Otter Tail Power Company Minnesota General Rate Case Documents Docket No. E017/GR

Transcription

1 Volume 3 Index 1/3

2 Otter Tail Power Company Minnesota General Rate Case Documents Docket No. E17/GR Volume 1 Notice of Change in Rates Interim Rate Petition Index Filing Letter Notice of Change in Rates Notice and Petition for Interim Rates Agreement and Undertaking, and Certification Interim Supporting Schedules and Workpapers Summary of Present and Interim Revenue Interim Tariff Sheets Redlined Interim Tariff Sheets Non-Redlined Proposed Notices 2A Direct Testimony and Supporting Schedules Index Thomas R. Brause Policy Peter J. Beithon Revenue Deficiency Proposed Test Year 216 Cost of Service Study Class Revenue Responsibility Stuart D. Tommerdahl Rider Roll-in Allocation Factors Compliance Items Tyler A. Akerman Budgeting Process Rate Base Operating Statement 2B Direct Testimony and Supporting Schedules Index Kevin G. Moug Financial Soundness Capital Structure Cost of Capital Robert B. Hevert Return on Equity Brian H. Draxten Sales Forecast Peter E. Wasberg Employee Compensation Mark A. Rolfes Environmental Projects

3 Volume 2C 2D Otter Tail Power Company Minnesota General Rate Case Documents Docket No. E17/GR Amparo Nieto Fixed Charges and Rate Design Policy David G. Prazak Rate Design Proposed Redlined and Non-Redlined Tariff Sheets Index Proposed Tariff Sheets Redlined Proposed Tariff Sheets Non-Redlined 3 Required Information Index Required Information A. Jurisdictional Financial Summary Schedules (Rule ) Definitions Summary of Revenue Requirements Proposed Test Year 216 Jurisdictional Financial Summary Schedule B. Rate Base Schedules (Rule ) Definitions 1. Rate Base Summary 2. Detailed Rate Base Components a. Materials and Supplies b. Fuel Stocks c. Prepayments d. Customer Advances and Deposits e. Cash Working Capital 3. Rate Base Adjustments 4. Summary of Approaches and Assumptions Used 5. Rate Base Jurisdictional Allocation Factors C. Operating Income Schedules (Rule ) Definitions 1. Jurisdictional Statement of Operating Income 2. Statement of Operating Income - Jurisdictional 3. Statement of Operating Income Proposed Test Year 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 ) 1. Summary Schedule 2. Composite Cost of Long-Term Debt 3. Average Short-Term Debt

4 Otter Tail Power Company Minnesota General Rate Case Documents Docket No. E17/GR Average Common-Equity Volume 3 E. Rate Structure and Design Information (Rule ) 1. Proposed Test Year 216 Operating Revenue Summary Comparison 2. Proposed Test Year 216 Operating Revenue Detailed Comparison 3. Class Cost of Service Study F. Other Supplemental Information 1. Annual Report and Statistical Supplement 2. Gross Revenue Conversion Factor G. Commission Policy Information 1. Advertising 2. Charitable Contributions 3. Organization Dues 4. Research Expense H. Travel, Entertainment, and Related Employee Expenses (Statute 216B.16, Subp. 17) 4A Work Papers Index A. Proposed Test Year 216 Workpapers 1. Jurisdictional Cost of Service Study (JCOSS) 2. Class Cost of Service Study (CCOSS) 3. Functionalization 4. Input Summary 5. Proposed Test Year 216 Adjustments TY-1 - Normalized Plant in Service TY-2 - BSP II Deferred Recovery TY-3 - Rate Case Expenses TY-4 KPA TY-5 - TCR MISO Removal TY-6 Prepaid Pension B. Unadjusted Projected Fiscal Year 216 Workpapers 1. Jurisdictional Cost of Service Study (JCOSS) 2. Functionalization 3. Input Summary 4. Work Papers A-D, MN C. Interim Cost of Service Study D. Hevert Cost of Capital Workpapers 4B Lead Lag Study Index Lead Lag Study 5 Budget Documentation Index O&M Budget Process Capital Budget Process

5 Volume 3 Required Information 1/3

6 Otter Tail Power Company Before the Minnesota Public Utilities Commission Application for Authority to Increase Electric Rates in Minnesota Docket No. E17/GR February 16, 216 Volume 3 Required Information PUBLIC DOCUMENT NOT PUBLIC DATA HAS BEEN EXCISED

7 Docket No. E17/GR REQUIRED SCHEDULES INDEX Jurisdictional Financial Summary Schedules (Rule ) Summary of Revenue Requirements Schedule A Jurisdictional Financial Summary Schedule (A)(B)(C) Schedule A-1 Rate Base Schedules (Rule ) Rate Base Summary (A) Schedule B-1 Detailed Rate Base Components Total utility and Minnesota jurisdiction Test Year (B)(1) Schedule B-2, p1 Total utility and Minnesota jurisdiction Most Recent and Projected Fiscal Years (B)(2) Schedule B-2, p 2 Materials and Supplies Fuel Stocks Prepayments Customer Advances and Deposits Cash Working Capital B-2-a B-2-b B-2c B-2-d B-2-e Rate Base Test Year Adjustments (C) Schedule B-3 Rate Base Assumptions and Approach to Adjustments (D) Schedule B-4 Rate Base Allocation Factors (E) Schedule B-5 Operating Income Schedules (Rule ) Jurisdictional Statement of Operating Income Schedule C-1, p1 Jurisdictional Statement of Operating Income (A) Schedule C-1-a Statement of Operating Income Total Utility and Minnesota Jurisdiction Most Recent and Projected Fiscal Years (B) Schedule C-2 Total Utility and Minnesota Jurisdiction Proposed Test Year (B) Schedule C-3 Computation of Federal & State Income Taxes (C) Schedule C-4 Computation of Deferred Income Taxes (C) Schedule C-5 Computation of Income Tax Rates (C) Schedule C-6 Operating Statement Test Year Adjustments (D) Schedule C-7 Operating Statement Assumptions and Approach to Adjustments (E) Schedule C-8 1

8 Docket No. E17/GR REQUIRED SCHEDULES INDEX Rate of Return Cost of Capital Schedules (Rule ) Summary Schedule - Utility (A) Schedule D-1-a Summary Schedule - Consolidated (A) Schedule D-1-b Summary Schedule - Unconsolidated Parent (A) Schedule D-1-c Composite Cost of Long-Term Debt - Utility (B) Schedule D-2-a Composite Cost of Long-Term Debt- Consolidated (B) Schedule D-2-b Composite Cost of Long-Term Debt- Unconsolidated Parent (B) Schedule D-2-c Average Short-Term Debt - Utility (C) Schedule D-3-a Average Short-Term Debt - Consolidated (C) Schedule D-3-b Average Short-Term Debt - Unconsolidated Parent (C) Schedule D-3-c Average Common-Equity - Utility Schedule D-4-a Average Common-Equity - Consolidated Schedule D-4-b Average Common-Equity - Unconsolidated Parent Schedule D-4-c Rate Structure and Design Information (Rule ) Summary Comparison - by Rate Schedule (A) Schedule E-1 Detailed Comparison - by Rate Schedule (B) Schedule E-2 Jurisdictional Class Cost of Service Study (C) Schedule E-3 Other Supplemental Information (Rule ) Annual Report - Fiscal Year (A) Schedule F-1 Gross Revenue Conversion Factor (B) Schedule F-2 2

9 Docket No. E17/GR OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota DEFINITIONS As required by Minnesota Rules, Part , the following information shall be supplied as a part of the utility s notice of a change in rates. Information requirements Parts , , item A; , item A; , item A; and , items A and B, as defined herein, shall be supplied by all gas and electric utilities and all other information requirements prescribed by Parts to shall be supplied where applicable to the utility. For purposes of complying with the Financial Information requirements prescribed by Parts , , , , , , and , the following definitions have been used by Otter Tail Power Company in this filing: Unadjusted Fiscal Year 214 This information represents actual financial information for the calendar year that ended December 31, 214. Unadjusted Most Recent Fiscal Year 215 This information represents actual financial information for the calendar year that ended December 31, 215. Unadjusted Projected Fiscal Year The projected fiscal year is the fiscal year immediately following the most recent fiscal year. For the purposes of this filing, this information represents projected financial information for the calendar year ending December 31, 216. Proposed Test Year The proposed test year information represents the unadjusted projected fiscal year (216) with ratemaking adjustments to normalize the data and for known and measurable changes expected to occur during the calendar year 216. Unadjusted Financial Information Unadjusted financial information consists of financial data before ratemaking adjustments. Adjusted Financial Information Adjusted financial information consists of financial data prepared with ratemaking adjustments included. 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 and the sum of the line items. These supporting schedules were prepared using individual line items with subtotals and totals calculated on each schedule. This may result in occasional differences of a few dollars between the subtotals and totals on the cost of service study and those on supporting schedules. 3

10 Volume 3 A. Jurisdictional Financial Summary Schedules (Rule ) 1/3

11 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota JURISDICTIONAL FINANCIAL SUMMARY SCHEDULE Docket No. E17/GR MINNESOTA RULE JURISDICTIONAL FINANCIAL SUMMARY SCHEDULE. A jurisdictional financial summary schedule as required by part shall be filed showing: A. the proposed rate base, operating income, overall rate of return, and the calculation of income requirements, income deficiency, and revenue requirements for the test year; B. the actual unadjusted average rate base consisting of the same components as the proposed rate base, unadjusted operating income, overall rate of return, and the calculation of income requirements, income deficiency, and revenue requirements for the most recent fiscal year; and C. the projected unadjusted average rate base consisting of the same components as the proposed rate base, unadjusted operating income under present rates, overall rate of return, and the calculation of income requirements, income deficiency, and revenue requirements for the projected fiscal year. STAT AUTH: MS s 216B.3; 216B.8; 216B.16 Current as of 1/2/5 1

12 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota SUMMARY OF REVENUE REQUIREMENTS Proposed Test Year 216 Line No. Description Docket No. E17/GR Exhibit (TAA-1) Schedule A, Page 1 of 1 Minnesota Jurisdiction Proposed Test Year Average Rate Base $483,,588 2 Operating Income (Before AFUDC) 3 Allowance for Funds Used During Construction (AFUDC) 4 Total Available for Return (Line 2 + Line 3 + Rounding) 5 Overall Rate of Return (Line 4 / Line 1) 5.73% 6 Required Rate of Return 8.7% 7 Operating Income Requirement (Line 1 x Line 6) $38,978,147 8 Income Deficiency (Line 7 - Line 4) $11,313,26 9 Gross Revenue Conversion Factor Revenue Deficiency (Line 8 x Line 9) 11 Retail Related Revenues Under Present Rates 12 Percent Increase Needed in Overall Revenue (Line 1 / Line 11) $26,993,574 $671,547 $27,665,121 $19,295,627 $196,817,16 9.8% 2

13 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota JURISDICTIONAL FINANCIAL SUMMARY SCHEDULE Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule A-1, Page 1 of 1 (A) Line No. Description 1 Average Rate Base 2 Operating Income (Before AFUDC) 3 Allowance for Funds Used During Construction (AFUDC) 4 Total Available for Return (Line 2 + Line 3 + Rounding) 5 Unadjusted Fiscal Year 214 $42,587,861 (B) Unadjusted Most Recent Fiscal Year 215 $43,6,76 (C) Unadjusted Projected Fiscal Year 216 $46,35,382 (D) Proposed Test Year 216 $483,,588 $28,633,63 $31,369,33 $27,586,395 $26,993,574 $993,289 $1,418,785 $818,137 $671,547 $29,626,352 $32,788,88 $28,44,532 $27,665,121 Overall Rate of Return (Line 4 / Line 1) 7.36% 7.61% 6.17% 5.73% 6 Required Rate of Return 8.3% 8.27% 8.7% 8.7% 7 Operating Income Requirement (Line 1 x Line 6) $32,327,85 $35,61,626 $37,124,855 $38,978,147 8 Income Deficiency (Line 7 - Line 4) $2,71,453 $2,822,538 $8,72,324 $11,313,26 9 Gross Revenue Conversion Factor Revenue Deficiency (Line 8 x Line 9) $4,67,629 $4,814,154 $14,873,484 $19,295, Retail Related Revenues Under Present Rates 12 Percent Increase Needed in Overall Revenue (Line 1 / Line 11) $196,817,16 9.8% (B) Rule , Sub. B. (C) Rule , Sub. C. (D) Rule , Sub. A. 3

14 Volume 3 B. Rate Base Schedules (Rule ) 1/3

15 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota JURISDICTIONAL FINANCIAL SUMMARY SCHEDULE Docket No. E17/GR MINNESOTA RULE RATE BASE SCHEDULES. The following rate of return cost of capital schedules as required by part shall be filed: A. A rate base summary schedule by major rate base component (e.g. plant in service, construction work in progress, and plant held for future use) showing the proposed rate base, the unadjusted average rate base for the most recent fiscal year and unadjusted average rate base for the projected fiscal year. The totals for this schedule shall agree with the rate base amounts included in the financial summary. B. A comparison of total utility and Minnesota jurisdictional rate base amounts by detailed rate base component showing: (1) total utility and the proposed jurisdictional rate base amounts for the test year including the adjustments, if any, used in determining the proposed rate base; (2) the unadjusted average total utility and jurisdictional rate base amounts for the most recent fiscal year and the projected fiscal year. C. Adjustment schedules, if any, showing the title, purpose, and description and the summary calculations of each adjustment used in determining the proposed jurisdictional rate base. D. A summary by rate base component of the assumptions made and the approaches used in determining average unadjusted rate base for the projected fiscal year. Such assumptions and approaches shall be identified and quantified into two categories: known changes from the most recent fiscal year and projected changes. E. For multijurisdictional utilities only, a summary by rate base component of the jurisdictional allocation factors used in allocating the total utility rate base amounts to the Minnesota jurisdiction. This summary shall be supported by a schedule showing for each allocation factor the total utility and jurisdictional statistics used in determining the proposed rate base and the Minnesota jurisdictional rate base for the most recent fiscal year and the projected fiscal year. STAT AUTH: MS s 216B.3; 216B.8; 216B.16 Current as of 1/2/5 1

16 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES RATE BASE SUMMARY Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule B-1, Page 1 of 1 Complies with Rule , Sub. A. (A) Line No. Description Unadjusted Fiscal Year 214 (A) (B) Unadjusted Most Recent Fiscal Year 215 (B) (C) Unadjusted Projected Fiscal Year 216 (C) (D) Proposed Test Year 216 (D) 1 Electric Plant in Service $78,73,372 $769,377,19 $928,153,287 $933,541,568 2 Less: Accumulated Depreciation (34,4,17) (318,775,876) (345,878,676) (346,149,23) $44,699,355 $45,61,142 $582,274,611 $587,392,337 $13,285 $13,263 $13,813 $13,813 3 Net Electric Plant in Service Other Rate Base Components: 4 Plant Held for Future Use 5 Construction Work in Progress 6 99,44,814 19,914,12 15,145,571 12,95,889 Materials and Supplies 8,54,757 9,94,66 9,48,219 9,48,372 7 Fuel Stocks 4,725,221 5,539,349 5,824,626 5,824,626 8 Prepayments (23,41,741) (24,83,127) (26,352,61) (5,679,13) 9 Customer Advances (852,188) (954,252) (1,34,452) (1,34,643) 1 Cash Working Capital 5,459,892 4,95, Accumulated Deferred Income Taxes 12 TOTAL 5,116,528 (95,649,17) $42,587,861 4,278,178 (123,83,94) (13,74,838) (13,736,573) $43,6,76 $46,35,382 $483,,588 Includes all rate base from TCR's and ECR's 2

17 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES DETAILED RATE BASE COMPONENTS Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule B-2, Page 1 of 2 Complies with Rules , Sub. B(1). (A) Line No. Description Utility Plant in Service: 1 Production 2 Transmission 3 Distribution 4 General 5 Intangible 6 TOTAL Utility Plant in Service Unadjusted Projected Fiscal Year 216 $884,52,468 41,385,1 459,399,545 88,637,982 1,115,49 $1,843,59,414 Total Utility (B) Adjustments $6,886,625 3,369,179 $1,255,84 (C) (A) + (B) Proposed Test Year 216 $89,939,93 44,754, ,399,545 88,637,982 1,115,49 $1,853,846,218 (D) Minnesota Jurisdiction (E) Unadjusted Projected Fiscal Year 216 $471,279,46 21,692,793 26,471,49 43,72,944 4,989,455 $928,153,287 Adjustments $3,692,798 1,694, $5,388,28 (F) (D) + (E) Proposed Test Year 216 $474,971,844 23,387,43 26,471,49 43,721,726 4,989,544 $933,541, Accumulated Depreciation Production Transmission Distribution General Intangible ($333,617,673) (111,742,522) (2,637,819) (39,229,749) (4,99,382) ($325,88) (189,78) ($333,943,553) (111,932,23) (2,637,819) (39,229,749) (4,99,382) ($177,689,338) (56,23,615) (9,174,14) (19,35,189) (2,461,52) ($174,746) (95,418) (346) (44) ($177,864,84) (56,299,33) (9,174,14) (19,35,534) (2,461,564) 12 TOTAL Accumulated Depreciation ($69,218,144) ($515,588) ($69,733,732) ($345,878,676) ($27,554) ($346,149,23) NET Utility Plant in Service Production Transmission Distribution General Intangible $55,434, ,642, ,761,726 49,48,233 5,125,27 $6,56,745 3,179,471 $556,995,54 292,821, ,761,726 49,48,233 5,125,27 $293,589,78 145,489, ,297,35 24,37,755 2,527,935 $3,518,52 1,599, $297,17,76 147,88,37 116,297,35 24,371,192 2,527, NET Utility Plant in Service $1,153,372,27 $9,74,216 $1,163,112,486 $582,274,611 $5,117,726 $587,392,337 Utility Plant Held for Future Use Construction Work in Progress Materials and Supplies* Fuel Stocks* Prepayments* Customer Advances & Deposits* Cash Working Capital* Accumulated Deferred Income Taxes $29,657 97,477,682 19,167,363 1,847,917 (52,198,285) (2,49,47) 1,741,32 (247,929,982) $13,813 15,145,571 9,48,219 5,824,626 (26,352,61) (1,34,452) 5,459,892 (13,74,838) $ (2,239,682) 152 2,672,93 (191) (553,994) (31,736) $13,813 12,95,889 9,48,372 5,824,626 (5,679,13) (1,34,643) 4,95,898 (13,736,573) 29 Total Average Rate Base $989,458,67 $ (4,224,315) 4,952, (1,83,336) $45,385,761 $29,657 93,253,367 19,167,363 1,847,917 (11,245,41) (2,48,726) 9,657,696 (247,929,982) $1,34,844,368 $46,35,382 $22,965,26 $483,,588 *Detailed on Schedules B-2-a through B-2-e 3

18 OTTER TAIL POWER COMPANY Docket No. E17/GR Electric Utility - State of Minnesota RATE BASE SCHEDULES DETAILED RATE BASE COMPONENTS Exhibit (TAA-1) Financial Information Schedule B-2, Page 2 of 2 Complies with Rules , Sub. B(2). Unadjusted Fiscal Year 214 Line No. Description Total Utility Unadjusted Most Recent Fiscal Year 215 MN Jurisdiction Total Utility MN Jurisdiction Unadjusted Projected Fiscal Year 216 Total Utility MN Jurisdiction Utility Plant in Service: Production Transmission Distribution General Intangible TOTAL Utility Plant in Service $678,611,316 31,913, ,67,77 84,418,123 7,62,848 $1,5,631,614 $335,55, ,716, ,114,337 39,776,19 3,59,796 $78,73,372 $69,49, ,976, ,16,743 86,333,42 8,694,233 $1,596,7,72 $355,785,96 176,21, ,94,99 41,291,455 4,158,287 $769,377,19 $884,52,468 41,385,1 459,399,545 88,637,982 1,115,49 $1,843,59,414 $471,279,46 21,692,793 26,471,49 43,72,944 4,989,455 $928,153, Accumulated Depreciation Production Transmission Distribution General Intangible ($317,565,83) (11,18,916) (184,65,285) (35,776,891) (2,32,555) ($157,68,938) (47,794,796) (8,713,23) (16,857,38) (957,7) ($321,483,376) (15,449,432) (191,91,715) (37,429,55) (3,382,951) ($165,595,733) (5,513,526) (83,147,9) (17,91,66) (1,618,1) ($333,617,673) (111,742,522) (2,637,819) (39,229,749) (4,99,382) ($177,689,338) (56,23,615) (9,174,14) (19,35,189) (2,461,52) ($641,134,45) ($34,4,17) ($659,655,529) ($318,775,876) ($69,218,144) ($345,878,676) $361,45,513 2,84,73 243,417,422 48,641,232 5,588,293 $177,824,719 94,921,596 16,41,134 22,918,89 2,633,96 $368,566, ,527, ,16,28 48,93,988 5,311,282 $19,189, ,687,746 18,793,9 23,389,848 2,54,285 $55,434, ,642, ,761,726 49,48,233 5,125,27 $293,589,78 145,489, ,297,35 24,37,755 2,527, TOTAL Accumulated Depreciation 13 NET Utility Plant in Service 14 Production 15 Transmission 16 Distribution 17 General 18 Intangible NET Utility Plant in Service $859,497,164 $44,699,355 $936,415,173 $45,61,142 Utility Plant Held for Future Use Construction Work in Progress Materials and Supplies $29, ,81,272 18,42,628 $13,285 99,44,814 8,54,757 $29, ,391,968 19,295,26 $13,263 19,914,12 9,94,66 $29,657 97,477,682 19,167,363 $13,813 15,145,571 9,48, Fuel Stocks Prepayments Customer Advances & Deposits Cash Working Capital Accumulated Deferred Income Taxes 9,481,452 (49,719,54) (1,89,869) 1,879,185 (216,845,433) 4,725,221 (23,41,741) (852,188) 5,116,528 (95,649,17) 1,686,75 (5,48,265) (1,983,76) 8,31,577 (243,739,855) 5,539,349 (24,83,127) (954,252) 4,278,178 (123,83,94) 1,847,917 (52,198,285) (2,49,47) 1,741,32 (247,929,982) 5,824,626 (26,352,61) (1,34,452) 5,459,892 (13,74,838) $915,349,133 $43,6,76 $989,458,67 $46,35, Total Average Rate Base $842,734,517 $42,587,861 $1,153,372,27 $582,274,611 4

19 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES DETAILED RATE BASE COMPONENTS MATERIALS AND SUPPLIES Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule B-2-a, Page 1 of 1 PROPOSED TEST YEAR 216 Line No December January February March April May June July August September October November December Total Average - total utility End End End End End End End End End End End End End Production $6,254,286 6,24,286 6,454,286 6,254,286 6,24,286 6,354,286 6,254,286 6,24,286 6,354,286 6,254,286 6,24,286 6,354,286 6,254,286 $81,65,722 $6,277,363 (1) All Other $13,4, 12,64, 12,94, 13,14, 13,39, 13,14, 12,94, 12,69, 12,54, 12,49, 12,59, 12,99, 13,4, $154,53, $12,89, Total $19,294,286 18,844,286 19,394,286 19,394,286 19,594,286 19,494,286 19,194,286 18,894,286 18,894,286 18,744,286 18,794,286 19,344,286 19,294,286 $229,881,436 $19,167,363 (1) Allocated between transmission and distribution using FERC Form 1, page 227 Transmission Distribution MINNESOTA JURISDICTION Total Production 6,277,363 Less: Production Total 6,277,363 Transmission 5,16,73 Distribution 7,873,27 $19,167,363 $4,93,846 7,696,154 $12,6, Allocator P1 D2 P % % 1% Unadjusted Fiscal Year 216 MN Percent MN Dollars 53.39% 5.297% % 3,346,396 2,523,286 3,538,537 $9,48,219 Proposed Test Year 216 MN Percent MN Dollars % 5.297% % 3,346,548 2,523,286 3,538,537 $9,48,372 5

20 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES DETAILED RATE BASE COMPONENTS FUEL STOCKS Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule B-2-b, Page 1 of 1 PROPOSED TEST YEAR 216 Line No December January February March April May June July August September October November December Total Average - total utility End End End End End End End End End End End End End MINNESOTA JURISDICTION Total Coal 8,361,923 Fuel Oil & Other 2,485,994 $1,847, Allocator E1 D1 Coal $8,64,11 8,672,193 8,594,579 8,352,779 8,141,332 8,143,69 7,991,463 7,65,925 7,778,467 8,291,93 8,644,246 8,878,96 8,926,29 $18,75,3 $8,361,923 Oil & Other $2,583,52 2,646,455 2,625,519 2,538,344 2,496,457 2,378,19 2,264,634 2,242,914 2,245,636 2,311,297 2,627,513 2,697,335 2,66,276 $32,317,917 $2,485,994 Total $11,223,531 11,318,649 11,22,98 1,891,123 1,637,788 1,521,628 1,256,96 9,893,839 1,24,13 1,62,39 11,271,759 11,575,431 11,586,484 $141,22,92 $1,847,917 Proposed Test Year 216 MN Percent MN Dollars % 4,565, % 1,259,227 $5,824,626 6

21 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES DETAILED RATE BASE COMPONENTS PREPAYMENTS Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule B-2-c, Page 1 of 1 PROPOSED TEST YEAR 216 Line No December January February March April May June July August September October November December Total End End End End End End End End End End End End End Average - total utility 19 MINNESOTA JURISDICTION 2 Allocator 21 Prepayments NEPIS FAS 87 $34,939,66 44,43,356 43,867,16 43,33,856 42,794,66 42,258,356 41,722,16 41,185,856 4,649,66 4,113,356 39,577,16 39,4,856 38,54,66 $532,387,375 Insurance $411,443 1,741,514 1,468,45 1,181,837 2,693,975 2,394,868 2,97,117 1,832,812 1,536,771 1,242, , , ,955 $18,667,66 $4,952,875 $1,435,928 Post-Retirement Post-Employment Benefits Benefits ($51,918,431) ($196,599) (52,266,747) (124,326) (52,615,64) (52,52) (52,864,381) 2,221 (53,212,698) 92,495 (53,561,15) 164,769 (53,81,332) 237,42 (54,158,649) 39,316 (54,56,966) 381,589 (54,756,283) 453,863 (55,14,599) 526,136 (55,452,916) 598,41 (56,98,233) 67,684 ($7,326,314) $3,81,547 ($53,871,255) Unadjusted Projected Fiscal Year 216 MN Percent MN Dollars 5.485% ($5,677,193) $237,42 Total ($16,763,982) (6,246,23) (7,331,66) (8,331,468) (7,631,623) (8,743,23) (9,754,67) (1,83,666) (11,939,) (12,946,831) (14,18,918) (15,124,953) (16,527,988) ($146,19,326) ($11,245,41) Proposed Test Year 216 MN Percent MN Dollars 5.52% ($5,679,13) 7

22 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES DETAILED RATE BASE COMPONENTS CUSTOMER ADVANCES AND DEPOSITS Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule B-2-d, Page 1 of 1 Proposed Test Year 216 Line No. 1 December 2 January February 3 March 4 5 April May 6 June 7 July 8 August 9 September 1 October 11 November 12 December Total End End End End End End End End End End End End End Average advances - total utility 15 Customer deposits - total utility (2) Total to allocate MINNESOTA JURISDICTION 2 Unadjusted Projected Fiscal Year Allocator MN Percent MN Dollars NEPIS 5.485% ($799,24) $ Customer Advances ($1,17,965) (1,17,965) (1,17,965) (1,17,965) (1,17,965) (1,17,965) (1,17,965) (1,17,965) (1,17,965) (1,17,965) (1,17,965) (1,17,965) (1,17,965) (14,43,548) (1,17,965) (475,11) ($1,583,66) Proposed Test Year 216 MN Percent MN Dollars 5.52% ($799,476) (2) MN Customer deposit balance is calculated based on interest paid for the year and is grossed up to the total utility amount needed for CCOSS purposes. 8

23 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES CASH WORKING CAPITAL Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule B-2-e, page 1 of 3 Unadjusted Fiscal Year 214 Line No. Item Total Utility Minnesota Unadjusted Projected Fiscal Year 215 Total Utility Proposed Test Year 216 Minnesota Total Utility Minnesota Cash Working Capital Calculation - Revenue Lead Days Revenues Computer Maintained Billings Manually Maintained Billings Cost of Energy Adjustment Revenues Sales for Resale Rent from Electric Property Miscellaneous ITA Deficiency Payments Wheeling Load Control and Dispatch Rent from Electric Property - Big Stone Rent from Electric Property - Coyote Profit on Materials and Supplies Miscellaneous Services Loan Pool Interest Total Revenues Revenue Lead Days from Service to Collection Computer Maintained Billings Manually Maintained Billings Cost of Energy Adjustment Revenues Sales for Resale Rent from Electric Property Miscellaneous ITA Deficiency Payments Wheeling Load Control and Dispatch Rent from Electric Property - Big Stone Rent from Electric Property - Coyote Profit on Materials and Supplies Miscellaneous Services Loan Pool Interest Revenue Dollar Days (Revenues X Revenue Lead Days) Computer Maintained Billings Manually Maintained Billings Cost of Energy Adjustment Revenues Sales for Resale Rent from Electric Property Miscellaneous ITA Deficiency Payments Wheeling Load Control and Dispatch Rent from Electric Property - Big Stone Rent from Electric Property - Coyote Profit on Materials and Supplies Miscellaneous Services Loan Pool Interest Total Dollar Days $38,142,153 36,551,293 1,21,916 2, ,774 3,191,427 3,581, ,11 2,423,543 1,474 14,325 3,343 1,225 $152,769,174 18,121,217 3,976, ,555 1,52,72 1,686,38 9,616,547 4,932 6,745 14,287 9,361 $321,47,748 3,538,88 12,812,822 2,125,55 485,277 1,89,825 3,19,41 452,986 24,767,174 14,512 11,167 29,716 7,899 $162,577,73 15,464,769 6,59, ,35 233,514 87,884 1,496,242 11,917,916 6,983 5,373 14,299 7,71 $346,618,3 32,971,139 4,875, , ,17 3,12,153 1,677,1 455,844 7,664,776 11,714 5,268 29,716 3,7 $177,912,116 16,923,414 2,495,896 17, ,42 1,575, ,965 3,87,847 5,916 2,66 15,7 2,41 $383,318,583 $187,939,124 $397,212,894 $199,641,546 $398,298,521 $23,994, (351.) (87.8) (369.6) (92.4) (369.6) (92.4) $47,946,919,41 $5,942,72,862 6,44,121, ,131,113 4,718,386,15 39,862,819 22,745,78 (172,632,285) (2,321,235) 543,18,86 63,939, ,593,477 84,47,79 72,396,462 2,728,585, ,192,663 1,867, ,688 2,554,2 27,377 5,49, ,688 1,822, ,221 $55,733,889,57 5,45,11,128 5,65,22,14 196,6,76 (179,377,672) 252,796,414 61,981,734 64,795,155 2,764,16,625 2,583,242 1,987,748 5,289,667 1,46,12 $7,55,872, ,694, ,116,513 22,767,255 (21,579,46) 3,411,285 72,418,17 332,59,843 35, , ,183 39,176 6,172,936,962 5,446,832,111 2,149,873,745 36,664,541 (173,31,1) 435,822, ,686,56 65,23, ,388,972 2,74, ,99 5,263, ,351 7,721,385, ,937,5 245,539,773 2,478,196 (21,845,94) 55,24,571 4,993,111 17,996, , , ,173 14,173 $62,632,95,519 $7,533,412,965 $7,14,641,975 $8,728,685, Avg Revenue Lead Days (Total Rev Dollar Days / Total Rev) Calculation of Days from Service to Collection Service Period to Date Meter is Read Read Date to Date Billing is Prepared Billing Date to Date collection is Received Total (365 / 12 / 2) (365 / 12 / 2) $69,323,34,995 $8,851,636, (365 / 12 / 2)

24 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES CASH WORKING CAPITAL Calculation applying lead-lag factors Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule B-2-e, page 2 of 3 UNADJUSTED FISCAL YEAR 214 (A) Line No. Item Operating Expense Fuel - Coal $3,692,527 Fuel - Oil 2,419,43 Purchased Power 32,389,131 Labor and Associated Payroll Expense 34,139,39 All Other O&M Expense 27,93,796 Property Taxes (Excl Coal Conversion Taxes) 5,589,329 Coal Conversion Taxes 343,253 Federal Income Taxes 1,676,3 State Income Taxes 988,12 Incremental Federal Income Taxes Incremental State Income Taxes Bank Balances Special Deposits Working Funds Tax Collections Available FICA Withholding (2,291,43) Federal Withholding (3,83,91) State Withholding- MN (1,829,456) State Withholding- ND (182,477) State Sales Tax (7,68,81) Franchise Taxes (1,59,166) Total Cash Working Capital Requirement MINNESOTA JURISDICTION (B) (C) (D) (E) Lead Days of Expense/day 4.1 at 365 Expense Over Expense Net Revenue day/year Lag Days Lag Days Lag Dollars $84,89 6,629 88,737 93,533 76,523 15, ,592 2,77 (6,278) (1,422) (5,12) (5) (21,43) (4,135) (253.4) (A) Net Revenue Lag Dollars Operating Expense 2,374, ,517 84,343 2,268,165 1,959,755 (3,88,977) 6, ,134 18,556 4,85 1,474,993 8,972 $4,93, ,642 1,785,57 4,676,615 4,62,69 (8,228,683) 14, , ,828 1,3 3,132,578 19,55 (9,573) (31,16) (267,4) (133,33) (4,589) (39,819) (133,33) $ 5,85,512 UNADJUSTED FISCAL YEAR 215 TOTAL UTILITY (F) $ 1,879,185 $21,872,814 87,244 4,251,158 2,852,593 64,572,87 6,336, ,394 (13,779,28) 2,92,385 (2,397,227) (3,864,59) (1,9,) (185,) (7,68,81) (1,59,166) MINNESOTA JURISDICTION (B) (C) (D) (E) Lead Days of Expense/day 43.7 at 365 Expense Over Expense Net Revenue day/year Lag Days Lag Days Lag Dollars $59,926 2,212 11,277 7, ,91 17,361 9 (37,751) 5,733 (6,568) (1,588) (5,25) (57) (21,43) (4,135) (25.8) ,689,3 71,834 1,336, ,719 5,414,449 (4,354,718) 9,339 25,513 5,41 26,3 8,873 (9,63) (34,998) (272,511) (113,952) $ 4,243,18 TOTAL UTILITY (F) Net Revenue Lag Dollars $5,28,756 24,428 1,182,5 356,374 7,193,686 (7,394,96) 11, ,478 65,148 1,3 4,91,815 19,55 (41,799) (283,465) (125,878) $11,176,996 1

25 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES CASH WORKING CAPITAL Calculation applying lead-lag factors Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule B-2-e, page 3 of 3 Proposed Test Year 216 (A) Line No. Item Fuel - Coal Fuel - Oil Purchased Power Labor and Associated Payroll Expense All Other O&M Expense Property Taxes (Excl Coal Conversion Taxes) Coal Conversion Taxes Federal Income Taxes State Income Taxes Incremental Federal Income Taxes Incremental State Income Taxes Bank Balances Special Deposits Working Funds Tax Collections Available FICA Withholding Federal Withholding State Withholding- MN State Sales Tax Franchise Taxes Total Cash Working Capital Requirement Operating Expense $27,729, ,652 38,633,948 3,154,493 67,374,589 6,968, ,391 5,43,914 1,441,574 (2,544,31) (3,998,19) (1,9,) (7,68,81) (1,59,166) MINNESOTA JURISDICTION (B) (C) (D) (E) Lead Days of Expense/day 43.4 at 365 Expense Over Expense Net Revenue day/year Lag Days Lag Days Lag Dollars $75,764 1,535 15,557 8, ,84 19, ,781 3,939 (6,952) (1,924) (5,191) (2,986) (4,123) $2,113, , ,247, , ,578,782 (252.9) (4,815,72) 1.1 9, , , ,959 97,216 8,555 (9,64) (271,766) (113,641) $ 4,95,898 TOTAL UTILITY (F) Net Revenue Lag Dollars $6,233,63 145,999 3,595, ,77 17,929,728 (14,471,725) 28,32 1,765,884 52,13 17, ,661 25,666 (28,811) (815,299) (34,923) $ 15,573,442 11

26 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES RATE BASE ADJUSTMENTS 216 Unadjusted Projected Fiscal Year versus 216 Proposed Test Year Complies with Rules , Sub. C. (A) Line No. Description Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule B-3, Page 1 of 1 (B) (C) (D) (E) Changes in 216 Unadjusted Allocations Due Normalized Prepaid Projected Fiscal to Effect of Test 216 Proposed Plant in Service Pension FAS 87 Year Adjustments Test Year Year Utility Plant in Service: 1 Production $471,279,46 $3,692,798 $ ($) $474,971,844 2 Transmission 21,692,793 1,694,61 23,387,43 3 Distribution 26,471,49 26,471,49 4 General 43,72,944 5 Intangible 6 TOTAL Utility Plant in Service 4,989,455 $928,153,287 $5,387,49 $ ,721, ,989,544 $872 $933,541,568 Accumulated Depreciation 7 Production ($177,689,338) ($174,746) $ $ 8 Transmission (56,23,615) (95,418) 9 Distribution (9,174,14) (9,174,14) (346) (44) (19,35,534) ($39) ($346,149,23) 1 11 General Intangible 12 TOTAL Accumulated Depreciation (19,35,189) (2,461,52) ($345,878,676) ($27,164) $ ($177,864,84) (56,299,33) (2,461,564) 13 NET Utility Plant in Service 14 Production $293,589,78 $3,518,52 $ $ $297,17,76 15 Transmission 145,489,178 1,599, ,88,37 16 Distribution 116,297,35 116,297,35 17 General 24,37, ,371, Intangible 2,527, ,527,98 $ $482 $587,392, NET Utility Plant in Service 2 Utility Plant Held for Future Use $582,274,611 $ $ $ 15,145,571 (2,239,89) 28 12,95, Materials and Supplies 9,48, ,48, Fuel Stocks 5,824,626 (26,352,61) (1,34,452) 5,459, Construction Work in Progress 24 Prepayments 25 Customer Advances & Deposits 26 Cash Working Capital $13,813 $5,117, Accumulated Deferred Income Taxes (13,74,838) 28 Total Average Rate Base $46,35,382 $2,877,354 2,681,927 13,813 5,824,626 (8,997) (5,679,13) (191) (1,34,643) (553,994) $2,681,927 (31,736) ($594,75) 4,95,898 (13,736,573) $483,,588 12

27 OTTER TAIL POWER COMPANY Electric Utility State of Minnesota RATE BASE SCHEDULES SUMMARY OF APPROACHES AND ASSUMPTIONS USED IN DETERMINING AVERAGE UNADJUSTED RATE BASE FOR THE PROPOSED TEST YEAR Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule B-4, Page 1 of 1 The 216 Proposed Test Year is based on Otter Tails 216 budget prepared during third quarter 215. A 13-month average calculation is used for all rate base components except Accumulated Deferred Income Taxes (ADIT) which is calculated on a simple average of the beginning and end of year balances. Please refer to the direct testimony of Mr. Tyler Akerman for an explanation of why ADIT remains as a simple average calculation. 13

28 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES SUMMARY OF RATE BASE JURISDICTIONAL ALLOCATION FACTORS Docket No. E17/GR Exhibit (SDT-1) Financial Information Schedule B-5, page 1 of 5 Complies with Rule , Sub. E The allocation factors on this page were used to determine Minnesota jurisdictional rate base amounts for all of the years presented in these schedules. Accounts not on this page have been directly assigned to jurisdictions. Descriptions under the Allocation Factor column with a / means the first method was used in historic actual and projected, the method after the / is used in the test year. The following allocation factors are used to compute Minnesota jurisdictional amounts for Plant-in-Service, Accumulated Depreciation, Accumulated Deferred Income Tax and Construction Work in Progress. For a full description of each allocation factor, see OTP's Cost Allocation Procedure Manual for Jurisdictional and Class Cost of Service Studies, Mr. Stuart Tommerdahl's direct testimony, Exhibit (SDT-1), Schedule 6. Line No. Description Allocation Basis RATE BASE COMPONENT ALLOCATION FACTOR Electric Plant in Service Production Plant Base Demand Peak Demand Base Energy kwh Sales Factor (E1) Generation Demand Factor (D1) kwh Sales Factor (E1) 6 Transmission Plant Transmission Demand Factor (D2) Distribution Plant Primary Demand Secondary Demand Primary Customer Secondary Customer Street Lighting Area Lighting Meters Load Management Rental Equipment Distribution Primary Demand Factor (D3) Distribution Secondary Demand Factor (D4) Total Retail Service Locations Factor (C2) Total Secondary Retail Service Location Factor (C3) Streetlight Factor (C4) Area Light Factor (C5) Meter Factor (C6) Load Management Factor (C9) Direct Assignment (North Dakota only) General Plant Production Transmission Distribution Customer Accounts Customer Service & Info. Load Management Gross Production Plant in Service Ratio (P1) Gross Transmission Plant in Service Ratio (P5) Gross Distribution Plant in Service Ratio (P6) Customer Accounts Expense Ratio (OXC) Customer Service & Info, Expense Ratio (OXI) Load Management Factor (C9) Intangible Plant Production Transmission Distribution General Gross Production Plant in Service Ratio (P1) Gross Transmission Plant in Service Ratio (P5) Gross Distribution Plant in Service Ratio (P6) Gross General Plant in Service Ratio (P9) 29 Accumulated Provision for Depreciation 3 Production Plant 31 Base Demand 32 Peak Demand 33 Base Energy Direct Assignment/kwh Sales Factor (E1) Direct Assignment/Generation Demand Factor (D1) Base Energy Direct Assignment/kwh Sales Factor (E1) Transmission Plant Distribution Plant General Plant Direct Assignment/Transmission Demand Factor (D2) Direct Assignment/Gross Distribution Plant in Service Ratio (P6) Direct Assignment/Gross General Plant in Service Ratio (P9) 37 Intangible Plant Gross General Plant in Service Ratio (P9) 14

29 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES SUMMARY OF RATE BASE JURISDICTIONAL ALLOCATION FACTORS Complies with Rule , Sub. E Line No RATE BASE COMPONENT Electric Plant Held for Future Use Production Plant Base Demand Peak Demand Base Energy Docket No. E17/GR Exhibit (SDT-1) Financial Information Schedule B-5, page 2 of 5 ALLOCATION FACTOR kwh Sales Factor (E1) Generation Demand Factor (D1) kwh Sales Factor (E1) 6 Transmission Plant Transmission Demand Factor (D2) Distribution Plant Primary Demand Secondary Demand Primary Customer Secondary Customer Streetlighting Area Lighting Meters Distribution Primary Demand Factor (D3) Distribution Secondary Demand Factor (D4) Total Retail Service Locations Factor (C2) Total Secondary Retail Service Location Factor (C3) Streetlight Factor (C4) Area Light Factor (C5) Metering Factor (C6) General Plant Production Transmission Distribution Customer Accounts Customer Service & Info. Gross Production Plant in Service Ratio (P1) Transmission Demand Factor (D2) Gross Distribution Plant in Service Ratio (P6) Customer Accounts Expense Ratio (OXC) Customer Service & Info, Expense Ratio (OXI) Intangible Plant Production Transmission Distribution General Gross Production Plant in Service Ratio (P1) Gross Transmission Plant in Service Ratio (P5) Gross Distribution Plant in Service Ratio (P6) Gross General Plant in Service Ratio (P9) Unamortized Balance Spiritwood Plant Gross Production Plant in Service Ratio (P1) Construction Work in Progress Short Term Production Plant Base Demand Peak Demand Base Energy Transmission Plant Distribution Plant General Plant Intangible Plant kwh Sales Factor (E1) Generation Demand Factor (D1) kwh Sales Factor (E1) Transmission Demand Factor (D2) Gross Distribution Plant in Service Ratio (P6) Gross General Plant in Service Ratio (P9) Gross General Plant in Service Ratio (P9) 15

30 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES SUMMARY OF RATE BASE JURISDICTIONAL ALLOCATION FACTORS Complies with Rule , Sub. E Line No RATE BASE COMPONENT Construction Work in Progress Other Production Plant Base Demand Peak Demand Base Energy Transmission Plant Distribution Plant General Plant Intangible Plant 1 Materials and Supplies 11 Diesel Parts and Supplies 12 Big Stone and Coyote Plants 13 Base Demand 14 Peak Demand 15 All Other 16 Transmission 17 Distribution Docket No. E17/GR Exhibit (SDT-1) Financial Information Schedule B-5, page 3 of 5 ALLOCATION FACTOR kwh Sales Factor (E1) Generation Demand Factor (D1) kwh Sales Factor (E1) Transmission Demand Factor (D2) Gross Distribution Plant in Service Ratio (P6) Gross General Plant in Service Ratio (P9) Gross General Plant in Service Ratio (P9) Generation Demand Factor (D1) kwh Sales Factor (E1) Generation Demand Factor (D1) Transmission Demand Factor (D2) Gross Distribution Plant in Service Ratio (P6) 18 Fuel Stocks 19 Coal Stocks 2 Fuel Oil Stocks kwh Sales Factor (E1) Generation Demand Factor (D1) 21 Prepayments Total Net Plant in Service Ratio (NEPIS) 22 Cash Working Capital Separately Calculated by Jurisdiction 23 Accumulated Deferred Income Taxes 24 Items South Dakota flows through: 25 Federal 26 excluding South Dakota (NPMNR) 27 Minnesota 28 North Dakota 29 All Other: 3 Federal 31 Minnesota 32 North Dakota Total Net Plant in Service Ratio (NEPIS) Total Net Plant in Service MN Ratio (NPISM) Total Net Plant in Service ND Ratio (NPISN) Total Net Plant in Service Ratio (NEPIS) Total Net Plant in Service MN Ratio (NPISM) Total Net Plant in Service ND Ratio (NPISN) 16

31 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES RATE BASE JURISDICTIONAL ALLOCATION FACTORS Complies with Rule , Sub. E Allocators - Demand, Energy and Customer Docket No. E17/GR Exhibit (SDT-1) Financial Information Schedule B-5, page 4 of 5 Unadjusted Projected Fiscal Year 216 Line No. Item Factor Total Utility Minnesota All Other Proposed Test Year 216 Total Utility Minnesota All Other 1 2 MWH Consumption at Generators - Partial Percentage E1 4,732,173 1.% 2,583, % 2,148, % 4,732,173 1.% 2,583, % 2,148, % 3 4 MWH Consumption at Generators - Total Percentage E2 5,333,274 1.% 2,826, % 2,56, % 5,333,274 1.% 2,826, % 2,56, % 5 6 Generation Demand Factor Percentage D1 717,624 1.% 363, % 354, % 717,624 1.% 363, % 354, % 7 8 Transmission Demand Factor Percentage D2 722,695 1.% 363, % 359, % 722,695 1.% 363, % 359, % 9 Distribution - Primary Demand Factor 1 Percentage D3 897,668 1.% 4, % 496, % 897,668 1.% 4, % 496, % 11 Distribution - Secondary Demand Factor 12 Percentage D4 1,191,421 1.% 54, % 686, % 1,191,421 1.% 54, % 686, % C1 132,49 1.% 61, % 7, % 132,49 1.% 61, % 7, % 13 Customer or Meter Factors 14 Total Retail Customers 15 Percentage Retail Service Locations Percentage C2 137,725 1.% 64, % 73, % 137,725 1.% 64, % 73, % Secondary Service Locations Percentage C3 138,339 1.% 64, % 73, % 138,339 1.% 64, % 73, % 2 21 Street Lighting Factor Percentage C4 4,982,666 1.% 2,276, % 2,75, % 4,982,666 1.% 2,276, % 2,75, % Area Lighting Factor Percentage C5 4,348,944 1.% 1,836, % 2,512, % 4,348,944 1.% 1,836, % 2,512, % Meter Factor Percentage C6 5,657,26 1.% 23,311, % 27,345, % 5,657,26 1.% 23,311, % 27,345, % Meter Reading Factor Percentage C7 179,997 1.% 87, % 92, % 179,997 1.% 87, % 92, % System Service Locations Percentage C8 138,439 1.% 64, % 73, % 138,439 1.% 64, % 73, % 3 31 Load Management Factor Percentage C9 42,624 1.% 2, % 22, % 42,624 1.% 2, % 22, % 17

32 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE BASE SCHEDULES RATE BASE JURISDICTIONAL ALLOCATION FACTORS Complies with Rule , Sub. E Allocators - General Plant, Operation and Maintenance Expense and Taxes Docket No. E17/GR Exhibit (SDT-1) Financial Information Schedule B-5, page 5 of 5 Unadjusted Projected Fiscal Year 216 Line No. Item Factor Total Utility Minnesota All Other Proposed Test Year 216 Total Utility Minnesota All Other 1 2 Production Plant Percentage P1 884,52,468 1.% 471,279, % 412,773, % 89,939,94 1.% 474,971, % 415,967, % 3 4 Distribution Plant Percentage P6 459,399,544 1.% 26,471, % 252,928, % 459,399,544 1.% 26,471, % 252,928, % 5 6 General Plant Percentage P9 88,637,981 1.% 43,72, % 44,917, % 88,637,982 1.% 43,721, % 44,916, % Electric Plant in Service Percentage EPIS 1,843,59,414 1.% 928,153, % 915,437, % 1,853,846,219 1.% 933,541, % 92,34, % 9 Net Electric Plant in Service 1 Percentage NEPIS 1,153,372,27 1.% 582,274, % 571,97, % 1,163,112,485 1.% 587,392, % 575,72, % OXPD 25,511,349 1.% 13,65, % 11,861, % 25,511,349 1.% 13,65, % 11,861, % Operation and Maintenance Expense 12 Production Expense (Excl Energy) 13 Percentage Distribution Expense Percentage OXD 16,729,447 1.% 7,594, % 9,135, % 16,729,447 1.% 7,594, % 9,135, % Customer Accounts Expense Percentage OXC 13,873,333 1.% 6,565, % 7,38, % 13,873,333 1.% 6,565, % 7,38, % Customer Service & Information Expense Percentage OXI 3,8,448 1.% 1,42, % 1,65, % 3,8,448 1.% 1,42, % 1,65, % Other Deferred Income Tax Factor Minnesota Percentage NPISM 586,351,671 1.% 582,274, % 4,77, % 591,52,272 1.% 587,392, % 4,19, % North Dakota Percentage NPISN 463,291,386 1.%.% 463,291,386 1.% 467,23,963 1.%.% 467,23,963 1.% Excluding South Dakota Percentage NPMNR 1,49,643,57 1.% 582,274, % 467,368, % 1,58,526,235 1.% 587,392, % 471,133, % CWIPLT 27,31,141 1.% 13,775, % 13,525, % 23,76,826 1.% 11,535, % 11,54, % Long-Term CWIP Ratio (W/AFDC) Percentage 29 3 Revenue Percentage R1 274,899,211 1.% 131,666, % 143,232, % 276,232,482 1.% 132,86, % 143,425, % Labor and Related Expense Percentage LRE 141,451,589 1.% 73,27, % 68,424, % 122,953,57 1.% 63,843, % 59,11, % 18

33 Volume 3 C. Operating Income Schedules (Rule ) 1/3

34 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME SCHEDULES Docket No. E17/GR Financial Information Page 1 of 1 MINNESOTA RULE OPERATING INCOME SCHEDULES. The following rate of return cost of capital schedules as required by part shall be filed: A. A summary schedule of jurisdictional operating income statements which reflect proposed test year operating income, and unadjusted jurisdictional operating income for the most recent fiscal year and the projected fiscal year calculated using present rates. B. For multijurisdictional utilities only, a schedule showing the comparison of total utility and unadjusted jurisdictional operating income statement for the test year, for the most recent fiscal year and the projected fiscal year. In addition, the schedule shall provide the proposed adjustments, if any, to jurisdictional operating income for the test year together with the proposed operating income statement. C. For investor-owned utilities only, a summary schedule showing the computation of total utility and allocated Minnesota jurisdictional federal and state income tax expense and deferred income taxes for the test year, the most recent fiscal year, and the projected fiscal year. This summary schedule shall be supported by a detailed schedule, showing the development of the combined federal and state income tax rates. D. A summary schedule of adjustments, if any, to jurisdictional test year operating income and detailed schedules for each adjustment providing an adjustment title, purpose and description of the adjustment, and summary calculations. E. A schedule summarizing the assumptions made and the approaches used in projecting each major element of operating income. Such assumptions and approaches shall be identified and quantified into two categories: known changes from the most recent fiscal year and projected changes. F. For multijurisdictional utilities only, a schedule providing, by operating income element, the factor or factors used in allocating total utility operating income to Minnesota jurisdiction. This schedule shall be supported by a schedule which sets forth the statistics used in determining each jurisdictional allocation factor for the test year, the most recent fiscal year, and the projected fiscal year. STAT AUTH: MS s 216B.3; 216B.8; 216B.16 Current as of 1/2/5 1

35 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME SCHEDULES JURISDICTIONAL STATEMENT OF OPERATING INCOME Complies with Rules , Sub. A. Line No. Description Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule C-1, Page 1 of 1 (A) Unadjusted Fiscal Year 214 (B) Unadjusted Most Recent Fiscal Year 215 (C) Unadjusted Projected Fiscal Year 216 (D) Proposed Test Year 216 OPERATING REVENUES 1 Retail Revenue 2 Other Electric Operating Revenue 3 TOTAL OPERATING REVENUE $174,274,469 $183,471,648 $196,817,16 $196,817,16 13,664,655 16,169,898 17,24,816 7,177,664 $187,939,124 $199,641,546 $214,57,975 $23,994,824 $76,815,48 $78,391,366 $87,59,992 $87,59,992 OPERATING EXPENSES 4 Production Expenses 5 Transmission Expenses 11,815,61 13,566,642 17,367,755 8,91,378 6 Distribution Expenses 7,343,382 6,512,46 7,594,39 7,594,39 7 Customer Accounting Expenses 6,341,243 5,684,636 6,565,33 6,565,33 8 Customer Service and Information Expenses 6,35,925 6,827,21 7,297,375 7,297,375 9 Sales Expenses 23,86 113,25 18,214 18,214 1 Administration and General Expenses 18,513,92 19,157,351 2,552,799 2,645,66 11 Charitable Contributions 187,789 13,27 93,27 93,27 12 Depreciation Expense 2,723,775 21,389,728 26,484,872 27,39, General Taxes 5,932,582 6,665,32 7,325,55 7,327, TOTAL OPERATING EXPENSES $154,227,64 $158,41,657 $18,448,16 $171,821,636 $33,711,52 $41,23,889 $33,69,816 $32,173,187 ($4,34,77) ($4,58,451) ($4,59,538) 15 NET OPERATING INCOME BEFORE INCOME TAXES 16 INCOME TAX EXPENSE 17 Investment Tax Credits ($4,449,378) 18 Deferred Income Taxes 6,863,73 25,889,188 3,23,513 3,23, Income Taxes 2,664,132 (11,686,895) 7,328,359 6,485,488 2 TOTAL INCOME TAX EXPENSE $5,78,457 $9,861,586 $6,23,421 $5,179,613 $28,633,63 $31,369,33 $27,586,395 $26,993, ,289 1,418, , ,547 $29,626,352 $32,788,88 $28,44,532 $27,665, NET OPERATING INCOME 22 Allowance for Funds Used During Construction 23 TOTAL AVAILABLE FOR RETURN 2

36 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME SCHEDULES STATEMENT OF OPERATING INCOME Complies with Rules , Sub. B. Line No. Description Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule C-2, Page 1 of 1 (A) (B) Undadjusted Actual Fiscal Year 214 Total MN Utility Jurisdiction (C) (D) Undadjusted Actual Fiscal Year 215 Total MN Utility Jurisdiction (E) (F) Unadjusted Projected Fiscal Year 216 Total MN Utility Jurisdiction OPERATING REVENUES 1 Retail Revenue 2 Other Electric Operating Revenue 3 TOTAL OPERATING REVENUE $353,733,792 $174,274,469 $363,251,415 $183,471,648 $383,432,734 32,349,44 13,664,655 38,246,312 16,169,898 45,465,285 $196,817,16 17,24,816 $386,83,196 $187,939,124 $41,497,727 $199,641,546 $428,898,18 $214,57,975 OPERATING EXPENSES 4 Production Expenses $156,117,384 $76,815,48 $152,351,386 $78,391,366 $164,41,287 $87,59,992 5 Transmission Expenses 25,299,348 11,815,61 28,687,233 13,566,642 34,92,778 17,367,755 6 Distribution Expenses 16,511,225 7,343,382 14,78,651 6,512,46 16,729,447 7,594,39 7 Customer Accounting Expenses 13,358,146 6,341,243 11,977,91 5,684,636 13,873,333 6,565,33 8 Customer Service and Information Expenses 8,29,7 6,35,925 8,376,47 6,827,21 9,255,857 7,297,375 9 Sales Expenses 411,586 23,86 179, ,25 24,697 18,214 1 Administration and General Expenses 39,61,4 18,513,92 4,37,78 19,157,351 41,551,498 2,552, Charitable Contributions 12 Depreciation Expense 13 General Taxes 14 TOTAL OPERATING EXPENSES 15 NET OPERATING INCOME BEFORE INCOME TAXES 187, ,789 13,27 13,27 93,27 93,27 43,576,384 2,723,775 44,94,99 21,389,728 52,238,513 26,484,872 12,599,569 5,932,582 13,85,913 6,665,32 14,59,53 7,325,55 $315,151,441 $154,227,64 $314,637,598 $158,41,657 $347,399,94 $18,448,16 $7,931,754 $33,711,52 $86,86,129 $41,23,889 $81,498,78 $33,69, INCOME TAX EXPENSE 17 Investment Tax Credits ($9,421,258) ($4,449,378) ($9,4,785) ($4,34,77) ($8,955,134) ($4,58,451) 18 Deferred Income Taxes 12,612,371 6,863,73 51,811,679 25,889,188 4,429,588 3,23, Income Taxes 5,994,753 2,664,132 (25,37,95) (11,686,895) 19,18,356 7,328,359 2 TOTAL INCOME TAX EXPENSE $9,185,866 $5,78,457 $17,498,988 $9,861,586 $14,582,81 $6,23,421 $61,745,888 $28,633,63 $69,361,141 $31,369,33 $66,915,268 $27,586,395 2,232, ,289 2,111,695 1,418,785 1,621, ,137 $63,978,66 $29,626,352 $71,472,836 $32,788,88 $68,536,696 $28,44, NET OPERATING INCOME 22 Allowance for Funds Used During Construction 23 TOTAL AVAILABLE FOR RETURN 3

37 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME SCHEDULES STATEMENT OF OPERATING INCOME - PROPOSED TEST YEAR Complies with Rules , Sub. B. Line No. Description Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule C-3, Page 1 of 1 (A) Unadjusted Total Utility (B) (C) Proposed Test Year 216 Unadjusted MN Jurisdiction Adjustments (D) Proposed MN Jurisdiction OPERATING REVENUES 1 Retail Revenue 2 Other Electric Operating Revenue 3 TOTAL OPERATING REVENUE $383,432,734 $196,817,16 45,465,285 17,24,816 (1,63,151) $ $196,817,16 7,177,664 $428,898,18 $214,57,975 ($1,63,151) $23,994,824 OPERATING EXPENSES 4 Production Expenses $164,41,287 $87,59,992 5 Transmission Expenses 34,92,778 17,367,755 6 Distribution Expenses 16,729,447 7,594,39 7,594,39 7 Customer Accounting Expenses 13,873,333 6,565,33 6,565,33 8 Customer Service and Information Expenses 9,255,857 7,297,375 7,297,375 9 Sales Expenses 1 Administration and General Expenses 11 Charitable Contributions 93,27 93,27 93,27 12 Depreciation Expense 52,238,513 26,484, ,86 27,39, General Taxes 14,59,53 7,325,55 2,5 7,327, TOTAL OPERATING EXPENSES $347,399,94 $18,448,16 ($8,626,523) $171,821,636 $81,498,78 $33,69,816 ($1,436,628) $32,173, NET OPERATING INCOME BEFORE INCOME TAXES $ (9,276,377) $87,59,992 8,91,378 24,697 18,214 18,214 41,551,498 2,552,799 92,268 2,645,66 16 INCOME TAX EXPENSE 17 Investment Tax Credits ($8,955,134) ($4,58,451) 18 Deferred Income Taxes 4,429,588 3,23, Income Taxes 2 TOTAL INCOME TAX EXPENSE 21 NET OPERATING INCOME 22 Allowance for Funds Used During Construction 23 TOTAL AVAILABLE FOR RETURN ($1,87) 15 ($4,59,538) 3,23,663 19,18,356 7,328,359 (842,871) 6,485,488 $14,582,81 $6,23,421 ($843,87) $5,179,613 $66,915,268 $27,586,395 ($592,821) $26,993,574 1,621, ,137 (146,589) 671,547 $68,536,696 $28,44,532 ($739,41) $27,665,121 4

38 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME SCHEDULES COMPUTATION OF FEDERAL AND STATE INCOME TAXES Complies with Rules , Sub. C. Line No. Description Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule C-4, Page 1 of 1 (A) (B) Total Utility Unadjusted Fiscal Year 214 (C) (D) Unadjusted Most Recent Fiscal Year 215 Total MN Utility Jurisdiction MN Jurisdiction (E) (G) (F) Unadjusted Projected Fiscal Year 216 Total MN Utility Jurisdiction (H) Proposed Test Year 216 MN Jurisdiction Total Utility 1 Income Before Taxes Total Operating Revenues $386,83,196 $187,939,124 $41,497,727 $199,641,546 $428,898,18 $214,57,975 $48,96,451 $23,994,824 2 Less: Total Operating Expenses (258,975,489) (127,571,247) (256,691,775) (13,355,896) (28,651,924) (146,638,233) (262,153,841) (137,454,124) (27,39,957) 3 Book Depreciation & Amortization (43,576,384) (2,723,775) (44,94,99) (21,389,728) (52,238,513) (26,484,872) (53,324,389) 4 Taxes Other Than Income (12,599,569) (5,932,582) (13,85,913) (6,665,32) (14,59,53) (7,325,55) (14,59,53) (7,327,555) 5 Interest Cost (2,984,589) (11,312,719) (21,982,481) (11,626,22) (25,468,477) (12,6,923) (26,74,661) (12,66,315) $49,947,165 $22,398,81 $64,877,648 $29,64,687 $56,29,61 $21,62,892 $52,268,56 $19,566,872 6 Total Before Tax Book Income Tax Additions 7 Additional Tax Depreciation 8 Directly Assigned Schedule M Items 9 Accrued Vacation Pay 1 Provisions - Operating Reserves 11 Other Schedule M Items 12 Total Tax Additions $ 218,926 $ 218,926 $ 136,439 $ 136,439 $ 126,196 $ 126,196 $ 126,196 $ 126,196 7,349,436 3,46,526 6,149,211 2,958,988 5,53,5 2,778,416 5,53,5 2,779,365 $7,568,362 $3,679,452 $6,285,65 $3,95,427 $5,629,696 $2,94,612 $5,629,696 $2,95,561 $131,252,821 $63,158,6 Tax Deductions 13 Additional Tax Depreciation 14 Cost to Remove 15 Accrued Vacation Pay 16 Charges - Operating Reserves 17 Preferred Dividends Paid Credit $19,782,186 $9,314,56 2,95,739 1,368,185 4,566,667 2,197,471 $1,771,378 5, $894, ,423 $1,771,378 5, $894, ,777 3,772 6,436,4 3,3,448 3,771,36 1,814,771 1,766, ,93 1,766, ,28 252,59 18 Other Schedule M Items 13,353,44 6,287,53 5,831,817 2,86,259 9,69,745 4,578,818 9,69,745 4,58, Total Tax Deductions $43,116,145 $2,31,494 $69,977,11 $13,17,81 $6,617,417 $13,17,81 $6,619,675 2 MN Adjustments to Federal Schedule M; MN Jurisdiction (4,28,977) $145,422,665 (58,53,916) 1,239,336 1,239, State Taxable Income $14,399,381 $9,985,736 ($74,259,366) $21,253,93 $48,551,488 $16,65,752 $44,789,943 $14,612, State Income Tax Rate 1.2% 9.8% -1.41% 9.8% 6.7% 9.8% 6.7% 9.8% $1,469,184 $988,12 $1,5,574 $2,92,385 $3,254,362 $1,641,274 $2,999,289 $1,441, Total State Income Taxes & Minimum Fee per statute ($9,5 in 214) 25 Federal Taxable Income Addback of MN Adjustments to Federal Schedule M; 26 MN Jurisdiction 27 Adjusted Federal Taxable Income 28 Federal Income Tax Rate $12,93,198 $12,93, % $8,997,633 (4,28,977) $4,788, % ($75,39,94) $45,297,125 $15,9,478 $41,79,654 $13,171,425 (58,53,916) 1,239,336 1,239,759 ($75,39,94) ($39,369,371) $45,297,125 $16,248,814 $41,79,654 $14,411, % 35.% $19,161, % 35.% 35.% 35.% 29 Total Federal Income Taxes $4,525,569 $1,676,3 ($26,358,479) ($13,779,28) $15,853,994 $5,687,85 $14,626,729 $5,43,914 3 Total State and Federal Income Tax $5,994,753 $2,664,132 ($25,37,95) ($11,686,895) $19,18,356 $7,328,359 $17,626,18 $6,485,488 5

39 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME SCHEDULES COMPUTATION OF DEFERRED INCOME TAXES Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule C-5, Page 1 of 1 (A) Line No. Description 1 Excess Tax Over Book Pensions 2 Excess Tax Over Book Depreciation 3 Capitalized A&G Expenses 4 Provisions for Operating Reserves in Excess of Actual Charges 5 Other Capitalized Items 6 TOTAL Deferred Income Taxes Total Utility $ (B) (C) (D) Unadjusted Most Recent Fiscal Year 215 Total MN Utility Jurisdiction Unadjusted Fiscal Year 214 6,22,547 MN Jurisdiction $ 58,585 $ 836,465 $ $ 1,394, ,744 1,219,456 47,526, , ,53 56,894 6,816,363 39,35 (46,59) (71,441) (3,26,283) $12,79, ,423 $2,739,917 (2,381,423) $51,798,222 (132,676) (G) (F) Unadjusted Projected Fiscal Year 216 Total MN Utility Jurisdiction 12,318 1,67,633 (999,428) (E) $ (H) Proposed Test Year 216 Total MN Utility Jurisdiction 487,334 $ 1,394, , ,744 $ 487, ,196 (1,462,72) (789,385) (1,462,72) (789,597) 1,965,72 3,613,68 $2,66,115 $4,429,588 $ 2,531,571 3,613,68 2,531,618 3,23,513 $4,429,588 $ 3,23,663 6

40 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME SCHEDULES DEVELOPMENT OF FEDERAL AND STATE INCOME TAX RATES Unadjusted Fiscal Year 214 Unadjusted Most Recent Fiscal Year 215 Unadjusted Projected Fiscal Year 216 Proposed Test Year 216 Let: Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule C-6, Page 1 of 1 F=Federal Income Tax 35.% M=Minnesota State Income Tax Rate = 9.8% D=North Dakota State Income Tax Rate = 4.31% S=South Dakota Income Tax Rate =.% N=Net Income After Interest Deductions but Before Income Taxes Jurisdictional: Only Minnesota and Federal Income Taxes M= 9.8% (N) F= 31.57% (N) M+F= 41.37% (N) Only North Dakota and Federal Income Taxes D= 4.31% (N) F= 33.49% (N) D+F= 37.8% (N) Only South Dakota and Federal Income Taxes S=.% (N) F= 35.% (N) S+F= 35.% (N) Composite: Combined Minnesota, North Dakota, South Dakota and Federal Income Taxes. M+D+S+F= 39.1% (N) Notes: 1 Investment tax credits and surtax credits are ignored. 2 State income taxes are deductible from federal taxable income. Federal income tax is deductible only from North Dakota's taxable income. 3 Net income is defined at each jurisdictional level. 4 Composite income tax rates are determined by the Income Tax Department based upon apportionment laws (unitary and nonunitary) for each state involved. 7

41 E17/GR Exhibit (TAA-1) Financial Information Schedule C-7, Page 1 of 1 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME STATEMENT SCHEDULES OPERATING INCOME STATEMENT ADJUSTMENTS SCHEDULE Line No. Description PROJECTED CHANGES 216 Unadjusted Base Data Rate Case Expense Normalized Plant in Service Big Stone II KPA Normalized Changes in Allocations due to Effect of Test Year Adjustments TCR MISO Removal 216 Proposed Test Year OPERATING REVENUES 1 Retail Revenue 2 Other Electric Operating Revenue 3 TOTAL OPERATING REVENUE $196,817,16 $ $ $ $ 17,24,816 (1,68,823) $ 5,672 $ $196,817,16 $214,57,975 $ $ $ $ ($1,68,823) $5,672 $23,994,824 $ $ $87,59,992 (9,276,377) 8,91,378 7,594,39 7,177,664 OPERATING EXPENSES 4 Production Expenses $87,59,992 $ $ $ $ 5 Transmission Expenses 17,367,755 6 Distribution Expenses 7,594,39 7 Customer Accounting Expenses 6,565,33 6,565,33 8 Customer Service and Information Expenses 7,297,375 7,297,375 9 Sales Expenses 18,214 1 Administration and General Expenses 2,552, , Charitable Contributions 12 Depreciation Expense 13 General Taxes 14 TOTAL OPERATING EXPENSES 15 NET OPERATING INCOME BEFORE INCOME TAXES (143,496) 93,27 26,484, , ,376 7,325,55 $18,448,16 $234,757 $176,669 $378,376 ($143,496) ($234,757) ($176,669) ($378,376) $143,496 $33,69,816 ($9,276,377) ($792,447) 1,7 4 18,214 2,645,66 93,27 27,39,957 2,5 7,327,555 $3,547 $171,821,636 $2,124 $32,173,187 ($1,87) ($4,59,538) 16 INCOME TAX EXPENSE 17 Investment Tax Credits ($4,58,451) $ $ $ $ $ 18 Deferred Income Taxes 3,23, Income Taxes 7,328,359 (97,119) (73,88) (156,534) 59,364 (327,835) (247,659) 6,485,488 2 TOTAL INCOME TAX EXPENSE $6,23,421 ($97,119) ($73,88) ($156,534) $59,364 ($327,835) ($248,595) $5,179,613 $27,586,395 (137,638) ($13,581) ($221,842) $84,132 ($464,611) $25,72 $26,993, NET OPERATING INCOME 22 Allowance for Funds Used During Construction 23 TOTAL AVAILABLE FOR RETURN 818,137 $28,44,532 ($137,638) (138,987) ($242,568) ($221,842) $84,132 ($464,611) 15 (7,62) $243,118 3,23, ,547 $27,665,121 8

42 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME STATEMENT SCHEDULES DESCRIPTION OF DETAILS Summary of Approach used and Assumptions Made to the Operating Statements Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule C-8, Page 1 of 1 Proposed Test Year 216 Item of Operating Income Narration Operating Revenues Revenue for the 216 Proposed Test Year is forecasted revenue. Revenues were then pro formed for known and measurable changes as listed in schedule C-7 for the following adjustments: rate case expenses, normalized plant in service, Big Stone II, KPA normalized, and the removal of TCR MISO dollars. Operating Expenses Expenses for the Proposed Test Year were developed by first using allocated expenses for the period. Jurisdicational Allocation methodologies are discussed in Exhibit (TAA-1), Schedule 2. These expenses were then pro formed for known and measurable changes as listed in Schedule C-7. Refer to Schedule C-9 (all pages) for more details on how costs were allocated to Minnesota Depreciation and Amortization Expense Depreciation and Amortization Expenses for the Proposed Test Year were developed by first using allocated (Jurisdicational Allocation methodologies are discussed in Exhibit (TAA-1), Schedule 2) expenses for the period. These expenses were then pro formed for known and measurable changes as listed in Schedule C-7. Taxes Other Than Income Taxes Other Than Income Taxes for the Proposed Test Year were developed by using expenses as allocated (Jurisdicational Allocation methodologies are discussed in Exhibit (TAA-1), Schedule 2) for the period. These expenses were then pro formed for known and measurable changes as listed in Schedule C-7. Federal and State Income Taxes Current taxes are determined by taking "Operating Income Before Taxes" for the jurisdiction and reducing it by the jurisdictional "Schedule M's" and interest expense (using the interst synchronization method) to arrive at taxable income. Current taxes are then computed using jurisdictional tax rates. 9

43 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME STATEMENT SCHEDULES OPERATING INCOME STATEMENT ALLOCATION FACTORS Docket No. E17/GR Exhibit (SDT-1) Financial Information Schedule C-9, page 1 of 5 The allocation factors on this page were used to determine Minnesota jurisdictional rate base amounts for all of the years presented in these schedules. Accounts not on this page have been directly assigned to jurisdictions. Descriptions under the Allocation Factor column with a / means the first method was used in historic actual and projected, the method after the / is used in the test year. The following allocation factors are used to compute Minnesota jurisdictional amounts for Expenses as listed below. For a full description of each allocation factor, see OTP's Cost Allocation Procedure Manual for Jurisdictional and Class Cost of Service Studies, Mr. Stuart Tommerdahl's direct testimony, Exhibit (SDT-1), Schedule 6. Line No. Description Allocation Basis ELEMENT OF OPERATING INCOME 1 Operating Revenues 2 Sales of Electricity 3 Other Operating Revenues 4 Asset Based Sales 5 Municipalities Other Electric Revenue Residential Conservation Services Forfeited Discounts Connection Fees Wheeling Income - Rent Integrated Transmission Agreements Load Control and Dispatch (also MISO Trans Rev.) All Other Loan Pool Interest 16 Operating Expenses 17 Production Expenses 18 Asset-based Sales 19 Production and Purchase Expenses 2 Base Demand 21 Peak Demand 22 Base Energy 23 Peak Energy Direct Assignment kwh Sales Factor (E2) Direct Assignment (FERC only) Direct Assignment Direct Assignment Direct Assignment Direct Assignment (FERC only) Total Net Plant in Service Ratio (NEPIS) Total Net Plant in Service Ratio (NEPIS) Total Net Plant in Service Ratio (NEPIS) Total Net Plant in Service Ratio (NEPIS) Directly assigned to Jurisdiction kwh Sales Factor (E2) kwh Sales Factor (E1) Generation Demand Factor (D1) kwh Sales Factor (E2) Generation Demand Factor (D1) 24 Transmission Expenses Transmission Demand Factor (D2) Distribution Expenses Primary Demand Secondary Demand Primary Custaaer Secondary Customer Streetlighting Area Lighting Meters Load Management Expenses Distribution Primary Demand Factor (D3) Distribution Secondary Demand Factor (D4) Total Retail Service Locations Factor (C2) Total Secondary Retail Service Locations Factor (C3) Streetlight Factor (C4) Area Light Factor (C5) Meter Factor (C6) Load Management Factor (C9) Customer Accounts Expenses Meter Reading Other Meter Reading Factor (C7) Total System Serv Locations Factor (C8) 1

44 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME STATEMENT SCHEDULES OPERATING INCOME STATEMENT ALLOCATION FACTORS Line No. Description Docket No. E17/GR Exhibit (SDT-1) Financial Information Schedule C-9, page 2 of 5 Allocation Basis ELEMENT OF OPERATING INCOME ALLOCATION FACTOR Operating Expenses - continued Customer Service & Informational Expenses Conservation & Promotional Rebates All Other Direct Assignment then E2 Total Retail Customers Factor (C1) Sales Expenses Off-Peak Development All Other Direct Assignment Total Retail Customers Factor (C1) Administrative and General Expenses A & G Salaries, Office Supplies & Exp., & Employee Pensions & Benefits Production 28 Charitable Contributions Direct Assignment Depreciation Expenses Production Base Demand Peak Demand Base Energy Transmission Distribution General Intangible kwh Sales Factor (E1) Generation Demand Factor (D1) kwh Sales Factor (E1) Transmission Demand Factor (D2) P6 General Plant in Service Ratio (P9) General Plant in Service Ratio (P9) General Taxes Other Expense Total Net Plant in Service Ratio (NEPIS) Gross Production Plant in Service Ratio (P1) Transmission Distribution Customer Accounts Customer Service & Informational Load Management Expenses Outside Services Property Insurance Injuries and Damages Regulatory Commission Expenses General Advertising Miscellaneous General Expenses, Rents and Maintenance of General Plant Production Expense Ratio (Excl. Energy Related) (OXPD) Transmission Expense Ratio (D2) Distribution Expense Ratio (OXD) Customer Accounts Expense Ratio (OXC) Customer Service & Informational Expense (C1) Ratio (OXI) Load Management Factor (C9) Total Net Plant in Service Ratio (NEPIS) Total Net Plant in Service Ratio (NEPIS) Total Net Plant in Service Ratio (NEPIS) Direct Assignment Total Retail Customers Factor (C1) General Plant in Service Ratio (P9) 11

45 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME STATEMENT SCHEDULES OPERATING INCOME STATEMENT ALLOCATION FACTORS Line No. Description ELEMENT OF OPERATING INCOME Operating Expenses - continued Investment Tax Credit Amortization of Prior Years Credits Debits Utilized Adjustments Deferred Income Tax Expense Items South Dakota flows through: Federal Minnesota North Dakota All Other: Federal Minnesota North Dakota Income Taxes Federal Income Taxes Minnesota Income Taxes North Dakota Income Taxes Allowance for Funds Used During Construction Docket No. E17/GR Exhibit (SDT-1) Financial Information Schedule C-9, page 3 of 5 Allocation Basis ALLOCATION FACTOR Total Gross Plant in Service Ratio (EPIS) Federal Income Taxes Before Credits (FITBC) Total Gross Plant in Service Ratio (EPIS) Total Net Plant in Service Ratio excluding South Dakota (NPMNR) Total Net Plant in Service - MN Ratio (NPISM) Total Net Plant in Service - ND Ratio (NPISN) Total Net Plant in Service Ratio (NEPIS) Total Net Plant in Service - MN Ratio (NPISM) Total Net Plant in Service - ND Ratio (NPISN) Separately Calculated by Jurisdiction State Income Tax Factor (ROOM) State Income Tax Factor (ROON) Other Construction Work in Progress Ratio (CWIP Accruing AFDC) (CWIPO) NOTE: See Schedule B-6 for the values for the allocation factors 12

46 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME STATEMENT SCHEDULES OPERATING INCOME JURISDICTIONAL ALLOCATION FACTOR AMOUNTS Docket No. E17/GR Exhibit (SDT-1) Financial Information Schedule C-9, page 4 of 5 Allocators - Demand, Energy and Customer Line No. Item Unadjusted Projected Fiscal Year 216 Factor Total Utility Minnesota All Other Proposed Test Year 216 Total Utility Minnesota All Other 1 2 MWH Consumption at Generators - Partial Percentage E1 4,732,173 1.% 2,583, % 2,148, % 4,732,173 1.% 2,583, % 2,148, % 3 4 MWH Consumption at Generators - Total Percentage E2 5,333,274 1.% 2,826, % 2,56, % 5,333,274 1.% 2,826, % 2,56, % 5 6 Generation Demand Factor Percentage D1 717,624 1.% 363, % 354, % 717,624 1.% 363, % 354, % 7 8 Transmission Demand Factor Percentage D2 722,695 1.% 363, % 359, % 722,695 1.% 363, % 359, % 9 Distribution - Primary Demand Factor 1 Percentage D3 897,668 1.% 4, % 496, % 897,668 1.% 4, % 496, % 11 Distribution - Secondary Demand Factor 12 Percentage D4 1,191,421 1.% 54, % 686, % 1,191,421 1.% 54, % 686, % C1 132,49 1.% 61, % 7, % 132,49 1.% 61, % 7, % 13 Customer or Meter Factors 14 Total Retail Customers 15 Percentage Retail Service Locations Percentage C2 137,725 1.% 64, % 73, % 137,725 1.% 64, % 73, % Secondary Service Locations Percentage C3 138,339 1.% 64, % 73, % 138,339 1.% 64, % 73, % 2 21 Street Lighting Factor Percentage C4 4,982,666 1.% 2,276, % 2,75, % 4,982,666 1.% 2,276, % 2,75, % Area Lighting Factor Percentage C5 4,348,944 1.% 1,836, % 2,512, % 4,348,944 1.% 1,836, % 2,512, % Meter Factor Percentage C6 5,657,26 1.% 23,311, % 27,345, % 5,657,26 1.% 23,311, % 27,345, % Meter Reading Factor Percentage C7 179,997 1.% 87, % 92, % 179,997 1.% 87, % 92, % System Service Locations Percentage C8 138,439 1.% 64, % 73, % 138,439 1.% 64, % 73, % 3 31 Load Management Factor Percentage C9 42,624 1.% 2, % 22, % 42,624 1.% 2, % 22, % 13

47 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota OPERATING INCOME STATEMENT SCHEDULES OPERATING INCOME JURISDICTIONAL ALLOCATION FACTOR AMOUNTS Docket No. E17/GR Exhibit (SDT-1) Financial Information Schedule C-9, page 5 of 5 Allocators - General Plant, Operation and Maintenance Expense and Taxes Unadjusted Projected Fiscal Year 216 Line No. Item Factor Total Utility Minnesota All Other Proposed Test Year 216 Total Utility Minnesota All Other 1 2 Production Plant Percentage P1 884,52,468 1.% 471,279, % 412,773, % 89,939,94 1.% 474,971, % 415,967, % 3 4 Distribution Plant Percentage P6 459,399,544 1.% 26,471, % 252,928, % 459,399,544 1.% 26,471, % 252,928, % 5 6 General Plant Percentage P9 88,637,981 1.% 43,72, % 44,917, % 88,637,982 1.% 43,721, % 44,916, % Electric Plant in Service Percentage EPIS 1,843,59,414 1.% 928,153, % 915,437, % 1,853,846,219 1.% 933,541, % 92,34, % 9 Net Electric Plant in Service 1 Percentage NEPIS 1,153,372,27 1.% 582,274, % 571,97, % 1,163,112,485 1.% 587,392, % 575,72, % OXPD 25,511,349 1.% 13,65, % 11,861, % 25,511,349 1.% 13,65, % 11,861, % Operation and Maintenance Expense 12 Production Expense (Excl Energy) 13 Percentage Distribution Expense Percentage OXD 16,729,447 1.% 7,594, % 9,135, % 16,729,447 1.% 7,594, % 9,135, % Customer Accounts Expense Percentage OXC 13,873,333 1.% 6,565, % 7,38, % 13,873,333 1.% 6,565, % 7,38, % Customer Service & Information Expense Percentage OXI 3,8,448 1.% 1,42, % 1,65, % 3,8,448 1.% 1,42, % 1,65, % Other Deferred Income Tax Factor Minnesota Percentage NPISM 586,351,671 1.% 582,274, % 4,77, % 591,52,272 1.% 587,392, % 4,19, % NPISN 463,291,386 1.%.% 463,291,386 1.% 467,23,963 1.%.% 467,23,963 1.% NPMNR 1,49,643,57 1.% 582,274, % 467,368, % 1,58,526,235 1.% 587,392, % 471,133, % CWIPLT 27,31,141 1.% 13,775, % 13,525, % 23,76,826 1.% 11,535, % 11,54, % North Dakota Percentage Excluding South Dakota Percentage Long-Term CWIP Ratio (W/AFDC) Percentage 29 3 Revenue Percentage R1 274,899,211 1.% 131,666, % 143,232, % 276,232,482 1.% 132,86, % 143,425, % Labor and Related Expense Percentage LRE 141,451,589 1.% 73,27, % 68,424, % 122,953,57 1.% 64,136, % 58,816, % 14

48 Volume 3 D. Rate of Return Cost of Capital Schedules (Rule ) 1/3

49 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota Docket No. E17/GR Financial Information RATE OF RETURN COST OF CAPITAL SCHEDULES MINNESOTA RULE RATE OF RETURN COST OF CAPITAL SCHEDULES. The following rate of return cost of capital schedules as required by part shall be filed: A. A rate of return cost of capital summary schedule showing the calculation of the weighted cost of capital using the proposed capital structure and the average capital structures for the most recent fiscal year and the projected fiscal year. This information shall be provided for the unconsolidated parent and subsidiary corporations, or for the consolidated parent corporation. B. Supporting schedules showing the calculation of the embedded cost of long-term debt, if any, and the embedded cost of preferred stock, if any, at the end of the most recent fiscal year and the projected fiscal year. C. Schedule showing average short-term securities for the proposed test year, most recent fiscal year, and the projected fiscal year. STAT AUTH: MS s 216B.3; 216B.8; 216B.16 Current as of 1/2/5 1

50 OTTER TAIL POWER COMPANY Docket No. E17/GR Electric Utility - State of Minnesota Exhibit (KGM-1) RATE OF RETURN COST OF CAPITAL SCHEDULES Financial Information SUMMARY SCHEDULE Schedule D-1-a, Page 1 of 1 Capitalization: FISCAL YEAR 214 Long-Term Debt Short-Term Debt Long-Term and Short-Term Debt Common Equity Total Capitalization MOST RECENT FISCAL YEAR 215 Long-Term Debt Short-Term Debt Long-Term and Short-Term Debt Common Equity Total Capitalization (A) (B) (C) (D) Percent of Total Cost of Debt / Weighted Cost / Amount Capitalization Return on Equity Return $416,481, % 5.63% 2.78% 15,79,58 1.9% 2.93%.5% $432,272, % 5.54% 2.83% $414,92, % 1.74% 5.25% $846,365,412 1.% 8.8% $44,2, % 5.61% 2.66% 6,636,562.7% 6.5%.4% $446,638, % 5.62% 2.7% $481,182, % 1.74% 5.57% $927,821,618 1.% 8.27% UNADJUSTED PROJECTED FISCAL YEAR 216 (1) Long-Term Debt $44,7, % 5.62% 2.53% Short-Term Debt 25,676, % 3.28%.9% Long-Term and Short-Term Debt $466,376, % 5.49% 2.61% Common Equity Total Capitalization PROPOSED TEST YEAR 216 Long-Term Debt Short-Term Debt Long-Term and Short-Term Debt Common Equity Total Capitalization $515,49, % 1.4% 5.46% $981,867,321 1.% 8.7% $44,7, % 5.62% 2.52% 25,676, % 3.28%.9% $466,376, % 5.49% 2.61% $515,49, % 1.4% 5.46% $981,867,321 1.% 8.7% The most recent fiscal year and unadjusted projected fiscal year are based on 13-month average balances except some short-term debt uses daily balances. (1) Based on 216 budget prepared in

51 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE OF RETURN COST OF CAPITAL SCHEDULES Composite Cost of Long-term Debt Docket No. E17/GR Exhibit (KGM-1) Financial Information Schedule D-2-a, Page 1 of 2 FISCAL YEAR 214 Description Interest Rate PRINCIPAL AMOUNTS OUTSTANDING Dec 213 Jan 214 Feb 214 Mar 214 Apr 214 May 214 Jun 214 Jul 214 Aug 214 Sep 214 Oct 214 Nov 214 Dec 214 DEBENTURES 4.63% Series for % 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 6,482, 5.95% Unsecured Series A 217 Senior Notes 5.95% 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 1,963,5 6.15% Unsecured Series B 222 Senior Notes 6.15% 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 1,845, 6.37% Unsecured Series C 227 Senior Notes 6.37% 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 2,675,4 6.47% Unsecured Series D 237 Senior Notes 6.47% 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 3,235, 214 Term Note 1.1% 4,9, 4,9, 4.68% Unsecured Series 228 Senior Notes 4.68% 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 5,769,231 2,363,4 5.47% Unsecured Series 243 Senior Notes 5.47% 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 76,153,846 4,143,525 TOTAL DEBENTURES $335,9, $335,9, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $421,923,77 $22,77,825 Average Monthly Balance Interest Cost LOSS/GAIN ON REACQUIRED DEBT TOTAL DEBT CAPITAL (5,39,83) (5,331,68) (5,38,298) (5,79,249) (5,646,857) (5,597,12) (5,534,222) (5,471,342) (5,48,462) (5,345,583) (5,284,6) (5,387,21) (5,32,67) (5,441,178) 756,551 $33,59,17 $33,568,32 $439,691,72 $439,29,751 $439,353,143 $439,42,898 $439,465,778 $439,528,658 $439,591,538 $439,654,417 $439,715,94 $439,612,979 $439,679,393 $416,481,899 $23,464,376 MOST RECENT FISCAL YEAR 215 Description Interest Rate PRINCIPAL AMOUNTS OUTSTANDING Dec 214 Jan 215 Feb 215 Mar 215 Apr 215 May 215 Jun 215 Jul 215 Aug 215 Sep 215 Oct 215 Nov 215 Dec 215 Embedded Cost of Long-Term Debt 5.63% DEBENTURES 4.63% Series for % 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 6,482, 5.95% Unsecured Series A 217 Senior Notes 5.95% 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 1,963,5 6.15% Unsecured Series B 222 Senior Notes 6.15% 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 1,845, 6.37% Unsecured Series C 227 Senior Notes 6.37% 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 2,675,4 6.47% Unsecured Series D 237 Senior Notes 6.47% 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 3,235, 4.68% Unsecured Series 228 Senior Notes 4.68% 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 2,88, 5.47% Unsecured Series 243 Senior Notes 5.47% 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 4,923, TOTAL DEBENTURES $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $23,931,9 Average Monthly Balance Interest Cost LOSS/GAIN ON REACQUIRED DEBT TOTAL DEBT CAPITAL (5,39,83) (5,269,338) (5,27,238) (5,145,138) (5,83,39) (5,2,939) (4,958,839) (4,896,74) (4,837,62) (4,775,481) (4,865,341) (4,794,639) (4,723,936) (4,997,624) 756,37 $439,69,17 $439,73,662 $439,792,762 $439,854,862 $439,916,961 $439,979,61 $44,41,161 $44,13,26 $44,162,38 $44,224,519 $44,134,659 $44,25,361 $44,276,64 $44,2,376 $24,687,937 Embedded Cost of Long-Term Debt 5.61% UNADJUSTED PROJECTED FISCAL YEAR 216 Description DEBENTURES Interest Rate PRINCIPAL AMOUNTS OUTSTANDING Dec 215 Jan 216 Feb 216 Mar 216 Apr 216 May 216 Jun 216 Jul 216 Aug 216 Sep 216 Oct 216 Nov 216 Dec % Series for % 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 6,482, 5.95% Unsecured Series A 217 Senior Notes 5.95% 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 1,963,5 6.15% Unsecured Series B 222 Senior Notes 6.15% 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 1,845, 6.37% Unsecured Series C 227 Senior Notes 6.37% 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 3,235, 6.47% Unsecured Series D 237 Senior Notes 6.47% 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 2,675,4 4.68% Unsecured Series 228 Senior Notes 4.68% 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 2,88, 5.47% Unsecured Series 243 Senior Notes 5.47% 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 4,923, TOTAL DEBENTURES $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $23,931,9 Average Monthly Balance Interest Cost LOSS/GAIN ON REACQUIRED DEBT TOTAL DEBT CAPITAL (4,723,936) (4,653,234) (4,582,532) (4,511,829) (4,441,127) (4,37,424) (4,299,722) (4,229,2) (4,158,317) (4,87,615) (4,16,912) (3,946,21) (3,875,58) (4,299,722) 848,429 $44,276,64 $44,346,766 $44,417,468 $44,488,171 $44,558,873 $44,629,576 $44,7,278 $44,77,98 $44,841,683 $44,912,385 $44,983,88 $441,53,79 $441,124,492 $44,7,278 $24,78,329 Embedded Cost of Long-Term Debt 5.62% 3

52 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota RATE OF RETURN COST OF CAPITAL SCHEDULES Composite Cost of Long-term Debt Docket No. E17/GR Exhibit (KGM-1) Financial Information Schedule D-2-a, Page 2 of 2 PROPOSED TEST YEAR 216 Average Interest PRINCIPAL AMOUNTS OUTSTANDING Monthly Interest Description Rate Dec 215 Jan 216 Feb 216 Mar 216 Apr 216 May 216 Jun 216 Jul 216 Aug 216 Sep 216 Oct 216 Nov 216 Dec 216 Balance Cost 4.63% Series for % 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 14,, 6,482, 5.95% Unsecured Series A 217 Senior Notes 5.95% 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 1,963,5 6.15% Unsecured Series B 222 Senior Notes 6.15% 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 1,845, 6.37% Unsecured Series C 227 Senior Notes 6.37% 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 3,235, 6.47% Series D 237 Unsecured Senior Notes 6.47% 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 2,675,4 4.68% Unsecured Series 228 Senior Notes 4.68% 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 2,88, 5.47% Unsecured Series 243 Senior Notes 5.47% 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 4,923, TOTAL DEBENTURES $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $445,, $23,931,9 LOSS/GAIN ON REACQUIRED DEBT TOTAL DEBT CAPITAL (4,723,936) (4,653,234) (4,582,532) (4,511,829) (4,441,127) (4,37,424) (4,299,722) (4,229,2) (4,158,317) (4,87,615) (4,16,912) (3,946,21) (3,875,58) (4,299,722) 848,429 $44,276,64 $44,346,766 $44,417,468 $44,488,171 $44,558,873 $44,629,576 $44,7,278 $44,77,98 $44,841,683 $44,912,385 $44,983,88 $441,53,79 $441,124,492 $44,7,278 $24,78,329 Embedded Cost of Long-Term Debt 5.62% 4

53 OTTER TAIL POWER COMPANY Docket No. E17/GR Electric Utility - State of Minnesota Exhibit (KGM-1) RATE OF RETURN COST OF CAPITAL SCHEDULES Financial Information Cost of Short-Term Debt Schedule D-3-a, Page 1 of 1 FISCAL YEAR 214 Description PRINCIPAL AMOUNTS OUTSTANDING Dec 213 Jan 214 Feb 214 Mar 214 Apr 214 May 214 Jun 214 Jul 214 Aug 214 Sep 214 Oct 214 Nov 214 Dec 214 Average Monthly Balances Line of credit (short-term debt) Interest $46,636,113 $66,798,893 $76,959,7 $ $ $ $5,82,927 $2,561,994 $1,32,81 $3,582,368 $245,665 $ $1,351,793 $15,79,58 $29,845 $97,336 $97,278 $25,658 $24,233 $25,41 $31,25 $28,365 $26,866 $28,66 $25,852 $24,739 $27,185 $462,461 Note: Short-Term (S-T) Debt was calculated using a daily average and was combined with actual interest charged to arrive at the S-T Cost of Debt. Embedded Cost of Short-Term Debt 2.93% MOST RECENT FISCAL YEAR 215 Description PRINCIPAL AMOUNTS OUTSTANDING Dec 214 Jan 215 Feb 215 Mar 215 Apr 215 May 215 Jun 215 Jul 215 Aug 215 Sep 215 Oct 215 Nov 215 Dec 215 Average Monthly Balances Line of credit (short-term debt) Interest $1,351,793 $2,448,758 $9,112,371 $11,566,643 $6,219,18 $3,93,948 $4,47,613 $3,361,82 $9,421,13 $11,129,559 $8,816,69 $6,74,64 $8,155,365 $6,636,562 $27,185 $28,526 $32,795 $38,87 $31,935 $3,357 $29,391 $29,735 $36,942 $36,8 $35,984 $35,144 $35,223 $41,74 Note: Short-Term (S-T) Debt was calculated using a daily average and was combined with actual interest charged to arrive at the S-T Cost of Debt. Embedded Cost of Short-Term Debt 6.5% UNADJUSTED PROJECTED FISCAL YEAR 216 PRINCIPAL AMOUNTS OUTSTANDING Description Dec 215 Jan 216 Feb 216 Mar 216 Apr 216 May 216 Jun 216 Jul 216 Aug 216 Sep 216 Oct 216 Nov 216 Dec 216 Average Monthly Balances Line of credit (short-term debt) Total interest expense $8,155,365 $14,641,275 $17,419,452 $18,24,64 $12,19,545 $18,683,376 $19,484,475 $16,845,413 $29,53,688 $39,94,158 $4,245,45 $43,376,21 $55,41,816 $25,676,482 $35,223 $41,864 $54,25 $59,234 $6,774 $49,43 $59,938 $61,44 $55,658 $76,943 $122,295 $98,699 $12,7 $842,373 Embedded Cost of Short-Term Debt 3.28% PROPOSED TEST YEAR 216 Description PRINCIPAL AMOUNTS OUTSTANDING Dec 215 Jan 216 Feb 216 Mar 216 Apr 216 May 216 Jun 216 Jul 216 Aug 216 Sep 216 Oct 216 Nov 216 Dec 216 Average Monthly Balances Line of credit (short-term debt) Interest $8,155,365 $14,641,275 $17,419,452 $18,24,64 $12,19,545 $18,683,376 $19,484,475 $16,845,413 $29,53,688 $39,94,158 $4,245,45 $43,376,21 $55,41,816 $25,676,482 $35,223 $41,864 $54,25 $59,234 $6,774 $49,43 $59,938 $61,44 $55,658 $76,943 $122,295 $98,699 $12,7 $842,373 Embedded Cost of Short-Term Debt 3.28% 5

54 OTTER TAIL POWER COMPANY Docket No. E17/GR Electric Utility - State of Minnesota Exhibit (KGM-1) RATE OF RETURN COST OF CAPITAL SCHEDULES Financial Information Common Equity Schedule D-4-a, Page 1 of 1 FISCAL YEAR 214 PRINCIPAL AMOUNTS OUTSTANDING Description Dec 213 Jan 214 Feb 214 Mar 214 Apr 214 May 214 Jun 214 Jul 214 Aug 214 Sep 214 Oct 214 Nov 214 Dec 214 Average Monthly Balances Contributed Capital $252,261,891 $252,261,891 $252,261,891 $252,261,891 $252,261,891 $252,261,891 $262,261,891 $272,261,891 $272,261,891 $291,261,891 $291,261,891 $291,261,891 $296,261,891 $268,492,66 Current Year Capital Contributions Common Stock Balance $252,261,891 $252,261,891 $252,261,891 $252,261,891 $252,261,891 $252,261,891 $262,261,891 $272,261,891 $272,261,891 $291,261,891 $291,261,891 $291,261,891 $296,261,891 $268,492,66 Retained Earnings Beginning Balance $14,53,549 $137,678,386 $144,69,958 $149,76,33 $145,56,12 $148,51,283 $15,463,942 $141,996,25 $144,349,627 $147,993,313 $141,759,185 $145,293,18 $15,162,26 $145,199,677 Net Income 5,886,923 6,391,572 5,636,345 4,625,294 2,95,271 1,953, ,27 2,353,421 3,643,686 2,615,218 3,533,833 4,869,8 4,773,778 3,813,157 Dividends (8,632,671) (8,794,44) (8,828,619) (8,872,22) (8,913,8) (3,387,765) Other 37,585 22,855 22,855 22,855 (761,5) (24,796) End of Month Balance $137,678,386 $144,69,958 $149,76,33 $145,56,12 $148,51,283 $15,463,942 $141,996,25 $144,349,627 $147,993,313 $141,759,185 $145,293,18 $15,162,26 $145,261,296 $145,6,273 Total Electric Common Equity $389,94,277 $396,331,849 $41,968,194 $397,821,93 $4,772,174 $42,725,833 $44,258,96 $416,611,518 $42,255,24 $433,21,75 $436,554,99 $441,423,917 $441,523,187 $414,92,933 MOST RECENT FISCAL YEAR 215 PRINCIPAL AMOUNTS OUTSTANDING Description Dec 214 Jan 215 Feb 215 Mar 215 Apr 215 May 215 Jun 215 Jul 215 Aug 215 Sep 215 Oct 215 Nov 215 Dec 215 Average Monthly Balances Contributed Capital $296,261,891 $31,261,891 $311,261,891 $316,261,891 $321,261,891 $331,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $327,555,783 Current Year Capital Contributions Common Stock Balance $296,261,891 $31,261,891 $311,261,891 $316,261,891 $321,261,891 $331,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $327,555,783 Retained Earnings Beginning Balance $15,162,26 $145,261,297 $15,655,679 $155,589,196 $149,296,988 $151,742,86 $153,637,249 $148,374,813 $153,68,676 $157,247,161 $152,94,11 $156,342,738 $166,38,544 $153,6,43 Net Income 4,773,778 5,394,383 4,933,517 2,85,527 2,445,98 1,895,163 3,911,894 4,693,863 4,178,484 4,48,373 4,248,637 9,965,86 524,666 4,143,399 Dividends (8,913,8) (9,191,488) (9,223,84) (9,25,186) (9,35,835) (3,532,969) Other (761,5) 48,753 48,753 48,753 48,753 (43,576) End of Month Balance $145,261,297 $15,655,679 $155,589,196 $149,296,988 $151,742,86 $153,637,249 $148,374,813 $153,68,676 $157,247,161 $152,94,11 $156,342,738 $166,38,544 $157,531,128 $153,626,897 Total Electric Common Equity $441,523,187 $451,917,57 $466,851,87 $465,558,879 $473,3,977 $485,626,715 $488,364,279 $493,58,142 $497,236,627 $492,83,566 $496,332,24 $56,298,1 $497,52,594 $481,182,68 UNADJUSTED PROJECTED FISCAL YEAR 216 PRINCIPAL AMOUNTS OUTSTANDING Description Dec 215 Jan 216 Feb 216 Mar 216 Apr 216 May 216 Jun 216 Jul 216 Aug 216 Sep 216 Oct 216 Nov 216 Dec 216 Average Monthly Balances Contributed Capital $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $357,339,466 $364,839,466 $364,839,466 $364,839,466 $364,839,466 $364,839,466 $364,839,466 $352,793,312 Current Year Capital Contributions Common Stock Balance $25,661,391 $25,661,391 $25,661,391 $25,661,391 $25,661,391 $25,661,391 $25,661,391 $25,661,391 $25,661,391 $25,661,391 $25,661,391 $25,661,391 $25,661,391 $352,793,312 Retained Earnings Beginning Balance $166,38,544 $157,531,128 $162,912,78 $167,72,384 $16,865,58 $162,74,877 $164,818,825 $157,732,618 $161,522,855 $165,751,968 $159,838,367 $162,958,389 $167,798,698 $162,98,996 Net Income 524,666 5,381,652 4,159,64 3,312,15 1,839,369 2,113,947 2,497,49 3,79,237 4,229,113 3,784,182 3,12,23 4,84,39 5,546,788 3,472,272 Dividends (9,35,835) (9,567,779) (9,632,449) (9,746,536) (9,838,4) (3,72,769) Other 48,753 48,753 48,753 48,753 48,753 18,751 End of Month Balance $157,531,128 $162,912,78 $167,72,384 $16,865,58 $162,74,877 $164,818,825 $157,732,618 $161,522,855 $165,751,968 $159,838,367 $162,958,389 $167,798,698 $163,555,839 $162,697,249 Total Electric Common Equity $363,192,519 $368,574,171 $372,733,775 $366,526,899 $368,366,268 $37,48,216 $363,394,9 $367,184,246 $371,413,359 $365,499,758 $368,619,78 $373,46,89 $369,217,23 $515,49,561 PROPOSED TEST YEAR 216 PRINCIPAL AMOUNTS OUTSTANDING Description Dec 215 Jan 216 Feb 216 Mar 216 Apr 216 May 216 Jun 216 Jul 216 Aug 216 Sep 216 Oct 216 Nov 216 Dec 216 Average Monthly Balances Contributed Capital $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $357,339,466 $364,839,466 $364,839,466 $364,839,466 $364,839,466 $364,839,466 $364,839,466 $352,793,312 Current Year Capital Contributions Common Stock Balance $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $339,989,466 $357,339,466 $364,839,466 $364,839,466 $364,839,466 $364,839,466 $364,839,466 $364,839,466 $352,793,312 Retained Earnings Beginning Balance $166,38,544 $157,531,128 $162,912,78 $167,72,384 $16,865,58 $162,74,877 $164,818,825 $157,732,618 $161,522,855 $165,751,968 $159,838,367 $162,958,389 $167,798,698 $162,98,996 Net Income 524,666 5,381,652 4,159,64 3,312,15 1,839,369 2,113,947 2,497,49 3,79,237 4,229,113 3,784,182 3,12,23 4,84,39 5,546,788 3,472,272 Dividends (9,35,835) (9,567,779) (9,632,449) (9,746,536) (9,838,4) (3,72,769) Other 48,753 48,753 48,753 48,753 48,753 18,751 End of Month Balance $157,531,128 $162,912,78 $167,72,384 $16,865,58 $162,74,877 $164,818,825 $157,732,618 $161,522,855 $165,751,968 $159,838,367 $162,958,389 $167,798,698 $163,555,839 $162,697,249 Total Electric Common Equity $497,52,594 $52,92,246 $57,61,85 $5,854,974 $52,694,343 $54,88,291 $515,72,84 $526,362,321 $53,591,434 $524,677,832 $527,797,855 $532,638,164 $528,395,35 $515,49,561 6

55 OTTER TAIL CORPORATION CONSOLIDATED RATE OF RETURN COST OF CAPITAL SCHEDULES SUMMARY SCHEDULE Docket No. E17/GR Exhibit (KGM-1) Financial Information Schedule D-1-b, Page 1 of 1 (A) (B) (C) (D) Capitalization: Amount Percent of Total Capitalization Cost of Debt / Return on Equity Weighted Cost / Return FISCAL YEAR 214 Long-Term Debt $476,559, % 5.93% 2.7% Short-Term Debt 17,366,91 1.7% 3.59%.6% Long-Term and Short-Term Debt $493,926, % 5.85% 2.76% Common Equity $554,461, % 1.4% 5.5% Total Capitalization $1,48,388,128 1.% 8.26% MOST RECENT FISCAL YEAR 215 Long-Term Debt $482,53, % 6.11% 2.64% Short-Term Debt 42,794, % 3.18%.12% Long-Term and Short-Term Debt $524,847, % 5.87% 2.76% Common Equity $591,254,55 53.% 1.1% 5.35% Total Capitalization $1,116,11,466 1.% 8.11% UNADJUSTED PROJECTED FISCAL YEAR 216 Long-Term Debt $49,58, % 5.98% 2.46% Short-Term Debt 66,67,48 5.5% 2.84%.16% Long-Term and Short-Term Debt $556,125, % 5.61% 2.62% Common Equity $635,882, % 1.1% 5.34% Total Capitalization $1,192,8,17 1.% 7.96% PROPOSED TEST YEAR 216 Long-Term Debt $49,58, % 5.98% 2.34% Short-Term Debt 91,743,53 7.3% 2.84%.21% Long-Term and Short-Term Debt $581,81, % 5.49% 2.55% Common Equity $668,73, % 1.1% 5.35% Total Capitalization $1,25,55,682 1.% 7.9% All are based on 13-month average balances. 7

56 OTTER TAIL CORPORATION CONSOLIDATED RATE OF RETURN COST OF CAPITAL SCHEDULES SUMMARY SCHEDULE Docket No. E17/GR Exhibit (KGM-1) Financial Information Schedule D-1-c, Page 1 of 1 (A) (B) (C) (D) Capitalization: Amount Percent of Total Capitalization Cost of Debt / Return on Equity Weighted Cost / Return FISCAL YEAR 214 Long-Term Debt $53,784, % 8.83%.76% Short-Term Debt 17,366,91 2.8% 4.18%.12% Long-Term and Short-Term Debt $71,151, % 7.7%.88% Common Equity $554,461, % 1.4% 9.22% Total Capitalization $625,612,819 1.% 1.9% MOST RECENT FISCAL YEAR 215 Long-Term Debt $53,59, % 8.85%.76% Short-Term Debt 42,794, % 2.74%.19% Long-Term and Short-Term Debt $96,384, % 6.14%.86% Common Equity $591,254,55 86.% 1.1% 8.68% Total Capitalization $687,638,64 1.% 9.54% UNADJUSTED PROJECTED FISCAL YEAR 216 Long-Term Debt $49,358, % 9.2%.6% Short-Term Debt 66,67,48 8.8% 2.67%.23% Long-Term and Short-Term Debt $115,425, % 5.46%.84% Common Equity $635,882, % 1.1% 8.47% Total Capitalization $751,37,533 1.% 9.31% PROPOSED TEST YEAR 216 Long-Term Debt $49,358, % 9.2%.73% Short-Term Debt 66,67,48 1.6% 2.67%.28% Long-Term and Short-Term Debt $115,425, % 5.46%.8% Common Equity $668,73, % 1.1% 8.54% Total Capitalization $784,129,96 1.% 9.34% All are based on 13-month average balances. 8

57 OTTER TAIL CORPORATION CONSOLIDATED RATE OF RETURN COST OF CAPITAL SCHEDULES Composite Cost of Long-term Debt Docket No. E17/GR Exhibit (KGM-1) Financial Information Schedule D-2-b, Page 1 of 2 FISCAL YEAR 214 Average Interest PRINCIPAL AMOUNTS OUTSTANDING Monthly Cost Description Interest Rate Dec-13 Jan-14 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Year 214 DEBENTURES Series for % $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $6,482, Unsecured Series A 217 Senior Notes 5.95% 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 1,963,5 Unsecured Series B 222 Senior Notes 6.15% 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 1,845, Unsecured Series C 227 Senior Notes 6.37% 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 2,675,4 Series D 237 Unsecured Senior Notes 6.47% 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 3,235, Credit Agreement with JP Morgan Chase LIBOR +.875% 4,9, 4,9, 6,292,38 67,83 TOTAL DEBENTURES 335,9, $335,9, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $31,292,38 $16,267,983 POLLUTION CONTROL REVENUE BONDS 228 Series 4.68% 4.68% 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 5,769,231 2,363,4 243 Series 5.47% 5.47% 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 76,153,846 4,143,525 TOTAL POLLUTION CONTROL $ $ $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $126,923,77 $6,56,925 Obligations Of Varistar Corporation - Various rates Various 53,878,541 53,863,452 53,848,276 53,832,397 53,817,5 53,81,417 53,785,899 53,77,97 53,754,47 53,738,628 53,722,574 53,76,62 53,69,395 53,785,366 4,75,767 SUBTOTAL $389,778,541 $389,763,452 $498,848,276 $498,832,397 $498,817,5 $498,81,417 $498,785,899 $498,77,97 $498,754,47 $498,738,628 $498,722,574 $498,76,62 $498,69,395 $482,,75 $27,525,675 LOSS/GAIN ON REACQUIRED DEBT (5,39,83) (5,331,68) (5,38,298) (5,79,249) (5,646,857) (5,597,12) (5,534,222) (5,471,342) (5,48,462) (5,345,583) (5,284,6) (5,387,21) (5,32,67) (5,441,178) 756,551 TOTAL DEBT CAPITAL $384,387,711 $384,431,772 $493,539,978 $493,123,148 $493,17,193 $493,24,315 $493,251,677 $493,298,755 $493,345,945 $493,393,45 $493,438,514 $493,319,599 $493,369,788 $476,559,572 $28,282,226 Embedded Cost of Long-Term Debt 5.93% MOST RECENT FISCAL YEAR 215 Average Interest PRINCIPAL AMOUNTS OUTSTANDING Monthly Cost Description Interest Rate Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Year 215 DEBENTURES Series for % $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $6,482, Unsecured Series A 217 Senior Notes 5.95% 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 1,963,5 Unsecured Series B 222 Senior Notes 6.15% 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 1,845, Unsecured Series C 227 Senior Notes 6.37% 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 2,675,4 Series D 237 Unsecured Senior Notes 6.47% 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 3,235, Credit Agreement with JP Morgan Chase LIBOR +.875% TOTAL DEBENTURES 295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $16,2,9 POLLUTION CONTROL REVENUE BONDS 228 Series 4.68% 4.68% 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 55,384,615 2,88, 243 Series 5.47% 5.47% 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 83,76,923 4,923, TOTAL POLLUTION CONTROL $ $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $138,461,538 $7,731, Obligations Of Varistar Corporation - Various rates Various 53,69,395 53,674,265 53,658,46 53,641,25 53,618,737 53,591,568 53,591,568 53,574,731 53,557,971 53,541,119 53,524,12 53,56,976 53,489,691 53,589,253 4,75,767 SUBTOTAL $348,69,395 $498,674,265 $498,658,46 $498,641,25 $498,618,737 $498,591,568 $498,591,568 $498,574,731 $498,557,971 $498,541,119 $498,524,12 $498,56,976 $498,489,691 $487,5,791 $28,682,667 LOSS/GAIN ON REACQUIRED DEBT (5,39,83) (5,269,338) (5,27,238) (5,145,138) (5,83,39) (5,2,939) (4,958,839) (4,896,74) (4,837,62) (4,775,481) (4,865,341) (4,794,639) (4,723,936) (4,997,624) 756,37 TOTAL DEBT CAPITAL $343,299,565 $493,44,927 $493,45,88 $493,496,67 $493,535,698 $493,57,629 $493,632,729 $493,677,991 $493,72,351 $493,765,638 $493,658,671 $493,712,337 $493,765,755 $482,53,167 $29,438,74 Embedded Cost of Long-Term Debt 6.11% 9

58 OTTER TAIL CORPORATION CONSOLIDATED RATE OF RETURN COST OF CAPITAL SCHEDULES Composite Cost of Long-term Debt Docket No. E17/GR Exhibit (KGM-1) Financial Information Schedule D-2-b, Page 2 of 2 UNADJUSTED PROJECTED FISCAL YEAR 216 Average Interest PRINCIPAL AMOUNTS OUTSTANDING Monthly Cost Description Interest Rate Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Year 216 DEBENTURES Series for % $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $6,482, Unsecured Series A 217 Senior Notes 5.95% 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 1,963,5 Unsecured Series B 222 Senior Notes 6.15% 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 1,845, Unsecured Series C 227 Senior Notes 6.37% 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 2,675,4 Series D 237 Unsecured Senior Notes 6.47% 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 3,235, 214 Term Loan Variable TOTAL DEBENTURES $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $16,2,9 POLLUTION CONTROL REVENUE BONDS 228 Series 4.68% 4.68% 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 2,88, 243 Series 5.47% 5.47% 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 4,923, TOTAL POLLUTION CONTROL $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $7,731, Obligations Of Varistar Corporation - Various rates Various 53,489,691 53,472,47 53,455,155 53,437,449 53,419,946 53,42,25 53,384,511 53,366,584 53,348,699 53,33,718 53,312,511 53,294, ,938 49,358,478 4,54,532 SUBTOTAL $498,489,691 $498,472,47 $498,455,155 $498,437,449 $498,419,946 $498,42,25 $498,384,511 $498,366,584 $498,348,699 $498,33,718 $498,312,511 $498,294,335 $445,945,938 $494,358,478 $28,472,432 UNAMORTIZED DISCOUNT ON LONG-TERM DEBT (43) (392) (355) (318) (28) (243) (25) (168) (131) (93) (56) (18) ($27) $43 LOSS/GAIN ON REACQUIRED DEBT (4,723,936) (4,653,234) (4,582,532) (4,511,829) (4,441,127) (4,37,424) (4,299,722) (4,229,2) (4,158,317) (4,87,615) (4,16,912) (3,946,21) (3,875,58) (4,299,722) 848,429 TOTAL DEBT CAPITAL $493,765,325 $493,819,236 $493,872,623 $493,925,62 $493,978,819 $494,31,781 $494,84,789 $494,137,564 $494,19,382 $494,243,13 $494,295,599 $494,348,125 $442,7,43 $49,58,756 $29,321,29 Embedded Cost of Long-Term Debt 5.98% PROPOSED TEST YEAR 216 Average Interest PRINCIPAL AMOUNTS OUTSTANDING Monthly Cost Description Interest Rate Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Year 216 DEBENTURES Series for % $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $14,, $6,482, Unsecured Series A 217 Senior Notes 5.95% 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 33,, 1,963,5 Unsecured Series B 222 Senior Notes 6.15% 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 3,, 1,845, Unsecured Series C 227 Senior Notes 6.37% 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 42,, 2,675,4 Series D 237 Unsecured Senior Notes 6.47% 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 5,, 3,235, 214 Term Loan Variable TOTAL DEBENTURES $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $295,, $16,2,9 POLLUTION CONTROL REVENUE BONDS 228 Series 4.68% 4.68% 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 6,, 2,88, 243 Series 5.47% 5.47% 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 9,, 4,923, TOTAL POLLUTION CONTROL $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $15,, $7,731, Obligations Of Varistar Corporation - Various rates Various 53,489,691 53,472,78 53,454,8 53,437,131 53,419,666 53,41,962 53,384,36 53,366,416 53,348,568 53,33,625 53,312,455 53,294, ,938 49,358,34 4,54,532 SUBTOTAL $498,489,691 $498,472,78 $498,454,8 $498,437,131 $498,419,666 $498,41,962 $498,384,36 $498,366,416 $498,348,568 $498,33,625 $498,312,455 $498,294,317 $445,945,938 $494,358,34 $28,472,432 UNAMORTIZED DISCOUNT ON LONG-TERM DEBT (43) (392) (355) (318) (28) (243) (25) (168) (131) (93) (56) (18) (27) 43 LOSS/GAIN ON REACQUIRED DEBT (4,723,936) (4,653,234) (4,582,532) (4,511,829) (4,441,127) (4,37,424) (4,299,722) (4,229,2) (4,158,317) (4,87,615) (4,16,912) (3,946,21) (3,875,58) (4,299,722) 848,429 TOTAL DEBT CAPITAL $493,765,325 $493,818,451 $493,871,914 $493,924,985 $493,978,259 $494,31,295 $494,84,378 $494,137,228 $494,19,121 $494,242,917 $494,295,487 $494,348,88 $442,7,43 $49,58,375 $29,321,29 Embedded Cost of Long-Term Debt 5.98% 1

59 OTTER TAIL CORPORATION CONSOLIDATED RATE OF RETURN COST OF CAPITAL SCHEDULES Composite Cost of Long-term Debt Docket No. E17/GR Exhibit (KGM-1) Financial Information Schedule D-2-c, Page 1 of 1 FISCAL YEAR 214 DEBENTURES PRINCIPAL AMOUNTS Description Interest Rate Dec-13 Jan-14 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Cost OTC 216 SERIES Notes 9.% 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ $52,33, $4,79,7 OTC PACE loan for NPP 2.54% 1,222,856 1,213,492 1,24,61 1,194,5 1,184,487 1,174,691 1,164,996 1,155,7 1,145,243 1,135,348 1,125,227 1,115,197 1,14,944 1,164,589 29,581 ND Development note (NPP) 3.95% 325, ,96 314,215 38,347 32, ,726 29,93 285,27 279, ,28 267, , ,451 29,776 11,486 TOTAL DEBENTURES $53,878,541 $53,863,452 $53,848,276 $53,832,398 $53,817,51 $53,81,417 $53,785,899 $53,77,98 $53,754,46 $53,738,628 $53,722,573 $53,76,62 $53,69,394 $53,785,365 $4,75,766 OUTSTANDING Average Monthly Interest UNAMORTIZED DISCOUNT ON LONG-TERM DEBT (1,327) (1,29) (1,252) (1,215) (1,177) (1,14) (1,13) (1,65) (1,28) (99) (953) (916) (878) (1,13) 449 TOTAL DEBT CAPITAL $53,877,214 $53,862,162 $53,847,24 $53,831,183 $53,815,873 $53,8,277 $53,784,796 $53,769,32 $53,753,378 $53,737,638 $53,721,62 $53,75,74 $53,689,516 $53,784,263 $4,751,215 Embedded Cost of Long-Term Debt 8.83% MOST RECENT FISCAL YEAR 215 DEBENTURES PRINCIPAL AMOUNTS Description Interest Rate Dec-14 Jan-15 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Cost OTC 216 SERIES Notes 9.% 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ 52,33, $ $52,33, $4,79,7 OTC PACE loan for NPP 2.54% 1,14,944 1,94,778 1,84,544 1,73,788 1,63,416 1,52,826 1,42,314 1,31,588 1,2,936 1,1, , , ,34 1,41,875 26,464 ND Development note (NPP) 3.95% 255, , ,52 237, , , , ,143 27,35 2,96 194, , , ,12 8,655 TOTAL DEBENTURES $53,69,394 $53,674,264 $53,658,46 $53,641,26 $53,624,87 $53,68,147 $53,591,568 $53,574,731 $53,557,971 $53,541,119 $53,524,12 $53,56,976 $53,489,691 $53,59,995 $4,744,819 OUTSTANDING Average Monthly Interest UNAMORTIZED DISCOUNT ON LONG-TERM DEBT (878) (841) (84) (766) (729) (691) (654) (617) (579) (542) (54) (467) (43) (654) 448 TOTAL DEBT CAPITAL $53,689,516 $53,673,423 $53,657,242 $53,64,439 $53,624,79 $53,67,455 $53,59,914 $53,574,114 $53,557,391 $53,54,577 $53,523,58 $53,56,59 $53,489,261 $53,59,341 $4,745,267 Embedded Cost of Long-Term Debt 8.85% UNADJUSTED PROJECTED FISCAL YEAR 216 Average PRINCIPAL AMOUNTS OUTSTANDING Monthly Interest Description Interest Rate Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Cost DEBENTURES OTC 216 SERIES Notes 9.% $52,33, $52,33, $52,33, $52,33, $52,33, $52,33, $52,33, $52,33, $52,33, $52,33, $52,33, $52,33, $48,34,615 $4,513,463 $ OTC PACE loan for NPP 2.54% 977,34 966, ,25 943, ,61 921,184 99,89 898, , ,12 863, , ,649 $99,38 21,394 ND Development note (NPP) 3.95% 182, , ,95 163, , ,21 144,72 138, , , , ,751 16,289 $144,555 5,675.1 TOTAL DEBENTURES $53,489,692 $53,472,47 $53,455,155 $53,437,45 $53,419,946 $53,42,25 $53,384,511 $53,366,584 $53,348,699 $53,33,718 $53,312,51 $53,294,335 $945,938 $49,358,478 $4,54,531 UNAMORTIZED DISCOUNT ON LONG-TERM DEBT (43) (392) (355) (318) (28) (243) (25) (168) (131) (93) (56) (18) (27) $43 TOTAL DEBT CAPITAL $53,489,262 $53,472,77 $53,454,8 $53,437,132 $53,419,666 $53,41,962 $53,384,36 $53,366,416 $53,348,569 $53,33,625 $53,312,455 $53,294,317 $945,938 $49,358,271 $4,54,961 Embedded Cost of Long-Term Debt 9.2% PROPOSED TEST YEAR 216 Average PRINCIPAL AMOUNTS OUTSTANDING Monthly Interest Description Interest Rate Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Cost DEBENTURES OTC 216 SERIES Notes 9.% 52,33, 52,33, 52,33, 52,33, 52,33, 52,33, 52,33, 52,33, 52,33, 52,33, 52,33, 52,33, $48,34,615 $4,513,463 $ $ $ $ $ $ $ $ $ $ $ $ $ 839,649 99,38 21,394 OTC PACE loan for NPP 2.54% 977,34 966, ,25 943, ,61 921,184 99,89 898, , ,12 863, ,584 ND Development note (NPP) 3.95% 182, , ,95 163, , ,21 144,72 138, , , , ,751 16, ,555 5,675.1 TOTAL DEBENTURES $53,489,692 $53,472,47 $53,455,155 $53,437,45 $53,419,946 $53,42,25 $53,384,511 $53,366,584 $53,348,699 $53,33,718 $53,312,51 $53,294,335 $945,938 $49,358,478 $4,54,531 UNAMORTIZED DISCOUNT ON LONG-TERM DEBT (43) (392) (355) (318) (28) (243) (25) (168) (131) (93) (56) (18) (27) 43 TOTAL DEBT CAPITAL $53,489,262 $53,472,77 $53,454,8 $53,437,132 $53,419,666 $53,41,962 $53,384,36 $53,366,416 $53,348,569 $53,33,625 $53,312,455 $53,294,317 $945,938 $49,358,271 $4,54,961 Embedded Cost of Long-Term Debt 9.2% 11

60 OTTER TAIL CORPORATION CONSOLIDATED RATE OF RETURN COST OF CAPITAL SCHEDULES Cost of Short-Term Debt Docket No. E17/GR Exhibit (KGM-1) Financial Information Schedule D-3-b, Page 1 of 1 FISCAL YEAR 214 PRINCIPAL AMOUNTS OUTSTANDING Interest Rate Dec-13 Jan-14 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Average Daily OTP line of credit (short-term debt) Variable based on LIBOR 51,194,66 79,, 2,869,534 8,512,35 15,79,58 OTC line of credit (short-term debt) Variable based on LIBOR 11,898,622 6,981,949 11,294,123 25,273,766 34,789,129 27,895,799 39,,26 29,785,881 27,996,876 1,853,663 17,366,91 Total line of credit (short-term debt) $33,157,49 OTP LOC interest and fees 462,461 OTC LOC interest 726,696 Total LOC interest $1,189,157 Embedded Cost of Short-Term Debt 3.59% MOST RECENT FISCAL YEAR 215 PRINCIPAL AMOUNTS OUTSTANDING Interest Rate Dec-14 Jan-15 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Average Daily OTP line of credit (short-term debt) Variable based on LIBOR 4,989,938 8,, 7,86, ,756 4,545,91 7,871,41 6,564,31 11,7,557 9,712,471 11,98,487 17,883,658 6,636,562 OTC line of credit (short-term debt) Variable based on LIBOR 1,853,663 21,599,148 3,, 4,846,351 31,894,539 3,789,47 38,493,877 37,889,632 58,, 75,881,121 62,353,62 59,751,326 57,972,53 42,794,245 Total line of credit (short-term debt) $49,43,87 OTP LOC interest and fees 41,74 OTC LOC interest 1,17,487 Total LOC interest $1,572,191 Embedded Cost of Short-Term Debt 3.18% UNADJUSTED PROJECTED FISCAL YEAR 216 Average PRINCIPAL AMOUNTS OUTSTANDING Daily Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances OTP line of credit (short-term debt) Variable based on LIBOR 17,883,658 18,935,873 21,756,21 22,369,798 14,889,767 19,817,93 19,827,358 2,224,763 33,9,495 44,37,13 44,168,21 48,278,418 61,78,936 25,676,482 OTC line of credit (short-term debt) Variable based on LIBOR 57,972,53 59,741,833 63,619,95 67,518,125 66,34,534 59,643,533 76,39,879 73,884,818 68,68,491 62,848,53 55,742,695 51,92,73 96,52,54 66,67,48 Total line of credit (short-term debt) $91,743,53 OTP LOC interest and fees 842,373 OTC LOC interest 1,762,574 Total LOC interest $2,64,947 Embedded Cost of Short-Term Debt 2.84% PROPOSED TEST YEAR 216 Average PRINCIPAL AMOUNTS OUTSTANDING Daily Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances OTP line of credit (short-term debt) Variable based on LIBOR 17,883,658 18,935,873 21,756,21 22,369,798 14,889,767 19,817,93 19,827,358 2,224,763 33,9,495 44,37,13 44,168,21 48,278,418 61,78,936 25,676,482 OTC line of credit (short-term debt) Variable based on LIBOR 57,972,53 59,741,833 63,619,95 67,518,125 66,34,534 59,643,533 76,39,879 73,884,818 68,68,491 62,848,53 55,742,695 51,92,73 96,52,54 66,67,48 Total line of credit (short-term debt) $91,743,53 OTP LOC interest and fees 842,373 OTC LOC interest 1,762,574 Total LOC interest $2,64,947 Embedded Cost of Short-Term Debt 2.84% 12

61 OTTER TAIL CORPORATION CONSOLIDATED RATE OF RETURN COST OF CAPITAL SCHEDULES Cost of Short-Term Debt Docket No. E17/GR Exhibit (KGM-1) Financial Information Schedule D-3-c, Page 1 of 1 FISCAL YEAR 214 PRINCIPAL AMOUNTS OUTSTANDING Dec-13 Jan-14 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Average Monthly Line of credit (short-term debt) $ $ $ $11,898,622 $6,981,949 $11,294,123 $25,273,766 $34,789,129 $27,895,799 $39,,26 $29,785,881 $27,996,876 $1,853,663 $17,366,91 Interest $726,696 Embedded Cost of Short-Term Debt 4.18% MOST RECENT FISCAL YEAR 215 PRINCIPAL AMOUNTS OUTSTANDING Average Monthly Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Line of credit (short-term debt) 1,853,663 21,599,148 3,, 4,846,351 31,894,539 3,789,47 38,493,877 37,889,632 58,, 75,881,121 62,353,62 59,751,326 57,972,53 $42,794,245 Total interest expense $ 1,17,487 Embedded Cost of Short-Term Debt 2.74% UNADJUSTED PROJECTED FISCAL YEAR 216 Average PRINCIPAL AMOUNTS OUTSTANDING Monthly Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Line of credit (short-term debt) 57,972,53 59,741,833 63,619,95 67,518,125 66,34,534 59,643,533 76,39,879 73,884,818 68,68,491 62,848,53 55,742,695 51,92,73 96,52,54 $66,67,48 Total interest expense $ 1,762,574 Embedded Cost of Short-Term Debt 2.67% PROPOSED TEST YEAR 216 PRINCIPAL AMOUNTS OUTSTANDING Average Monthly Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Line of credit (short-term debt) $57,972,53 $59,741,833 $63,619,95 $67,518,125 $66,34,534 $59,643,533 $76,39,879 $73,884,818 $68,68,491 $62,848,53 $55,742,695 $51,92,73 $96,52,54 $66,67,48 Interest $ 1,762,574 Embedded Cost of Short-Term Debt 2.67% 13

62 OTTER TAIL CORPORATION CONSOLIDATED RATE OF RETURN COST OF CAPITAL SCHEDULES Common Equity Docket No. E17/GR Exhibit (KGM-1) Financial Information Schedule D-4-b, Page 1 of 1 FISCAL YEAR 214 Average PRINCIPAL AMOUNTS OUTSTANDING Monthly Description Dec-13 Jan-14 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Common Stock 181,358,48 181,461, ,728,94 182,62, ,36, ,4, ,116, ,245,9 183,529,72 183,987,19 184,3,8 184,5, ,9, ,67,145 Premium on Common Stock 266,5, ,576, ,939, ,747, ,665,131 27,65, ,65, ,328,87 275,795,7 278,49, ,366,969 28,824, ,4, ,881,523 Common Stock Balance $447,48,973 $448,38,7 $449,668,637 $451,89,63 $452,25,686 $452,465,718 $456,766,841 $457,573,897 $459,324,727 $462,36,46 $462,397,769 $465,324,942 $475,49,761 $456,948,668 Retained Earnings Beginning Balance $77,81,616 $87,42,851 $94,52,912 $9,721,771 $97,864,466 $12,528,689 $95,366,415 $96,566,238 $1,93,586 $95,994,825 $11,25,56 $16,437,578 $1,862,892 $96,15,719 Net Income 7,194,536 7,97,594 7,191,443 7,141,418 4,678,971 3,884,995 1,428,24 4,335,235 6,232,52 5,257,372 5,229,882 5,615,558 (37,177) 4,993,661 Dividends (1,993,5) (11,35,774) (11,9,252) (11,141,259) (3,44,641) Other 2,415,7 2,467 2,467 1,277 (14,748) (11,495) (228,417) 2,114 (51,29) (46,692) 2,19 (48,985) (3,217,74) (91,761) End of Month Balance $87,42,851 $94,52,912 $9,721,771 $97,864,466 $12,528,689 $95,366,415 $96,566,238 $1,93,586 $95,994,825 $11,25,56 $16,437,578 $1,862,892 $97,274,974 $97,512,977 Total Electric Common Equity $534,829,825 $542,559,612 $54,39,48 $549,674,96 $554,554,376 $547,832,133 $553,333,78 $558,477,484 $555,319,552 $563,241,911 $568,835,347 $566,187,834 $572,765,735 $554,461,645 MOST RECENT FISCAL YEAR 215 Average PRINCIPAL AMOUNTS OUTSTANDING Monthly Description Dec-14 Jan-15 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Common Stock 186,9, ,423,4 186,821,2 187,114, ,419, ,464,66 187,827,95 187,958, ,3, ,63, ,74,76 189,398,28 191,27, ,937,93 Premium on Common Stock 289,4, ,194,89 293,632,54 295,33, ,156, ,533, ,278, ,845,632 3,454,372 31,847,145 32,248,664 35,463,48 312,889,64 298,636,631 Common Stock Balance $475,49,761 $477,618,29 $48,453,254 $482,445,792 $483,576,1 $483,997,978 $486,16,489 $486,84,557 $488,754,997 $49,477,72 $49,953,424 $494,861,76 $53,917,295 $486,573,724 Retained Earnings Beginning Balance $1,862,892 $97,274,974 $12,477,436 $12,2,455 $13,828,646 $16,873,134 $97,728,933 $13,61,59 $19,184,247 $13,112,541 $17,437,42 $111,69,25 $14,883,751 $13,929,515 Net Income (37,177) 5,22,418 11,187,812 1,544,699 3,19,94 2,486,337 5,93,43 5,555,498 5,518,415 4,317,792 4,225,685 4,95,142 5,84,96 4,567,197 Dividends (11,489,35) (11,537,481) (11,562,725) (11,655,466) (3,557,39) Other (3,217,74) 44 24,557 83,492 24,548 (93,57) (48,917) 18,69 (27,396) 7,87 (53,9) (2,13) (65,219) (259,72) End of Month Balance $97,274,974 $12,477,436 $12,2,455 $13,828,646 $16,873,134 $97,728,933 $13,61,59 $19,184,247 $13,112,541 $17,437,42 $111,69,25 $14,883,751 $11,623,492 $14,68,33 Total Electric Common Equity $572,765,735 $58,95,726 $582,653,79 $586,274,438 $59,449,234 $581,726,911 $589,716,548 $595,988,84 $591,867,538 $597,915,14 $62,562,629 $599,745,511 $614,54,787 $591,254,55 UNADJUSTED PROJECTED FISCAL YEAR 216 Average PRINCIPAL AMOUNTS OUTSTANDING Monthly Description Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Common Stock 191,27, ,166, ,333,21 191,656,36 191,824,9 192,593,93 194,36,44 194,175,33 194,875,66 196,32,9 196,73, ,712,94 198,36,5 193,811,78 Premium on Common Stock 312,889,64 313,54, ,515,19 316,39,26 316,216, ,719, ,173,61 326,8, ,987, ,182, ,471,84 338,39,43 344,318,37 325,323,747 Common Stock Balance $53,917,295 $54,671,277 $55,848,229 $57,695,62 $58,4,315 $512,313,799 $52,29,51 $52,975,656 $524,863,586 $531,214,456 $531,545,595 $535,13,343 $542,354,42 $519,134,824 Retained Earnings Beginning Balance $14,883,751 $11,623,492 $115,922,351 $19,333,454 $114,684,689 $118,392,465 $11,151,396 $114,311,173 $119,778,174 $114,48,182 $12,98,292 $125,24,29 $119,32,597 $115,133,42 Net Income 5,84,96 5,188,283 5,344,871 5,326,677 3,683,218 3,82,645 4,21,776 5,442,444 6,469,638 6,81,798 5,81,358 6,48,723 6,545,929 5,339,178 Dividends (11,958,326) (12,37,12) (12,179,729) (12,294,559) (3,728,441) Other (65,219) 11,576 24,558 24,558 24,558 (24,594) (51,) 24,558 (19,92) (31,689) 24,558 (15,775) 17,64 3,25 End of Month Balance $11,623,492 $115,922,351 $19,333,454 $114,684,689 $118,392,465 $11,151,396 $114,311,173 $119,778,174 $114,48,182 $12,98,292 $125,24,29 $119,32,597 $125,865,59 $116,747,389 Total Electric Common Equity $614,54,787 $62,593,628 $615,181,683 $622,38,39 $626,432,78 $622,465,195 $634,52,674 $64,753,83 $638,911,768 $651,312,748 $656,749,84 $654,45,94 $668,219,632 $635,882,214 PROPOSED TEST YEAR 216 Average PRINCIPAL AMOUNTS OUTSTANDING Monthly Description Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Common Stock 176,923,1 176,929,6 177,45, ,45, ,331, ,45,13 177,792, ,58, ,16,65 178,416, ,448, ,498, ,61,4 177,774,21 Premium on Common Stock 241,73,5 241,984, ,587,65 241,886,59 242,16, ,45, ,932, ,974, ,452,12 246,948, ,37, ,854,451 25,398,27 244,517,81 Common Stock Balance $418,653,6 $418,914,385 $418,633,315 $418,931,724 $419,492,652 $419,855,722 $421,725,28 $423,33,134 $423,558,77 $425,365,38 $425,819,66 $426,353,366 $429,459,427 $422,292,12 Retained Earnings Beginning Balance $253,628,479 $257,363,978 $259,293,424 $249,278,66 $25,57,357 $25,422,298 $24,821,999 $243,739,269 $248,58,855 $24,732,974 $244,89,72 $236,178,626 $239,596,325 $247,33,453 Net Income 5,47,996 2,14,632 1,217,475 1,156,28 (832,67) (4,873) 3,63,613 3,738,961 3,229,785 3,623,252 2,263,461 3,127,535 2,928,577 2,39,658 Dividends (1,717,835) (1,739,64) (1,781,228) (1,81,576) (2,4) (3,31,975) Other (1,312,497) (85,186) (514,458) 135, ,8 1,18,214 (686,343) 1,3,625 (224,438) 453,476 (92,961) 292,564 (488,373) 28,629 End of Month Balance $257,363,978 $259,293,424 $249,278,66 $25,57,357 $25,422,298 $24,821,999 $243,739,269 $248,58,855 $24,732,974 $244,89,72 $236,178,626 $239,596,325 $242,36,529 $246,411,765 Total Electric Common Equity $676,17,578 $678,27,89 $667,911,921 $669,52,81 $669,914,95 $66,677,721 $665,464,477 $671,541,989 $664,291,681 $67,175,1 $661,998,232 $665,949,691 $671,495,956 $668,73,777 14

63 OTTER TAIL CORPORATION CONSOLIDATED RATE OF RETURN COST OF CAPITAL SCHEDULES Common Equity Docket No. E17/GR Exhibit (KGM-1) Financial Information Schedule D-4-c, Page 1 of 1 FISCAL YEAR 214 Average PRINCIPAL AMOUNTS OUTSTANDING Monthly Description Dec-13 Jan-14 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Common Stock 181,358,48 181,461, ,728,94 182,62, ,36, ,4, ,116, ,245,9 183,529,72 183,987,19 184,3,8 184,5, ,9, ,67,145 Premium on Common Stock 266,5, ,576, ,939, ,747, ,665,131 27,65, ,65, ,328,87 275,795,7 278,49, ,366,969 28,824, ,4, ,881,523 Common Stock Balance $447,48,973 $448,38,7 $449,668,637 $451,89,63 $452,25,686 $452,465,718 $456,766,841 $457,573,897 $459,324,727 $462,36,46 $462,397,769 $465,324,942 $475,49,761 $456,948,668 Retained Earnings Beginning Balance $77,81,616 $87,42,851 $94,52,912 $9,721,771 $97,864,466 $12,528,689 $95,366,415 $96,566,238 $1,93,586 $95,994,825 $11,25,56 $16,437,578 $1,862,892 $96,15,719 Net Income 7,194,536 7,97,594 7,191,443 7,141,418 4,678,971 3,884,995 1,428,24 4,335,235 6,232,52 5,257,372 5,229,882 5,615,558 (37,177) 4,993,661 Dividends (1,993,5) (11,35,774) (11,9,252) (11,141,259) (3,44,641) Other 2,415,7 2,467 2,467 1,277 (14,748) (11,495) (228,417) 2,114 (51,29) (46,692) 2,19 (48,985) (3,217,74) (91,761) End of Month Balance $87,42,851 $94,52,912 $9,721,771 $97,864,466 $12,528,689 $95,366,415 $96,566,238 $1,93,586 $95,994,825 $11,25,56 $16,437,578 $1,862,892 $97,274,974 $97,512,977 Total Electric Common Equity $534,829,825 $542,559,612 $54,39,48 $549,674,96 $554,554,376 $547,832,133 $553,333,78 $558,477,484 $555,319,552 $563,241,911 $568,835,347 $566,187,834 $572,765,735 $554,461,645 MOST RECENT FISCAL YEAR 215 Average PRINCIPAL AMOUNTS OUTSTANDING Monthly Description Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Common Stock 186,9, ,423,4 186,821,2 187,114, ,419, ,464,66 187,827,95 187,958, ,3, ,63, ,74,76 189,398,28 191,27, ,937,93 Premium on Common Stock 289,4, ,194,89 293,632,54 295,33, ,156, ,533, ,278, ,845,632 3,454,372 31,847,145 32,248,664 35,463,48 312,889,64 298,636,631 Common Stock Balance $475,49,761 $477,618,29 $48,453,254 $482,445,792 $483,576,1 $483,997,978 $486,16,489 $486,84,557 $488,754,997 $49,477,72 $49,953,424 $494,861,76 $53,917,295 $486,573,724 Retained Earnings Beginning Balance $1,862,892 $97,274,974 $12,477,436 $12,2,455 $13,828,646 $16,873,134 $97,728,933 $13,61,59 $19,184,247 $13,112,541 $17,437,42 $111,69,25 $14,883,751 $13,929,515 Net Income (37,177) 5,22,418 11,187,812 1,544,699 3,19,94 2,486,337 5,93,43 5,555,498 5,518,415 4,317,792 4,225,685 4,95,142 5,84,96 4,567,197 Dividends (11,489,35) (11,537,481) (11,562,725) (11,655,466) (3,557,39) Other (3,217,74) 44 24,557 83,492 24,548 (93,57) (48,917) 18,69 (27,396) 7,87 (53,9) (2,13) (65,219) (259,72) End of Month Balance $97,274,974 $12,477,436 $12,2,455 $13,828,646 $16,873,134 $97,728,933 $13,61,59 $19,184,247 $13,112,541 $17,437,42 $111,69,25 $14,883,751 $11,623,492 $14,68,33 Total Electric Common Equity $572,765,735 $58,95,726 $582,653,79 $586,274,438 $59,449,234 $581,726,911 $589,716,548 $595,988,84 $591,867,538 $597,915,14 $62,562,629 $599,745,511 $614,54,787 $591,254,55 UNADJUSTED PROJECTED FISCAL YEAR 216 Average PRINCIPAL AMOUNTS OUTSTANDING Monthly Description Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Common Stock 191,27, ,166, ,333,21 191,656,36 191,824,9 192,593,93 194,36,44 194,175,33 194,875,66 196,32,9 196,73, ,712,94 198,36,5 193,811,78 Premium on Common Stock 312,889,64 313,54, ,515,19 316,39,26 316,216, ,719, ,173,61 326,8, ,987, ,182, ,471,84 338,39,43 344,318,37 325,323,747 Common Stock Balance $53,917,295 $54,671,277 $55,848,229 $57,695,62 $58,4,315 $512,313,799 $52,29,51 $52,975,656 $524,863,586 $531,214,456 $531,545,595 $535,13,343 $542,354,42 $519,134,824 Retained Earnings Beginning Balance $14,883,751 $11,623,492 $115,922,351 $19,333,454 $114,684,689 $118,392,465 $11,151,396 $114,311,173 $119,778,174 $114,48,182 $12,98,292 $125,24,29 $119,32,597 $115,133,42 Net Income 5,84,96 5,188,283 5,344,871 5,326,677 3,683,218 3,82,645 4,21,776 5,442,444 6,469,638 6,81,798 5,81,358 6,48,723 6,545,929 5,339,178 Dividends (11,958,326) (12,37,12) (12,179,729) (12,294,559) (3,728,441) Other (65,219) 11,576 24,558 24,558 24,558 (24,594) (51,) 24,558 (19,92) (31,689) 24,558 (15,775) 17,64 3,25 End of Month Balance $11,623,492 $115,922,351 $19,333,454 $114,684,689 $118,392,465 $11,151,396 $114,311,173 $119,778,174 $114,48,182 $12,98,292 $125,24,29 $119,32,597 $125,865,59 $116,747,389 Total Electric Common Equity $614,54,787 $62,593,628 $615,181,683 $622,38,39 $626,432,78 $622,465,195 $634,52,674 $64,753,83 $638,911,768 $651,312,748 $656,749,84 $654,45,94 $668,219,632 $635,882,214 PROPOSED TEST YEAR 216 Average PRINCIPAL AMOUNTS OUTSTANDING Monthly Description Dec-15 Jan-16 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Balances Common Stock 176,923,1 176,929,6 177,45, ,45, ,331, ,45,13 177,792, ,58, ,16,65 178,416, ,448, ,498, ,61,4 177,774,21 Premium on Common Stock 241,73,5 241,984, ,587,65 241,886,59 242,16, ,45, ,932, ,974, ,452,12 246,948, ,37, ,854,451 25,398,27 244,517,81 Common Stock Balance $418,653,6 $418,914,385 $418,633,315 $418,931,724 $419,492,652 $419,855,722 $421,725,28 $423,33,134 $423,558,77 $425,365,38 $425,819,66 $426,353,366 $429,459,427 $422,292,12 Retained Earnings Beginning Balance $253,628,479 $257,363,978 $259,293,424 $249,278,66 $25,57,357 $25,422,298 $24,821,999 $243,739,269 $248,58,855 $24,732,974 $244,89,72 $236,178,626 $239,596,325 $247,33,453 Net Income 5,47,996 2,14,632 1,217,475 1,156,28 (832,67) (4,873) 3,63,613 3,738,961 3,229,785 3,623,252 2,263,461 3,127,535 2,928,577 2,39,658 Dividends (1,717,835) (1,739,64) (1,781,228) (1,81,576) (2,4) (3,31,975) Other (1,312,497) (85,186) (514,458) 135, ,8 1,18,214 (686,343) 1,3,625 (224,438) 453,476 (92,961) 292,564 (488,373) 28,629 End of Month Balance $257,363,978 $259,293,424 $249,278,66 $25,57,357 $25,422,298 $24,821,999 $243,739,269 $248,58,855 $24,732,974 $244,89,72 $236,178,626 $239,596,325 $242,36,529 $246,411,765 Total Electric Common Equity $676,17,578 $678,27,89 $667,911,921 $669,52,81 $669,914,95 $66,677,721 $665,464,477 $671,541,989 $664,291,681 $67,175,1 $661,998,232 $665,949,691 $671,495,956 $668,73,777 15

64 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota Docket No. E17/GR Financial Information RATE STRUCTURE AND DESIGN INFORMATION MINNESOTA RULE RATE STRUCTURE AND DESIGN INFORMATION. The following rate structure and design information as required by part shall be filed: A. A summary comparison of test year operating revenue under present and proposed rates by customer class of service showing the difference in revenue and the percentage change. B. A detailed comparison of test year operating revenue under present and proposed rates by type of charge including minimum, demand, energy by block, gross receipts, automatic adjustments, and other charge categories within each rate schedule and within each customer class of service. C. A cost-of-service study by customer class of service, by geographic area, or other categorization as deemed appropriate for the change in rates requested, showing revenues, costs, and profitability for each class of service, geographic area, or other appropriate category, identifying the procedures and underlying rationale for cost and revenue allocations. Such study is appropriate whenever the utility proposes a change in rates which results in a material change in its rate structure. STAT AUTH: MS s 216B.3; 216B.8; 216B.16 Current as of 1/2/5 1

65 Docket No. E17/GR Exhibit (DGP-1), Schedule E-1 Page 1 of 1 Proposed Test Year 216 Operating Revenue Summary Comparison - By Rate Schedule Line No. Rate Schedule Operating Revenues Present Proposed Difference Percent Change Residential Service (Rate 11) $ 44,24,75 $ 48,938,424 $ 4,913, % Residential Demand Control (Rate 241) $ 4,531,949 $ 5,22,245 $ 67, % 3 Total Residential: $ 48,556,654 $ 54,14,669 $ 5,584, % Farm Service (Rate 361) $ 3,136,239 $ 3,418,51 $ 282,262 9.% 6 Total Farm: $ 3,136,239 $ 3,418,51 $ 282,262 9.% Small General Service - Under 2 kw - Metered Service Secondary (Rate 44) $ 9,772,258 $ 1,523,321 $ 751,63 7.7% Small General Service - Under 2 kw - Metered Service Primary (Rate 45) $ 4,931 $ 5,686 $ % Small General Service - Under 2 kw - Non-metered Service - 1, Watts and Under (Rate 48) $ 55,386 $ 56,434 $ 1,48 1.9% General Service - 2 kw or Greater - Secondary Service (Rate 41) $ 19,11,868 $ 2,451,891 $ 1,44,22 7.6% General Service - 2 kw or Greater - Primary Service (Rate 43) $ 284,526 $ 314,121 $ 29, % General Service - Time of Use (Commercial TOU) - (Rates 78, 79, 71) $ 2,272,532 $ 2,875,72 $ 63, % 14 Total General Service: $ 31,41,51 $ 34,227,171 $ 2,825,67 9.% Large General Service - Secondary Service (Rate 63) $ 25,118,917 $ 27,341,265 $ 2,222, % Large General Service - Primary Service (Rate 62) $ 3,66,952 $ 3,755,259 $ 148,37 4.1% Large General Service - Transmission Service (Rate 632) $ 291,492 $ 284,479 $ (7,13) -2.4% Large General Service Time of Day - Secondary Service (Rates 611, 615, 613) $ 9,335,529 $ 1,58,888 $ 1,245, % Large General Service Time of Day - Primary Service (Rates 61, 614, 612) $ 13,65,461 $ 15,658,41 $ 2,7, % Large General Service Time of Day - Transmission Service (Rates 639, 637, 64, 649) $ 46,483,316 $ 49,73,536 $ 3,247,22 7.% 22 Total Large General Service: $ 98,486,668 $ 17,35,468 $ 8,863,8 9.% Irrigation Service - Option 1: Non-Time-of-Use (Rate 73) $ 7,813 $ 89,997 $ 19, % Irrigation Service - Option 2 (Rates 74, 75, 76) $ 33,32 $ 387,331 $ 57, % 26 Total Irrigation: $ 41,116 $ 477,328 $ 76, % Outdoor Lighting - Metered - Energy Only (Rate 748) $ 28,245 $ 23,122 $ 21, % Outdoor Lighting - Non-Metered - Energy Only (Rate 749) $ 182,533 $ 2,916 $ 18, % Outdoor Lighting - Street & Area Lighting (Rate 745) $ 1,911,51 $ 2,2,94 $ 289, % Outdoor Lighting - Flood Lighting (Rate 746) $ 544,89 $ 585,333 $ 4, % 32 Total Lighting: $ 2,847,178 $ 3,217,311 $ 37, % Municipal Pumping - Secondary Service (Rate 871) $ 1,571,23 $ 1,775,516 $ 24, % Civil Defense - Fire Sirens (Rate 843) $ 4,68 $ 5,262 $ % 36 Total Other Public Authority: $ 1,575,91 $ 1,78,779 $ 24, % Water Heating - Controlled Service (Rate 191) $ 1,639,361 $ 1,827,887 $ 188, % 39 Total Water Heating: $ 1,639,361 $ 1,827,887 $ 188, % Controlled Service - Interruptible Load Rider CT Metering (Rates 17, 165, 881, 168, 268, 169, 269) $ 1,732,262 $ 1,928,336 $ 196, % Controlled Service - Interruptible Load Rider Self-Contained Metering (Rates 19, 185, 882) $ 5,429,881 $ 6,57,453 $ 627, % 43 Total Interruptible: $ 7,162,143 $ 7,985,789 $ 823, % Controlled Service - Deferred Load Rider (Rates 197, 195, 883) $ 997,335 $ 1,19,576 $ 112, % Fixed Time of Service Rider - Self-Contained Metering (Rates 31, 884) $ 329,429 $ 311,63 $ (17,799) -5.4% Fixed Time of Service Rider - CT Metering (Rates 32, 885) $ 283,626 $ 265,676 $ (17,95) -6.3% 48 Total Deferred Load: $ 1,61,389 $ 1,686,883 $ 76, % 49 5 TOTAL REVENUE: $ 196,817,16 $ 216,112,786 $ 19,295, % 2

66 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 1 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Pct Inc. Annual Residential Service (Rate 11) 2 Customer Charge Bills 46,471 $8.5 $8.5 $ 13.3 $ 13.3 $ 4,739,997 $ 7,416,78 $ 2,676,711 3 Seasonal Fixed Charge Bills 1,512 $34. $34. $53.2 $ 53.2 $ 51,417 $ 8,453 $ 29,36 4 Energy kwh 131,896, ,36, ,23,71 $.7976 $.8192 $.1125 $.935 $ 34,55,748 $ 41,51,861 $ 7,455,113 5 Water Heating Control Credit 14.1 Bills 6,133 -$4. -$4. -$8. -$8. $ (24,532) $ (49,64) $ (24,532) 6 Air Conditioning Control Rider 14.8 Bills 3,559 -$7. -$7. -$8.25 -$8.25 $ (24,913) $ (29,361) $ (4,448) 7 TailWinds Program 14.9 kwh 6,761 $.13 $.13 $.13 $.13 $ 8,827 $ 8,827 $ - 8 Small Power Producer 12.1 Bills - $3.7 $3.7 $3.7 $3.7 9 Total Base Revenue: $ 38,86,544 $ 48,938,424 $ 1,131,88 1 Adjustments for Riders included in Base Rates 11 Conservation Program Adjustment kwh 419,23,71 $.51 $.51 $ - $ - $ 213,69 $ - 12 Economic Recovery Rider Adjustment $ $38,86, % 7.23% $ - $ - $ 2,85,893 $ - 13 Fuel Adjustment kwh 419,23,71 $.92 $.92 $ - $ - $ 386,213 $ - 14 Transmission Rider Adjustment kwh 419,23,71 $.432 $.432 $ - $ - $ 1,812,365 $ - 15 Total Adjustments: $ 5,218,161 $ - $ (5,218,161) Residential Demand Control (Rate 241) 18 Customer Charge Bills 2,365 $11. $11. $17. $17. $ 312,224 $ 482,528 $ 17,34 19 Facilities Charge Bills 2,365 $5. $5. $7. $7. $ 141,92 $ 198,688 $ 56,768 2 Energy - All kwh kwh 1,845,771 44,662,252 55,58,23 $.4671 $.558 $.631 $.6324 $ 2,766,47 $ 3,478,72 $ 712, All kw kw 43,463 86,825 13,289 $6.8 $5.11 $8. $8. $ 77,935 $ 1,42,39 $ 334, Total Base Revenue: $ 3,928,485 $ 5,22,245 $ 1,273,76 23 Adjustments for Riders included in Base Rates 24 Conservation Program Adjustment kwh 55,58,23 $.51 $.51 $ - $ - $ 28,295 $ - $ (28,295) 25 Economic Recovery Rider Adjustment $ $3,928, % $.723 $ - $ - $ 284,48 $ - $ (284,48) 26 Fuel Adjustment kwh 55,58,23 $.92 $.92 $ - $ - $ 51,14 $ - $ (51,14) 27 Transmission Rider Adjustment kwh 55,58,23 $.432 $.432 $ - $ - $ 239,981 $ - $ (239,981) 28 Total Adjustments: $ 63,464 $ - $ (63,464) 29 3 Total Base Revenue for the COSS Class: $ 42,735,29 $ 54,14,669 $ 11,45, Total Adjustments for the COSS Class: $ 5,821,625 $ - $ (5,821,625) 32 Total for the COSS Class: $ 48,556,654 $ 54,14,669 $ 5,584, % Farm Service (Rate 361) 35 Customer Charge Bills 1,356 $12. $12. $18.5 $18.5 $ 195,229 $ 3,979 $ 15, Energy - All kwh kwh 9,577,241 22,815,761 32,393,2 $.7666 $.7873 $.195 $.95 $ 2,53,174 $ 3,99,24 $ 568,85 37 All Three Phase Facilities Bills 179 $8. $8. $9.5 $9.5 $ 17,17 $ 2,389 $ 3, Water Heating Control Credit 14.1 Bills 211 -$4. -$4. -$8. -$8. $ (844) $ (1,688) $ (844) 39 Air Conditioning Control Rider 14.8 Bills 58 -$7. -$7. -$8.25 -$8.25 $ (46) $ (479) $ (73) 4 TailWinds Program 14.9 kwh 212 $.13 $.13 $.13 $.13 $ 261 $ 261 $ - 41 Small Power Producer 12.1 Bills - $3.7 $3.7 $3.7 $ Total Base Revenue: $ 2,741,584 $ 3,418,486 $ 676,92 43 Adjustments for Riders included in Base Rates 44 Conservation Program Adjustment kwh 32,393,2 $.51 $.51 $ - $ - $ 16,512 $ - $ (16,512) 45 Economic Recovery Rider Adjustment % 2,741, % 7.23% $ - $ - $ 198,235 $ - $ (198,235) 46 Fuel Adjustment kwh 32,393,2 $.16 $.16 $ - $ - $ 34,399 $ - $ (34,399) 47 Transmission Rider Adjustment kwh 32,393,2 $.449 $.449 $ - $ - $ 145,58 $ - $ (145,58) 48 Total Adjustments: $ 394,654 $ - $ (394,654) 49 5 Total Base Revenue for the COSS Class: $ 2,741,585 $ 3,418,51 $ 676, Total Adjustments for the COSS Class: $ 394,654 $ - $ (394,654) 52 Total for the COSS Class: $ 3,136,239 $ 3,418,51 $ 282,262 9.% 3

67 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 2 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Small General Service - Under 2 kw - Metered Service Secondary (Rate 44) 56 Customer Charge Bills 8,36 $15.5 $15.5 $21.5 $21.5 $ 1,544,917 $ 2,142,949 $ 598,32 57 Seasonal Fixed Charge Bills 25 $62. $62. $86. $86. $ 12,938 $ 17,889 $ 4, Energy kwh 29,57,864 62,571,23 91,629,67 $.7579 $.7784 $.1426 $.8525 $ 7,7,626 $ 8,363,427 $ 1,292,82 59 Water Heating Control Credit 14.1 Bills 287 -$4. -$4. -$8. -$8. $ (1,148) $ (2,296) $ (1,148) 6 Air Conditioning Control Rider 14.8 Bills 7 -$7. -$7. -$8.25 -$8.25 $ (49) $ (58) $ (9) 61 TailWinds Program 14.9 kwh 1,83 $.13 $.13 $.13 $.13 $ 1,49 $ 1,49 $ - 62 Small Power Producer 12.1 Bills - $3.7 $3.7 $3.7 $ Total Base Revenue: $ 8,628,693 $ 1,523,321 $ 1,894, Adjustments for Riders included in Base Rates 65 Conservation Program Adjustment kwh 91,629,67 $.51 $.51 $ - $ - $ 46,78 $ - $ (46,78) 66 Economic Recovery Rider Adjustment % 8,628, % 7.23% $ - $ - $ 623,892 $ - $ (623,892) 67 Fuel Adjustment kwh 91,629,67 $.13 $.13 $ - $ - $ 94,657 $ - $ (94,657) 68 Transmission Rider Adjustment kwh 91,629,67 $.413 $.413 $ - $ - $ 378,38 $ - $ (378,38) 69 Total Adjustments: $ 1,143,565 $ - $ (1,143,565) Small General Service - Under 2 kw - Metered Service Primary (Rate 45) 72 Customer Charge Bills 4 $15.5 $15.5 $21.5 $21.5 $ 755 $ 1,48 $ Seasonal Fixed Charge Bills 3 $62. $62. $86. $86. $ 187 $ 258 $ Energy kwh 32,172 14,75 46,248 $.7331 $.7484 $.149 $.8149 $ 3,411 $ 4,38 $ Total Base Revenue: $ 4,354 $ 5,686 $ 1, Adjustments for Riders included in Base Rates 77 Conservation Program Adjustment kwh 46,248 $.51 $.51 $ - $ - $ 24 $ - $ (24) 78 Economic Recovery Rider Adjustment % 4, % 7.23% $ - $ - $ 315 $ - $ (315) 79 Fuel Adjustment kwh 46,248 $.13 $.13 $ - $ - $ 48 $ - $ (48) 8 Transmission Rider Adjustment kwh 46,248 $.413 $.413 $ - $ - $ 191 $ - $ (191) 81 Total Adjustments: $ 577 $ - $ (577) Small General Service - Under 2 kw - Non-metered Service - 1, Watts and Under (Rate 48) 84 Customer Charge Bills 35 $2. $2. $4.5 $4.5 $ 845 $ 1,92 $ 1,57 85 Seasonal Fixed Charge Bills - $62. $62. $86. $86. $ - $ - $ - 86 Energy kwh 24, , ,659 $.7715 $.7715 $.8843 $.8843 $ 47,544 $ 54,531 $ 6, Total Base Revenue: $ 48,39 $ 56,434 $ 8,44 88 Adjustments for Riders included in Base Rates 89 Conservation Program Adjustment kwh 616,659 $.51 $.51 $ - $ - $ 314 $ - $ (314) 9 Economic Recovery Rider Adjustment % 48, % 7.23% $ - $ - $ 3,499 $ - $ (3,499) 91 Fuel Adjustment kwh 616,659 $.13 $.13 $ - $ - $ 637 $ - $ (637) 92 Transmission Rider Adjustment kwh 616,659 $.413 $.413 $ - $ - $ 2,546 $ - $ (2,546) 93 Total Adjustments: $ 6,996 $ - $ (6,996) 94 Pct Inc. Annual 4

68 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 3 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual General Service - 2 kw or Greater - Secondary Service (Rate 41) 96 Customer Charge Bills 2,23 $19. $19. $35. $35. $ 52,237 $ 925,174 $ 422, Energy kwh 63,397, ,282, ,679,97 $.6791 $.7353 $.7788 $.8167 $ 14,174,449 $ 15,93,668 $ 1,729, Demand per kw kw 344,6 76,51 1,5,58 $1.22 $1.2 $3.63 $1.39 $ 1,139,86 $ 2,23,154 $ 1,9, Facilities Charge kw 1,428,61 $.6 $.6 $.97 $.97 $ 857,16 $ 1,382,42 $ 525,26 1 TailWinds Program 14.9 kwh 8,437 $.13 $.13 $.13 $.13 $ 1,968 $ 1,968 $ - 11 Water Heating Control Credit 14.1 Bills 3 -$4. -$4. -$8. -$8. $ (12) $ (241) $ (12) 12 Air Conditioning Control Rider 14.8 Bills 42 -$5. -$5. -$6. -$6. $ (21) $ (252) $ (42) 13 Total Base Revenue: $ 16,684,344 $ 2,451,891 $ 3,767, Adjustments for Riders included in Base Rates 15 Conservation Program Adjustment kwh 197,679,97 $.51 $.51 $ - $ - $ 1,768 $ - $ (1,768) 16 Economic Recovery Rider Adjustment % 16,684, % 7.23% $ - $ - $ 1,26,386 $ - $ (1,26,386) 17 Fuel Adjustment kwh 197,679,97 $.13 $.13 $ - $ - $ 24,213 $ - $ (24,213) 18 Transmission Rider Adjustment kwh 197,679,97 $.413 $.413 $ - $ - $ 816,158 $ - $ (816,158) 19 Total Adjustments: $ 2,327,525 $ - $ (2,327,525) General Service - 2 kw or Greater - Primary Service (Rate 43) 112 Customer Charge Bills 11 $19. $19. $24. $24. $ 2,468 $ 3,117 $ Energy kwh 1,468,897 1,678,75 3,147,62 $.6583 $.79 $.7527 $.783 $ 215,674 $ 241,995 $ 26, Demand per kw kw 7,719 9,75 17,469 $1.17 $.97 $4.2 $1.89 $ 18,488 $ 49,457 $ 3, Facilities Charge kw 3,157 $.4 $.4 $.65 $.65 $ 12,63 $ 19,552 $ 7, Total Base Revenue: $ 248,693 $ 314,121 $ 65, Adjustments for Riders included in Base Rates 118 Conservation Program Adjustment kwh 3,147,62 $.51 $.51 $ - $ - $ 1,64 $ - $ (1,64) 119 Economic Recovery Rider Adjustment % 248, % 7.23% $ - $ - $ 17,982 $ - $ (17,982) 12 Fuel Adjustment kwh 3,147,62 $.13 $.13 $ - $ - $ 3,252 $ - $ (3,252) 121 Transmission Rider Adjustment kwh 3,147,62 $.413 $.413 $ - $ - $ 12,995 $ - $ (12,995) 122 Total Adjustments: $ 35,834 $ - $ (35,834) General Service - Time of Use (Commercial TOU) - (Rates 78, 79, 71) 125 Customer Charge Bills 46 $19. $19. $27. $27. $ 1,561 $ 15,7 $ 4, Energy - Declared-Peak kwh 87, , ,785 $.2332 $ $ $.2819 $ 251,24 $ 187,413 $ (63,611) 127 Energy - Intermediate kwh 5,8,477 13,378,865 18,459,342 $.5162 $.473 $.7414 $.7478 $ 1,12,446 $ 1,377,94 $ 364, Energy - Off-Peak kwh 8,285,452 12,778,43 21,63,855 $.2331 $.355 $.4179 $.4997 $ 558,949 $ 984,732 $ 425, Demand per kw - Declared-Peak kw N/A N/A N/A N/A $ - $ - $ - 13 Demand per kw - Intermediate kw 37,94 73, ,311 $2.64 $1.36 $2.67 $2.69 $ 199,947 $ 298,687 $ 98, Demand per kw - Off-Peak kw $. $. $. $. $ - $ - $ Facilities Charge kw - $.6 $.6 $.97 $.97 $ 7,928 $ 12,787 $ 4, Forecasted WAPA Credits $ (133,75) $ 133, Total Base Revenue: $ 1,97,15 $ 2,875,72 $ 968, Adjustments for Riders included in Base Rates 136 Conservation Program Adjustment kwh 4,18,983 $.51 $.51 $ - $ - $ 2,446 $ - $ (2,446) 137 Economic Recovery Rider Adjustment % 1,97, % 7.23% $ - $ - $ 137,94 $ - $ (137,94) 138 Fuel Adjustment kwh 4,18,983 $.13 $.13 $ - $ - $ 41,435 $ - $ (41,435) 139 Transmission Rider Adjustment kwh 4,18,983 $.413 $.413 $ - $ - $ 165,597 $ - $ (165,597) 14 Total Adjustments: $ 365,381 $ - $ (365,381) Total Base Revenue for the COSS Class: $ 27,521,622 $ 34,227,171 $ 6,75, Total Adjustments for the COSS Class: $ 3,879,878 $ - $ (3,879,878) 144 Total for the COSS Class: $ 31,41,51 $ 34,227,171 $ 2,825,67 9.% Pct Inc. Annual 5

69 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 4 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Large General Service - Secondary Service (Rate 63) 148 Customer Charge Bills 531 $4. $4. $8. $8. $ 254,879 $ 59,759 $ 254, Energy - All kwh kwh 18,58,996 28,351, ,41,355 $.4618 $.5 $.5715 $.5993 $ 15,49,894 $ 18,66,993 $ 3,251,99 15 Demand per kw kw 311,145 6, ,713 $7.22 $6.7 $1.32 $7.36 $ 5,891,913 $ 7,631,194 $ 1,739, Facilities Charge <1, kw kw 34, , ,788 $.33 $.33 $.55 $.55 $ 35,18 $ 58,634 $ 23, Facilities Charge >=1, kw kw 22,922 45,27 68,192 $.24 $.24 $.45 $.45 $ 16,366 $ 3,687 $ 14, Total Base Revenue: $ 21,878,232 $ 27,341,265 $ 5,463, Adjustments for Riders included in Base Rates 155 Conservation Program Adjustment kwh 316,41,355 $.51 $.51 $ - $ - $ 161,291 $ - $ (161,291) 156 Economic Recovery Rider Adjustment % 21,878, % 7.23% $ - $ - $ 1,581,915 $ - $ (1,581,915) 157 Fuel Adjustment kwh 316,41,355 $.11 $.11 $ - $ - $ 348,14 $ - $ (348,14) 158 Transmission Rider Adjustment kw 911, $1.261 $ - $ - $ 1,149,465 $ - $ (1,149,465) 159 Total Adjustments: $ 3,24,685 $ - $ (3,24,685) Large General Service - Primary Service (Rate 62) 161 Customer Charge Bills 1 $4. $4. $8. $8. $ 4,683 $ 9,366 $ 4, Energy - All kwh kwh 17,45,72 33,198,59 5,243,581 $.4477 $.4821 $.5275 $.5487 $ 2,363,787 $ 2,72,54 $ 356, Demand per kw kw 43,18 8, ,395 $6.93 $5.76 $1.1 $7.1 $ 761,278 $ 994,541 $ 233, Facilities Charge - All kw kw 43,18 8, ,395 $.12 $.12 $.25 $.25 $ 13,482 $ 3,848 $ 17, Total Base Revenue: $ 3,143,231 $ 3,755,259 $ 612, Adjustments for Riders included in Base Rates 167 Conservation Program Adjustment kwh 5,243,581 $.51 $.51 $ - $ - $ 25,612 $ - $ (25,612) 168 Economic Recovery Rider Adjustment % 3,143, % 7.23% $ - $ - $ 227,273 $ - $ (227,273) 169 Fuel Adjustment kwh 5,243,581 $.11 $.11 $ - $ - $ 55,262 $ - $ (55,262) 17 Transmission Rider Adjustment kw 123,395 $ $ - $ - $ 155,574 $ - $ (155,574) 171 Total Adjustments: $ 463,72 $ - $ (463,72) Large General Service - Transmission Service (Rate 632) 174 Customer Charge Bills 1 $4. $4. $8. $8. $ 465 $ 929 $ Energy - All kwh kwh 1,521,139 3,23,98 4,751,237 $.4244 $.4533 $.4556 $.4679 $ 21,82 $ 22,429 $ 9, Demand per kw kw 2,779 5,732 8,511 $5.37 $4.97 $8.79 $6.75 $ 43,413 $ 63,121 $ 19, Facilities Charge kw 2,779 5,732 8,511 N/A N/A N/A N/A $ - $ - $ Total Base Revenue: $ 254,697 $ 284,479 $ 29, Adjustments for Riders included in Base Rates 18 Conservation Program Adjustment kwh 4,751,237 $.51 $.51 $ - $ - $ 2,422 $ - $ (2,422) 181 Economic Recovery Rider Adjustment % 254, % 7.23% $ - $ - $ 18,416 $ - $ (18,416) 182 Fuel Adjustment kwh 4,751,237 $.11 $.11 $ - $ - $ 5,226 $ - $ (5,226) 183 Transmission Rider Adjustment kw 8,511 $ $ - $ - $ 1,731 $ - $ (1,731) 184 Total Adjustments: $ 36,795 $ - $ (36,795) 185 Pct Inc. Annual 6

70 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 5 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Large General Service Time of Day - Secondary Service (Rates 611, 615, 613) 187 Customer Charge Bills 15 $6. $6. $12. $12. $ 1,963 $ 21,926 $ 1, Facilities Charge <1, kw kw 14,81 $.33 $.33 $.55 $.55 $ 1,786 $ 8,145 $ (2,641) 189 Facilities Charge >=1, kw kw 96,51 $.24 $.24 $.45 $.45 $ 53,789 $ 43,429 $ (1,36) 19 Energy - On-Peak kwh 9,716,559 1,436,912 2,153,471 $.7319 $.657 $.1139 $.8459 $ 2,382,3 1,867,957 $ (514,343) 191 Energy - Shoulder kwh 5,738,542 19,163,35 24,91,847 $.5397 $.4917 $.7712 $.7777 $ 2,99,79 1,932,949 $ (166,76) 192 Energy - Off-Peak kwh 32,646,675 61,871,47 94,518,82 $.2437 $.3665 $.4347 $.5197 $ 2,48,833 $ 4,634,457 $ 2,585, Demand per kw - On-Peak kw 85,33 161, ,769 $5.54 $5.13 $8.18 $5.21 $ 1,3,786 $ 1,538,211 $ 237, Demand per kw - Shoulder kw 85,48 163, ,683 $1.68 $.94 $ $ 296,964 $ 533,814 $ 236, Demand per kw - Off-Peak kw $. $. $. $. $ Total Base Revenue: $ 8,24,131 $ 1,58,888 $ 2,376, Adjustments for Riders included in Base Rates 198 Conservation Program Adjustment kwh 139,573,4 $.51 $.51 $ - $ - $ 71,148 $ - $ (71,148) 199 Economic Recovery Rider Adjustment % 8,24, % 7.23% $ - $ - $ 593,23 $ - $ (593,23) 2 Fuel Adjustment kwh 139,573,4 $.11 $.11 $ - $ - $ 153,514 $ - $ (153,514) 21 Transmission Rider Adjustment kw 248,683 $ $ - $ - $ 313,534 $ - $ (313,534) 22 Total Adjustments: $ 1,131,399 $ - $ (1,131,399) Large General Service Time of Day - Primary Service (Rates 61, 614, 612) 25 Customer Charge Bills 2 $6. $6. $12. $12. $ 3,554 $ 2,787 $ (766) 26 Facilities Charge - All kw kw 393,62 $.12 $.12 $.25 $.25 $ 53,392 $ 98,266 $ 44, Energy - On-Peak kwh 13,913,218 15,42,422 29,333,639 $.767 $.6251 $.9828 $.8134 $ 3,199,1 $ 2,621,621 $ (577,381) 28 Energy - Shoulder kwh 8,122,446 27,812,579 35,935,25 $.5228 $.4742 $.7499 $.751 $ 3,49,658 $ 2,695,363 $ (354,295) 29 Energy - Off-Peak kwh 5,825,384 96,34, ,129,755 $.2376 $.3546 $.4246 $.531 $ 3,197,97 $ 7,3,15 $ 3,86,8 21 Demand per kw - On-Peak kw 135, ,637 43,472 $5.32 $4.94 $7.86 $4.96 $ 2,44,768 $ 2,395,139 $ 35, Demand per kw - Shoulder kw 135,81 268,19 43,991 $1.61 $.82 $2.15 $2.5 $ 438,555 $ 841,761 $ 43, Demand per kw - Off-Peak kw 96, , ,542 $. $. $. $. $ - $ - $ Total Base Revenue: $ 11,986,25 $ 15,658,41 $ 3,672, Adjustments for Riders included in Base Rates 215 Conservation Program Adjustment kwh 212,398,419 $.51 $.51 $ - $ - $ 18,271 $ - $ (18,271) 216 Economic Recovery Rider Adjustment % 11,986, % 7.23% $ - $ - $ 866,655 $ - $ (866,655) 217 Fuel Adjustment kwh 212,398,419 $.11 $.11 $ - $ - $ 233,613 $ - $ (233,613) 218 Transmission Rider Adjustment kw 43,991 $1.128 $1.128 $ - $ - $ 455,898 $ - $ (455,898) 219 Total Adjustments: $ 1,664,436 $ - $ (1,664,436) 22 Pct Inc. Annual 7

71 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 6 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Large General Service Time of Day - Transmission Service (Rates 639, 637, 64) 222 Customer Charge Bills 7 $6. $6. $12. $12. $ 21,756 $ 1,8 $ 16, Customer Charge LGS RIDER Bills 7 $199. $199. $34. $34. $ - $ 28,56 $ Facilities Charge kw - N/A N/A N/A N/A $ - $ - $ Energy - On-Peak kwh 54,195,24 66,46,226 12,241,466 $.666 $.5844 $.8276 $.6764 $ 11,745,531 $ 8,952,772 $ (2,792,759) 226 Energy - Shoulder kwh 31,671, ,89, ,561,633 $.4952 $.446 $.6347 $.6268 $ 11,367,948 $ 9,211,197 $ (2,156,751) 227 Energy - Off-Peak kwh 188,818,85 394,378, ,196,9 $.2272 $.3352 $.362 $.4228 $ 12,365,644 $ 23,512,443 $ 11,146, Demand per kw - On-Peak kw 319,6 639,2 958,8 $4.31 $4.27 $ $ 4,615,72 $ 6,44,876 $ 1,429, Demand per kw - Shoulder kw 319,6 639,2 958,8 $1.6 $.7 $1.72 $1.88 $ 883,632 $ 1,97,68 $ 1,86, Demand per kw - Off-Peak kw 319,6 639,2 958,8 $. $. $. $. $ - $ - $ Nominated kw kw 1, $5.37 $4.97 $8.79 $6.75 $ - $ - $ Total Base Revenue: $ 41,,232 $ 49,73,536 $ 8,73, Adjustments for Riders included in Base Rates 234 Conservation Program Adjustment kwh 849,999,999 $.51 $.51 $ - $ - $ 433,29 $ - $ (433,29) 235 Economic Recovery Rider Adjustment % 41,, % 7.23% $ - $ - $ 2,964,539 $ - $ (2,964,539) 236 Fuel Adjustment kwh 849,999,999 $.11 $.11 $ - $ - $ 934,899 $ - $ (934,899) 237 Transmission Rider Adjustment kw 1,78, $1.66 $ - $ - $ 1,15,356 $ - $ (1,15,356) 238 Total Adjustments: $ 5,483,85 $ - $ (5,483,85) Total Base Revenue for the COSS Class: $ 86,466,549 $ 17,35,468 $ 2,883, Total Adjustments for the COSS Class: $ 12,2,119 $ - $ (12,2,119) 242 Total for the COSS Class: $ 98,486,668 $ 17,35,468 $ 8,863,8 9.% Standby Service - Option A: Firm - Secondary Service (Rates 947, 948, 949) 246 Customer Charge Bills - $199. $199. $ $ Facilities Charge per month per kw of Contracted Backup kw - $.7226 $.7226 $.55 $ Reservation Charge per kw of Contracted Backup kw - $.1677 $.537 $ $ Metered Demand per day per kw On-Peak Backup kw - $.7138 $.7373 $ $ Energy - On-Peak kwh - $.7319 $.657 $.1139 $ Energy - Shoulder kwh - $.5397 $.4917 $.7712 $ Energy - Off-Peak kwh - $.2437 $.3665 $.4347 $ Total: Pct Inc. Annual 8

72 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 7 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Standby Service - Option A: Firm - Primary Service (Rates 944, 945, 946) 256 Customer Charge Bills - $199. $199. $34.33 $ Facilities Charge per month per kw of Backup kw - $.5283 $.5283 $.45 $ Reservation Charge per kw of Contracted Backup kw - $.164 $.51 $ $ Metered Demand per day per kw On-Peak Backup kw - $.6838 $.73 $ $ Energy - On-Peak kwh - $.767 $.6251 $.9829 $ Energy - Shoulder kwh - $.5228 $.4742 $.7499 $ Energy - Off-Peak kwh - $.2376 $.3546 $.4246 $ Conservation Improvement Program Total: Standby Service - Option A: Firm - Transmission Service (Rates 941, 942, 943) 266 Customer Charge Bills - $199. $199. $34.33 $ Facilities Charge per month per kw of Backup kw - N/A N/A N/A N/A 268 Reservation Charge per kw of Contracted Backup kw - $.149 $.468 $ $ Metered Demand per day per kw On-Peak Backup kw - $.6367 $.6433 $ $ Energy - On-Peak kwh - $.666 $.5844 $.8276 $ Energy - Shoulder kwh - $.4952 $.446 $.6347 $ Energy - Off-Peak kwh - $.2272 $.3352 $.362 $ Conservation Improvement Program Total: Standby Service - Option B: Non-Firm - Secondary Service (Rates 956, 957, 958) 276 Customer Charge Bills - $199. $199. $ $ Facilities Charge per month per kw of Backup kw - $.7226 $.7226 $.55 $ Energy - On-Peak kwh - N/A N/A N/A N/A 279 Energy - Shoulder kwh - $.5397 $.4917 $.7712 $ Energy - Off-Peak kwh - $.2437 $.3665 $.4347 $ Conservation Improvement Program Total: Standby Service - Option B: Non-Firm - Primary Service (Rates 953, 954, 955) 284 Customer Charge Bills - $199. $199. $34.33 $ Facilities Charge per month per kw of Backup kw - $.5283 $.5283 $.45 $ Energy - On-Peak kwh - N/A N/A N/A N/A 287 Energy - Shoulder kwh - $.5228 $.4742 $.7499 $ Energy - Off-Peak kwh - $.2376 $.3546 $.4246 $ Conservation Improvement Program - 29 Total: Standby Service - Option B: Non-Firm - Transmission Service (Rates 95, 951, 952) 292 Customer Charge Bills - $199. $199. $34.33 $ Facilities Charge per month per kw of Backup kw - N/A N/A N/A N/A 294 Energy - On-Peak kwh - N/A N/A N/A N/A 295 Energy - Shoulder kwh - $.4952 $.446 $.6347 $ Energy - Off-Peak kwh - $.2272 $.3352 $.362 $ Conservation Improvement Program Total: Increase Annual Pct Inc. Annual 9

73 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 8 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Irrigation Service - Option 1: Non-Time-of-Use (Rate 73) 32 Customer Charge Bills 72 $2. $2. $8. $8. $ 1,7 $ 3,485 $ 2, Energy kwh 93,598 68,45 999,3 $.651 $.4291 $.879 $.689 $ 63,423 $ 86,512 $ 23, % Return of Distribution Facilities - 35 Total Base Revenue: $ 64,431 $ 89,997 $ 25, Adjustments for Riders included in Base Rates 37 Conservation Program Adjustment kwh 999,3 $.51 $.51 $ - $ - $ 59 $ - $ (59) 38 Economic Recovery Rider Adjustment % 64, % 7.23% $ - $ - $ 4,658 $ - $ (4,658) 39 Fuel Adjustment kwh 999,3 $.12 $.12 $ - $ - $ 1,199 $ - $ (1,199) 31 Transmission Rider Adjustment kwh 999,3 $.2 $.2 $ - $ - $ 17 $ - $ (17) 311 Total Adjustments: $ 6,383 $ - $ (6,383) Irrigation Service - Option 2 (Rates 74, 75, 76) 314 Customer Charge Bills 149 $6. $6. $18. $18. $ 6,242 $ 16,52 $ 9, Energy - Declared-Peak kwh 55, ,626 $ $.2261 $ $.3172 $ 22,26 $ 27,96 $ 4, Energy - Intermediate kwh 1,558,66 98,491 1,657,152 $.4236 $.488 $.1933 $ $ 67,758 $ 182,352 $ 114, Energy - Off-Peak kwh 1,237,582 84,42 1,321,624 $.1623 $.1816 $.6427 $.192 $ 21,578 $ 88,714 $ 67, Demand per kw - Declared-Peak kw 12, ,371 $. $. $. $. $ 33,121 $ - $ (33,121) 319 Demand per kw - Intermediate kw 2,422 3,592 24,13 $2.53 $1.3 $3. $3.3 $ 56,336 $ 73,117 $ 16, Demand per kw - Off-Peak kw 2,67 3,12 23,79 $. $. $. $. $ 53,253 $ - $ (53,253) % Return of Distribution Facilities - $ 42,61 $ - $ (42,61) 322 Total Base Revenue: $ 33,148 $ 387,331 $ 84, Adjustments for Riders included in Base Rates 324 Conservation Program Adjustment kwh 3,34,41 $.51 $.51 $ - $ - $ 1,547 $ - $ (1,547) 325 Economic Recovery Rider Adjustment % 33, % 7.23% $ - $ - $ 21,915 $ - $ (21,915) 326 Fuel Adjustment kwh 3,34,41 $.12 $.12 $ - $ - $ 3,641 $ - $ (3,641) 327 Transmission Rider Adjustment kwh 3,34,41 $.2 $.2 $ - $ - $ 51 $ - $ (51) 328 Total Adjustments: $ 27,154 $ - $ (27,154) Total Base Revenue for the COSS Class: $ 367,579 $ 477,328 $ 19, Total Adjustments for the COSS Class: $ 33,537 $ - $ (33,537) 332 Total for the COSS Class: $ 41,116 $ 477,328 $ 76, % Outdoor Lighting - Metered - Energy Only (Rate 748) 335 Customer Charge Bills 179 $2.5 $2.5 $5. $5. $ 5,367 $ 1,733 $ 5, Energy kwh 2,378,53 $.7518 $.7518 $.9226 $.9226 $ 178,83 $ 219,388 $ 4, Total Base Revenue: $ 184,196 $ 23,122 $ 45, Adjustments for Riders included in Base Rates 339 Conservation Program Adjustment kwh 2,378,53 $.51 $.51 $ - $ - $ 1,212 $ - $ (1,212) 34 Economic Recovery Rider Adjustment % 184, % 7.23% $ - $ - $ 13,317 $ - $ (13,317) 341 Fuel Adjustment kwh 2,378,53 $.16 $.16 $ - $ - $ 2,528 $ - $ (2,528) 342 Transmission Rider Adjustment kwh 2,378,53 $.294 $.294 $ - $ - $ 6,992 $ - $ (6,992) 343 Total Adjustments: $ 24,49 $ - $ (24,49) 344 Pct Inc. Annual 1

74 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 9 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Outdoor Lighting - Non-Metered - Energy Only (Rate 749) 346 kwh 2,177,821 $. $. $. $. 347 Monthly charge for connected KW kw 531 $ $ $31.52 $31.52 $ 161,61 $ 2,916 $ 39, Total Base Revenue: $ 161,61 $ 2,916 $ 39, Adjustments for Riders included in Base Rates 35 Conservation Program Adjustment kwh 2,177,821 $.51 $.51 $ - $ - $ 1,11 $ - $ (1,11) 351 Economic Recovery Rider Adjustment % 161, % 7.23% $ - $ - $ 11,644 $ - $ (11,644) 352 Fuel Adjustment kwh 2,177,821 $.16 $.16 $ - $ - $ 2,315 $ - $ (2,315) 353 Transmission Rider Adjustment kwh 2,177,821 $.294 $.294 $ - $ - $ 6,43 $ - $ (6,43) 354 Total Adjustments: $ 21,473 $ - $ (21,473) Outdoor Lighting - Street & Area Lighting (Rate 745) 357 Type: kwh/lt Annual Kwh Quantity 358 MV-6 Lts 7 2,148,589 3,694 $7.1 $7.1 $8.87 $ MV-6PT Lts 7 44,69 63 $9.27 $9.27 $11.57 $ MV-11 Lts 1 32, $13.28 $13.28 $16.58 $ MV-21 Lts ,5 14 $17.17 $17.17 $21.44 $ MV-35 Lts $25.87 $25.87 $32.3 $ MV-55 Lts $35.54 $35.54 $44.38 $ MH-8 Lts ,24 4,518 $8.8 $8.8 $1.9 $ MH-8PT Lts $11.48 $11.48 $14.33 $ MH-14 Lts $15.39 $15.39 $19.22 $ MH-2 Lts 98 7, $17.57 $17.57 $21.94 $ MH-36 Lts , $17.24 $17.24 $21.53 $ MH-11 Lts , $36.8 $36.8 $45.95 $ HPS-9 Lts 44 6,536, ,564 $7.9 $7.9 $9.86 $ HPS-9PT Lts ,943 3,749 $9.54 $9.54 $11.91 $ HPS-14 Lts ,735 6,527 $12.25 $12.25 $15.3 $ HPS-14PT Lts 64 37, $12.23 $12.23 $15.27 $ HPS-19 Lts ,536 4,296 $14.19 $14.19 $17.72 $ HPS-23 Lts ,872 4,783 $16.3 $16.3 $2.2 $ HPS-44 Lts ,426 1,58 $19.86 $19.86 $24.8 $ UMV6 Lts 7 26, $9.22 $9.22 $11.51 $ UMV-55 Lts 366 4,38 12 $37.66 $37.66 $47.2 $ UHPS9 Lts 44 6,179 1,368 $1.2 $1.2 $12.51 $ UHPS19 Lts 83 5, $16.31 $16.31 $2.37 $ UHPS23 Lts 12 3,77 3 $18.15 $18.15 $22.66 $ UMH-8 Lts $1.2 $1.2 $12.74 $ UHPS14 Lts 64 1, $14.37 $14.37 $17.94 $ UHPS44 Lts 156 5, $21.98 $21.98 $27.44 $ Lts $4.5 $4.5 $5.62 $ SIGN Lts 25 38, $15.41 $15.41 $19.24 $ Seasonal Fixed Charge Bills $27.59 $27.59 $34.45 $ Total: $ 1,761,35 $ 2,2,94 $ 464, Closed non standard lighting 45,583 $ 18, MH Lights that were not accounted for in the forecast (245,47) $ (43,695) 391 Total Base Revenue: 11,86,522 $ 1,735, Adjustments for Riders included in Base Rates 394 Conservation Program Adjustment kwh 11,86,522 $.51 $.51 $ - $ - $ 5,651 $ - $ (5,651) 395 Economic Recovery Rider Adjustment % 1,735, % 7.23% $ - $ - $ 125,54 $ - $ (125,54) 396 Fuel Adjustment kwh 11,86,522 $.16 $.16 $ - $ - $ 11,785 $ - $ (11,785) 397 Transmission Rider Adjustment kwh 11,86,522 $.294 $.294 $ - $ - $ 32,597 $ - $ (32,597) 398 Total Adjustments: $ 175,538 $ - $ (175,538) 399 Pct Inc. Annual 11

75 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 1 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Outdoor Lighting - Flood Lighting (Rate 746) 41 Type: kwh/lt Annual Kwh Quantity 42 4 MVF* Lts 156 $17.17 $17.17 $21.44 $ MAF Lts 156 1,12,14 7, $2.14 $25.15 $ HPSF Lts 156 1,587,617 1, $19.86 $24.8 $ MVF Lts , $33.76 $42.15 $ MAF Lts 371 1,17,377 2, $37.32 $46.6 $ U4MAF Lts , $22.26 $27.79 $ U4MVF Lts 154 7, $21.41 $26.73 $ U4CHPSF Lts 156 3, $21.98 $27.44 $ U1M-MAF Lts , $39.44 $49.25 $ M-HPSF Lts 371 4, $37.32 $46.6 $ ,97, Seasonal Fixed Charge Bills - $27.59 $27.59 $34.45 $ Total Base Revenue: $ 491,76 $ 585,333 $ 93, Adjustments for Riders included in Base Rates 416 Conservation Program Adjustment kwh 3,97,568 $.51 $.51 $ - $ - $ 1,992 $ - $ (1,992) 417 Economic Recovery Rider Adjustment % 491, % 7.23% $ - $ - $ 35,548 $ - $ (35,548) 418 Fuel Adjustment kwh 3,97,568 $.16 $.16 $ - $ - $ 4,154 $ - $ (4,154) 419 Transmission Rider Adjustment kwh 3,97,568 $.294 $.294 $ - $ - $ 11,489 $ - $ (11,489) 42 Total Adjustments: $ 53,183 $ - $ (53,183) Total Base Revenue for the COSS Class: $ 2,572,935 $ 3,217,311 $ 644, Total Adjustments for the COSS Class: $ 274,243 $ - $ (274,243) 424 Total for the COSS Class: $ 2,847,178 $ 3,217,311 $ 37, % Municipal Pumping - Secondary Service (Rate 871) 429 Customer Charge Bills 51 $4. $4. $12. $12. $ 24,52 $ 73,55 $ 49,3 43 Facilities Charge kw 116,863 $.14 $.14 $.97 $.97 $ 16,361 $ 113,357 $ 96, Energy - All kwh kwh 6,814,819 13,86,182 2,621,1 $.6298 $.6468 $.8976 $.776 $ 1,322,594 $ 1,588,654 $ 266, Total Base Revenue: $ 1,363,456 $ 1,775,516 $ 412,6 433 Adjustments for Riders included in Base Rates 434 Conservation Program Adjustment kwh 2,621,1 $.51 $.51 $ - $ - $ 1,512 $ - $ (1,512) 435 Economic Recovery Rider Adjustment % 1,363, % 7.23% $ - $ - $ 98,59 $ - $ (98,59) 436 Fuel Adjustment kwh 2,621,1 $.15 $.15 $ - $ - $ 21,726 $ - $ (21,726) 437 Transmission Rider Adjustment kwh 2,621,1 $.373 $.373 $ - $ - $ 76,945 $ - $ (76,945) 438 Total Adjustments: $ 27,774 $ - $ (27,774) Municipal Pumping -Primary Service (Rate 874) 441 Customer Charge Bills - $4. $4. $12. $ Facilities Charge kw - $.9 $.9 $.65 $ Energy - All kwh kwh - $.691 $.6219 $.8652 $ Total Base Revenue: $ - $ - $ Pct Inc. Annual 12

76 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 11 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Civil Defense - Fire Sirens (Rate 843) 447 Customer Charge Bills - $1. $1. $1.22 $1.22 $ 36 $ 439 $ Load Charge HP - $ $ $.7254 $.7254 $ 4,365 $ 5,262 $ Total Base Revenue: $ 4,365 $ 5,262 $ Adjustments for Riders included in Base Rates 451 Conservation Program Adjustment kwh - $.51 $.51 $ - $ - $ - $ - $ Economic Recovery Rider Adjustment % 4, % 7.23% $ - $ - $ 315 $ - $ (315) 453 Fuel Adjustment kwh - $.15 $.15 $ - $ - $ - $ - $ Transmission Rider Adjustment kwh - $.373 $.373 $ - $ - $ - $ - $ Total Adjustments: $ 315 $ - $ (315) Total Base Revenue for the COSS Class: $ 1,367,821 $ 1,78,779 $ 412, Total Adjustments for the COSS Class: $ 28,89 $ - $ (28,89) 459 Total for the COSS Class: $ 1,575,91 $ 1,78,779 $ 24, % Water Heating - Controlled Service (Rate 191) 463 Customer Charge Bills 8,149 $2. $2. $4. $4. $ 195,579 $ 391,157 $ 195, Energy - All kwh kwh 6,72,421 14,181,493 2,883,914 $.5919 $.6328 $.7631 $.6524 $ 1,294,472 $ 1,436,731 $ 142, Total Base Revenue: $ 1,49,51 $ 1,827,888 $ 337, Adjustments for Riders included in Base Rates 467 Conservation Program Adjustment kwh 2,883,914 $.51 $.51 $ - $ - $ 1,646 $ - $ (1,646) 468 Economic Recovery Rider Adjustment % 1,49, % 7.23% $ - $ - $ 17,722 $ - $ (17,722) 469 Fuel Adjustment kwh 2,883,914 $.16 $.16 $ - $ - $ 22,194 $ - $ (22,194) 47 Transmission Rider Adjustment kwh 2,883,914 $.42 $.42 $ - $ - $ 8,748 $ - $ (8,748) 471 Total Adjustments: $ 149,31 $ - $ (149,31) Total Base Revenue for the COSS Class: 2,883,914 $ 1,49,51 $ 1,827,887 $ 337, Total Adjustments for the COSS Class: $ 149,31 $ - $ (149,31) 475 Total for the COSS Class: $ 1,639,361 $ 1,827,887 $ 188, % Real Time Pricing - Secondary Service (Rate 664) 478 Administrative Charge Bills - $ 199. $ 199. $34. $ Consumption Change from CBL kwh - 48 Conservation Improvement Program Total: Real Time Pricing - Primary Service (Rate 662) 483 Administrative Charge Bills - $ 199. $ 199. $34. $ Consumption Change from CBL kwh Conservation Improvement Program Total: Real Time Pricing - Transmission Service (Rate 66) 488 Administrative Charge Bills - $199. $199. $34. $ Consumption Change from CBL kwh - 49 Conservation Improvement Program Total: Large General Service Rider 493 Administrative Charge Bills - $199. $199. $34. $ Fixed Rate Energy Pricing (FREP) Peak kwh Fixed Rate Energy Pricing (FREP) Shoulder kwh Fixed Rate Energy Pricing (FREP) Off-Peak kwh Capacity Purchase kw Conservation Improvement Program Total: 5 Pct Inc. Annual 13

77 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 12 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Controlled Service - Interruptible Load Rider CT Metering - Option 1 (Rates 17, 165, 881) 52 Customer Charge Bills 236 $5. $5. $7. $7. $ 14,181 $ 19,853 $ 5, Facilities Charge kw 21,3 $.12 $.12 $.18 $.18 $ 3,672 $ 46,8 $ 15, Energy - All kwh kwh 3,614,624 36,258,37 39,872,661 $.3455 $.3745 $.4888 $.4649 $ 1,48,755 $ 1,862,475 $ 381,72 55 Penalty kwh kwh 1,596 68,819 79,415 $.1523 $.1553 $.3896 $ $ 15,241 $ - $ (15,241) 56 Total Base Revenue: $ 1,54,849 $ 1,928,336 $ 387, Adjustments for Riders included in Base Rates 58 Conservation Program Adjustment kwh 39,952,76 $.51 $.51 $ - $ - $ 2,366 $ - $ (2,366) 59 Economic Recovery Rider Adjustment % 1,54, % 7.23% $ - $ - $ 111,399 $ - $ (111,399) 51 Fuel Adjustment kwh 39,952,76 $.6 $.6 $ - $ - $ 23,996 $ - $ (23,996) 511 Transmission Rider Adjustment kwh 39,952,76 $.71 $.71 $ - $ - $ 28,542 $ - $ (28,542) 512 Total Adjustments: $ 184,33 $ - $ (184,33) Controlled Service - Interruptible Load Rider CT Metering - Option 2 (Rates 168, 268, 169, 269) 515 Customer Charge Bills 2 $6. $6. $7. $7. $ 112 $ - $ (112) 516 Facilities Charge kw 827 $.12 $.12 $.18 $.18 $ 99 $ - $ (99) 517 Energy - All kwh kwh 13,71 126,576 14,286 $.3725 $.438 $.5873 $.5586 $ 5,653 $ - $ (5,653) 518 Control Period Demand kw $7.22 $6.7 $1.32 $7.36 $ 527 $ - $ (527) 519 Total Base Revenue: $ 6,39 $ - $ (6,39) 52 Adjustments for Riders included in Base Rates 521 Conservation Program Adjustment kwh 141,23 $.51 $.51 $ - $ - $ 72 $ - $ (72) 522 Economic Recovery Rider Adjustment % 6, % 7.23% $ - $ - $ 462 $ - $ (462) 523 Fuel Adjustment kwh 141,23 $.6 $.6 $ - $ - $ 85 $ - $ (85) 524 Transmission Rider Adjustment kwh 141,23 $.71 $.71 $ - $ - $ 11 $ - $ (11) 525 Total Adjustments: $ 719 $ - $ (719) Controlled Service - Interruptible Load Rider Self-Contained Metering (Rates 19, 185, 882) 528 Customer Charge Bills 5,469 $2. $2. $4. $4. $ 154,538 $ 262,494 $ 17, Facilities Charge Bills 5,469 $5. $5. $8. $8. $ 386,345 $ 524,988 $ 138, Energy - All kwh kwh 9,659,44 84,177,467 93,836,97 $.4291 $.4693 $.5946 $.5578 $ 4,362,313 $ 5,269,971 $ 97, Penalty kwh kwh 96 4,16 4,22 $.1572 $.1693 $ $ $ 892 $ (892) 532 Total Base Revenue: $ 4,94,89 $ 6,57,453 $ 1,153, Adjustments for Riders included in Base Rates 534 Conservation Program Adjustment kwh 93,841,11 $.51 $.51 $ - $ - $ 47,836 $ - $ (47,836) 535 Economic Recovery Rider Adjustment % 4,94, % 7.23% $ - $ - $ 354,552 $ - $ (354,552) 536 Fuel Adjustment kwh 93,841,11 $.6 $.6 $ - $ - $ 56,363 $ - $ (56,363) 537 Transmission Rider Adjustment kwh 93,841,11 $.71 $.71 $ - $ - $ 67,41 $ - $ (67,41) 538 Total Adjustments: $ 525,792 $ - $ (525,792) Total Base Revenue for the COSS Class: $ 6,451,328 $ 7,985,789 $ 1,534, Total Adjustments for the COSS Class: $ 71,815 $ - $ (71,815) 543 Total for the COSS Class: $ 7,162,143 $ 7,985,789 $ 823, % Pct Inc. Annual 14

78 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 13 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Controlled Service - Deferred Load Rider (Rates 197, 195, 883) 548 Customer Charge Bills 1,77 $2. $2. $4. $4. $ 25,85 $ 51,71 $ 25, Facilities Charge Bills 1,77 $4. $4. $8. $8. $ 51,71 $ 66,668 $ 14, Energy - All kwh kwh 965,145 12,987,295 13,952,439 $.5588 $.5975 $.7132 $.712 $ 829,293 $ 991,27 $ 161, Penalty kwh kwh $ $ $ $.1898 $ 14 $ (14) 552 Total Base Revenue: $ 96,948 $ 1,19,576 $ 22, Adjustments for Riders included in Base Rates 554 Conservation Program Adjustment kwh 13,952,923 $.51 $.51 $ - $ - $ 7,113 $ - $ (7,113) 555 Economic Recovery Rider Adjustment % 96, % 7.23% $ - $ - $ 65,569 $ - $ (65,569) 556 Fuel Adjustment kwh 13,952,923 $.49 $.49 $ - $ - $ 6,87 $ - $ (6,87) 557 Transmission Rider Adjustment kwh 13,952,923 $.78 $.78 $ - $ - $ 1,898 $ - $ (1,898) 558 Total Adjustments: $ 9,387 $ - $ (9,387) Fixed Time of Service Rider - Self-Contained Metering (Rates 31, 884) 561 Customer Charge Bills 533 $1.5 $1.5 $3. $3. $ 9,6 $ 19,2 $ 9,6 562 Facilities Charge Bills 533 $3. $3. $4. $4. $ 19,2 $ 25,6 $ 6,4 563 Energy - All kwh kwh 196,34 7,524,15 7,72,319 $.1626 $.3325 $.2861 $.3472 $ 253,749 $ 266,829 $ 13,8 564 Penalty kwh kwh 11,84 155,51 166,594 $.5676 $.365 $.4634 $.1761 $ 11,586 $ (11,586) 565 Total Base Revenue: $ 294,136 $ 311,63 $ 17, Adjustments for Riders included in Base Rates 567 Conservation Program Adjustment kwh 7,886,913 $.51 $.51 $ - $ - $ 4,2 $ - $ (4,2) 568 Economic Recovery Rider Adjustment % 294, % 7.23% $ - $ - $ 21,265 $ - $ (21,265) 569 Fuel Adjustment kwh 7,886,913 $.49 $.49 $ - $ - $ 3,848 $ - $ (3,848) 57 Transmission Rider Adjustment kwh 7,886,913 $.78 $.78 $ - $ - $ 6,16 $ - $ (6,16) 571 Total Adjustments: $ 35,293 $ - $ (35,293) Fixed Time of Service Rider - CT Metering (Rates 32, 885) 574 Customer Charge Bills 76 $2. $2. $4. $4. $ 1,827 $ 3,655 $ 1, Facilities Charge Bills 76 $16. $16. $24. $24. $ 14,619 $ 21,929 $ 7, Energy - All kwh kwh 196,185 6,753,98 6,95,166 $.1626 $.3325 $.2861 $.3472 $ 228,15 $ 24,92 $ 11, Penalty kwh kwh 6,87 111, ,338 $.5676 $.365 $.4634 $.1761 $ 8,226 $ (8,226) 578 Total Base Revenue: $ 252,778 $ 265,676 $ 12, Adjustments for Riders included in Base Rates 58 Conservation Program Adjustment kwh 7,68,54 $.51 $.51 $ - $ - $ 3,63 $ - $ (3,63) 581 Economic Recovery Rider Adjustment % 252, % 7.23% $ - $ - $ 18,275 $ - $ (18,275) 582 Fuel Adjustment kwh 7,68,54 $.49 $.49 $ - $ - $ 3,448 $ - $ (3,448) 583 Transmission Rider Adjustment kwh 7,68,54 $.78 $.78 $ - $ - $ 5,521 $ - $ (5,521) 584 Total Adjustments: $ 3,847 $ - $ (3,847) Fixed Time of Service Rider - Primary CT Metering (Rates 33, 886) 587 Customer Charge Bills - $5. $5. $5.5 $ Facilities Charge Bills - $8. $8. $12. $ Energy - All kwh kwh - $.162 $.3312 $.285 $ Penalty kwh kwh - $.567 $.3592 $.4622 $ Pct Inc. Annual 15

79 Docket No. E17/GR Exhibit (DGP-1), Schedule E-2 Page 14 of 14 Proposed Test Year 216 Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units Line No. Charge Units Billing Units Present Rate Proposed Rate Present Operating Revenues Proposed Operating Revenues Summer Winter Annual Summer Winter Summer Winter Annual Annual Increase Annual Off-Peak Electric Vechicle Rider (Rates 781, 887, 782,888, 783, 889) 593 Self-Contained Metering 594 Customer Charge Bills - $1.5 $1.5 $3. $ Facilities Charge Bills - $3. $3. $4. $ Energy - All kwh kwh - $.2962 $.4661 $.4197 $ Penalty kwh kwh - $.5676 $.365 $.4634 $ CT Metering 599 Customer Charge Bills - $2. $2. $4. $4. 6 Facilities Charge Bills - $16. $16. $24. $ Energy - All kwh kwh - $.2962 $.4661 $.4197 $ Penalty kwh kwh - $.5676 $.365 $.4634 $ Primary CT Metering 64 Customer Charge Bills - $5. $5. $5.5 $ Facilities Charge Bills - $8. $8. $12. $ Energy - All kwh kwh - $.2956 $.4648 $.4186 $ Penalty kwh kwh - $.567 $.3592 $.4622 $ Total Base Revenue for the COSS Class: $ 1,453,862 $ 1,686,883 $ 233, Total Adjustments for the COSS Class: $ 156,527 $ - $ (156,527) 612 Total for the COSS Class: $ 1,61,389 $ 1,686,883 $ 76, % Total Base Revenue: $ 173,168,361 $ 216,112,786 $ 42,944, Total Adjustments: $ 23,648,797 $ - $ (23,648,797) 618 TOTAL : $ 196,817,16 $ 216,112,786 $ 19,295, % Pct Inc. Annual 16

80 Volume 3 E. Rate Structure and Design Information (Rule ) 3. Class Cost of Service Study 1/5

81 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year MN Rate Case COSS 13 MA (values from pull report) - BASE CASE without MISO E (Test Year COSS) scenario MINNESOTA Page 1-2 Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Rate Base 483,, ,429,895 8,323,74 76,327,94 233,653,888 1,396,55 7,684,777 4,7,582 5,137,564 15,89,293 3,85, Total Available for Return 27,665,121 5,475,672 52,32 5,279,341 15,17,222 21, ,845 22,446 23,49 529,241 21, Rate of Return Earned 5.73% 4.3% 6.25% 6.92% 6.43% 1.55% 5.14% 4.97%.45% 3.33% 6.54% 6 7 Rate of Return Requested 8.7% 8.7% 8.7% 8.7% 8.7% 8.7% 8.7% 8.7% 8.7% 8.7% 8.7% 8 9 Operating Income Required 38,978,147 1,283, ,723 6,159,662 18,855, ,698 62, , ,61 1,282, , Total Available for Return 27,665,121 5,475,672 52,32 5,279,341 15,17,222 21, ,845 22,446 23,49 529,241 21, Operating Income Defeciency 11,313,26 4,87,92 151,691 88,321 3,838,647 91,7 225, ,5 391, ,15 47, Incremental Taxes GRCF = 7,982,61 3,392,524 17,35 621,164 2,78,593 64,26 158,986 88, , ,4 33, Revenue Increase Required 19,295,626 8,2, ,726 1,51,485 6,547, , ,33 214, ,836 1,284,55 8, Percentage Increase 9.8% 16.89% 8.25% 4.78% 6.65% 38.72% 13.5% 13.64% 4.74% 17.93% 5.2%

82 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 2-2 Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Electric Plant in Service 933,541, ,96,581 16,31, ,836, ,843,812 2,985,154 15,913,852 7,864,792 1,781,965 31,863,775 6,188, Accumulated Depreciation (346,149,231) (94,296,163) (6,176,27) (55,63,53) (16,466,17) (1,28,85) (6,558,19) (2,914,581) (4,516,394) (12,454,384) (2,422,942) 4 5 Net Plant Excluding Big Stone Plant Capitalized Items 587,392, ,664,417 1,125,692 92,773, ,377,642 1,74,34 9,355,662 4,95,211 6,265,571 19,49,391 3,765, Net Capitalized Items - Big Stone Plant 8 9 Net Electric Plant in Service 587,392, ,664,417 1,125,692 92,773, ,377,642 1,74,34 9,355,662 4,95,211 6,265,571 19,49,391 3,765, Plant Held for Future Use 13,813 4, ,367 4, Construction Work in Progress 12,95,889 3,728, ,428 2,127,46 5,941,59 33, ,213 18, , ,815 61, Materials and Supplies 9,48,372 2,714, ,43 1,527,52 3,996,76 45, ,63 78,42 15, ,11 71, Fuel Stocks 5,824,626 1,21,687 85,16 873,866 3,53,22 39,132 51,2 19,329 17,51 25, Prepayments (5,679,13) (1,495,354) (97,899) (896,969) (2,749,47) (16,478) (9,454) (47,861) (6,578) (187,657) (36,411) 2 21 Customer Advances (1,34,643) (272,429) (17,836) (163,413) (5,98) (3,2) (16,479) (8,719) (11,36) (34,188) (6,633) Cash Working Capital 4,95,898 1,299,24 73,16 732,743 2,376,24 11,773 7,864 4,255 52,45 27,99 41, Accumulated Deferred Income Taxes (13,736,575) (34,423,834) (2,253,687) (2,648,692) (63,294,253) (379,329) (2,82,3) (1,11,774) (1,394,535) (4,319,97) (838,21) Unamortized CIP Tracker Unamortized Rate Case Expense Total Average Rate Base 483,, ,429,895 8,323,74 76,327,94 233,653,888 1,396,55 7,684,777 4,7,582 5,137,564 15,89,293 3,85,

83 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 3-2 1// 12: AM Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Plant in Service 2 A/C 11 & 16 - Direct MN Direct MN 3,487, ,67 5, ,56 2,43,117 1,241 22,914 29,984 15,132 58,577 19,64 3 A/C 11 & 16 - Direct ND Direct ND 4 A/C 11 & 16 - Direct SD Direct SD 5 Subtotal A/C 11 & 16 - Direct Assigned 3,487, ,67 5, ,56 2,43,117 1,241 22,914 29,984 15,132 58,577 19, Production Plant 8 A/C 11 & 16 - Base Demand E1-E ,84,14 46,76,186 3,395,546 35,261,882 15,48,67 1,638,19 2,142,92 976,426 1,221,165 9 Peak Demand D1 115,71,998 29,957,95 1,918,727 19,16,952 6,67, , ,948 81,675 1,558, ,86 1 Base Energy E2-E ,67,863 22,311,511 1,471,45 15,276,434 65,161, ,738 79, ,14 987,374 6,359,947 1,234, Subtotal A/C 11 & ,971,844 99,762,28 6,835,515 7,69, ,22, ,979 3,12,334 4,83,38 2,6,67 7,976,678 2,674, A/C Base Demand E1-E Peak Demand D1 16 Base Energy E1-E Subtotal A/C Total Production Plant P1 474,971,844 99,762,28 6,835,515 7,69, ,22, ,979 3,12,334 4,83,38 2,6,67 7,976,678 2,674, Transmission Plant 24 A/C 11 & 16 D2 23,387,43 52,949,983 3,391,31 33,612,74 17,121,98 1,324,967 1,737,34 144,359 2,754,6 351, A/C 11 & 16 (Direct FERC) Direct FERC 26 A/C 114 D Total Transmission Plant 23,387,43 52,949,983 3,391,31 33,612,74 17,121,98 1,324,967 1,737,34 144,359 2,754,6 351, Distribution Plant 32 Primary Demand D3 76,47,359 14,247,14 1,98,717 13,399,381 3,72,835 1,159,69 983, ,34 2,135,487 1,94,13 1,364,12 33 Secondary Demand D4 4,183,359 9,334,662 1,56,56 7,871,532 1,157,96 718,186 4,346 49,16 2,371,892 6,488,41 926, Primary Customer C2 33,591,326 26,248,16 716,966 5,738, ,88 291,674 99,34 264,118 11,438 2,797 2,8 35 Secondary Customer C3 32,284,834 25,247,62 689,625 5,59, ,532 28,551 95,17 254,46 11,2 2,4 2, 36 Streetlighting C4 5,934,11 5,934,11 37 Area Lighting C5 3,14,965 3,14, Meters C6 11,29,994 3,195,57 34,151 3,449,92 638, ,326 36,925 99,864 1,632,74 1,397,946 33,86 39 Load Management C9 4,79,22 758,154 6,926 2,37 3,351 1,666,24 1,388,591 28, Total Distribution Plant P6 26,471,49 79,29,965 5,24,44 35,99,44 41,241,791 2,64,156 1,69,4 1,638,438 7,828,547 19,49,392 2,834, General Plant 45 Production P1 17,197,855 3,612,26 247,51 2,537,99 1,73,839 6, , ,839 74, ,821 96, Transmission D2 6,575,858 1,711,962 19,647 1,86,735 3,463,434 42,838 56,171 4,667 89,42 11, Distribution P6 9,77,486 3,739,84 246,281 1,73,97 1,951, ,232 55,865 77,533 37, , , Customer Accounts OXC 8,236,35 5,88, ,358 1,752,491 74,88 56,395 27,229 68, , ,439 29, Customer Service & Info OXI 1,791, ,38 25, , ,752 3,444 9,886 14,45 12,811 81,523 15,87 5 Load Management C9 149,339 27, ,111 6,993 5,836 7, Total General Plant P9 43,721,727 15,454, ,293 7,328,685 16,389,521 19,31 698, , ,787 1,547, , Intangible Plant P9 4,989,544 1,763,71 89, ,353 1,87,38 21,717 79,747 41,584 76, ,56 33, Total Plant in Service EPIS 933,541, ,96,581 16,31, ,836, ,843,812 2,985,154 15,913,852 7,864,792 1,781,965 31,863,775 6,188,

84 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 4-2 1// 12: AM Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Accumulated Depreciation 2 Production Plant 3 Base Demand E1-E876 (1,243,813) (19,385,21) (1,47,679) (14,618,391) (62,354,351) (679,15) (888,39) (44,794) (56,254) 4 Peak Demand D1 (44,431,85) (11,567,4) (74,862) (7,342,86) (23,41,759) (289,451) (379,538) (31,536) (61,637) (76,763) 5 Base Energy E2-E876 (33,188,466) (6,461,3) (425,989) (4,423,793) (18,869,568) (48,574) (25,51) (268,737) (285,926) (1,841,731) (357,68) 6 7 Total Production Plant P1 (177,864,84) (37,413,63) (2,574,531) (26,385,43) (14,625,678) (48,574) (1,174,65) (1,536,314) (722,256) (2,443,369) (94,625) Transmission Plant D2 (56,299,33) (14,656,92) (938,738) (9,34,53) (29,652,11) (366,76) (48,98) (39,959) (762,328) (97,266) 11 Transmission Plant (Direct FERC) Direct FERC 12 TOTAL TRANSMISSION PLANT Distribution Plant P6 (9,174,14) (34,515,489) (2,272,983) (15,718,265) (18,11,91) (1,137,337) (4,668,745) (715,57) (3,419,34) (8,476,844) (1,237,838) General Plant P9 (19,35,535) (6,84,13) (345,788) (3,243,558) (7,253,739) (84,224) (39,277) (161,274) (297,322) (684,739) (13,61) Intangible Plant P9 (2,461,564) (87,112) (43,987) (412,61) (922,742) (1,714) (39,343) (2,515) (37,822) (87,15) (16,614) Total Accumulated Depreciation (346,149,231) (94,296,163) (6,176,27) (55,63,53) (16,466,17) (1,28,85) (6,558,19) (2,914,581) (4,516,394) (12,454,384) (2,422,942) Net Plant Excluding BSP Capitalized Items 587,392, ,664,417 1,125,692 92,773, ,377,642 1,74,34 9,355,662 4,95,211 6,265,571 19,49,391 3,765, BSP Capitalized Items P Total Net Plant in Service NEPIS 587,392, ,664,417 1,125,692 92,773, ,377,642 1,74,34 9,355,662 4,95,211 6,265,571 19,49,391 3,765, Plant Held for Future Use 43 Production Plant P1 44 Transmission Plant D2 4,546 1, , Distribution Plant P6 9,267 3, ,615 1, General Plant P9 47 Intangible Plant P Total Plant Held for Future Use 13,813 4, ,367 4,

85 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 5-2 1// 12: AM Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Const Work-in-Progress - Direct Assigned 2 Production Plant - Direct MN P1 3 Production Plant - Direct ND P1 4 Production Plant - Direct SD P1 5 Production Plant - Direct FERC Direc FERC 6 Transmission Plant - Direct MN D2 7 Transmission Plant - Direct ND D2 8 Transmission Plant - Direct SD D2 9 Transmission Plant - Direct FERC Direc FERC 1 Distribution Plant - Direct MN P6 11 Distribution Plant - Direct ND P6 12 Distribution Plant - Direct SD P6 13 Distribution Plant - Direct FERC Direc FERC 14 General Plant - Direct MN P9 15 General Plant - Direct ND P9 16 General Plant - Direct SD P9 17 General Plant - Direct FERC Direc FERC 18 Intangible Plant - Direct MN P9 19 Intangible Plant - Direct ND P9 2 Intangible Plant - Direct SD P9 21 Intangible Plant - Direct FERC Direc FERC 22 Total CWIP - Major Projects Const Work-in-Progress - Short-Term 26 Production Plant P1 9,57 1, ,42 5, Transmission Plant D2 12,768 3, ,11 6, Distribution Plant P6 714,21 273,32 17, , ,623 9,6 36,968 5,666 27,73 67,122 9,82 29 General Plant P9 633,73 224,1 11,325 16, ,56 2,758 1,129 5,282 9,737 22,425 4,277 3 Intangible Plant P Total CWIP - Short-Term 1,37,26 52,634 29, ,2 392,476 11,767 47,243 11,139 36,86 89,88 14, Const Work-in-Progress - Long Term 36 Production Plant (AFUDC Projects) P1 1,533,95 322,179 22,75 226, , ,77 13,186 6,655 25,76 8, Production Plant (Rider Projects) P1 38 Transmission Plant (AFUDC Projects) D2 7,15,726 1,849,98 118,482 1,174,32 3,742,51 46,29 6,697 5,43 96,216 12, Transmission Plant (Rider Projects) D2 4 Distribution Plant P6 1,14, ,334 25, ,846 22,652 12,796 52,528 8,51 38,468 95,373 13, General Plant P9 213,893 75,67 3,822 35,853 8, ,419 1,783 3,286 7,569 1, Intangible Plant P9 1,667, ,53 29,83 279, ,188 7,259 26,656 13,9 25,626 59,17 11, Total CWIP - Long Term 11,535,863 3,225, ,755 1,892,846 5,549,32 21, ,97 97,617 79,78 283,935 47, Total Construction Work-in-Progress 12,95,889 3,728, ,428 2,127,46 5,941,59 33, ,213 18, , ,815 61, Materials & Supplies 51 Production P1 3,346,548 72,93 48, ,697 1,96,279 1,191 21,985 28,768 14,519 56,22 18, Transmission D2 2,523, ,914 42,74 417,2 1,328,988 16,438 21,554 1,791 34,167 4, Distribution P6 3,538,537 1,354,429 89, ,84 76,89 44,63 183,27 28,8 134, ,642 48, Total Materials and Supplies 9,48,372 2,714, ,43 1,527,52 3,996,76 45, ,63 78,42 15, ,11 71, Fuel Stocks 59 Coal Stocks E1-E876 4,565, ,859 64,11 665,765 2,839,81 3,928 4,444 18,435 23,56 6 Fuel Oil Stocks D1 1,259, ,828 2,997 28,11 663,221 8,23 1, ,51 2, Total Fuel Stocks 5,824,626 1,21,687 85,16 873,866 3,53,22 39,132 51,2 19,329 17,51 25, Prepayments NEPIS (5,679,13) (1,495,354) (97,899) (896,969) (2,749,47) (16,478) (9,454) (47,861) (6,578) (187,657) (36,411) Customer Advances NEPIS (1,34,643) (272,429) (17,836) (163,413) (5,98) (3,2) (16,479) (8,719) (11,36) (34,188) (6,633) Cash Working Capital OX 4,95,898 1,299,24 73,16 732,743 2,376,24 11,773 7,864 4,255 52,45 27,99 41,

86 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 6-2 1// 12: AM Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Accumulated Deferred Income Taxes 2 Items SD Flows Through 3 Federal NPMNR 148,45 38,981 2,552 23,382 71, ,358 1,248 1,579 4, Minnesota NPISM 46,628 12, ,365 22, , North Dakota NPISN 6 7 Subtotal 194,673 51,259 3,356 3,747 94, ,11 1,641 2,77 6,433 1, All Other 1 Federal NEPIS (92,588,627) (24,379,218) (1,596,78) (14,623,559) (44,825,466) (268,644) (1,474,71) (78,285) (987,62) (3,59,435) (593,62) 11 Federal (Direct FERC) Direct FERC 12 Minnesota NPISM (38,342,622) (1,95,874) (66,965) (6,55,88) (18,563,35) (111,25) (61,7) (323,13) (48,991) (1,266,967) (245,829) 13 North Dakota NPISN Subtotal (13,931,248) (34,475,93) (2,257,42) (2,679,439) (63,388,51) (379,894) (2,85,41) (1,13,415) (1,396,612) (4,326,43) (839,449) Total Accumulated Deferred Income Taxes (13,736,575) (34,423,834) (2,253,687) (2,648,692) (63,294,253) (379,329) (2,82,3) (1,11,774) (1,394,535) (4,319,97) (838,21) Unamortized Balance - Spiritwood Plant P Unamortized Rate Case Expenses R Total Average Rate Base 483,, ,429,895 8,323,74 76,327,94 233,653,888 1,396,55 7,684,777 4,7,582 5,137,564 15,89,293 3,85,

87 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 7-2 1// 12: AM Large Controlled Controlled Controlled Line General General Outdoor Service Service Service No. Item Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Operating Revenues 2 Sales of Electricity 196,817,16 48,556,654 3,136,239 31,41,51 98,486,668 41,116 2,847,178 1,575,91 1,639,361 7,162,143 1,61,389 3 Other Operating Revenue 7,177,664 2,155, ,361 1,132,77 3,238,145 21,161 16,431 6,194 71, ,318 43, Total Operating Revenue 23,994,824 5,712,1 3,26,6 32,534,272 11,724, ,277 2,953,68 1,636,14 1,71,73 7,386,461 1,653, Operating Expenses 9 Production Expenses 87,59,992 17,185,36 1,144,223 11,852,427 49,878,58 17,15 546, , ,847 4,112, ,973 1 Transmission Expenses 8,91,378 2,16, ,917 1,337,192 4,261,643 52,711 69,117 5,743 19,563 13, Distribution Expenses 7,594,39 2,826, ,4 1,399,535 1,196,758 84, ,256 57, , ,3 12, Customer Accounting Expenses 6,565,33 4,629,96 121,442 1,396,884 59,686 44,952 21,74 54, ,166 94,46 23, Customer Service and Information Expenses 7,297,375 2,257,689 12,837 1,12,77 3,362,842 14,26 4,259 58,847 52, ,997 64, Sales Expenses 18,214 85,631 2,96 17, Administrative and General Expenses 2,645,66 7,236,67 365,454 3,499,496 7,811,134 78,224 59, , , ,23 123, Charitable Contributions 93,27 73,613 1,82 15, Depreciation Expense 27,39,957 7,45, ,11 4,223,428 13,192,54 78, , , ,669 91, , Amortization of Big Stone Plant Capitalized Costs 19 Spiritwood Amortization 2 General Taxes 7,327,555 1,929, ,315 1,157,323 3,547,532 21, ,79 61,752 78, ,127 46, Total Operating Expenses 171,821,636 45,377,17 2,634,138 25,91,835 83,311,845 43,22 2,523,344 1,417,387 1,834,2 6,977,759 1,45, Net Operating Income Before Income Taxes 32,173,187 5,334,84 626,462 6,623,437 18,412,969 (7,746) 43, ,717 (123,317) 48,72 248, Income Tax Expense 29 Investment Tax Credit (4,59,538) (1,22,622) (78,747) (714,137) (2,148,849) (14,42) (76,873) (37,991) (52,83) (153,92) (29,896) 3 Deferred Income Taxes 3,23, ,546 55,226 55,99 1,551,8 9,295 51,26 26,999 34,173 15,86 2,54 31 Income Taxes 6,485,488 46,15 141,58 1,662,432 4,316,619 (22,995) 69,356 32,946 (123,853) (55,95) 59, Total Income Tax Expense 5,179,613 46,94 118,59 1,454,285 3,718,778 (28,12) 43,59 21,954 (141,763) (14,1) 49, Net Operating Income 26,993,574 5,287,9 58,43 5,169,151 14,694,191 2, , ,764 18, , , Allowance for Funds Used During Construction 671, ,772 11,629 11,19 323,31 1,253 8,9 5,683 4,63 16,529 2,768 4 Allowance for Funds Used During Construction - MN Only 41 Allowance for Funds Used During Construction - SD Only 42 Total Allowance for Funds Used During Construction 671, ,772 11,629 11,19 323,31 1,253 8,9 5,683 4,63 16,529 2, Total Available for Return 27,665,121 5,475,672 52,32 5,279,341 15,17,222 21, ,845 22,446 23,49 529,241 21,

88 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 8-2 1// 12: AM Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Operating Revenues 2 3 Sales of Electricity R1 196,817,16 48,556,654 3,136,239 31,41,51 98,486,668 41,116 2,847,178 1,575,91 1,639,361 7,162,143 1,61, Other Operating Revenues 7 Sales for Resale 8 Municipalities 9 Non-Associated Utilities, Co-Ops & OPA 1 Non-Asset Wholesale Transactions D2 11 All Other Transactions 12 Base Demand E1-E Peak Demand D1 14 Base Energy E2-E876 17,467 2,921 1,379 14,325 61, ,964 1, Peak Energy D Total All Other Transactions 17,467 2,921 1,379 14,325 61, ,964 1, Total Sales for Resale 17,467 2,921 1,379 14,325 61, ,964 1, Other Electric Revenues 23 Late Fees C1 327, ,533 6,354 52,925 2,695 1, , , Connection Fees C1 186, ,413 3,69 3,61 1, , Rent from Electric Property NEPIS 236,42 62,246 4,75 37, , ,765 1,992 2,522 7,812 1, Rent from Electric Property - Big Stone NEPIS 5,916 1, , Rent from Electric Property - Coyote NEPIS 2, , Other Misc Electric Revenue NEPIS 1,575, ,91 27, , ,868 4,572 25,97 13,279 16,88 52,67 1,13 29 Other Misc Electric Revenue - MN C1 3 Other Misc Electric Revenue - ND C1 31 Other Misc Electric Revenue - SD C1 32 ITA Deficiency Payments NEPIS 846, ,12 14,6 133,771 41,46 2,457 13,49 7,138 9,34 27,987 5, ,7 3, ,37 7, Miscellaneous Services NEPIS 35 Wheeling 36 Load Control and Dispatch NEPIS 3,87,847 1,19,22 66, ,366 1,874,16 11,231 61,653 32,621 41, ,96 24, Load Control and Dispatch (Direct FERC) Direct FERC 38 Loan Pool Interest C1 2,41 1, Total Other Electric Revenues 7,7,197 2,134, ,982 1,118,446 3,177,43 21,3 15,765 59,324 7, ,354 42, Total Other Operating Revenues 7,177,664 2,155, ,361 1,132,77 3,238,145 21,161 16,431 6,194 71, ,318 43, Total Operating Revenues 23,994,824 5,712,1 3,26,6 32,534,272 11,724, ,277 2,953,68 1,636,14 1,71,73 7,386,461 1,653,

89 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 9-2 1// 12: AM Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Operating Expenses 2 Production Expenses 3 Prod Expenses Excluding Purchased Power 4 Base Demand E1-E876 9,8,356 1,742,41 126,5 1,313,674 5,63,44 61,27 79,83 36,377 45,494 5 Peak Demand D1 3,574,939 93,71 59,69 59,799 1,882,882 23,289 3,537 2,537 48,47 6,176 6 Base Energy E2-E876 35,612,734 6,932, ,16 4,746,931 2,247,95 52,122 22, ,367 36,812 1,976, ,729 7 Peak Energy D1 23,15 59,882 3,835 38,13 121,146 1,498 1, , Total Excluding Purchased Power 48,426,44 9,665,63 647,51 6,689,416 27,855,374 52,122 36,336 4, ,889 2,27, , Purchased Power 13 Non-Asset Wholesale Transactions D2 14 for Retail 15 Base Demand E1-E876 1,66,857 26,39 14, , ,614 7,227 9,451 4,38 5, Peak Demand D1 17 Base Energy E2-E876 37,567,91 7,313, ,191 5,7,433 21,359,71 54, ,623 34, ,649 2,84,715 44, Peak Energy D Total All Other Transactions 38,633,948 7,519, ,173 5,163,11 22,22,684 54, ,85 313, ,957 2,84,715 41, Total Purchased Power 38,633,948 7,519, ,173 5,163,11 22,22,684 54, ,85 313, ,957 2,84,715 41, Total Production Expenses 87,59,992 17,185,36 1,144,223 11,852,427 49,878,58 17,15 546, , ,847 4,112, , Transmission Expenses D2 8,91,378 2,16, ,917 1,337,192 4,261,643 52,711 69,117 5,743 19,563 13, Transmission Expenses (Direct FERC) 29 Total Transmission Expenses Distribution Expenses 31 Primary Demand D3 2,31, ,88 6,182 47, ,73 35,217 29,881 18,574 64,884 36,695 41, Secondary Demand D4 734,836 17,74 27, , ,744 13,134 7,321 7,481 43, ,647 16, Primary Customer C2 1,355,719 1,59,349 28, ,615 7,995 11,772 4,8 1, Secondary Customer C3 949, ,851 2, ,122 5,165 8,255 2,796 7, Streetlighting C4 71,661 71, Area Lighting C5 54,723 54, Meters C6 1,477, ,132 4,89 454,725 84,125 16,387 4,867 13, ,22 184,26 43,61 38 Load Management C Total Distribution OXD 7,594,39 2,826, ,4 1,399,535 1,196,758 84, ,256 57, , ,3 12, Customer Accounting Expenses 44 Meter Reading C7 2,544,9 1,489,775 35,668 71,316 34,557 1,57 9,823 22, ,798 91,918 23,67 45 Other C8 4,2,133 3,14,184 85, ,567 25,129 34,894 11,88 31,598 1,368 2, Total Customer Accounts OXC 6,565,33 4,629,96 121,442 1,396,884 59,686 44,952 21,74 54, ,166 94,46 23,

90 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 1-2 1// 12: AM Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Customer Service & Information Expense 2 Conservation & DSM Rebates E2-E876 5,894,49 1,147,56 75, ,684 3,351,313 8,627 36,499 47,729 5, ,99 63,513 3 Other C1 1,42,966 1,11,184 27,18 226,393 11,528 5,4 3,759 11,118 1,39 4,898 1, Total Customer Service & Information Expense OXI 7,297,375 2,257,689 12,837 1,12,77 3,362,842 14,26 4,259 58,847 52, ,997 64, Sales Expenses 9 Off-Peak Development C1 85,29 67,491 1,652 13, Other C1 22,924 18, , Total Sales Expenses 18,214 85,631 2,96 17, Administrative & General Expenses 16 Salaries, Supplies, Pensions & Benefits 17 Production OXPD 5,71,344 1,24,41 84, ,793 3,49,48 38,296 5,113 18,81 2,25 23,87 18 Transmission D2 2,175, ,367 36, ,524 1,145,85 14,172 18,583 1,544 29,458 3, Distribution OXD 3,264,695 1,215,297 76,11 61, ,489 36,44 35,51 24, , ,683 43,911 2 Customer Accounts OXC 2,724,81 1,921,66 5,44 579,775 24,773 18,657 9,8 22,628 49,45 39,183 9, Customer Service & Info C1 592,87 469,95 11,485 95,66 4,871 2,282 1,588 4, , Total Salaries, Supplies, Pensions, and Benefits 14,468,14 5,376, ,397 2,498,414 5,99,345 57, ,115 12,678 28, ,644 81, Load Management Expenses C Outside Services NEPIS 256,557 67,553 4,423 4, , ,86 2,162 2,737 8,478 1, Property Insurance NEPIS 1,492, ,957 25, ,71 722,521 4,33 23,77 12,577 15,919 49,314 9, Injuries & Damages NEPIS 1,72, ,422 18,49 169,47 519,282 3,112 17,84 9,39 11,441 35,442 6, Regulatory Commission Expense R1 831,5 25,17 13, , ,832 1,694 12,21 6,654 6,922 3,24 6, General Advertising C1 44,571 35, , Miscellaneous, Rents, Maintenance P9 2,479,83 876,559 44, , ,579 1,793 39,634 2,667 38,12 87,75 16, Total Administrative & General Exp 2,645,66 7,236,67 365,454 3,499,496 7,811,134 78,224 59, , , ,23 123, Charitable Contributions C1 93,27 73,613 1,82 15, Total O & M Expenses 137,454,124 36,42,289 2,49,812 2,53,84 66,571, ,846 1,985,486 1,127,875 1,458,19 5,825,22 1,173,

91 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 11-2 Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Depreciation Expense 2 Production 3 Base Demand E1-E876 7,45,75 1,432,119 13,995 1,79,962 4,66,548 5,17 65,66 29,95 37,4 4 Peak Demand D1 3,87, ,242 63, ,23 2,5,36 24,84 32,524 2,72 51,556 6,578 5 Base Energy E2-E876 4,731, ,142 6,733 63,695 2,69,212 6,925 29,299 38,314 4, ,573 5, Total Production 15,944,829 3,344,53 228,214 2,339,886 9,32,121 6,925 14, ,443 73, ,129 94, Transmission D2 3,924,22 1,21,633 65, ,522 2,66,845 25,564 33,521 2,785 53,137 6,78 11 Transmission (Direct FERC) 12 Total Transmission Distribution P6 4,936,86 1,889, ,442 86, ,119 62, ,65 39, , ,91 67, General P9 1,365,38 482,634 24, , ,826 5,943 21,823 11,38 2,979 48,315 9, Intangible P9 868,669 37,56 15, ,67 325,629 3,781 13,884 7,24 13,347 3,739 5, Total Depreciation Expense 27,39,957 7,45, ,11 4,223,428 13,192,54 78, , , ,669 91, , Big Stone Expense Offsets P Spiritwood Amortization P

92 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 12-2 Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 General Taxes NEPIS 7,327,555 1,929, ,315 1,157,323 3,547,532 21, ,79 61,752 78, ,127 46, Net Operating Income Before Tax (NOIBT) 32,173,187 5,334,84 626,462 6,623,437 18,412,969 (7,746) 43, ,717 (123,317) 48,72 248, Investment Tax Credit 6 Amortize Prior Years Credit EPIS (4,59,538) (1,22,622) (78,747) (714,137) (2,148,849) (14,42) (76,873) (37,991) (52,83) (153,92) (29,896) 7 Debits Utilized EPIS 8 9 Total Investment Tax Credit (4,59,538) (1,22,622) (78,747) (714,137) (2,148,849) (14,42) (76,873) (37,991) (52,83) (153,92) (29,896) 1 11 Deferred Income Taxes 12 Items South Dakota Flows Through 13 Federal NPMNR 14 Minnesota NPISM 15 North Dakota NPISN Subtotal All Other 2 Federal NEPIS 398,76 14,982 6,873 62, ,28 1,157 6,35 3,36 4,253 13,175 2, Minnesota NPISM 2,84, ,564 48, ,18 1,357,98 8,139 44,676 23,639 29,92 92,685 17, North Dakota NPISN Subtotal 3,23, ,546 55,226 55,99 1,551,8 9,295 51,26 26,999 34,173 15,86 2, Total Deferred Income Taxes 3,23, ,546 55,226 55,99 1,551,8 9,295 51,26 26,999 34,173 15,86 2, Current Income Taxes 3 Federal Income Taxes 5,43, ,513 19,635 1,282,742 3,338,379 (17,218) 54,481 25,969 (93,247) (39,26) 45, Minnesota Income Taxes 1,441,574 69,52 31, ,69 978,24 (5,778) 14,875 6,977 (3,66) (16,744) 13, North Dakota Income Taxes Total Current Income Taxes 6,485,488 46,15 141,58 1,662,432 4,316,619 (22,995) 69,356 32,946 (123,853) (55,95) 59, Total Income Taxes 5,179,613 46,94 118,59 1,454,285 3,718,778 (28,12) 43,59 21,954 (141,763) (14,1) 49, Net Operating Income 26,993,574 5,287,9 58,43 5,169,151 14,694,191 2, , ,764 18, , , AFDC CWIPLT 671, ,772 11,629 11,19 323,31 1,253 8,9 5,683 4,63 16,529 2, AFDC - MN Only CWIPLT 43 AFDC - SD Only CWIPLT 44 Total AFDC CWIPLT 671, ,772 11,629 11,19 323,31 1,253 8,9 5,683 4,63 16,529 2, Total Available for Return 27,665,121 5,475,672 52,32 5,279,341 15,17,222 21, ,845 22,446 23,49 529,241 21, Rate of Return on Rate Base 5.73% 4.3% 6.25% 6.92% 6.43% 1.55% 5.14% 4.97%.45% 3.33% 6.54%

93 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 13-2 Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Development of Federal Income Tax Expense 2 3 Net Operating Income Before Tax (NOIBT) 32,173,187 5,334,84 626,462 6,623,437 18,412,969 (7,746) 43, ,717 (123,317) 48,72 248,859 4 Less: Interest Cost 12,66,315 3,325,92 217,249 1,992,158 6,98,366 36,449 2,573 16, ,9 414,737 8, Net Income Before Tax 19,566,872 2,8,92 49,214 4,631,278 12,314,62 (44,195) 229, ,475 (257,48) (6,35) 168, Federal Schedule M Adjustments: 9 Additional Tax Depreciation NEPIS 894, ,548 15, , ,97 2,596 14,248 7,539 9,542 29,56 5,735 1 Cost to Remove NEPIS 252,59 66,487 4,353 39, , ,22 2,128 2,693 8,344 1, Directly Assigned Schedule M Items NEPIS (126,196) (33,228) (2,175) (19,932) (61,96) (366) (2,1) (1,64) (1,346) (4,17) (89) 12 Accrued Vacation Pay NEPIS 13 Charges - Operating Reserves NEPIS 892,28 234,924 15,38 14, ,95 2,589 14,211 7,519 9,517 29,482 5,72 14 Provisions - Operating Reserves NEPIS (2,779,365) (731,826) (47,912) (438,976) (1,345,59) (8,64) (44,268) (23,423) (29,647) (91,839) (17,82) 15 Unbilled Revenues NEPIS 16 Preferred Dividends Paid Credit NEPIS 17 Other Schedule M Items NEPIS 4,58,381 1,26,46 78, ,431 2,217,526 13,29 72,954 38,61 48, ,351 29, Subtotal Federal Schedule M Adjustments 3,714, ,952 64,25 586,612 1,798,136 1,776 59,156 31,3 39, ,727 23, Federal Adjusted Income Before Income Taxes 15,852,758 1,3, ,188 4,44,667 1,516,466 (54,971) 17,535 81,175 (297,25) (128,761) 144, Less: 24 Minnesota State Income Taxes 1,441,574 69,52 31, ,69 978,24 (5,778) 14,875 6,977 (3,66) (16,744) 13, North Dakota State Income Taxes Federal Taxable Income 14,411, , ,244 3,664,976 9,538,227 (49,193) 155,66 74,197 (266,419) (112,18) 131,44 28 Federal Tax Rate 35.% 35.% 35.% 35.% 35.% 35.% 35.% 35.% 35.% 35.% 35.% 29 3 Federal Income Tax Before Credits 5,43, ,513 19,635 1,282,742 3,338,379 (17,218) 54,481 25,969 (93,247) (39,26) 45, Investment Tax Credit - Debits Utilized EPIS Federal Income Taxes 5,43, ,513 19,635 1,282,742 3,338,379 (17,218) 54,481 25,969 (93,247) (39,26) 45,

94 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 14-2 Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Development of Minnesota State Income Tax Expense 2 3 Federal Adjusted Income Before Income Taxes 15,852,758 1,3, ,188 4,44,667 1,516,466 (54,971) 17,535 81,175 (297,25) (128,761) 144, Minnesota Adjustments to Federal Schedule M: 6 PAYSOP Adjustment NEPIS 7 Change in Excess Tax Depreciation - MN NEPIS (1,17,567) (38,218) (2,179) (184,881) (566,714) (3,396) (18,644) (9,865) (12,486) (38,679) (7,55) 8 Change in ACRS - Ordinary Loss NEPIS 9 Preferred Dividends Paid Credit NEPIS 1 Miscellaneous Adjustments to Fed Schedule M NEPIS (69,192) (18,219) (1,193) (1,928) (33,498) (21) (1,12) (583) (738) (2,286) (444) Total Minnesota Adjustments to Fed Schedule M (1,239,759) (326,437) (21,371) (195,89) (6,212) (3,597) (19,746) (1,448) (13,224) (4,966) (7,949) Minnesota Taxable Income 14,612,998 74, ,817 3,848,858 9,916,254 (58,568) 15,789 7,727 (31,249) (169,727) 136, Minnesota Tax Rate 9.8% 9.8% 9.8% 9.8% 9.8% 9.8% 9.8% 9.8% 9.8% 9.8% 9.8% Minnesota Income Tax 1,441,574 69,52 31, ,69 978,24 (5,778) 14,875 6,977 (3,66) (16,744) 13, Development of North Dakota State Income Tax Expense Federal Adjusted Income Before Income Taxes North Dakota Adjustments to Federal Schedule M: 3 Change in Excess Tax Depreciation - ND NEPIS 31 Change in ACRS - Ordinary Loss - ND NEPIS 32 Change in Income from ADR Property - ND NEPIS 33 Miscellaneous Adjustments to Fed Schedule M NEPIS Total North Dakota Adjustments to Fed Schedule M Subtotal 38 Deduction of Federal Income Taxes 39 4 North Dakota Taxable Income 41 North Dakota Tax Rate.%.%.%.%.%.%.%.%.%.%.% North Dakota Income Tax

95 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 15-2 Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 MWH Consumption at Generators - Partial E1-E876 2,583, ,627 36, ,769 1,67,98 17,53 22,888 1,433 13,48 2 Percentage 1.% % % % %.%.67745%.88588%.4381%.%.552% 3 4 MWH Consumption at Generators - Total E2-E876 2,826,621 55,278 36, ,769 1,67,98 4,137 17,53 22,888 24, ,858 3,457 5 Percentage 1.% % % % %.14636%.61922%.8973%.86152% % % 6 7 Generation Demand Factor D1 363,497 94,633 6,61 6,72 191,45 2,368 3, , Percentage 1.% % % % %.%.65145%.8542%.798% %.17277% 9 1 Transmission Demand Factor D2 363,497 94,633 6,61 6,72 191,45 2,368 3, , Percentage 1.% % % % %.%.65145%.8542%.798% %.17277% Distribution - Primary Demand Factor D3 4,947 75,115 1,443 7, ,554 6,111 5,185 3,223 11,259 53,219 7, Percentage 1.% % % % % % %.8385% 2.881% % % Distribution - Secondary Demand Factor D4 54, ,212 18,911 98,84 127,539 9,18 5,27 5,137 29,783 81,468 11, Percentage 1.% % % % % %.9963% 1.181% % % % Customer or Meter Factors 2 Total Retail Customers C1 61,58 48,729 1,193 9, Percentage 1.% % % %.8217%.38487%.26794%.79247%.996%.34914%.7957% Retail Service Locations C2 64,69 5,485 1,379 11, Percentage 1.% % % %.5897%.8683%.29562%.78627%.345%.6191%.619% Secondary Service Locations C3 64,558 5,485 1,379 11, Percentage 1.% 78.21% % %.5437%.86899%.29431%.78689%.348%.6196%.62% Street Lighting Factor C4 2,276,816 2,276,816 3 Percentage 1.%.%.%.%.%.% 1.%.%.%.%.% Area Lighting Factor C5 1,836,3 1,836,3 33 Percentage 1.%.%.%.%.%.% 1.%.%.%.%.% Meter Factor C6 23,311,764 6,644, ,498 7,174,288 1,327, ,543 76,788 27,672 3,395,292 2,97,12 688,4 36 Percentage 1.% % % % % 1.197%.3294%.8985% % % % Meter Reading Factor C7 87,47 5,957 1,22 24,296 1, ,995 3, Percentage 1.% % % % %.39519%.386%.966% % %.9641% 4 41 System Service Locations C8 64,632 5,485 1,379 11, Percentage 1.% % % %.6258%.86799%.29552%.78599%.344%.6189%.619% Load Management Factor C9 2,26 3, ,179 6,817 1,25 45 Percentage 1.% %.16978%.49935%.%.7443%.%.% % % %

96 Docket No. E17/GR Exhibit (PJB-1), Schedule E-3 Otter Tail Power Company Class Cost of Service Study Proposed Test Year 216 MINNESOTA Page 16-2 Large Controlled Controlled Controlled Line Allocation General General Outdoor Service Service Service No. Item Factors Minnesota Residential Farms Service Service Irrigation Lighting OPA Water Heating Interruptible Deferred 1 Gross Plant in Service 2 Production Plant P1 474,971,844 99,762,28 6,835,515 7,69, ,22, ,979 3,12,334 4,83,38 2,6,67 7,976,678 2,674,517 3 Percentage 1.% % % % %.3558%.65695%.85964%.43384% %.5639% 4 5 Distribution Plant P6 26,471,49 79,29,965 5,24,44 35,99,44 41,241,791 2,64,156 1,69,4 1,638,438 7,828,547 19,49,392 2,834,272 6 Percentage 1.% % % % % % %.79354% % 9.454% % 7 8 General Plant P9 43,721,727 15,454, ,293 7,328,685 16,389,521 19,31 698, , ,787 1,547, ,87 9 Percentage 1.% % 1.787% % %.4353% %.83343% % %.67492% Electric Plant in Service EPIS 933,541, ,96,581 16,31, ,836, ,843,812 2,985,154 15,913,852 7,864,792 1,781,965 31,863,775 6,188, Percentage 1.% % % % %.31977% %.84247% % %.66295% Net Electric Plant in Service NEPIS 587,392, ,664,417 1,125,692 92,773, ,377,642 1,74,34 9,355,662 4,95,211 6,265,571 19,49,391 3,765, Percentage 1.% % % % %.2915% %.84274% % %.64114% Operation and Maintenance Expense 19 Production Expense (Excl Energy) OXPD 13,65,152 2,879,51 21,91 2,6,51 8,149,936 91, ,791 43,222 48,47 57,58 2 Percentage 1.% % % % %.%.6764%.87758%.31664%.35463%.4181% Distribution Expense OXD 7,594,39 2,826, ,4 1,399,535 1,196,758 84, ,256 57, , ,3 12, Percentage 1.% % % % % % %.75523% % % % Customer Accounts Expense OXC 6,565,33 4,629,96 121,442 1,396,884 59,686 44,952 21,74 54, ,166 94,46 23, Percentage 1.% % % %.9915%.68471%.3359%.8344% % %.35515% Customer Service & Information Expense OXI 7,297,375 2,257,689 12,837 1,12,77 3,362,842 14,26 4,259 58,847 52, ,997 64, Percentage 1.% % % % %.19221%.55168%.8641%.71493% %.88565% 3 31 Other Deferred Income Tax Factor 32 Minnesota NPISM 587,392, ,664,417 1,125,692 92,773, ,377,642 1,74,34 9,355,662 4,95,211 6,265,571 19,49,391 3,765, Percentage 1.% % % % %.2915% %.84274% % %.64114% North Dakota NPISN 36 Percentage.%.%.%.%.%.%.%.%.%.%.% Excluding South Dakota NPMNR 587,392, ,664,417 1,125,692 92,773, ,377,642 1,74,34 9,355,662 4,95,211 6,265,571 19,49,391 3,765, Percentage 1.% % % % %.2915% %.84274% % %.64114% 4 41 Long-Term CWIP Ratio (W/AFDC) CWIPLT 11,535,863 3,225, ,755 1,892,846 5,549,32 21, ,97 97,617 79,78 283,935 47,54 42 Percentage 1.% % % % %.18665% %.8462%.6855% %.41211% Revenue R1 196,817,16 48,556,654 3,136,239 31,41,51 98,486,668 41,116 2,847,178 1,575,91 1,639,361 7,162,143 1,61, Percentage 1.% % % % %.238% %.87%.83294% %.81822% Labor and Related Expense LRE 63,843,42 21,936,736 1,12,781 1,75,234 24,841, ,966 1,53,34 531, ,366 1,76, , Percentage 1.% % % % %.34767% %.83291% % %.6222% 49 5 Total O & M Expense OX 137,454,124 36,42,289 2,49,812 2,53,84 66,571, ,846 1,985,486 1,127,875 1,458,19 5,825,22 1,173, Percentage 1.% % % % %.23997% %.8255% 1.686% %.85377%

97 Volume 3 E. Rate Structure and Design Information (Rule ) 1/3

98 Volume 3 F. Other Supplemental Information 1/3

99 Volume 3 F. Other Supplemental Information 1. Annual Report and Statistical Supplement 1/5

100 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota Docket No. E17/GR Financial Information OTHER SUPPLEMENTAL INFORMATION MINNESOTA RULE OTHER SUPPLEMENTAL INFORMATION. The following supplemental information as required by part shall be filed: A. Annual report to stockholders or members including financial statements and statistical supplements for the most recent fiscal year. If a utility is not audited by an independent public accountant, unaudited financial statements will satisfy this filing requirement. B. For investor-owned utilities only, a schedule showing the development of the gross revenue conversion factor. C. For cooperatives only, REA Form 7, Financial and Statistical Report for the last month of the most recent fiscal year. D. For cooperatives only, REA Form 7A, Annual Supplement to Financial and Statistical Report. E. For REA cooperatives only, REA Form 325, Financial Forecast. STAT AUTH: MS s 216B.3; 216B.8; 216B.16 Current as of 1/2/5

101 Volume 3 F. Other Supplemental Information 2. Gross Revenue Conversion Factor 1/5

102 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota DEVELOPMENT OF GROSS REVENUE CONVERSION FACTOR Docket No. E17/GR Exhibit (TAA-1) Financial Information Schedule F-2, Page 1 of 1 Definition: The incremental amount of gross revenue required to generate an additional dollar of operating income. Gross earnings fees included. Line No. Description Proposed Test Year 216 % of Incremental Gross Revenues 1 Federal Income Taxes 31.57% 2 State Income Taxes 9.8% 3 Total Tax Percentage 41.37% 4 Operating Income % = 1% % = 58.63% 5 Gross Revenue = 1.% = %

103 Volume 3 G. Commission Policy Information 1/3

104 Volume 3 G. Commission Policy Information 1. Advertising 1/5

105 OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota Schedule Detailing Advertising Expenses Proposed Test Year 216 Docket No. E17/GR Exhibit (SDT-1) Schedule G-1 Page 1 of 2 Line No. Amount 1 Total 216 Advertising $91, Includable in FERC 99 4 Conservation (not included in CIP) 5 Print 42,723 6 Radio 11,569 7 Television 25,839 8 Web 8,9 9 1 Safety 11 Print 4,46 12 Radio 87,17 13 Web 25, Customer Information 16 Print 6, Radio 72,52 18 Web 14, Total Includable FERC 99 advertising $396, Includable in FERC Demand-side Management 25 Radio 74, Web 12, Total Includable FERC 93.1 advertising $87, Total Includable Advertising $484, Excludable in FERC Sales $1, Excludable in FERC Brand and Image $415, Total Excludable $416, Proposed Test Year Advertising (Line 1 - Line 37) $484,324 4 $ 41 Advertising examples in the categories (informational, conservation, safety, bill inserts, demand-side management) follow. NOTE: See COSS Budgeted workpaper B-14 for more detail on Advertising Expense.

106 OTTER TAIL POWER COMPANY Advertising Expense Allocated to MN Proposed Test Year 216 Docket No. E17/GR Exhibit (SDT-1) Schedule G-1 Page 2 of 2 Line System Allocation Allocation MN No. FERC Account Amount Factor Percentage Amount 1 FERC ,582 C % $184, FERC ,742 C % $4, Total Includable Advertising Expense in the 216 Proposed Test Year 484,324 $225,86

107 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Conservation Advertising 1 of 96

108 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVL-2 (CoolSavings: Coffe break) Acct. Task CPRT Category Print 2 of 96

109 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-6-CR (Landscaping) Acct. Task CPRT Category Print 3 of 96

110 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-6-CR (Landscaping) Acct. Task CPRT Category Print 4 of 96

111 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-11-BW (Winter weatherization) Acct. Task CPRT Category Print 5 of 96

112 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-11-CR (Winter weatherization) Acct. Task CPRT Category Print 6 of 96

113 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-12-BW (Baseball) Acct. Task CPRT Category Print 7 of 96

114 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-12-CR (Baseball) Acct. Task CPRT Category Print 8 of 96

115 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-14-BW (Football) Acct. Task CPRT Category Print 9 of 96

116 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-14-CR (Football) Acct. Task CPRT Category Print 1 of 96

117 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-15-BW (Boys hockey) Acct. Task CPRT Category Print 11 of 96

118 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-15-CR (Boys hockey) Acct. Task CPRT Category Print 12 of 96

119 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-16-BW (Girls hockey) Acct. Task CPRT Category Print 13 of 96

120 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-16-CR (Girls hockey) Acct. Task CPRT Category Print 14 of 96

121 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-17-BW (Boys soccer) Acct. Task CPRT Category Print 15 of 96

122 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-17-CR (Boys soccer) Acct. Task CPRT Category Print 16 of 96

123 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-18-BW (Girls soccer) Acct. Task CPRT Category Print 17 of 96

124 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-18-CR (Girls soccer) Acct. Task CPRT Category Print 18 of 96

125 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-19-BW (Softball) Acct. Task CPRT Category Print 19 of 96

126 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-19-CR (Softball) Acct. Task CPRT Category Print 2 of 96

127 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-2-BW (Sports) Acct. Task CPRT Category Print 21 of 96

128 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-2-CR (Sports) Acct. Task CPRT Category Print 22 of 96

129 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-21-BW (Swimming) Acct. Task CPRT Category Print 23 of 96

130 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-21-CR (Swimming) Acct. Task CPRT Category Print 24 of 96

131 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-22-BW (Tennis) Acct. Task CPRT Category Print 25 of 96

132 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-22-CR (Tennis) Acct. Task CPRT Category Print 26 of 96

133 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-23-BW (Volleyball) Acct. Task CPRT Category Print 27 of 96

134 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-23-CR (Volleyball) Acct. Task CPRT Category Print 28 of 96

135 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-24-BW (Wrestling) Acct. Task CPRT Category Print 29 of 96

136 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-24-CR (Wrestling) Acct. Task CPRT Category Print 3 of 96

137 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-27-CR (Baseball) Acct. Task CPRT Category Print 31 of 96

138 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-29-CR (Air-source heat pump) Acct. Task CPRT Category Print 32 of 96

139 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-32-CR (Biking) Acct. Task CPRT Category Print 33 of 96

140 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-34 (Geothermal) Acct. Task CPRT Category Print 34 of 96

141 t Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-34-CR (Conserving Electricity) Acct. Task CPRT Category Print 35 of 96

142 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-35-BW (Be the lead) Acct. Task CPRT Category Print 36 of 96

143 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-35-CR (Be the lead) Acct. Task CPRT Category Print 37 of 96

144 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-2 (Winter Sports) Acct. Task CPRT Category Print 38 of 96

145 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-2-CR (Sports) Acct. Task CPRT Category Print 39 of 96

146 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-2-CR (Spring sports) Acct. Task CPRT Category Print 4 of 96

147 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-2-CR (Summer sports) Acct. Task CPRT Category Print 41 of 96

148 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-2-CR (Winter sports) Acct. Task CPRT Category Print 42 of 96

149 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Ad Name CSRVP-21-BW (boys hockey) Acct. Task CPRT Category Print 43 of 96

150 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVR-14 (Sponsorship spot) Length: 15 sec Category: Radio Acct. Task: CRAD Script Text: Ad name: CSRVR-14 Topic: Sponsorship spot Length: 15 seconds Medium: Radio Task: CRAD As demand for electricity grows, one small habit can help you save energy and money. By turning it down, unplugging it, or turning it off, a simple change can make a real difference. Otter Tail Power Company on for conservation. 44 of 96

151 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVR-16 (Refrigerator roundup) Length: 3 sec Category: Radio Acct. Task: CRAD Script Text: Ad name: CSRVR-16 Topic: Appliance recycling Length: 3 seconds Medium: Radio Task: CRAD Note: Minnesota program. Use only in Minnesota markets. Ready to get rid of a working but inefficient refrigerator or freezer? Want to earn a cool $5 reward and have someone pick up the old unit for free? Otter Tail Power Company s Minnesota customers should write this down! (sound efx pencil on paper writing notes) Inefficient fridge or freezer. 1 to 27 cubic feet. Free pick up. Call It s that easy! Did you catch the cool $5 reward? Otter Tail Power Company On for conservation. 45 of 96

152 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVR_19 (More than before) Length: 3 sec Category: Radio Acct. Task: CRAD Script Text: ANNC: Otter Tail Power company s rebates and programs help your business save money up to half the cost of your project when you install energy-efficient technologies. We have more rebates and programs than ever before too many to list in 3 seconds. Visit otpco.com/takingcareofbusiness to find what s right for you and start saving. ANNC: Otter Tail Power Company. On for business. 46 of 96

153 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVR_2 (CoolSavings) Length: 3 sec Category: Radio Acct. Task: CRAD Script Text: ANNC: Do good every day simply by doin what you do. CoolSavings from Otter Tail Power Company cycles your air conditioner on and off for fifteen minutes only during peak energy times. It's free to join - actually it's better than free! We'll pay you $7 a month all summer just for signing up. Think of it as a little reward for making a big difference on the electrical system. Go to otpco.com/coolsavings. ANNC: Otter Tail Power Company. On for you. 47 of 96

154 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVR_21 (Be the lead) Length: 3 sec Category: Radio Acct. Task: CRAD Script Text: ANNC: Little ones are watching, learning, copying, mimicking, mirroring. They re developing their unique personalities based on what you do. When you make the choice to save energy, they will too. Be the lead they want to follow. Visit otpco.com/saveenergy to learn about available rebates. ANNC: Otter Tail Power Company. On for you. 48 of 96

155 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVW-1 (Insulation) Category: Web Accounting Task: CWEB 49 of 96

156 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVW-2 (CoolSavings) Category: Web Accounting Task: CWEB 5 of 96

157 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVW-3 (Appliance recycling) Category: Web Accounting Task: CWEB 51 of 96

158 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVW-5 (More than before) Category: Web Accounting Task: CWEB 52 of 96

159 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVW-6 (Use energy wisely) Category: Web Accounting Task: CWEB 53 of 96

160 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVW-7 (CoolSavings) Category: Web Accounting Task: CWEB 54 of 96

161 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVT-8 (CoolSavings) Length: 3 sec Category: Television Acct. Task: CTEL Script Text: ANNC: These folks enrolled in Cool Savings from Otter Tail Power Company. During peak hours, we cycle their AC on and off for fifteen minutes. Sign up and we ll give you seven bucks a month all summer long. Use it to turn dandelions into daisies, a single scoop into a banana split, or movie night into a 3D double feature. Think of it as a little reward for making a big difference on the electrical system. Otter Tail Power Company on for you. 55 of 96

162 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Conservation Title: CSRVT-9 (Be the lead) Length: 3 sec Category: Television Acct. Task: CTEL Script Text: Scene: Father washes his motorcycle, son washes his bicycle. ANNC: Little ones are watching, learning, copying Scene: Mom and daughter are watering flowers with 2 different sized cans. ANNC: Mimicking, mirroring, growing Scene: A family is taking a walk. The husband is pushing a stroller and the son is pushing a smaller child in a stroller. ANNC: Shaping their unique personalities Scene: Father and daughter carrying golf bags. Father picks club out of bag. ANNC: Based on what you do. Scene: Boy realizes he left the light on in the playroom and goes back to turn it off. ANNC: When you make the choice to save energy, they will too. Be the lead they want to follow. Otter Tail Power Company on for you. 56 of 96

163 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Safety Advertising 57 of 96

164 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-1-BW (Outlet safety) Acct. Task SPRT Category Print 58 of 96

165 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-1-CR (Outlet safety) Acct. Task SPRT Category Print 59 of 96

166 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-6-BW (Ag safety) Acct. Task SPRT Category Print 6 of 96

167 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-6-CR (Ag safety) Acct. Task SPRT Category Print 61 of 96

168 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-8-BW (Ag safety) Acct. Task SPRT Category Print 62 of 96

169 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-9-BW (Harvest safety) Acct. Task SPRT Category Print 63 of 96

170 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-9-CR (Harvest safety) Acct. Task SPRT Category Print 64 of 96

171 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-17-BW (Summer storm) Acct. Task SPRT Category Print 65 of 96

172 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-17-CR (Summer storm) Acct. Task SPRT Category Print 66 of 96

173 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-18-BW (Call B4 Dig) Acct. Task SPRT Category Print 67 of 96

174 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-18-CR (CALL B4 DIG) Acct. Task SPRT Category Print 68 of 96

175 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Ad Name SAFEP-19-CR (Harvest safety stickers) Acct. Task SPRT Category Print 69 of 96

176 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER-2 (Harvest safety) Length: 3 sec Category: Radio Acct. Task: SRAD Script Text: Ad name: SAFER-2 Topic: Harvest safety Length: 3 seconds Medium: Radio Task: SRAD Harvest is often a hectic time for farmers. More workers, large equipment, and tight schedules increase the potential for accidents and injuries. Otter Tail Power Company offers these tips for a safe harvest season. Take note of overhead power lines with your workers before you get in the field. Pay special attention when hoisting augers and truck boxes or when folding tillage equipment for transport. Always have a spotter when moving large equipment near power lines. Tag: Plan ahead for a safe harvest season. Otter Tail Power Company. On for you. 7 of 96

177 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER-4 (Electrical safety month) Length: 3 sec Category: Radio Acct. Task: SRAD Script Text: Ad name: SAFER-4 Topic: Electrical safety month Length: 3 seconds Medium: Radio Task: SRAD Outdoor electrical safety Each year hundreds of people die and thousands are injured from electrical accidents. During Electrical Safety Month, Otter Tail Power Company wants to help reduce these numbers by urging you to follow these safety tips when working outdoors: After washing your vehicle, move it to a dry location before using the vacuum. Always contact your state s one call center before you dig. Never use electric lawn mowers or power tools in wet conditions. Stay at least 1 feet away from power lines when cleaning, painting or repairing your home. Otter Tail Power Company, ON for safety. 71 of 96

178 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER-5 (Electrical Safety Month) Length: 3 sec Category: Radio Acct. Task: SRAD Script Text: Ad name: SAFER-5 Topic: Electrical safety month Length: 3 seconds Medium: Radio Task: SRAD Indoor electrical safety May is Electrical Safety Month. It s the perfect time to look around your home and teach your family some of the basic rules of electrical safety. Otter Tail Power Company encourages you to plug into safety by following these simple tips: Keep all electrical appliances away from water. Use a ground fault circuit interrupter wherever water and electricity may come into contact. Don t overload outlets or extension cords. Instead use power strips whenever possible. If you have a toddler, use outlet covers and keep cords out of reach. Otter Tail Power Company, ON for safety. 72 of 96

179 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER-6 (Electrical Safety Month) Length: 3 sec Category: Radio Acct. Task: SRAD Script Text: Ad name: SAFER-6 Topic: Electrical safety month Length: 3 seconds Medium: Radio Task: SRAD Kids electrical safety Each year hundreds of people die from electrical accidents. During Electrical Safety Month, Otter Tail Power Company hopes to reduce this number by encouraging everyone to be safe around electricity. Help your kids play safely this summer by sharing these tips: Play with kites, balloons and other flying toys in open areas away from power lines. Never climb trees or build tree houses near power lines. Stay away from utility poles, transformers, and other electrical equipment. Call 911 if you notice a fallen power line. Otter Tail Power Company, ON for safety. 73 of 96

180 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER-7 (Weather spotter) Length: 6 sec Category: Radio Acct. Task: SRAD Script Text: Ad name: SAFER-7 Topic: Weather spotter Length: 6 seconds Medium: Radio Task: SRAD Customer Service Managers: This is a weather-spotter message that we run on Lakes Radio. If your local radio stations offer similar programs, you may wish to adapt your message accordingly based on the message below. If you choose to do that, please let me know and we ll create a new ad file so that we can track your message separately. Weather spotter Listen to the Lakes Radio Power of five for you every morning for your weather-eye forecasts and the latest reports from the Otter Tail Power Company weather spotter network, brought to you by the Ottertail Wadena Community Action Council. You ll hear the latest weather spotter information directly from our listeners around the region and our listening area. In the event of severe weather, you can rely on Lakes Radio and the Otter Tail Power Company weather spotter network for up-to-the-minute weather conditions throughout the area. Visit Otter Tail Power Company online at otpco.com and click on Outages and safety for power-outage information and electrical-safety and storm-preparation tips. From your backyard to major roadways and beyond the Otter Tail Power Company weather spotter network on Lakes Radio, brought to you by the Otter Tail Wadena Community Action Council. 74 of 96

181 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER-8 (Holiday safety) Length: 3 sec Category: Radio Acct. Task: SRAD Script Text: Ad name: SAFER-8 Topic: Holiday safety Length: 6 seconds Medium: Radio Task: SRAD It s easy to get overloaded during the holidays, especially when it comes to electricity. Otter Tail Power Company wants you to keep the holidays bright by thinking safety first. Toss out decorations with old or frayed cords. Don t overload circuits or run cords under rugs or furniture. And keep in mind that even small holiday bulbs carry enough current to be dangerous. Lighten the load and stay safe. Otter Tail Power Company On for you. 75 of 96

182 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER-9 (Holiday safety) Length: 6 sec Category: Radio Acct. Task: SRAD Script Text: Ad name: SAFER-9 Topic: Holiday safety Length: 6 seconds Medium: Radio Task: SRAD With the hustle and bustle of the holidays, Otter Tail Power Company reminds you that electrical safety cannot be overlooked. Periodically inspect your electric holiday decorations for cracked sockets or loose connections. Either take down your holiday lights in a timely manner after the festive season, or inspect them on a regular basis until you take them down. Holiday lights are designed for temporary use, after all. Separate outdoor holiday lights from indoor holiday lights and label them as such. And, of course, discard broken or faulty lights. Wishing you a Happy and Safe holiday season! Otter Tail Power Company On for you. 76 of 96

183 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER-9 (Holiday safety) Length: 6 sec Category: Radio Acct. Task: SRAD Script Text: Ad name: SAFER-9 Topic: Holiday safety Length: 6 seconds Medium: Radio Task: SRAD With the hustle and bustle of the holidays, Otter Tail Power Company reminds you that electrical safety cannot be overlooked. Periodically inspect your electric holiday decorations for cracked sockets or loose connections. Either take down your holiday lights in a timely manner after the festive season, or inspect them on a regular basis until you take them down. Holiday lights are designed for temporary use, after all. Separate outdoor holiday lights from indoor holiday lights and label them as such. And, of course, discard broken or faulty lights. Wishing you a Happy and Safe holiday season! Otter Tail Power Company On for you. 77 of 96

184 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER-1 (Flood safety) Length: 3 sec Category: Radio Acct. Task: SRAD Script Text: Ad name: SAFER-1 Topic: Flood safety Length: 3 seconds Medium: Radio Task: SRAD Electricity and water don t mix Spring flooding can be stressful and emotional. It also can be dangerous. Otter Tail Power Company reminds us that electricity and water don t mix. If you have water in your basement, don t go down there to shut off your main breaker or fuse box. Stay away from flooded areas where the water level has reached any part of the electrical system. Never use power tools or other electrical appliances in damp or wet areas. For more flood-safety reminders, visit otpco.com. Otter Tail Power Company On for you. Pack an emergency kit Spring flooding can be difficult especially if it catches you unprepared. Otter Tail Power Company reminds us to plan ahead this flood season. Stock a supply of drinking water, food that requires little cooking and no refrigeration, and a manual can opener. Include in your emergency kit a battery-powered radio and flashlight, batteries, medicines, and baby and pet supplies. Charge your cell phone and keep a car charger with you in case you lose power or need to leave your home. For more flood-safety reminders, visit otpco.com. Otter Tail Power Company On for you. Prepare your home Spring flooding isn t within your control. But you can be prepared. Otter Tail Power Company reminds you to: Make sure your sump pump is operational and that the discharge hose isn t frozen or plugged. Have a battery-operated power supply or portable generator to run the sump pump in case of a power interruption. But never plug a generator directly into a regular household outlet. Plug basement floor drains, bathtubs, sinks, and toilets in case your basement floods. For more flood-safety reminders, visit otpco.com. Otter Tail Power Company On for you. Otter Tail Power Company and the river Just as you must protect your home and family from rising water, Otter Tail Power Company must protect its facilities and is raising embankments and adding rock to the bases of its hydroelectric dams along the Otter Tail River. This work will not reduce the amount of water flowing. The company s licenses require that river flows run unchanged through the dams. Otter Tail Power Company urges property owners preparing for high water to use information at Otter Tail County s web site, the city of Fergus Falls web site, and at the company s web site -- otpco.com. 78 of 96

185 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER-11 (Call before you dig) Length: 3 sec Category: Radio Acct. Task: SRAD Script Text: Ad name: SAFER-11 Topic: Call before you dig Length: 3 seconds Medium: Radio Task: SRAD If you have spring or summer plans that involve excavating, be sure to Call before you dig! Otter Tail Power Company reminds you that when you dial 811 at least 48 hours before you start to dig, utilities will mark the power lines, pipes, or cables buried on your property. With just one call, you can stay safe and prevent needless outages. It s easy. And it s the law. This reminder to call 811 before you dig is brought to you by Otter Tail Power Company. 79 of 96

186 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER-12 (Summer storm readiness) Length: 3 sec Category: Radio Acct. Task: SRAD Script Text: Ad name: SAFER-12 Topic: Summer storm readiness Length: 3 seconds Medium: Radio Task: SRAD Sound efx Thunder, siren. Storms can cause unpredictable electrical outages. But you can be prepared. Otter Tail Power Company reminds you to assemble a storm kit today. Include: A flashlight, radio, and extra batteries. Drinking water, nonperishable food, and bathroom items. A first aid kit with essential medicines. Blankets and sleeping gear. Be prepared. Be safe. For more information, go to otpco.com. Otter Tail Power Company On for safety. 8 of 96

187 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFER_13 (Winter storm readiness) Length: 3 sec Category: Radio Acct. Task: SRAD Script Text: Winter storms can last for extended periods and cause unpredictable electrical outages. Otter Tail Power Company reminds you to assemble a winter storm kit today. Include: A flashlight, radio, and batteries. Drinking water and non-perishable food. A first aid kit with essential medicines. An alternate heating source, blankets, and sleeping gear. For more, go to otpco.com. Otter Tail Power Company On for safety. 81 of 96

188 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFEW-1 (Summer storm readiness) Category: Web Accounting Task: SWEB 82 of 96

189 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Safety Title: SAFEW-2 (Winter storm readiness) Category: Web Accounting Task: SWEB 83 of 96

190 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Customer Information Customer Information 84 of 96

191 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Customer Information Ad Name INFP-1-BW (Energy plan) Acct. Task IPRT Category Print 85 of 96

192 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Customer Information Ad Name INFP-1-CR (Energy plan) Acct. Task IPRT Category Print 86 of 96

193 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Customer Information Ad Name INFP-3-BW (See the light) Acct. Task IPRT Category Print 87 of 96

194 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Customer Information Ad Name INFP-3-CR (See the light) Acct. Task IPRT Category Print 88 of 96

195 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Customer Information Ad Name INFP-8-CR Acct. Task IPRT Category Print 89 of 96

196 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Customer Information Title: INFR_6 (epay: Free. Easy.) Length: 3 sec Category: Radio Acct. Task: IRAD Script Text: V.O. Paying your energy bill the old-fashioned way takes a lot of steps, including all those steps to the mailbox. SFX: Footsteps to a mailbox. Mailbox opening. Mailbox flag raising. V.O.: epay from Otter Tail Power Company is an easier way to manage your account any time, anywhere even from your mobile phone. MFX: Slow music goes to regular speed, something light and upbeat V.O.: It s free. It s easy and we ll give you $5 towards merchandise, travel and more. Take the first step, enroll at otpco.com/epay. Otter Tail Power Company, on for you. 9 of 96

197 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Customer Information Title: INFR_7 (epay - skydiving) Length: 3 sec Category: Radio Acct. Task: IRAD Script Text: PILOT: We re at 3,5 feet. You ready? SFX: Airplane engine roaring SALLY: Of course! I just enrolled in epay from Otter Tail Power Company. Managing my account is so easy. SFX: Metal door slides open. The air whips past. SALLY: and epay is available on my phone. Anytime, anywhere even way up here. PILOT: Go! Go! Go! SALLY: Try something neewww! SFX: Airplane noise fades away as Sally descends SFX: Parachute opens V.O. Free. Easy. Mobile. Enroll at otpco.com/epay. Otter Tail Power Company, on for you. 91 of 96

198 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Demand Side Management Demand Side Management 92 of 96

199 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Demand Side Management Ad Name DSMP_1_CR (Dual fuel) Acct. Task DPRT Category Print 93 of 96

200 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Demand Side Management Ad Name DSML-1 (Water Heating) Acct. Task WPRT Category Print 94 of 96

201 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Demand Side Management Ad Name DSMP-4-CR (water heating) Acct. Task WPRT Category Print 95 of 96

202 Docket No. E17/GR Exhibit (SDT-1), Schedule G-1A Demand Side Management Ad Name DSMP-4-CR (water heating) Acct. Task WPRT Category Print 96 of 96