5

2014 Attachment O True-Up Customer Meeting

August 25, 2015

Agenda◦ Introduction◦ Purpose of Today’s Meeting◦ Attachment O Rates Structure◦ Regulatory Timeline◦ Disclosure◦ 2014 True Up and Projected Attachment O Review◦ Supporting Documentation◦ Changes to Formula Rate True Protocols◦ Questions

2014 True-Up Customer Meeting

◦ Comply with the Formula Rate Protocol requiring a Customer Meeting to discuss the Actual 2014 Attachment O rate information between June 1 and September 1.

◦ Review the 2014 True-Up calculation that will be included in the development of the projected rates that will be effective January 1 through December 31, 2016.

◦ Review and compare the 2014 actual Attachment O information and 2014 budget Attachment O information upon which 2014 Attachment O rates were based.

2014 True-Up Meeting Purpose

◦ Minnesota Power Attachment O to the MISO Tariff

Develops rates for the AC system Schedule 7 Firm Point to Point Transactions Schedule 8 Non Firm Point to Point Transactions Schedule 9 Network Transmission Service

Develops rate for the HVDC system Schedule 7 Firm Point to Point Transactions

Minnesota Power 2014 True-Up Attachment O

◦ Submitted to MISO and posted on MISO’s website on May 28, 2015

◦ MISO is in the process of reviewing Minnesota Power’s 2014 True-Up Attachment O

◦ The 2014 true-up amount, plus any interest will be applied to the annual 2016 Attachment O revenue requirement and rates.

Minnesota Power 2014 True-Up Attachment O

Formula Rate Protocol Timeline Beginning 1/1/2015

6/1/2014 9/1/2014 10/2014

2014 True-up PostingInformation Request & Informal Challenge

Period Begin

2016 Projected Posting

8/25/2015

2014 True-up Customer Meeting

2016 Projected Customer Meeting

10//2015

RegionalCost Shared

Project Meeting

Information Request

Period Ends12/1/2015

1/10/2016

InformationRequest

ResponseDeadline

Informal Challenge

Period Ends1/31/2016

2/28/2016

InformalChallengeResponseDeadline

InformationalFiling

Deadline3/15/2016

3/31/2016

FormalChallengeDeadline

2015 2016

2014 True Up Results

◦ Minnesota Power’s 2014 True-Up transmission rate is subject to change pending review by MISO and other Interested Parties. Information in this presentation is based upon Minnesota Power’s 2014 True-Up Attachment O, filed at MISO on May 28, 2015.

2014 True-Up Disclosure

2014 AC System True-Up Results

2014 Actual 2014 Projected DifferenceRevenue Requirement True-Up 34,240,683$ 36,748,925$ (2,508,242)$

Divisor (KW) X 1,548,000 1,534,589 (13,411)$ Projected Transmission Rate ($/KW/YR) 23.95$ Divisor True-Up (321,153)$

Interest (91,188)$

Total True-Up Amount (Revenue Requirement plus Divisor True-Up plus Interest) (2,920,583)$

2014 AC System True-Up History

Attachment O AC True-Up History

YearRevenue

Requirement + Divisor + Interest = Total2014 (2,508,242)$ (321,153)$ (91,188)$ (2,920,583)$ 2013 8,238,513$ 2,889,748$ 312,839$ 11,441,100$ 2012 (177,177)$ (240,818)$ (27,170)$ (445,165)$ 2011 (209,825)$ (2,774,840)$ (194,003)$ (3,178,668)$

2014 Projected vs. Actual Revenue Requirement

2014 Projected Net Revenue Requirement 36,748,924$ 2012 True-Up 445,165$ Cost Deviations for 2014

Lower Operating Costs (396,212)$ Lower Return Requirement (443,240)$ Higher Attachment GG and ZZ Credits (1,108,483)$ Lower Revenue Credits (1,005,471)$ 2014 Actual Net Revenue Requirement 34,240,683$

2014 Projected vs. Actual Operating Costs

2014 Projected Net Revenue Requirement 36,748,924$ 2012 True-Up 445,165$ Cost Deviations for 2014

Lower Operating Costs (396,212)$ Lower Return Requirement (443,240)$ Higher Attachment GG and ZZ Credits (1,108,483)$ Lower Revenue Credits (1,005,471)$ 2014 Actual Net Revenue Requirement 34,240,683$

2014 Projected vs. Actual Operating Cost Detail

Projected 2014 Operating Costs 47,061,995$ Lower O&M Costs (Transmission and A&G) (636,492)$ Higher Depreciation Expense 456,793$ Lower Taxes Other Than Income Taxes (183,003)$ Lower Income Taxes (33,510)$ Net Decreased Operating Costs (396,212)$ Actual Operating Costs for 2014 46,665,783

2014 Projected vs. Actual Return Requirement

2014 Projected Net Revenue Requirement 36,748,924$ 2012 True-Up 445,165$ Cost Deviations for 2014

Lower Operating Costs (396,212)$ Lower Return Requirement (443,240)$ Higher Attachment GG and ZZ Credits (1,108,483)$ Lower Revenue Credits (1,005,471)$ 2014 Actual Net Revenue Requirement 34,240,683$

2014 Projected vs. Actual Return Requirement DetailChange in Rate Base

Projected 2014 Rate Base 235,431,510$ Lower Average Net Plant In Service (5,170,657)$ Lower Average CWIP (631,941)$ Lower Accumulated Deferred Taxes 4,933,849$ Lower Land Held For Future Use (230)$ Higher Total Working Capital 455,627$ Net Decrease in Rate Base (413,352)$ Total Actual Rate Base - 2014 235,018,158$

2014 Projected vs. Actual Return Requirement DetailChange in Cost of Capital

Weighted Cost of Capital

D/E Ratio Cost D/E Ratio CostLong Term Debt 46.00% 2.01% 46.00% 1.85%Common Stock 54.00% 6.70% 54.00% 6.68%

8.71% 8.53%

2014 Projected 2014 Actual

2014 Projected vs. Actual Return Requirement DetailChange of Return Calculation

Lower Return Requirement was caused by decrease in Rate Base:

Change in Rate Base ($-413,352 x 8.53%) (35,259)$ Projected Rate Base x Decrease in Cost of Capital ($235,431,510 x .18%) (423,777)$ Net Change in Return (459,036)$

2014 Projected vs. Actual Attachment GG and ZZ Credits

2014 Projected Net Revenue Requirement 36,748,924$ 2012 True-Up 445,165$ Cost Deviations for 2014

Lower Operating Costs (396,212)$ Lower Return Requirement (443,240)$ Higher Attachment GG and ZZ Credits (1,108,483)$ Lower Revenue Credits (1,005,471)$ 2014 Actual Net Revenue Requirement 34,240,683$

2014 Projected vs. Actual Lower Attachments GG and ZZ Credits Detail

Attachment GG Attachment ZZ

2014 Projected Revenue Requirment 21,521,790$ 4,776,079$ 2014 Revenue Requirement Deviations Annual Expense Charge 271,283$ (322,435)$ Annual Return Charge 485,762$ (501,725)$ Depreciation Expense 35,153$ (89,878)$ Total Revenue Requirement Deviations 792,198$ (914,038)$ 2014 Actual Revenue Requirement 22,313,988$ 3,862,041$

2014 Projected vs. Actual Revenue Credits

2014 Projected Net Revenue Requirement 36,748,924$ 2012 True-Up 445,165$ Cost Deviations for 2014

Lower Operating Costs (396,212)$ Lower Return Requirement (443,240)$ Higher Attachment GG and ZZ Credits (1,108,483)$ Lower Revenue Credits (1,005,471)$ 2014 Actual Net Revenue Requirement 34,240,683$

2014 Projected vs. Actual Revenue Credit Detail

2014 Projected Revenue Credits ($4,068,164)2014 Actual Revenue Credits ($5,073,635)Increase in Revenue Credits $1,005,471

(Decrease to Revenue Requirement)

2014 DC System True-Up Results

2014 Actual 2014 Projected DifferenceRevenue Requirement True-Up 17,371,659$ 13,851,317$ 3,520,342$

Divisor (KW) X 588,000 500,000 (88,000) Projected Transmission Rate ($/KW/YR) 27.70$ Divisor True-Up (2,437,864)$

Interest 70,361$

Total True-Up Amount (Revenue Requirement plus Divisor True-Up plus Interest) 1,152,839$

2014 DC System True-Up History

Attachment O DC True-Up History

YearRevenue

Requirement + Divisor + Interest = Total2014 3,520,342$ (2,437,864)$ 70,361$ 1,152,839$ 2013 (1,618,249)$ -$ (105,186)$ (1,723,435)$ 2012 28,244$ -$ 835$ 29,079$ 2011 889,486$ -$ 26,470$ 915,956$

2014 Projected vs. Actual DC Revenue Requirement

2014 Projected Net Revenue Requirement 13,851,317$ 2012 True-Up (29,079)$ Cost Deviations for 2014

Higher Operating Costs 1,432,722$ Higher Return Requirement 940,714$ Lower Attachment ZZ Credits* 698,856$ Lower Revenue Credits 72,501$ Lower Attachment N-1 Project Credits 404,629$ 2014 Actual Net Revenue Requirement 17,371,659$

* Minnesota Power does not have any DC cost shared projects .

2014 Projected vs. Actual DC Operating Costs

2014 Projected Net Revenue Requirement 13,851,317$ 2012 True-Up (29,079)$ Cost Deviations for 2014

Higher Operating Costs 1,432,722$ Higher Return Requirement 940,714$ Lower Attachment ZZ Credits* 698,856$ Lower Revenue Credits 72,501$ Lower Attachment N-1 Project Credits 404,629$ 2014 Actual Net Revenue Requirement 17,371,659$

* Minnesota Power does not have any DC cost shared projects .

2014 Projected vs. Actual DC Operating Cost Detail

Projected 2014 Operating Costs 9,954,504$ Higher O&M Costs (Transmission and A&G) 410,228$ Higher Depreciation Expense 205,538$ Increased Taxes Other Than Income Taxes 250,376$ Increased Income Taxes 566,580$ Net Increased Operating Costs 1,432,722$ Actual Operating Costs for 2014 11,387,225

2014 Projected vs. Actual DC Return Requirement

2014 Projected Net Revenue Requirement 13,851,317$ 2012 True-Up (29,079)$ Cost Deviations for 2014

Higher Operating Costs 1,432,722$ Higher Return Requirement 940,714$ Lower Attachment ZZ Credits* 698,856$ Lower Revenue Credits 72,501$ Lower Attachment N-1 Project Credits 404,629$ 2014 Actual Net Revenue Requirement 17,371,659$

* Minnesota Power does not have any DC cost shared projects .

2014 Projected vs. Actual DC Return Requirement Detail Change in Rate Base

Projected 2014 Rate Base 57,929,706 Higher Average Net Plant In Service 13,386,095$ Higher Accumulated Deferred Taxes (1,566,031)$ Lower Total Working Capital 380,298$ Net Increase in Rate Base 12,200,362$ Total Actual Rate Base - 2014 70,130,068$

2014 Projected vs. Actual DCReturn Requirement Detail Change in Cost of Capital

Weighted Cost of Capital

D/E Ratio Cost D/E Ratio CostLong Term Debt 46.00% 2.01% 46.00% 1.85%Common Stock 54.00% 6.70% 54.00% 6.68%

8.71% 8.53%

2014 Projected 2014 Actual

2014 Projected vs. Actual DC Return Requirement Detail Change of Return Calculation

Higher Return Requirement was caused by increase in Rate Base:

Change in Rate Base ($12,200,362 x 8.53%) 1,040,691$ Projected Rate Base x Decrease in Cost of Capital ($57,929,706 x .18%) (104,273)$ Net Change in Return 936,417$

2014 Projected vs. Actual DC Attachment ZZ Credit

2014 Projected Net Revenue Requirement 13,851,317$ 2012 True-Up (29,079)$ Cost Deviations for 2014

Higher Operating Costs 1,432,722$ Higher Return Requirement 940,714$ Lower Att achment ZZ Credits* 698,856$ Lower Revenue Credits 72,501$ Lower Attachment N-1 Project Credits 404,629$ 2014 Actual Net Revenue Requirement 17,371,659$

* Minnesota Power does not have any DC cost shared projects .

2014 Projected vs. Actual Attachment ZZ Credit Detail

Attachment GG * Attachment ZZ

2014 Projected Revenue Requirment * -$ 698,856$ 2014 Revenue Requirement Deviations Annual Expense Charge -$ 121,807$ Annual Return Charge -$ 336,265$ Depreciation Expense -$ 73,393$ Total Revenue Requirement Deviations -$ 531,465$ 2014 Actual Revenue Requirement -$ 1,230,321$

* Minnesota Power does not have any DC cost shared projects.

2014 Projected vs. Actual DC Revenue Credit

2014 Projected Net Revenue Requirement 13,851,317$ 2012 True-Up (29,079)$ Cost Deviations for 2014

Higher Operating Costs 1,432,722$ Higher Return Requirement 940,714$ Lower Attachment ZZ Credits* 698,856$ Lower Revenue Credits 72,501$ Lower Attachment N-1 Project Credits 404,629$ 2014 Actual Net Revenue Requirement 17,371,659$

* Minnesota Power does not have any DC cost shared projects .

2014 Projected vs. Actual DC Revenue Credit Detail

2014 Projected Revenue Credits ($72,501)2014 Actual Revenue Credits $0Net Decrease in Revenue Credits $72,501

(Increase to Revenue Requirement)

2014 Projected vs. Actual DC Attachment N-1 Project Credit

2014 Projected Net Revenue Requirement 13,851,317$ 2012 True-Up (29,079)$ Cost Deviations for 2014

Higher Operating Costs 1,432,722$ Higher Return Requirement 940,714$ Lower Attachment ZZ Credits* 698,856$ Lower Revenue Credits 72,501$ Lower Attachment N-1 Project Credits 404,629$ 2014 Actual Net Revenue Requirement 17,371,659$

* Minnesota Power does not have any DC cost shared projects .

2014 Projected vs. Actual DC Attachment N-1 Project Credit Detail

2013 Projected Attachment N-1 Revenue Credits ($404,629)2013 Actual Attachment N-1 Revenue Credits $0Net Increase in Revenue Credits ($404,629)

(Decrease to Revenue Requirement)

◦ Interested Parties can submit information requests until December 1, 2015.*

◦ MP shall make a good faith effort to respond within 15 business days.◦ Submit information requests via email to:

FormulaRateResponseTeam@mnpower.com◦ All questions and responses will be distributed via email to the

Interested Party who asked the question and also will be posted on the MISO website.

* Subject to FERC’s final decision on Docket ER13-2379 (FERC’s Investigation of MISO Formula Rate Protocols)

2014 True-Up Information Exchange

Questions?

2014 Transmission Customer Meeting

Contacts: Jeanne Kallberg

jkallberg@mnpower.com(218) 355-2648

Kara Hendersonkhenderson@mnpower.com(218) 355-2869

2014 Transmission Customer Meeting