesota Interim Minnesota, Section 14.07 Fixed Time of Delivery Rider (Fixed TOD) Page 1 of 3 Fourth Revision FIXED TIME OF DELIVERY RIDER (Commonly identified as FIXED TOD) DESCRIPTION RATE CODES Fixed Time of Delivery Service Self-Contained Metering 29-301 Fixed Time of Delivery Service CT Metering 29-302 Fixed Time of Delivery Service Primary CT Metering 29-303 REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule. APPLICATION OF SCHEDULE: This rider is applicable to customers requesting service to permanently connected thermal storage space heating technologies that are designed and installed with the capability to operated under the limitations and terms of this rider. Rider threshold determinations will be made based on connected load and service level and will be independent of actual registered demand or energy usage. RATES: SECONDARY SERVICE - Self-Contained Metering Customer Charge per Month: $1.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $3.00 Energy Charge per kwh: Summer Winter 2.394 /kwh 2.661 /kwh R Docket No. E-017/GR-10-239 Approved:(DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Service

Fergus Falls, Minnesota Interim Minnesota, Section 14.07 Fixed Time of Delivery Rider (Fixed TOD) Page 2 of 3 Fourth Revision SECONDARY SERVICE CT Metering Customer Charge per Month: $2.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $14.00 Energy Charge per kwh: Summer Winter 2.394 /kwh 2.661 /kwh R PRIMARY SERVICE - CT Metering Customer Charge per Month: $3.00 Monthly Minimum Bill: Customer + Facilities Charge Facilities Charge per Month: $9.00 Energy Charge per kwh: Summer Winter 2.386 /kwh 2.654 /kwh R INTERIM RATE ADJUSTMENT A 3.8 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 or Voluntary Rate Riders selected by the Customer. See sections 12 through 14 of the electric rates for the applicability matrices of riders. DEFINITIONS OF SEASONS: Summer: June through September. Winter: October through May. Docket No. E-017/GR-10-239 Approved:(DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Service

Fergus Falls, Minnesota Interim Minnesota, Section 14.07 Fixed Time of Delivery Rider (Fixed TOD) Page 3 of 3 Fourth Revision CONTROL CRITERIA: The customer will receive electric service from 10:00 p.m. until 6:00 a.m. each day. In all other hours, the customer's load will be controlled. EQUIPMENT SUPPLIED: Otter Tail Power Company will supply and maintain the necessary metering and control equipment. Docket No. E-017/GR-10-239 Approved:(DATE) and after June 1, 2010, in Minnesota Manager, Regulatory Service