Otter Tail Power Company Profile and Capital Projects Overview
This document provides detailed information about Otter Tail Power Company's 2013 Attachment O calculations, true-up processes, customer meetings, and projected net revenue requirements. It includes data on rate base changes, operating expenses, revenue requirements, and rate summaries for transparency and stakeholder engagement.
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Meeting Purpose Otter Tail Power Company Profile Attachment O Calculation Capital Projects Question/Answer 2
To provide an informational forum regarding Otter Tails 2013 Attachment O for True-up. The 2013 Actual Year Attachment O is calculated using the FERC Form 1 Attachment O template under the MISO Tariff utilizing actual data as reported in the 2013 FERC Form 1 for Otter Tail Power. Any True-up for 2013 will be included in the 2015 FLTY Attachment O Calculation for rates effective January 1, 2015 for the joint pricing zone comprised of Otter Tail, Great River Energy, and Missouri River Energy Services. 3
Actual Year Rate Requirements Rate Base Operating Expenses Revenue Requirement and Rate Network Rate Summary 5
By June 1 of each year, Otter Tail will post on OASIS all information regarding any Attachment O True-up Adjustments for the prior year. By September 1, 2014, and September 1 all years thereafter, Otter Tail will hold a customer meeting to explain its Actual Year True-up Calculation. Ex., 2013 Forward Looking Attachment O will be trued-up by June 1, 2014 with a corresponding Customer Meeting being held by September 1, 2014. Beginning Sept. 1, 2010 and Sept. 1 all years thereafter, Otter Tail will post on OASIS its projected Net Revenue Requirement ,including the True- Up Adjustment and load for the following year, and associated work papers. Beginning in 2010 and each year thereafter, Otter Tail will hold a customer meeting by October 31, to explain its formula rate input projections and cost detail. Beginning in 2014 and each year thereafter, the MISO Transmission Owners will hold a Regional Cost Sharing stakeholder meeting by November 1. 6
2013 Actual 2013 Projected % Rate Base Item $ Change Explanation Change The decrease in Plant in Service from Projected to Actual was due to a combination of the Bemidji CAPX project going into service at less than expected capitalized cost as well as the delayed in-service of various line segments on the Bookings and Fargo CAPX projects Gross Plant in Service $275,626,777 $287,571,748 $(11,944,971) (4.2%) Accumulated Depreciation Net result of Annual Depreciation Expense combined with projected retirements. $102,362,268 $102,744,252 $(381,984) (0.4%) Net Plant in Service $173,264,509 $184,827,496 $(11,562,987) (6.3%) = Gross Plant - A/D ADIT - Book vs Tax Depreciation Timing Differences originating due to accelerated tax depreciation methods such as Bonus depreciation and MACRS tables created when large Transmission (i.e., Fargo Phase II and Fargo Phase III) projects go into service. Reduced spend on Fargo CAPX project in late 2012 due to delays associated with material deliveries that carried forward through 2013. All is expected to be timing in nature. Adjustments to Rate Base $(42,727,177) $(44,023,296) $1,296,119 (2.9%) $47,702,021 $53,482,317 $(5,780,296) (10.8%) CWIP for CON Projects Land Held for Future Use $9,037 $9,038 $(1) 0.0% Decrease in CWC due to drop in Transmission- related O&M which is discussed on the next tab. $5,359,241 $5,830,055 $(470,814) (8.1%) Working Capital = Net Plant + Adj + CWIP + Land + Working Capital $183,607,631 $200,125,610 $(16,517,979) (8.3%) Rate Base 7 Note: The above numbers are Transmission only
Expense Item 2013 Actual 2013 Projected $ Change % Change Explanation Total Company 2013 Actual O&M for Transmission expense decreased by ~$540K or only about 3% compared to the reported amounts used in the Forward Looking Test Year (FLTY). However, the amounts related to MISO 26/26A and Schedule 10 charges actually went up ~$1.75M which increased the amount removed from O&M s on Attachment O. $12,766,870 $15,223,429 $(2,456,559) (16.1%) O&M Decrease in depreciation expense coincides with the reduction in expected Plant in Service reported on the previous slide. Depreciation Expense $5,785,772 $5,923,798 $(138,026) (2.3%) Property Tax Assessments came in lower than expected and a lower GP allocator are driving the decrease in transmission-related property tax allocations calculated on Attachment O. Taxes Other than Income $2,173,165 $2,373,190 $(200,025) (8.4%) Decrease in Rate Base = Decrease in Return = Decrease in Income Tax Expense; Also, 2013 had a lower ETR than at the time the FLTY calculation was completed as the ND State Tax rate has been lowered from 5.15% to 4.53%. Income Taxes $7,144,939 $7,933,216 $(788,277) (9.9%) Operating Expense $27,870,746 $31,453,633 $(3,582,887) (11.4%) = O&M + A&G + Depreciation + Taxes 8 Note: The above numbers are Transmission only
2013 Actual 2013 Projected $ Change % Change Explanation 46.48% 46.17% 0.31% Long Term Debt Tracking close to forecast. 53.52% 53.83% (0.31%) Tracking close to forecast. Common Stock 100.00% 100.00% = Debt + Equity Refinanced slightly more outstanding debt at a lower rate than originally expected . Unchanged = (LTD*Cost)+(Preferred Stock*Cost)+(Common Stock*Cost) From "Rate Base" Calculation = Rate of Return * Rate Base Total 5.49% 5.73% (0.24%) Weighted Cost of Debt 12.38% 9.18% 12.38% 9.31% 0.00% (0.13%) (8.25%) (9.55%) Cost of Common Stock Rate of Return Rate Base Allowed Return $183,607,631 $16,850.312 $200,125,610 $18,629,007 $(16,517,979) $(1,778,695) $27,870,746 $31,453,633 $(3,582,887) (11.39%) From "Operating Expense" Calculation Operating Expenses As with the discussion associated with the change in CWIP on Attachment O, GG projects have spent less to date than expected due to delays in material deliveries which also leads to less than expected revenue requirements. As with the discussion associated with the change in CWIP on Attachment O, MM projects have spent less to date than expected which leads to lower than expected revenue requirements. Attachment GG Adjustments $10,937,462 $13,142,264 $(2,204,802) (16.78%) Attachment MM Adjustments $2,377,316 $3,007,552 $(630,236) (20.96%) Gross Revenue Requirement $31,406,280 $33,932,824 $(2,526,544) (7.45%) = Return + Expenses - Adjustments 2013 Actual Year Other MISO Schedule revenue as well as ITA contractual payments were less than projected. $4,566,650 $7,328,404 $(2,771,754) -37.82% Revenue Credits 2012 True-up (Including Interest) $(4,159,423) $(4,159,423) - 0.00% N/A Net Revenue Requirement $22,690,207 $22,444,998 $245,210 1.09% = Gross Revenue Requirement - Revenue Credits + True-up 9
Attachment O True-up Calculation 2013 Actual 2013 Projected $ Change % Change Explanation From Net Revenue Requirement line on previous slide. $245,210 ATRR True-up $704,697 $670,317 $(34,380) (5.13%) From FERC Form 1 Divisor Projected Cost ($/kW/Yr) $33.484 From 2013 FLTY Attachment O Template $(1,151,185) Divisor True-up = Divisor x Projected Cost ($/kW/Yr) Total Principal True-up = ATRR + Divisor True-up Amounts $(905,975) = Avg Monthly FERC Interest Rate on Refunds x Principal True-up To be Applied to 2015 FLTY Attachment O Calculation $(59,508) Interest on True-up Total Principal and Interest True-up $(965,483) 10
$3.00 $2.79 $2.68 $2.50 $0.11 or 3.9% Decrease $2.00 $1.50 $1.00 $0.50 $0.35 $0.27 $0.08 $0.00 ($0.03) ($0.04) ($0.10) ($0.14) ($0.24) ($0.27) ($0.50) ($1.00) 11
Total Rev. Req. = $36,004,985 Net Attch. O ATRR = $22,690,207 Attch. GG Rev. Req. = $10,937,462 Attch. MM Rev. Req. = $2,377.316 12
Actual 2013 Capital Addition Forecasted 2013 Capital Addition % Project $ Change Reason for Variance Reason for Variance Variance Project scope changed to include 5 breaker replacements rather than 4 Circuit Breaker Replacements $300,000 $342,593 $42,593 14.2% Rejected Pole Replacements $400,000 $415,960 $15,960 4.0% Tracking close to forecast Jamestown Edgeley Oakes Line Rebuild Reliability concerns addressed by a lower cost plan $500,000 $202,273 ($297,727) (59.5%) Project delayed due to negotiations with third party Parshall Area 115 kV Source $600,000 $5,348 ($594,652) (99.1%) Summit 115/41.6 kV Transformer Replacement Material costs were lower than expected $1,000,000 $619,717 ($380,283) (37.8%) Engineering has delayed the initiation of expected construction activities Transmission Line Capacity Upgrades $5,000,000 $2,452,216 ($2,547,784) (51.0%) Oakes Area Transmission Improvements Project delayed due to budget constraints $5,637,004 $455,650 ($5,181,354) (91.9%) 14
Forecasted 2013 Capital Addition Actual 2013 Capital Addition % Project $ Change Reason for Variance Variance Attachment GG Buffalo Casselton 115 kV Line Underlying improvements delayed until 2014 and 2015 ($4,179,883) $7,506,464 $3,326,581 (55.7%) Fargo St. Cloud 345 kV Line Material deliveries accelerated during 2013 $20,683,120 $27,077,796 30.9% $6,394,676 Attachment MM Weather impacted expected project schedule. ($1,093,967) $11,587,249 $10,493,282 (9.4%) Brookings Hampton Line Project development activities did not occur as quickly as forecasted Big Stone South Brookings Line ($980,140) $1,562,040 $581,900 (62.7%) Project development activities did not occur as quickly as forecasted Big Stone South Ellendale Line ($1,444,924) $3,865,059 $2,420,133 (37.4%) 15
If you have any additional questions after the meeting, please submit via e-mail to: Kyle Sem, CPA Manager Business Planning ksem@otpco.com All questions and answers will be distributed by e-mail to all attendees. Additionally, the questions and answers will be posted on Otter Tail s OASIS website (http://www.oasis.oati.com/OTP/index.html) within two weeks from the date of inquiry. 16
