2014 Attachment O True-Up Customer Meeting
August 25, 2015
2014 True-Up Customer Meeting

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 Meeting Purpose
◦ 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.
Minnesota Power 2014 True-Up
Attachment O
◦ Minnesota Power Attachment O to the MISO Tariff
 Develops rates for the AC system
 Schedule 7
 Schedule 8
 Schedule 9
Firm Point to Point Transactions
Non Firm Point to Point Transactions
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.
Formula Rate Protocol Timeline
Beginning 1/1/2015
2015
2016
2014 True-up
Customer
Meeting
Regional
Cost Shared
Project Meeting
Information
Request
Period Ends
8/25/2015
10//2015
12/1/2015
6/1/2014
2014 True-up Posting
Information Request
& Informal Challenge
Period Begin
9/1/2014
2016 Projected
Posting
10/2014
2016 Projected
Customer
Meeting
Informal
Challenge
Period Ends
Informational
Filing
Deadline
3/15/2016
1/31/2016
1/10/2016
Information
Request
Response
Deadline
2/28/2016
3/31/2016
Informal
Challenge
Response
Deadline
Formal
Challenge
Deadline
2014 True Up Results
2014 True-Up Disclosure
◦ 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 AC System True-Up Results
Revenue Requirement True-Up
2014 Actual
2014 Projected
Difference
$ 34,240,683
$ 36,748,925
$ (2,508,242)
1,548,000
1,534,589
Divisor True-Up
$
$
$
(13,411)
23.95
(321,153)
Interest
$
(91,188)
Total True-Up Amount (Revenue Requirement plus Divisor True-Up plus Interest)
$ (2,920,583)
Divisor (KW) X
Projected Transmission Rate ($/KW/YR)
2014 AC System True-Up History
Attachment O AC True-Up History
Year
2014
2013
2012
2011
Revenue
Requirement +
Divisor
+
$ (2,508,242)
$ (321,153)
$ 8,238,513
$ 2,889,748
$ (177,177)
$ (240,818)
$ (209,825)
$ (2,774,840)
Interest =
$ (91,188)
$ 312,839
$ (27,170)
$ (194,003)
$
$
$
$
Total
(2,920,583)
11,441,100
(445,165)
(3,178,668)
2014 Projected vs. Actual Revenue Requirement
2014 Projected Net Revenue Requirement
2012 True-Up
$ 36,748,924
$ 445,165
Cost Deviations for 2014
Lower Operating Costs
Lower Return Requirement
Higher Attachment GG and ZZ Credits
Lower Revenue Credits
2014 Actual Net Revenue Requirement
$
$
$
$
$
(396,212)
(443,240)
(1,108,483)
(1,005,471)
34,240,683
2014 Projected vs. Actual Operating Costs
2014 Projected Net Revenue Requirement
2012 True-Up
$ 36,748,924
$ 445,165
Cost Deviations for 2014
Lower Operating Costs
Lower Return Requirement
Higher Attachment GG and ZZ Credits
Lower Revenue Credits
2014 Actual Net Revenue Requirement
$
$
$
$
$
(396,212)
(443,240)
(1,108,483)
(1,005,471)
34,240,683
2014 Projected vs. Actual Operating Cost Detail
$ 47,061,995
Projected 2014 Operating Costs
Lower O&M Costs (Transmission and A&G)
Higher Depreciation Expense
Lower Taxes Other Than Income Taxes
Lower Income Taxes
Net Decreased Operating Costs
Actual Operating Costs for 2014
$
$
$
$
(636,492)
456,793
(183,003)
(33,510)
$
(396,212)
46,665,783
2014 Projected vs. Actual Return Requirement
2014 Projected Net Revenue Requirement
2012 True-Up
$ 36,748,924
$ 445,165
Cost Deviations for 2014
Lower Operating Costs
Lower Return Requirement
Higher Attachment GG and ZZ Credits
Lower Revenue Credits
2014 Actual Net Revenue Requirement
$ (396,212)
$ (443,240)
$ (1,108,483)
$ (1,005,471)
$ 34,240,683
2014 Projected vs. Actual Return Requirement Detail
Change in Rate Base
$ 235,431,510
Projected 2014 Rate Base
Lower Average Net Plant In Service
Lower Average CWIP
Lower Accumulated Deferred Taxes
Lower Land Held For Future Use
Higher Total Working Capital
Net Decrease in Rate Base
Total Actual Rate Base - 2014
$ (5,170,657)
$ (631,941)
$ 4,933,849
$
(230)
$ 455,627
$ (413,352)
$ 235,018,158
2014 Projected vs. Actual Return Requirement Detail
Change in Cost of Capital
Long Term Debt
Common Stock
Weighted Cost of Capital
2014 Projected
2014 Actual
D/E Ratio Cost
D/E Ratio Cost
46.00% 2.01%
46.00% 1.85%
54.00% 6.70%
54.00% 6.68%
8.71%
8.53%
2014 Projected vs. Actual Return Requirement Detail
Change of Return Calculation
Lower Return Requirement was caused by decrease in Rate Base:
Change in Rate Base ($-413,352 x 8.53%)
Projected Rate Base x Decrease in Cost of Capital ($235,431,510 x .18%)
Net Change in Return
$ (35,259)
$ (423,777)
$ (459,036)
2014 Projected vs. Actual Attachment GG and ZZ Credits
2014 Projected Net Revenue Requirement
2012 True-Up
$ 36,748,924
$ 445,165
Cost Deviations for 2014
Lower Operating Costs
Lower Return Requirement
Higher Attachment GG and ZZ Credits
Lower Revenue Credits
2014 Actual Net Revenue Requirement
$
$
$
$
$
(396,212)
(443,240)
(1,108,483)
(1,005,471)
34,240,683
2014 Projected vs. Actual
Lower Attachments GG and ZZ Credits Detail
2014 Projected Revenue Requirment
2014 Revenue Requirement Deviations
Annual Expense Charge
Annual Return Charge
Depreciation Expense
Total Revenue Requirement Deviations
2014 Actual Revenue Requirement
Attachment GG
Attachment ZZ
$ 21,521,790
$
4,776,079
$
271,283
$
485,762
$
35,153
$
792,198
$ 22,313,988
$
$
$
$
$
(322,435)
(501,725)
(89,878)
(914,038)
3,862,041
2014 Projected vs. Actual Revenue Credits
2014 Projected Net Revenue Requirement
2012 True-Up
$ 36,748,924
$ 445,165
Cost Deviations for 2014
Lower Operating Costs
Lower Return Requirement
Higher Attachment GG and ZZ Credits
Lower Revenue Credits
2014 Actual Net Revenue Requirement
$ (396,212)
$ (443,240)
$ (1,108,483)
$ (1,005,471)
$ 34,240,683
2014 Projected vs. Actual Revenue Credit Detail
2014 Projected Revenue Credits
2014 Actual Revenue Credits
Increase in Revenue Credits
(Decrease to Revenue Requirement)
($4,068,164)
($5,073,635)
$1,005,471
2014 DC System True-Up Results
2014 Actual
2014 Projected
Difference
$ 17,371,659
$ 13,851,317
$ 3,520,342
588,000
500,000
Divisor True-Up
(88,000)
$
27.70
$ (2,437,864)
Interest
$
Total True-Up Amount (Revenue Requirement plus Divisor True-Up plus Interest)
$ 1,152,839
Revenue Requirement True-Up
Divisor (KW) X
Projected Transmission Rate ($/KW/YR)
70,361
2014 DC System True-Up History
Attachment O DC True-Up History
Year
2014
2013
2012
2011
Revenue
Requirement + Divisor + Interest =
Total
$ 3,520,342
$ (2,437,864)
$ 70,361
$ 1,152,839
$ (1,618,249)
$
$ (105,186) $ (1,723,435)
$
28,244
$
$ 835
$ 29,079
$ 889,486
$
$ 26,470
$ 915,956
2014 Projected vs. Actual DC Revenue Requirement
2014 Projected Net Revenue Requirement
2012 True-Up
$ 13,851,317
$
(29,079)
Cost Deviations for 2014
Higher Operating Costs
Higher Return Requirement
Lower Attachment ZZ Credits*
Lower Revenue Credits
Lower Attachment N-1 Project Credits
2014 Actual Net Revenue Requirement
* Minnesota Power does not have any DC cost shared projects.
$ 1,432,722
$
940,714
$
698,856
$
72,501
$
404,629
$ 17,371,659
2014 Projected vs. Actual DC Operating Costs
2014 Projected Net Revenue Requirement
2012 True-Up
$ 13,851,317
$ (29,079)
Cost Deviations for 2014
Higher Operating Costs
Higher Return Requirement
Lower Attachment ZZ Credits*
Lower Revenue Credits
Lower Attachment N-1 Project Credits
2014 Actual Net Revenue Requirement
* Minnesota Power does not have any DC cost shared projects.
$ 1,432,722
$ 940,714
$ 698,856
$
72,501
$ 404,629
$ 17,371,659
2014 Projected vs. Actual DC Operating Cost Detail
$ 9,954,504
Projected 2014 Operating Costs
Higher O&M Costs (Transmission and A&G)
Higher Depreciation Expense
Increased Taxes Other Than Income Taxes
Increased Income Taxes
Net Increased Operating Costs
Actual Operating Costs for 2014
$
$
$
$
410,228
205,538
250,376
566,580
$ 1,432,722
11,387,225
2014 Projected vs. Actual DC Return Requirement
2014 Projected Net Revenue Requirement
2012 True-Up
$ 13,851,317
$ (29,079)
Cost Deviations for 2014
Higher Operating Costs
Higher Return Requirement
Lower Attachment ZZ Credits*
Lower Revenue Credits
Lower Attachment N-1 Project Credits
2014 Actual Net Revenue Requirement
* Minnesota Power does not have any DC cost shared projects.
$ 1,432,722
$ 940,714
$ 698,856
$
72,501
$ 404,629
$ 17,371,659
2014 Projected vs. Actual DC
Return Requirement Detail Change in Rate Base
Projected 2014 Rate Base
Higher Average Net Plant In Service
Higher Accumulated Deferred Taxes
Lower Total Working Capital
Net Increase in Rate Base
Total Actual Rate Base - 2014
57,929,706
$ 13,386,095
$ (1,566,031)
$ 380,298
$ 12,200,362
$ 70,130,068
2014 Projected vs. Actual DC
Return Requirement Detail Change in Cost of Capital
Long Term Debt
Common Stock
Weighted Cost of Capital
2014 Projected
2014 Actual
D/E Ratio Cost
D/E Ratio Cost
46.00% 2.01%
46.00% 1.85%
54.00% 6.70%
54.00% 6.68%
8.71%
8.53%
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%)
Projected Rate Base x Decrease in Cost of Capital ($57,929,706 x .18%)
Net Change in Return
$ 1,040,691
$ (104,273)
$ 936,417
2014 Projected vs. Actual DC Attachment ZZ Credit
2014 Projected Net Revenue Requirement
2012 True-Up
$ 13,851,317
$ (29,079)
Cost Deviations for 2014
Higher Operating Costs
Higher Return Requirement
Lower Attachment ZZ Credits*
Lower Revenue Credits
Lower Attachment N-1 Project Credits
2014 Actual Net Revenue Requirement
* Minnesota Power does not have any DC cost shared projects.
$ 1,432,722
$ 940,714
$ 698,856
$
72,501
$ 404,629
$ 17,371,659
2014 Projected vs. Actual
Attachment ZZ Credit Detail
Attachment GG *
2014 Projected Revenue Requirment *
2014 Revenue Requirement Deviations
Annual Expense Charge
Annual Return Charge
Depreciation Expense
Total Revenue Requirement Deviations
2014 Actual Revenue Requirement
Attachment ZZ
$
-
$
698,856
$
$
$
$
$
-
$
$
$
$
$
121,807
336,265
73,393
531,465
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
2012 True-Up
$ 13,851,317
$
(29,079)
Cost Deviations for 2014
Higher Operating Costs
Higher Return Requirement
Lower Attachment ZZ Credits*
Lower Revenue Credits
Lower Attachment N-1 Project Credits
2014 Actual Net Revenue Requirement
* Minnesota Power does not have any DC cost shared projects.
$ 1,432,722
$ 940,714
$ 698,856
$
72,501
$ 404,629
$ 17,371,659
2014 Projected vs. Actual DC Revenue Credit Detail
2014 Projected Revenue Credits
2014 Actual Revenue Credits
Net Decrease in Revenue Credits
(Increase to Revenue Requirement)
($72,501)
$0
$72,501
2014 Projected vs. Actual DC
Attachment N-1 Project Credit
2014 Projected Net Revenue Requirement
2012 True-Up
$ 13,851,317
$
(29,079)
Cost Deviations for 2014
Higher Operating Costs
Higher Return Requirement
Lower Attachment ZZ Credits*
Lower Revenue Credits
Lower Attachment N-1 Project Credits
2014 Actual Net Revenue Requirement
* Minnesota Power does not have any DC cost shared projects.
$ 1,432,722
$ 940,714
$ 698,856
$
72,501
$ 404,629
$ 17,371,659
2014 Projected vs. Actual DC
Attachment N-1 Project Credit Detail
2013 Projected Attachment N-1 Revenue Credits
2013 Actual Attachment N-1 Revenue Credits
Net Increase in Revenue Credits
(Decrease to Revenue Requirement)
($404,629)
$0
($404,629)
2014 True-Up Information Exchange
◦ 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 Transmission Customer Meeting
Questions?
2014 Transmission Customer Meeting
Contacts:
Jeanne Kallberg
jkallberg@mnpower.com
(218) 355-2648
Kara Henderson
khenderson@mnpower.com
(218) 355-2869