1. August 28, 2015 2014 ATTACHMENT O TRUE-UP CUSTOMER MEETING

2. Meeting Purpose Otter Tail Power Company Profile Attachment O Calculation 2014 Transmission Projects Question/Answer 2

3. To provide an informational forum regarding Otter Tail’s 2014 Attachment O for True-up. The 2014 Actual Year Attachment O is calculated using the FERC Form 1 Attachment O template under the MISO Tariff utilizing actual data as reported in the 2014 FERC Form 1 for Otter Tail Power. Any True-up for 2014 will be included in the 2016 FLTY Attachment O Calculation for rates effective January 1, 2016 for the joint pricing zone comprised of Otter Tail, Great River Energy, Missouri River Energy Services, Benson Municipal Utilities, Detroit Lakes Public Utilities, and Alexandria Light & Power. 3

4. OTTER TAIL POWER COMPANY PROFILE

5. NORTH DAKOTA SOUTH DAKOTA Garrison Rugby LANGDON WIND ENERGY CENTER COYOTE STATION Jamestown LEGEND Headquarters Customer service center HOOT LAKE PLANT Fergus Falls Wahpeton Oakes Morris LAKE PRESTON COMBUSTION TURBINE BIG STONE PLANT LUVERNE WIND FARM ASHTABULA WIND ENERGY CENTER ASHTABULA III Milbank SOLWAY COMBUSTION TURBINE Crookston Devils Lake Bemidji JAMESTOWN COMBUSTION TURBINE 70,000 Square miles 130,200 Customers 422 Communities Avg. population about 400 785 Employees 495 Minnesota 200 North Dakota 90 South Dakota About 800 MW owned generation About 245 MW wind generation About 5,400 miles of transmission lines SERVICE AREA 5

6. OUR MISSION To produce and deliver electricity as reliably, economically, and environmentally responsibly as possible to the balanced benefit of customers, shareholders, and employees and to improve the quality of life in the areas in which we do business. 6

7. ATTACHMENT O CALCULATION

8. Actual Year Rate Requirements Rate Base Operating Expenses Revenue Requirement and Rate Network Rate Summary 8

9. By June 1 of each year, Otter Tail will post on OASIS all information regarding any Attachment O True-up Adjustments for the prior year. By September 1 of each year, Otter Tail will hold a customer meeting to explain its Actual Year True-up Calculation. –Ex., 2014 Forward Looking Attachment O will be trued-up by June 1, 2015 with a corresponding Customer Meeting being held by September 1, 2015. By September 1 of each year, Otter Tail will post on OASIS its projected Net Revenue Requirement, including the True-Up Adjustment and load for the following year, and associated work papers. Otter Tail will hold a customer meeting by October 31 of each year to explain its formula rate input projections and cost detail. The MISO Transmission Owners will hold a Regional Cost Sharing stakeholder meeting by November 1 of each year. 9

10. 10 Note: The above numbers are Transmission only Rate Base Item 2014 Actual 2014 Projected $ Change% ChangeExplanation Gross Plant in Service $315,321,865$318,287,029$(2,965,164)(0.9%) The decrease in Plant in Service from Projected to Actual was due to timing of in-service dates and lower capitalized project costs than expected. Variance is less than 1% overall so very close to forecast. Accumulated Depreciation $106,772,283$107,878,058$(1,105,775)(1.0%) Net result of Annual Depreciation Expense combined with projected retirements. Net Plant in Service $208,549,582$210,408,971$(1,859,389)(0.9%) = Gross Plant - A/D Adjustments to Rate Base $(52,627,921)$(50,181,698)($2,446,223)4.9% ADIT - Book vs Tax Depreciation Timing Differences originating due to accelerated tax depreciation methods being used for large Transmission projects going into service. CWIP for CON Projects $58,045,533$65,920,432$(7,874,899)(11.9%) The decrease in CWIP for CON Projects from Projected to Actual was mainly due to Fargo Phase III CAPX project going into service earlier than anticipated. Land Held for Future Use $9,037$9,038$(1)0.0% Working Capital $5,840,784$5,710,799$129,9852.3% Increase in CWC due to slight increases in inventory, prepayments and direct Transmission and A&G-related O&Ms. Rate Base $219,817,014$231,867,542$(12,050,527)(5.2%) = Net Plant + Adj + CWIP + Land + Working Capital

11. 11 Note: The above numbers are Transmission only Expense Item 2014 Actual 2014 Projected $ Change% Change Explanation O&M $14,259,856$14,317,565 $(57,709)(0.4%) Tracking close to forecast. Depreciation Expense $5,867,878$6,566,168$(698,290)(10.6%) Decrease in depreciation expense coincides with the reduction in Plant in Service reported on the previous slide as well as lower transmission depreciation rates filed late in 2013 for use in actual year 2014. Taxes Other than Income $2,647,490$2,711,397$(63,907)(2.4%) Tracking close to forecast. Income Taxes $8,617,574$8,343,341$274,2333.3% Higher ETR in the 2014 actual vs the FLTY filing increased the tax calculation slightly. This is somewhat offset by a Decrease in Rate Base = Decrease in Return = Decrease in Income Tax Expense. Operating Expense $31,392,798$31,938,471$(545,673)(1.7%) = O&M + A&G + Depreciation + Taxes

12. 12 2014 Actual 2014 Projected $ Change% ChangeExplanation Long Term Debt 50.84%50.54% 0.30% Tracking close to forecast. Common Stock 49.16%49.46% (0.30%) Tracking close to forecast. Total 100.00% = Debt + Equity Weighted Cost of Debt 5.50%5.49% 0.01% Tracking close to forecast. Cost of Common Stock 12.38% 0.00% Unchanged Rate of Return 8.88%8.90% (0.02%) = (LTD*Cost)+(Preferred Stock*Cost)+(Common Stock*Cost) Rate Base $219,817,014$231,867,542$(12,050,528)(5.20%) From "Rate Base" Calculation Allowed Return $19,519,538$20,629,078$(1,109,540)(5.38%) = Rate of Return * Rate Base Operating Expenses $31,392,798$31,938,471$(545,673)(1.71%) From "Operating Expense" Calculation Attachment GG Adjustments $16,168,882$16,562,703$(393,821)(2.38%) The reduction in revenue requirements is mainly due to less spend on Fargo CAPX than originally projected and a lower rate of return as calculated above. Attachment MM Adjustments $4,373,580$4,573,259($199,679)(4.37%) The reduction in revenue requirements is mainly due to less capital spend on all projects, pushing the in-service date for Brookings CAPX from December 2013 in the FLTY to an actual in-service date of April 2014 as well as a lower Rate of Return as calculated above. Gross Revenue Requirement $30,369,874$31,431,586$(1,061,713)(3.38%) = Return + Expenses - Adjustments Revenue Credits $6,129,709$6,449,668$(319,959)(4.96%) The reduction is mainly due to less MISO Schedule 26 and 26A credits than forecasted. 2014 True-up (Including Interest) $(4,638,732) -0.00% N/A Net Revenue Requirement $19,601,433$20,343,186(741,753)(3.65%) = Gross Revenue Requirement - Revenue Credits + True-up

13. 13 Attachment O True-up Calculation 2014 Actual 2014 Projected $ Change% ChangeExplanation ATRR True-up $(741,753) From “Net Revenue Requirement” line on previous slide. Divisor $730,327$659,524$(70,803)(10.74%) From Line Above Projected Cost ($/kW/Yr) $30.85 From 2014 FLTY Attachment O Template Divisor True-up $(2,183,927) = Divisor x Projected Cost ($/kW/Yr) Total Principal True-up $(2,925,680) = ATRR + Divisor True-up Amounts Interest on True-up $(192,171) = Avg. Monthly FERC Interest Rate on Refunds x Principal True-up Total Principal and Interest True-up $(3,117,851) To be Applied to 2016 FLTY Attachment O Calculation

14. 14 Z $0.33 or 12.8% Decrease

15. TOTAL TRANSMISSION REVENUE REQUIREMENT BREAKDOWN 15

16. 2014 TRANSMISSION PROJECTS

17. 17 Project Forecasted 2014 Capital Addition Actual 2014 Capital Addition $ Change% Variance Reason for Variance Circuit Breaker Replacements$300,000$277,949($22,051)-7.4%Tracking close to budget. Rejected Pole Replacements$500,000$635,533$135,53327.1% Material purchases for 2015 projects accelerated into 2014. Parshall Area 115 kV Source$1,151,478$197,929($953,549)-82.8% Project delayed due to stalled negotiations with a third party. Summit 115/41.6 kV Transformer Replacement $252,012$348,791$96,77938.4% Progress payments to third party resulted in more spend in 2014. Proactive Worst Performing Lines$319,688$383,701$64,01320.0% Material purchases for 2015 projects accelerated into 2014. Proactive Relay Upgrade$200,000$89,136($110,864)-55.4% Resource constraints did not allow for all of this work to get completed.

18. 18 Project Forecasted 2014 Capital Addition Actual 2014 Capital Addition $ Change% Variance Reason for Variance Oakes Area Transmission Improvements $3,153,332$3,562,015$408,68313.0% Poor soil conditions led to a change in the design of the structures. Devils Lake – Spirit Lake 41.6 kV Line$532,031$614,686$82,65515.5% Permit conditions required a change in the project design. Winger – Thief River Falls 230 kV Line$60,000$0($60,000)-100.0% Refreshed load projections allowed for a delay in the project. Clearbrook – Solway 115 kV Line$1,045,000$233,108($811,892)-77.7% Project was placed on hold due to addressing an expanded need for the project. Transmission Line Capacity Upgrades (NERC Alert) $6,800,826$3,634,674($3,166,152)-46.6% Engineering efforts delayed the initiation of construction work.

19. 19 Project Forecasted 2014 Capital Addition Actual 2014 Capital Addition $ Change% VarianceReason for Variance Attachment GG Buffalo – Casselton 115 kV Line$7,199,999$1,996,629($5,203,370)-72.3% Underlying improvements delayed to analyze design opportunity. Fargo – St. Cloud 345 kV Line$22,939,882$20,855,423($2,084,459)-9.1%Tracking close to budget. Bemidji – Grand Rapids 230 kV Line$0$221,612 100.0% Financial close of the project resulted in a true-up of final costs. Attachment MM Brookings – Hampton Line$6,505,790$6,304,795($200,995)-3.1%Tracking close to budget. Big Stone South – Brookings Line$2,420,065$2,967,388$547,32322.6% Easement payments for land rights occurred prior to forecasted. Big Stone South – Ellendale Line$3,696,143$2,971,198($724,945)-19.6% Obtaining project permits took longer than forecasted.

20. If you have any additional questions after the meeting, please submit via e-mail to: Kyle Sem, CPA Manager – Business Planning ksem@otpco.com All questions and answers will be distributed by e-mail to all attendees. Additionally, the questions and answers will be posted on Otter Tail’s OASIS website (http://www.oasis.oati.com/OTP/index.html) within two weeks from the date of inquiry. 20