Otter Tail Power Company Before the Otter Tail Power Company South Dakota Public Utilities Commission Before the South Dakota Public Utilities Commission Application for Authority to Application for Increase Electric Rates in South Dakota Authority to Increase Electric Docket No. EL18-___ Rates in South Dakota Docket No. EL18-___ Volume 1
Index
Otter Tail Power Company South Dakota General Rate Case Documents
Volume Section
1 1 Letter of Transmittal Application for Change in Electric Rates & Interim Rates Pending Final Rates Notice of Proposed Change of Rates and Charges Attestation by Chief Financial Officer Request for Confidential Treatment 2 Statements A through R showing Cost of Service
2A 1 Testimony and Schedules of Witnesses Bruce G. Gerhardson Policy Tyler A. Akerman Rate Base Revenue Requirement Adjustments Stuart D. Tommerdahl Major Projects Test Year Revenues Allocation Factors Other Regulatory Matters Bryce C. Haugen Transition of Capital Projects from Riders to Base Rates Class Cost of Service Study Class Revenue Responsibilities Kevin G. Moug Financial Soundness Capital Structure Cost of Capital
2B 1 Kirk A. Phinney Big Stone AQCS Hoot Lake MATS Bradley E. Tollerson Merricourt Wind Project Robert B. Hevert Return on Equity Peter E. Wasberg Employee Compensation David G. Prazak Rate Design
3 1 Interim Tariffs Non-Redlined Redlined 2 Proposed Tariffs Non-Redlined Redlined 3 Step In Tariffs Non-Redlined Redlined
4A 1 2017 Test Year Workpapers 1. Jurisdictional Cost of Service Study (JCOSS) 2. Class Cost of Service Study (CCOSS) 3. Input Summary a. Rate Base b. Net Operating Income 4. Test Year Adjustments TY-01 Normalize PIS TY-02 BSP II TY-03 New Depreciation Rates TY-04 Special Deposits TY-05 Weather Normalization TY-06 Revenue Normalization TY-07 Wages TY-08 Medical/Dental TY-09 Rate Case Expense Amortization TY-10 Storm Damages TY-11 PTC Removal TY-12 2018 Known and Measurable Items TY-13 TCR Rider Revenue Removal TY-14 ECR Rider Revenue Removal TY-15 Deferred Tax Expense and ADIT for Tax Act 2 2017 Actual Year Workpapers 1. Jurisdictional Cost of Service Study (JCOSS) 2. Functionalization 3. Input Summary a. Rate Base b. Net Operating Income 4. Work papers A – D, SD 3 Supporting Information A. Jurisdictional Financial Summary Schedules of Revenue Requirements 2017 Test Year 1. Summary of Revenue Requirements – Jurisdictional B. Rate Base Schedules 1. Rate Base Summary 2. Rate Base Components – 2017 Test Year 3. Rate Base Components - 2017 Test Year to Most Recent General Rate Case 4. Cash Working Capital 5. Rate Base Adjustments 6. Summary of Approaches and Assumptions Used 7. Rate Base Jurisdictional Allocation Factors C. Operating Income Schedules 1. Jurisdictional Statement of Operating Income 2. Reserved for Future Use 3. Statement of Operating Income – 2017 Test Year 4. Statement of Operating Income – 2017 Test Year to Most Recent General Rate Case 5. Computation of Federal and State Income Taxes 6. Computation of Deferred Income Taxes 7. Development of Federal and State Income Tax Rates 8. Operating Income Statement Adjustments Schedule 9. Summary of Approaches and Assumptions Used 10. Operating Income Statement Allocation Factors D. Rate of Return / Cost of Capital Schedules 1. Summary Schedule 2. Cost of Long-Term Debt 3. Cost of Short-Term Debt 4. Common-Equity
E. Rate Structure and Design Information 1. Class Cost of Service Study F. Other Supplemental Information 1. Annual Report 2. Gross Revenue Conversion Factor 4 Interim COSS 1. Jurisdictional Cost of Service Study (JCOSS) 2. Input Summary a. Rate Base b. Net Operating Income 3. Interim Supporting Schedules
5 Step In Workpapers 1. Jurisdictional Cost of Service Study (JCOSS) 2. Class Cost of Service Study 3. Input Summary a. Rate Base b. Net Operating Income 4. Statement P 5. Test Year Adjustment TY-16 Merricourt Wind Step In 6. Statement I
6 Hevert Cost of Capital Workpapers
4B 1 Lead Lag Study
Volume 1 - Section 1
Section 1 – Application for Change in Rates
Volume 1 – Section 1
Section 1- Application for Change in Rates
Letter of Transmittal 215 South Cascade Street PO Box 496 Fergus Falls, Minnesota 56538-0496 218 739-8200 (web site)
April 20, 2018
Ms. Patricia Van Gerpen Executive Director South Dakota Public Utilities Commission State Capitol Building 500 East Capitol Avenue Pierre, South Dakota 57501
Re: Transmittal Letter - Application of Otter Tail Power Company for Authority to Increase Rates for Electric Service in South Dakota & Interim Rates Pending Final Rates
Dear Ms. Van Gerpen:
Otter Tail Power Company (OTP or Company) submits its Application to the South Dakota Public Utilities Commission (Commission) for authority and consent to increase rates for electric service provided to the Company’s South Dakota customers. This increase is needed for the Company to continue providing high quality, reliable, and safe electric service. The Company’s current South Dakota base rates were set in 2011 and are based on a 2009 Test Year (Docket No. EL10-011).
There are three components to the Company’s Application and Notice of Proposed Rates and Charges: (1) the Company’s rate increase request (Final Rates) proposed to be effective following the Commission’s final disposition in this case, or no later than 180 days hereafter if interim rates are suspended or otherwise not authorized as requested; (2) Interim Rates commencing May 21, 2018, and remaining in effect pending the Commission’s final disposition of the Company’s rate increase request; and (3) a later incremental increase (Step Increase) to Final Rates to be effective January 1, 2020, following the Merricourt Wind Project entering service in 2019. The proposed changes would affect the billings of the approximately 11,700 customers in the Company’s South Dakota service area.
The following summarizes the key components of OTP’s Application.
Final Rates
The Company’s proposed Final Rates constitute a net increase of non-fuel revenues of $3,358,547, or 10.10 percent. The proposed change in rates will result in an average increase of $11.29 per month for
An Equal Opportunity Employer
Ms. Patricia Van Gerpen April 20, 2018 Page 2 residential customers under the rate design proposed by the Company. Additional rate impacts are discussed in the Direct Testimony of Mr. David Prazak.
As part of this this request, the Company proposes to recover in base rates certain capital costs currently recovered through the Company’s Environmental Cost Recovery Rider (ECRR) and Transmission Cost Recovery Rider (TCRR). To facilitate the transition from rider to base rate recovery, OTP proposes to discontinue certain cost recovery through the ECRR and TCRR when proposed Rates go into effect. Without accounting for the reduction in rider revenues, the effect of the proposed increase to base rates and the transition of rider recoveries to base rates is a non-fuel revenue increase of $5,978,109, or 19.50 percent. When the reduction in rider revenue is considered, the effect is a net increase in non-fuel revenue of $3,358,574, or 10.10 percent. OTP witness Mr. Bruce Gerhardson summarizes OTP rate requests in his Direct Testimony. OTP witness Mr. Bryce Haugen discusses the transition of rider recoveries to base rates in his Direct Testimony.
The test year for the proposed increase is 2017, with known and measurable changes and other appropriate adjustments. OTP proposes that Final Rates become effective following the Commission’s final disposition in this case, or no later than 180 days hereafter if interim rates are suspended or otherwise not authorized as requested.
Interim Rates
The proposed Interim Rates are based on a net annual increase of non-fuel revenues of $2,386,538, or 7.17 percent, and will result in an average increase of $6.54 per month for residential customers under the Company’s current rate design. The Company has adjusted the proposed Interim Rates to remove any known and measurable changes that are included in the final rate test year but for which the changes will not have yet occurred during the interim rate period. This ensures that known and measurable adjustments for changes occurring outside the interim rate period are not the cause of any identified deficiency in the interim period. Interim Rates will be refundable to the extent they exceed the Commission’s final determinations in this case, ensuring that the Interim Rates will apply only to the extent that OTP ultimately demonstrates a deficiency existed during the interim rate period.
Interim Rates as requested are permitted under South Dakota law. Specifically, SDCL § 49-34A-14 requires that a utility that has requested a rate increase may not have that request suspended for a period that lasts longer than 180 days after the proposed rate was filed. This law permits a rate to be implemented sooner than 180 days following the filing. Additionally, SDCL § 49-34A-17 permits implementation of a proposed rate after 30 days has passed from the date of the filing, and SDCL §§49-34A-22 and 49-34A-23 address how refunding shall be handled for rates implemented on an interim basis. OTP’s request for interim rates is consistent with this statutory framework.
Mr. Bruce Gerhardson addresses Interim Rates in Section II of his Direct Testimony. As Mr. Gerhardson explains, the Company believes its Interim Rate proposal is consistent with the establishment of just and reasonable rates. Mr. Gerhardson also explains that OTP’s requested Interim Rates have been calculated to recognize the effects of the Tax Cuts and Job’s Act that became effective on January 1, 2018.
Ms. Patricia Van Gerpen April 20, 2018 Page 3
2019 Step Increase to Final Rates
The Company also proposes a Step Increase, effective January 1, 2020, to facilitate recovery of the Merricourt Wind Project, which is currently projected to enter service later in 2019. The Merricourt Step Increase is intended to permit OTP to commence timely recovery for the Merricourt Wind Project without exposing customers to the cost of a general rate case filed on the heels of this case. The Step Increase will result in a net increase of non-fuel revenues of $629,107, or 1.72% percent over current rates. Mr. Bradley Tollerson describes the Merricourt Wind Project in his Direct Testimony. Mr. Tyler Akerman describes the balance sheet and income statement effects of the Step Increase his Direct Testimony. Company witnesses Bruce Gerhardson and Stuart Tommerdahl describe why the proposed Step Increase is administratively efficient, economical for OTP customers, and in the public interest. Mr. Bryce Haugen and Mr. David Prazak address Step Increase rate design.
Description of Application
The Company submits the following as its Application:
Volume 1 – Rate Application Letter of Transmittal Application for Change in Electric Rates & Interim Rates Pending Final Rates Notice of Proposed Changes of Rates and Charges Attestation by Chief Financial Officer Request for Confidential Treatment Statements A-R
Volume 2 – Testimony Policy – Bruce G. Gerhardson Revenue Requirement – Tyler A. Akerman Revenue Requirement and Regulatory Issues – Stuart D. Tommerdahl Rider Roll-In and Class Cost of Service – Bryce C. Haugen Cost of Capital – Kevin G. Moug Big Stone AQCS and Hoot Lake MATS – Kirk A. Phinney Merricourt Wind Project – Bradley E. Tollerson Return on Equity – Robert B. Hevert Employee Compensation and Benefits – Peter E. Wasberg Rate Design – David G. Prazak
Volume 3 – Tariffs Interim Tariffs (Non-Redlined and Redlined) Proposed Tariffs (Non-Redlined and Redlined) Step In Tariffs (Non-Redlined and Redlined)
Volume 4 – Workpapers, Supporting Information and Lead Lag Study
Ms. Patricia Van Gerpen April 20, 2018 Page 4
The Company certifies that notice has been or is being provided to the public in all respects as required by S.D. Admin R. 20:10:13:17 through 20:10:13:19. Specifically, the Company certifies that the Notice of Proposed Change of Rates and Charges (Notice) for the all the rate increases proposed in its Application, will be exhibited in a conspicuous place in the Company’s local customer service offices for the territory affected, for at least 30 days prior to the date such change is to become effective. The Notice states that the proposed rates and charges are available in that office for inspection. The Company will also notify customers of the proposed change in rates, including proposed Interim Rates and the Merricourt Step Increase, through a bill insert, a copy of which is included in Volume 1. Upon the implementation of Interim Rates, the Company will include a message on customer bills informing customers of the interim rate increase pending Final Rates, and post additional information concerning the administration of Interim Rates at the Company’s offices and on the Company’s website. The bill message and informational notice are included in Volume 1.
Additionally, local media outlets will receive a news release and our website www.otpco.com will contain information describing the Application, including the Company’s request for Interim Rates. We are also prepared to meet with customer groups as reasonably requested to provide detailed information regarding our Application.
The Commission’s communications with the Company regarding this Application should be directed to: Bruce G. Gerhardson Vice President, Regulatory Affairs OTP Power Company 215 South Cascade Street Fergus Falls, MN 56537 (218) 739-8475
Also, please send copies of all written inquiries, correspondence and pleadings to:
Matthew J. Olsen Manager, Regulatory Proceedings & Compliance OTP Power Company 215 South Cascade Street Fergus Falls, MN 56537 (218) 739-8657
and
Cary R. Stephenson Associate General Counsel OTP Power Company 215 South Cascade Street Fergus Falls, MN 56537 (218) 739-8956
Volume 1 – Section 1
Section 1- Application for Change in Rates
Application for Change in Electric Rates PUBLIC UTILITIES COMMISSION STATE OF SOUTH DAKOTA
In the Matter of the Application of Otter Tail Docket No. EL18-___ Power Company for Authority to Increase Rates for Electric Service in South Dakota & For Interim Rates Pending Final Rates
APPLICATION
COMES NOW, Otter Tail Power Company (OTP or Company), the Applicant in the above-captioned proceeding, and respectfully states as follows:
I.
That OTP is a Minnesota corporation duly authorized to do business in the State of South
Dakota as a foreign corporation, and that it is doing business in the State of South Dakota as a public utility, providing electric service to approximately 11,700 South Dakota retail customers.
II.
That the Certificate of Incorporation and Amendments thereto, have previously been filed with the South Dakota Public Utilities Commission (Commission) and such Certificate and
Amendments are incorporated into this Application by reference as though fully set forth herein.
III.
That Applicant’s full name and post office address are:
Otter Tail Power Company 215 South Cascade Street Fergus Falls, MN 56537
1 IV.
As part of this Application, OTP has filed revised rate sheets that modify the rates the
Company will charge to its approximately 11,700 South Dakota retail customers. The revised rate sheets are provided in Volume 3 of this Application in both legislative format and non- legislative format.
V.
That the existing rates of OTP are inadequate to allow the Company to recover its cost of providing electric service along with an adequate rate of return, and that the rates should be increased so that the Company will have an opportunity to recover its cost of providing service and earn a reasonable rate of return on its electric property used and useful in providing electric service in South Dakota.
VI.
That OTP is seeking a net increase of non-fuel revenues of $3,358,574, or 10.10 percent, based on 2017 Test Year with known and measurable changes and other appropriate adjustments.
As part of this this request, OTP proposes to recover in base rates certain capital costs currently recovered through the Company’s Environmental Cost Recovery Rider (ECRR) and
Transmission Cost Recovery Rider (TCRR). To facilitate the transition from rider to base rate recovery, OTP proposes to discontinue certain cost recovery through the ECRR and TCRR when proposed Rates go into effect. Without accounting for the reduction in rider revenues, the effect of the proposed increase to base rates and the transition of rider recoveries to base rates is a non- fuel revenue increase of $5,978,109, or 19.50 percent. When the reduction in rider revenue is considered, the effect is a net increase in non-fuel revenue of $3,358,574, or 10.10 percent. The
2 Company seeks to implement these proposed rates (Final Rates) following the Commission’s final disposition in this case, or no later than 180 days hereafter if interim rates are suspended or otherwise not authorized as requested. The revenue increases to customer classes are proposed to move rates closer to the cost of service. Increases to individual customer classes within a class will vary depending on particular usage patterns.
VII.
That in addition to the proposed rate increase set forth in Paragraph VI, OTP seeks authority to implement a later incremental increase (Step Increase) to Final Rates to recover the
Company’s investment in the Merricourt Wind Project, which is projected to enter service in
2019. OTP requests that the Step Increase of $629,107 or 1.72 percent over current rates take effect January 1, 2020, after the Merricourt Wind Project enters service.
VIII.
That pending the Commission’s final disposition of the Company’s rate increase request,
OTP seeks interim rate relief, effective May 21, 2018. The Interim Rates proposed by the
Company are based on a net annual increase of non-fuel electric revenues of $2,386,538, or 7.17 percent and shall be recovered through the Company’s current rate design. Interim Rates will be subject to refund if and to the degree final rates approved by the Commission are less than
Interim Rates.
IX.
That it is necessary, reasonable, and just for OTP to implement Interim Rates effective thirty days after this Application and for Interim Rates to remain in effect until the Commission
3 issues a final order in this case. Absent interim rate relief, the Company is unable to recover its prudently incurred costs of providing service.
X.
That Interim Rates are consistent with South Dakota law. SDCL § 49-34A-14 permits a rate to be implemented sooner than 180 days following the filing. Additionally, SDCL § 49-
34A-17 permits implementation of a proposed rate after 30 days has passed from the date of the filing, and SDCL §§49-34A-22 and 49-34A-23 guide refunding for rates implemented on an interim basis.
XI.
The primary reasons for Company’s need to increase rates are to recover: (1) additional rate base investments and associated depreciation expense; (2) increases in operating costs incurred by the Company in providing electric service to its customers; and (3) on-going and planned investments in infrastructure and technology.
XII.
OTP will prove by competent evidence that existing rates are inadequate and that said rates should be increased as requested herein. Filed concurrently with this Application are supporting Statements and Schedules, along with direct testimony and schedules of the
Company’s witnesses. More specifically, OTP relies on the following testimony:
Bruce G. Gerhardson Policy
Tyler A, Akerman, Revenue Requirement
Bryce C. Haugen Rider Roll-In and Class Cost of Service
4 Bradley E. Tollerson Merricourt Wind Project
Stuart D. Tommerdahl Revenue Requirment and Regulatory Issues
Kevin G. Moug Cost of Capital
Robert B. Hevert Return on Equity
Peter E. Wasberg Employee Compensation and Benefits
David G. Prazak Rate Design
Kirk A. Phinney Big Stone AQCS and Hoot Lake MATS projects
XIII.
That this Application is submitted in accordance with the provisions of South Dakota
Codified Laws, Chapter 49-34A and the rules and regulations promulgated by the Commission.
XIV.
That the attestation of the accounting officer required by ARSD § 20:10:13:50 of the
Commission’s Rules is included with this Application. The revenue estimates required by
ARSD § 20:20:13:41 are provided in Statement I. The cost of service study required by ARSD
§ 20:10:13:43 is found in Statement O. The statement of system costs required by ARSD
§ 20:10:13:44 is found in Statement N. These statements are in Volume 1, Section 3.
XV.
OTP hereby certifies that a notice of proposed change in electric service rates and Interim
Rates will be exhibited in a conspicuous place in business offices for OTP’s service territory affected by this Application at least thirty days prior to the date the change is to become effective. The notice will state that the proposed rates are available in that office for inspection.
5 OTP further certifies that the notice to individuals will be sent with customer bills during the period of April 23 to May 18, 2018 and that it will give such other public notice as the
Commission may direct.
XVI.
By this filing, OTP does not waive any right it may have to update and amend this
Application or the statements of fact, expert opinions, substantiating documents and exhibits to meet all claims, objections and allegations that may be made by any party to this proceeding. If the Commission desires additional information, the Company will handle such matters through data requests.
WHEREFORE, OTP respectfully requests that the Commission:
1. Approve and adopt the proposed rate changes as set forth in this Application to be
effective following the Commission’s final disposition in this case, or no later
than 180 days hereafter if Interim Rates are suspended or otherwise not authorized
as requested;
2. Approve and adopt the Merricourt Wind Project Step Increase as set forth in this
Application;
3. Authorize the implementation of Interim Rates as set forth in this Application
effective May 21, 2018, with Interim Rates to remain in effect until final
disposition of this docket, and to be subject to refund as required by South Dakota
law;
4. Approve the general tariff changes requested by the Company;
6
Volume 1 – Section 1
Section 1- Application for Change in Rates
Notice of Proposed Change of Rates and Charges
STATE OF SOUTH DAKOTA PUBLIC UTILITIES COMMISSION
In the Matter of the Application of Otter ) Case No. EL18-______Tail Power Company for Authority to ) Increase Rates for Electric Service in ) South Dakota
NOTICE OF PROPOSED CHANGE OF RATES AND CHARGES
NOTICE IS HEREBY GIVEN that on April 20, 2018 Otter Tail Power Company (OTP or Company) has filed an Application with the South Dakota Public Utilities Commission (Commission) for an increase in its electric rates and other tariff changes for service to its South Dakota electric customers. The last time the Company’s base electric rates were increased in South Dakota was June 2011.
The Company is seeking a net increase of non-fuel revenues of $3,358,574, or 10.10 percent, based on a 2017 Test Year with known and measurable changes and other appropriate adjustments. The proposed change in rates will result in an average increase of $11 per month for residential customers under the rate design proposed by the Company. As part of this request, the Company proposes to recover in base rates certain capital costs currently recovered through the Company’s Environmental Cost Recovery Rider (ECRR) and Transmission Cost Recovery Rider (TCRR). To facilitate the transition from rider to base rate recovery, OTP proposes to discontinue certain cost recovery through the ECRR and TCRR when requested rates go into effect. Without accounting for the reduction in rider revenues, the effect of the proposed increase to base rates and the transition of rider recoveries to base rates is a non-fuel revenue increase of $5,978,109, or 19.50 percent. When the reduction in rider revenue is considered, the effect is a net increase in non-fuel revenue of $3,358,574, or 10.10 percent. The Company proposes that the change in rates be effective following the Commission’s final disposition of the Company’s Application, provided that, pending the Commission’s final disposition, the Company is authorized to implement an interim rate increase (Interim Rates) as described in this Notice. If the Commission suspends or does not authorize Interim Rates, the proposed rates would be effective 180 days from the Application’s filing date and remain in effect pending the Commission’s final disposition of OTP’s Application.
The Company has also requested a later incremental increase in rates (Step Increase), effective January 1, 2020, to facilitate cost recovery for the Company’s Merricourt Wind Project, which is projected to enter service in 2019. If approved, the Step Increase to rates would add 1.72 percent, or approximately $1.75 per month to residential customers’ bills over current rates.
Pending the Commission issuing a final order on the Company’s rate increase request, the Company has asked the Commission for Interim Rates effective May 21, 2018. The Company’s proposed Interim Rates are based on a net annual increase of non-fuel electric revenues of $2,386,538, or 7.17 percent, and will result in an average increase of $6.50 per month for residential customers. Interim Rates will be subject to refund if and to the degree final rates approved by the Commission are less than interim rates. The proposed changes would affect the billings of approximately 11,700 customers in the Company’s South Dakota service area.
This notice was included as part of the Company’s Application to the South Dakota Public Utilities Commission. Under South Dakota law, you have a right to join with 24 other
Volume 1 – Section 1
South Dakota Rate Case Customer Bill Insert
OTTER TAIL POWER COMPANY REQUESTS SOUTH DAKOTA RATE REVIEW
On April 20, 2018, Otter Tail Power Company submitted an application with the South Dakota Public Utilities Commission (SDPUC) for permission to increase our electric rates by approximately $3.3 million, or 10.1 percent. These rates are proposed. If the rates are suspended by the SDPUC, they will not be effective until the SDPUC takes action. We have also requested an interim rate increase of 7.17 percent to be effective May 21, 2018 and remain in place until the SDPUC makes a final determination.
This is what’s driving our request The SDPUC established our current rates in 2011 based on 2009 costs. Since then, costs we incur to provide our customers with energy and related services have increased. We’ve also made investments in stronger, cleaner infrastructure and smarter technologies that ensure we can continue to provide you with reliable, affordable energy. Customer bill impacts We estimate that a typical residential customer’s bill will increase by approximately $11 a month and a typical business customer’s bill will increase by approximately $24 a month. Increases will vary depending on your electric service rate and the amount of electricity you use. This table shows changes to the average monthly bill by customer type.
Monthly Kilowatt- Previous Monthly Proposed Increase Customer type hour Usage Bill to Monthly Bill Residential 927 $91.27 $11.29 Farms 1,730 $160.04 $17.40 General Service 2,604 $243.88 $24.16 Large General Service 279,050 $17,428.31 $1,477.63 Irrigation 2,036 $205.14 $36.17 Outdoor Lighting 191 $2.30 $0.34 Other Public Authority 2,430 $175.97 $24.75 Controlled Service Water Heating 198 $14.53 $1.56 Controlled Service Interruptible 43,225 $2,046.20 $131.42 Controlled Service Deferred 2,159 $108.20 $8.12
We’ve also requested to increase rates by an additional 1.7 percent in 2020 to recover costs for a wind generation facility that’s scheduled for construction in 2019. If the SDPUC approves that portion of our request as filed, a typical residential customer’s bill would increase by approximately $1.75 a month and a typical business customer’s bill would increase by approximately $4.50 a month.
For more information, visit otpco.com/SDRateReview or call 800-257-4044.
You may contact the South Dakota Public Utilities Commission at: Phone: 605-773-3201 Email: [email protected] Under South Dakota law, you have the right to join with 24 other customers in Otter Tail Power Company’s South Dakota service area to file a written objection to this proposed rate increase, and you may request the Commission suspend the rate increase and hold a public hearing to determine whether such a rate increase should be allowed.
Volume 1 – Section 1
Interim Rates Bill Message
Otter Tail Power Company Interim bill message – Docket No. EL18-___
On April 20, 2018, Otter Tail Power Company submitted an application to increase South Dakota rates. Under South Dakota law 49-34A-17, we have increased rates on an interim basis. The net impact of the increase is 7.17%. This increase is subject to refund with interest and will be included on your bill until the South Dakota Public Utilities Commission approves final rates. For more information, visit otpco.com/SDRateReview or call 800-257-4044.
Volume 1 – Section 1
Interim Rates Customer Notice for Office and Web
STATE OF SOUTH DAKOTA PUBLIC UTILITIES COMMISSION
In the Matter of the Application of Otter ) Case No. EL18-_____ Tail Power Company for Authority to ) Increase Rates for Electric Service in ) South Dakota )
OTTER TAIL POWER COMPANY REQUESTS INTERIM RATE INCREASE
On April 20, 2018, Otter Tail Power Company submitted an application to the South Dakota Public Utilities Commission (SDPUC) to increase our electric rates. The rates applied for are proposed only and the proposed rates will not be effective until SDPUC action has been taken. To address the period during which the SDPUC considers our full request, we requested an interim rate increase to begin on May 21, 2018.
The interim rate increase will result in a net annual increase of non-fuel electric revenues of $2,386,538, or 7.17 percent. The interim rate increase, which applies to the customer charge, energy charge, demand charge, facilities charge, fixed charge, and the monthly minimum charge, will begin with meter readings on and after May 21, 2018. For most customers, that means only a portion of their first electric service statements after May 21, 2018, will reflect the increase. When average residential customers using 927 kwh of electricity get their first statements reflecting a full month at the interim rate, they will see an increase of $6.54. When average commercial customers using 2,604 kwh of electricity get their first statements reflecting a full month at the interim rate, they will see an increase of $17.49. Customers will see more or less of an increase depending on the amount of electricity they use and the rate(s) on which they take service.
If you have any questions regarding the Company’s interim rate increase, visit otpco.com/SDRateReview or call 800-257-4044.
Volume 1 – Section 1
Section 1- Application for Change in Rates
Attestation by Chief Financial Officer
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF SOUTH DAKOTA
In the Matter of the Application of Otter Tail Power Company For Authority to Increase EL18-___ Rates For Electric Utility Service in South Dakota
REQUEST FOR CONFIDENTIAL TREATMENT OF INFORMATION
COMES NOW, Otter Tail Power Company (OTP or Company) and respectfully moves the South Dakota Public Utilities Commission (the Commission) for confidential treatment of information pursuant to Administrative Rules of South Dakota (ARSD) 20:10:01:41.
1. OTP requests confidential protection and treatment of the following documents: a. Schedule K working papers located in Section 2 of Volume 1. Schedule K-3 is the working papers of the consolidated income tax return of Otter Tail Corporation. Schedule K is included as part of the Application pursuant to ARSD § 20:10:13:91. OTP joins in the filing of a consolidated federal income tax return. Schedule K-3 contains working papers showing the net taxable income or loss for each company included in the consolidated tax return, along with consolidating adjustments. The Company and Otter Tail Corporation treat this information as highly confidential information. b. Employee Compensation, Benefits, and Benchmarking Data (Compensation & Benefits Data) attached to the Direct Testimony of Peter Wasberg, located in Section 1 of Volume 2B: i. Schedule 2 – 2015 Mercer Compensation Benchmark Study NOT PUBLIC ii. Schedule 3 – 2015 Mercer Executive Compensation Review NOT PUBLIC iii. Schedule 6 – 2017 Willis Towers Watson Energy Industry BenVal Study NOT PUBLIC iv. Schedule 7b – 5-year payouts of the OTP Management Incentive Plan NOT PUBLIC v. Schedule 9a – 2018 ASC 715 and ASC 712 Accounting Expense Report – Mercer NOT PUBLIC vi. Schedule 9b – 2017 Pension DAMP – Mercer NOT PUBLIC vii. Schedule 9c – 2017 Post-retirement Medical and LTD Medical DAMP – Mercer NOT PUBLIC
c. Merricourt Wind Project estimates, pricing and contract terms (Merricourt Data) located in Section 1 of Volume 2B: i. The portions of the Direct Testimony of OTP witness Bradley Tollerson noted as Protected Data describing certain Merricourt Wind Project estimates, vendor pricing and contract provisions with counter party EDF. ii. The items designated as Protected Data in OTP’s Application for an Advanced Determination of Prudence (ADP) for the Merricourt Wind Project filed in North Dakota Public Service Commission Case No. PU-17-141. The ADP with Protected Data designations is attached as Schedule 1 to the Direct Testimony of Bradley Tollerson. The material noted as Protected Data contain non-public Merricourt Wind Project estimates, vendor pricing, and contract provisions with counter party EDF.
2. The Company requests that such confidential treatment be afforded the Confidential Documents indefinitely. When the docket is closed, all protected information must be returned to OTP.
3. Please refer all inquiries regarding this filing to:
Cary Stephenson Associate General Council Otter Tail Power Company 215 South Cascade Street P. O. Box 496 Fergus Falls, MN 56538-0496 (218) 739-8956
2 4. The claim for confidential treatment is based on ARSD 20:10:01:39 (4), SDCL 37- 29-1 (4), and SDCL 1-27-30.
5. The factual basis that qualifies the information for confidentiality is as follows: a. Schedule K. Schedule K is non-public income and tax information that meets the definition of “trade secret” under the SDCL §37-29-1(4), defined as information that “[d]erives independent economic value, actual or potential, from not being generally known to, and not being readily ascertainable by proper means by, other persons who can obtain economic value from its disclosure or use, and… is the subject of efforts that are reasonable under the circumstances to maintain its secrecy.” This information is also meets the definition of “proprietary information” under SDCL § 1-27-28, which is defined as “information on pricing, costs, revenue, taxes, market share, customers, and personnel held by private entities and used for that private entity’s business purposes.” Schedule K-3 provides the net taxable income or loss for each company in the consolidation, some of whom are unregulated. This information would provide actual and potential competitors with information concerning the profitability of its various unregulated affiliates that could provide competitors with an unfair competitive advantage. b. Compensation and Benefits Data. The Employee Compensation Data referenced above includes non-public, confidential benchmarking studies subject to prohibitions against disclosure, as well as non-public confidential OTP employee compensation and benefits data. This data meets the definition of trade secret under SDCL § 37-29-1(4) and proprietary information” under SDCL § 1-27-28. This information would provide actual and potential competitors with information on confidential employee compensation practice and plans, which could provide competitors with an unfair advantage in a highly competitive employment market to the ultimate harm OTP customers. c. Merricourt Data. The Merricourt data is non-public, confidential information concerning the Merricourt Wind Project including pricing, cost estimates,
3
Volume 1 – Section 1
Report to Commission of Tariff Schedule Changes
ARSD 20:10:13:26 Report to commission of tariff schedule changes on notice.
1 Utility Name: OTTER TAIL POWER COMPANY PO Box 496 Fergus Falls, MN 56538-0496 218 739-8200 www.otpco.com (web site)
2 Section & Sheet No. Class of Service Section 1.01 Sheets 1-5 South Dakota Index Section 1.01 Sheet 1 Scope of General Rules and Regulations Section 1.02 Sheets 1-2 Application of Service Section 1.03 Sheets 1-2 Deposits, Guarantees and Credit Policy Section 1.04 Sheet 1 Customer Connection Charge Section 1.05 Sheets 1-23 Contracts, Agreements and Sample Forms Section 1.06 Sheet 1 N/A (reserved for future use) Section 1.07 Sheet 1 N/A (reserved for future use) Section 1.08 Sheet 1 N/A (reserved for future use) Section 1.09 Sheets 1-3 Customer Meter Data Privacy Section 2.01 Sheet 1 Assisting Customers in Rate Selection Section 2.02 Sheets 1-2 Service Classification Section 3.01 Sheets 1-2 Disconnection of Service Section 3.02 Sheet 1 Curtailment or Interruption of Service Section 3.03 Sheet 1 N/A (reserved for future use) Section 3.04 Sheet 1 N/A (reserved for future use) Section 3.05 Sheet 1 Continuity of Service Section 4.01 Sheets 1-3 Meter and Service Installations Section 4.02 Sheet 1 Meter Readings Section 4.03 Sheet 1 Estimated Billing Section 4.04 Sheet 1 Meter Testing and Meter Failure Section 4.05 Sheet 1 Access to Customer Premises Section 4.06 Sheet 1 Establishing Demands Section 4.07 Sheet 1 Monthly Billing Period and Prorated Bills Section 4.08 Sheet 1 Electric Service Statement - Identification of Amounts and Meter Reading Section 4.09 Sheet 1 Billing Adjustments Section 4.10 Sheet 1 Payment Policy Section 4.11 Sheet 1 Even Monthly Payment (EMP) Plan Section 4.12 Sheet 1 Summary Billing Services Section 4.13 Sheet 1 Account History Charge Section 4.14 Sheet 1 Combined Metering Section 5.01 Sheets 1-2 Service Connection Section 5.02 Sheets 1-5 Voltage Classification Section 5.03 Sheets 1-5 Facilities Definitions, Installations and Payments Section 5.04 Sheets 1-2 Extension Rules and Minimum Revenue Guarantee Section 5.05 Sheets 1-2 Temporary Services Section 6.01 Sheet 1 Customer Equipment Section 6.02 Sheet 1 Use of Service; Prohibition on Resale Section 7.01 Sheet 1 Waiver of Rights or Default Section 7.02 Sheet 1 Modification of Rates, Rules and Regulations Section 8.01 Sheets 1-4 Glossary Section 8.02 Sheet 1 Definition of Symbols Section 9.01 Sheets 1-2 Residential Service Section 9.02 Sheets 1-2 Residential Demand Control Service Section 9.03 Sheets 1-2 Farm Service Section 9.04 Sheets 1-2 Residential Time of Day Service - Pilot Section 10.01 Sheets 1-2 Small General Service (Under 20 kW) Section 10.02 Sheets 1-2 General Service (20 kW or Greater) Section 10.03 Sheets 1-3 General Service - Time of Use Section 10.04 Sheets 1-3 Large General Service Section 10.05 Sheets 1-4 Large General Service - Time of Day Section 10.06 Sheets 1-3 Super Large General Service Section 11.01 Sheets 1-8 Standby Service
1 Section 11.02 Sheets 1-3 Irrigation Service Section 11.03 Sheets 1-2 Outdoor Lighting - Energy Only Section 11.04 Sheets 1-3 Outdoor Lighting (CLOSED) Section 11.05 Sheets 1-2 Municipal Pumping Service Section 11.06 Sheet 1 Civil Defense - Fire Sirens Section 11.07 Sheets 1-3 LED Street and Area Lighting Section 12.00 Sheet 1 Power Producer Riders - Availability Matrix Section 12.01 Sheet 1 Small Power Producer Rider - Occacsional Delivery Energy Service Section 12.02 Sheet 1 Small Power Producer Rider - Time of Delivery Energy Service Section 12.03 Sheet 1 Small Power Producer Rider - Dependable Service Section 13.00 Sheets 1-2 Mandatory Riders - Applicability Matrix Section 13.01 Sheets 1-3 Energy Adjustment Rider Section 13.01 Sheets 1-3 Energy Adjustment Rider by Service Category Section 13.02 Sheet 1 N/A (reserved for future use) Section 13.03 Sheet 1 N/A (reserved for future use) Section 13.04 Sheet 1 Energy Efficiency Partnership (EEP) Cost Recovery Rider Section 13.05 Sheets 1-2 Transmission Cost Recovery Rider Section 13.06 Sheet 1 N/A (reserved for future use) Section 13.07 Sheet 1 N/A (reserved for future use) Section 13.08 Sheets 1-2 Environmental Cost Recovery Rider Section 14.00 Sheet 1 Voluntary Riders - Availability Matrix Section 14.01 Sheets 1-2 Water Heating Control Rider Section 14.02 Sheets 1-5 Real Time Pricing Rider Section 14.03 Sheets 1-6 Large General Service Rider Section 14.04 Sheets 1-4 Controlled Service - Interruptible Load Section 14.05 Sheets 1-3 Controlled Service - Interruptible Load Section 14.06 Sheets 1-3 Controlled Service - Interruptible Load Section 14.07 Sheets 1-3 Fixed Time of Service Rider Section 14.08 Sheets 1-2 Air Conditioning Control Rider (CoolSavings) Section 14.09 Sheet 1 Renewable Energy Rider (TailWinds) Section 14.10 Sheet 1 N/A (reserved for future use) Section 14.11 Sheet 1 N/A (reserved for future use) Section 14.12 Sheets 1-2 Bulk Interruptible Service Section 14.13 Sheets 1-2 Economic Development Rate Rider Section 15.00 Sheet 1 South Dakota Communities Served Section 16.00 Sheets 1-4 Summary of Contracts with Deviations
3 Description of Change: Change in Rates, Availability, and Applicability Addition of new tariff schedules
4 Reason for Change: Allow Otter Tail to recover its cost of providing service and earn a reasonable rate of return on its electric property.
5 Present Base Rates: $18,556,637
6 Proposed Base Rates (including rider roll-in): $24,534,747 Proposed Step-In Rates: $25,163,855
7 Effective Date of Rates: January 1, 2019 Effective Date of Step-In Rates: January 1, 2020
8 Approximation of annual amount of increase or decrease in revenue: Proposed Increase: $5,978,110 Proposed Step-In Increase: $629,108
9 Points affected: South Dakota electric customers.
10 Number of customers whose cost of service will be affected and annual amounts of either increase or decrease: Otter Tail currently serves approximately 11,700 electric utility customers in South Dakota; annual amount of increase is noted in #8 above.
11 Statement of facts, expert opinions, documents and exhibits to support the proposed changes: Otter Tail has included Statement of Facts, Attachments in this filing to support all rate changes and costs.
2
Volume 1 – Section 2
Section 2 - Statements A-R
Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement A Assets and Other Debits Page 1 of 2
(A) (B) (C) (D)
Line December 31 December 31 No. Description FERC Acct # 2017 2016
Utility Plant 1 Electric Plant in Service 101 $ 1,680,183,078 $ 1,635,803,102 2 Held for Future Use 105 29,656 29,656 3 Completed Construction Not Classified 106 299,158,257 222,877,093 4 Construction Work in Progress 107 132,556,717 149,997,025 5 Gross Utility Plant 2,111,927,708 2,008,706,876 6 Accum Prov for Depreciation and Amortization 108,108.1,111 (743,884,083) (701,413,532) 7 Elec Plant Acquisition Adj. 114 1,647,128 1,647,128 8 Accum. Prov. For Amort. Of Acq Adj 115 (1,647,128) (1,647,128) 9 Total Utility Plant 1,368,043,625 1,307,293,344
Other Property & Investments 10 Nonutility Property 121 579,911 879,911 11 Res for Depr-Non-Utility Property 122 12 Net Non-Utility Property 579,911 879,911 13 Long Term Notes Receivable 124 68,656 76,551 14 Other Investments 128 1,369,506 1,095,535 15 Total Other Property & Investments 2,018,073 2,051,997
Current and Accrued Assets 16 Cash 131 9,800 9,800 17 Special Deposits 132-134 6,842,190 3,208,360 18 Working Funds 135 12,462 12,446 19 Temporary Cash Investments 136 - - 20 Notes & Accts Receivable - Net 141-145,173 47,554,586 47,326,731 21 Accounts Receivable Assoc Company 146 7,374 10,447 22 Fuel Stock 151 8,894,145 9,830,796 23 Materials & Supplies 154-163 19,260,064 18,853,894 24 Prepayments 165 1,276,704 910,903 25 Interest & Dividends Receivable 171 - - 26 Other Current Assets 174,176 - (33,000,000) 27 Derivative Instrument Assets 175 - 33,000,000 28 Total Current & Accrued Assets 83,857,325 80,163,377
Deferred Debits 29 Unamortized Debt Expense 181 2,461,734 2,619,437 30 Preliminary Survey 183 - - 31 Miscellaneous Debits 184-187 328,704 - 32 Unrecovered plant & regulatory study costs 182.2 2,827,910 3,507,827 33 Other Regulatory Assets 182.3 147,405,218 146,545,982 34 Unamortized Loss on Reacquired Bond 189 1,214,022 1,539,120 35 Deferred Income Taxes 190 103,691,997 127,522,091 36 Total Deferred Debits 257,929,585 281,734,457 37 Total Assets and Other Debits $ 1,711,848,608 $ 1,671,243,175
Page 1 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement A Liabilities and Other Credits Page 2 of 2
(A) (B) (C) (D)
Line December 31 December 31 No. Description FERC Acct # 2017 2016
Proprietary Capital 1 Common Stock Issued 201 $ 500 $ 500 2 Preferred Stock Issued 204 - - 3 Premium on Capital Stock 207 - - 4 Other Paid-In Capital 208-211 376,988,966 376,988,966 5 Capital Stock Expense 214 - - 6 Retained Earnings 215-216.1, 436-438 179,258,022 169,810,191 7 Other Comprehensive Income 219 (2,419,283) (1,641,899) 8 Total Proprietary Capital 553,828,205 545,157,758
Long-Term Debt 9 Bonds 221 412,000,000 445,000,000 10 Advances from Associated Companies 223 - - 11 Other Long-Term Debt 224 - - 12 Total Long-Term Debt 412,000,000 445,000,000
Other Noncurrent Liabilities 13 Accumulated Provision for Injuries & Damages 228.2 618,804 603,589 14 Accumulated Provision for Pensions & Benefits 228.3 155,936,999 141,072,155 15 Accumulated Provision for Rate Refunds 229 - 3,624,425 16 Asset Retirement Obligations 230 8,719,408 8,341,004 17 Total Other Noncurrent Liabilities 165,275,211 153,641,173
Current & Accrued Liabilities 18 Notes Payable 231 112,370,691 42,883,278 19 Accounts Payable 232 49,338,850 56,764,068 20 Notes Payable Assoc Company 233 - - 21 Accounts Pay. Assoc Company 234 2,066,743 1,571,640 22 Customer Deposits 235 1,071,755 1,074,025 23 Taxes Accrued 236 14,109,924 14,801,360 24 Interest Accrued 237 6,208,534 6,928,094 25 Tax Collections Payable 241 1,352,088 1,364,872 26 Misc Current & Accrued Liabilities 242 4,568,417 4,824,021 27 Derivative Instrument Liabilities 244 - - 28 Total Current & Accrued Liabilities 191,087,002 130,211,358
Deferred Credits 29 Customer Advance for Construction 252 30 Other Deferred Credits 253,257 9,140,505 7,643,892 31 Other Regulatory Liabilities 254 153,023,039 5,323,068 32 Acc Deferred Inv Tax Credits 255 21,378,750 22,849,314 33 Acc Def Inc Taxes - Property 281,282 191,362,285 340,032,503 34 Acc Def Inc Taxes - Other 283 14,753,611 21,384,109 35 Total Deferred Credits 389,658,190 397,232,886 36 Total Liabilities and Other Credits $ 1,711,848,608 $ 1,671,243,175
Page 2 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement B Statement of Income Page 1 of 1
(A) (B) (C)
Line 12 Months Ended No. Description FERC Acct # December 31, 2017
1 Electric Sales 440-449.1 $ 377,349,391 2 Other Revenue 456 53,209,921 3 Sub-Total 430,559,312
4 Fuel 501 & 547 59,690,492 5 Purchased Power 555 64,807,218 6 Production Expense (Excludes Fuel) 500, 502-514, 535-546, 548-557 32,142,257 7 Transmission Expense 560-573 31,129,536 8 Regional Market Expense 575.1 - 576.5 1,005,861 9 Distribution Expense 580 - 598 17,761,844 10 Customer Accounting Expense 901 - 905 12,912,126 11 Customer Service/Sales Expense 907-916 9,697,274 12 Administrative & General Expense 920-935 45,577,184 13 Total O&M 274,723,792
14 Depreciation, Amortization, & Accretion 403-407 52,938,690 15 Regulatory Debits & Credits 407.3-407.4 (676,071) 16 (Gains) and Losses from Disposition of Allowances 411.7-411.8 (16) 17 Taxes Other than Income 408.1, 408.2 15,053,134 18 Sub-Total 67,315,737
19 Net Operating Income 88,519,783
20 Non-Operating Income (& Expense) 415-419, 421-426.5 2,287,490 21 Interest (Expense) 427-431 (26,075,041) 22 AFUDC - Debt & Equity 419.1, 432 1,726,880 23 Non-Operating (Expense) (22,060,671)
24 Income Before Tax 66,459,112
25 Income Taxes 409.1-411.5 17,012,568
26 Net Utility Income $ 49,446,544
Page 3 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement C Retained Earnings Statement Page 1 of 1
(A) (B)
Line 12 Months Ended No. Description December 31, 2017
1 Balance at Beginning of Period $ 169,810,191 2 Net Income 49,446,542 3 Total Before Deductions 219,256,733
4 Dividends Paid/Declared and Other 5 Post Retirement Benefits (457,702) 6 Common Stock Dividends 40,456,412 7 Total Dividends/Declared and Other 39,998,710
8 Balance at End of Period $ 179,258,023
Page 4 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C Otter Tail Power Company Notes to Financial Statements For the years ended December 31, 2017 and 2016
1. Summary of Significant Accounting Policies
Organization and Operations Otter Tail Power Company (OTP) was incorporated in 1907 under the laws of the State of Minnesota and is a wholly owned subsidiary of Otter Tail Corporation.
On July 1, 2009, Otter Tail Corporation completed a holding company reorganization whereby OTP, which had previously been operated as a division of Otter Tail Corporation, became a wholly owned subsidiary of the new parent holding company named Otter Tail Corporation. The new parent holding company was incorporated in June 2009 under the laws of the State of Minnesota in connection with the holding company reorganization.
OTP includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets.
OTP provides electricity to more than 130,000 customers in a service area encompassing 70,000 square miles of western Minnesota, eastern North Dakota and northeastern South Dakota. The territory served by OTP is predominantly agricultural. The aggregate population of OTP’s retail electric service area is approximately 230,000. In this service area of 422 communities and adjacent rural areas and farms, approximately 126,000 people live in communities having a population of more than 1,000, according to the 2010 census. The only communities served which have a population in excess of 10,000 are Jamestown, North Dakota (15,427); Bemidji, Minnesota (13,431); and Fergus Falls, Minnesota (13,138). As of December 31, 2017, OTP served 132,146 customers. Although there are relatively few large customers, sales to commercial and industrial customers are significant. One customer accounted for 11.7% of the 2017 revenue from the Electric segment.
Related Party Included in the amounts presented in the balance sheet and income statement are the following related party balances:
(in thousands) 2017 2016 Accounts Receivable $ 6 $ 10 Accounts Payable 2,067 1,572 Operating Revenues 31 34 Other Operation and Maintenance Expenses 10,725 9,582
The related party transactions predominately relate to the allocation of corporate overhead expenses and corporate aircraft usage to OTP and rent charged to Otter Tail Corporation for its use of office space in Fergus Falls. The corporate overhead expenses include such items as labor, professional services, office rent, subscriptions, information technology and general office expenses incurred by Otter Tail Corporation.
These expenses are allocated to OTP based on the type of expenditure, using an allocation methodology as defined in Otter Tail Corporation’s Corporate Cost Allocation Manual.
Regulation and Accounting Standards Codification (ASC) Topic 980 (ASC 980) OTP, a regulated electric utility company, accounts for the financial effects of regulation in accordance with ASC 980. This standard allows for the recording of a regulatory asset or liability for costs and revenues that will be collected or refunded through the ratemaking process in the future. In accordance with regulatory treatment, OTP defers utility debt redemption premiums and amortizes such costs over the original life of the reacquired bonds. See note 3 for further discussion.
OTP is subject to various state and federal agency regulations. The accounting policies followed by this business are subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC).
Plant, Retirements and Depreciation Utility plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction. The amount of interest capitalized on electric utility plant was $741,000 in 2017 and $495,000 in 2016. The cost of depreciable units of property retired less salvage is charged to accumulated depreciation. Removal costs, when incurred, are charged against the accumulated reserve for estimated removal expenses. Maintenance, repairs and replacement of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the
Page 5 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C estimated remaining service lives of the properties (5 to 82 years). Such provisions as a percent of the average balance of depreciable electric utility property were 2.74% in 2017 and 2.88% in 2016. Gains or losses on group asset dispositions are taken to the accumulated provision for depreciation reserve and impact current and future depreciation rates.
Recoverability of Long-Lived Assets OTP reviews its long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. OTP determines potential impairment by comparing the carrying amount of the assets with net cash flows expected to be provided by operating activities of the business or related assets. If the sum of the expected future net cash flows is less than the carrying amount of the assets, OTP would recognize an impairment loss. Such an impairment loss would be measured as the amount by which the carrying amount exceeds the fair value of the asset, where fair value is based on the discounted cash flows expected to be generated by the asset.
Jointly Owned Facilities OTP is a joint owner in two coal-fired steam-powered electric generation plants: Big Stone Plant near Big Stone City, South Dakota and Coyote Station near Beulah, North Dakota. OTP is also a joint owner, with other regional utilities, in four major in-service transmission lines and one additional major transmission line under construction. The following table provides ownership percentages and amounts included in the OTP’s December 31, 2017 and 2016 balance sheets for its share of jointly owned assets in each of these jointly owned facilities:
OTP Construction Ownership Electric Plant Work in Accumulated Jointly Owned Facilities (dollars in thousands) Percentage in Service Progress Depreciation Net Plant December 31, 2017 Big Stone Plant 53.9% $ 329,942 $ 1,074 $ (74,165) $ 256,851 Coyote Station 35.0% 177,721 158 (103,944) 73,935 Fargo–Monticello 345 kV line 14.2% 78,192 -- (4,667) 73,525 Brookings–Southeast Twin Cities 345 kV line1 4.8% 26,269 -- (1,293) 24,976 Bemidji–Grand Rapids 230 kV line 14.8% 16,331 -- (1,753) 14,578 Big Stone South–Brookings 345 kV line1 50.0% 53,225 -- (434) 52,791 Big Stone South–Ellendale 345 kV line1 50.0% -- 89,980 -- 89,980 December 31, 2016 Big Stone Plant 53.9% $ 328,809 $ 23 $ (65,665) $ 263,167 Coyote Station 35.0% 176,315 113 (101,499) 74,929 Fargo–Monticello 345 kV line 14.2% 78,298 -- (3,511) 74,787 Brookings–Southeast Twin Cities 345 kV line1 4.8% 26,406 -- (924) 25,482 Bemidji–Grand Rapids 230 kV line 14.8% 16,331 -- (1,573) 14,758 Big Stone South–Brookings 345 kV line1 50.0% -- 45,050 -- 45,050 Big Stone South–Ellendale 345 kV line1 50.0% -- 49,160 -- 49,160 1MISO Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff).
OTP’s share of direct revenue and expenses of the jointly owned facilities is included in operating revenue and expenses in the statements of income.
Coyote Station Lignite Supply Agreement – Variable Interest Entity—In October 2012 the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and OTP is not required to include CCMC in OTP’s financial statements.
Page 6 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C
If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of December 31, 2017 could be as high as $57.1 million, OTP’s 35% share of unrecovered costs.
Income Taxes Deferred income taxes arise for all temporary differences between the book and tax basis of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect in the periods when the temporary differences reverse. OTP amortizes investment tax credits over the estimated lives of related property. OTP records income taxes in accordance with ASC Topic 740, Income Taxes, and has recognized in its financial statements the tax effects of all tax positions that are “more-likely-than-not” to be sustained on audit based solely on the technical merits of those positions as of the balance sheet date. The term “more-likely-than-not” means a likelihood of more than 50%. OTP classifies interest and penalties on tax uncertainties as components of the provision for income taxes. See note 11 regarding the OTP’s accounting for uncertain tax positions.
Otter Tail Corporation and its subsidiaries, including OTP, file a consolidated U.S. federal income tax return and various state income tax returns. In OTP’s financial statements, comprehensive interperiod income tax allocation is used for substantially all book and tax temporary differences. In accordance with ASC 740, OTP records separate company deferred tax attribute balances as if OTP filed separate tax returns. OTP’s deferred taxes included $2.5 million and $7.9 million of deferred taxes associated with net operating losses that had been utilized by the consolidated group as of December 31, 2017 and 2016, respectively. This deferred tax asset would be reclassified to an intercompany receivable asset in the event the entity were to leave the consolidated return filing group.
OTP also is required to assess the realizability of its deferred tax assets, taking into consideration its forecast of future taxable income, the reversal of other existing temporary differences, available net operating loss carryforwards and available tax planning strategies that could be implemented to realize the deferred tax assets. Based on this assessment, management must evaluate the need for, and amount of, valuation allowances against the OTP’s deferred tax assets. To the extent facts and circumstances change in the future, adjustments to the valuation allowance may be required.
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (TCJA) was signed into law. The major impacts of the changes included in the TCJA are discussed in note 11 to the financial statements.
Revenue Recognition Customer electricity use is metered and bills are rendered monthly. Revenue is accrued for electricity consumed but not yet billed. Rate schedules applicable to substantially all customers include a fuel clause adjustment, under which the rates are adjusted to reflect changes in average cost of fuels and purchased power, and a surcharge for recovery of conservation-related expenses. Revenue is recognized for fuel and purchased power costs incurred in excess of amounts recovered in base rates but not yet billed through the fuel clause adjustment, for conservation program incentives and bonuses earned but not yet billed and for renewable resource, transmission-related and environmental incurred costs and investment returns approved for recovery through riders.
Revenues on wholesale electricity sales from company-owned generating units are recognized when energy is delivered. For shared use of transmission facilities with certain regional transmission cooperatives, revenues are estimated. Bills are rendered based on anticipated usage and settlements are made later based on actual usage. Estimated revenues may be adjusted prior to settlement, or at the time of settlement, to reflect actual usage.
Under ASC Topic 815, Derivatives and Hedging, OTP accounts for forward energy contracts as derivatives subject to mark- to-market accounting unless those contracts meet the definition of a capacity contract or are not subject to unplanned netting, then OTP accounts for the contracts under the normal purchases and sales exception to mark-to-market accounting.
Use of Estimates OTP uses estimates based on the best information available in recording transactions and balances resulting from business operations. As better information becomes available (or actual amounts are known), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Page 7 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C Cash Equivalents OTP considers all highly liquid debt instruments purchased with maturity of 90 days or less to be cash equivalents.
Investments The following table provides a breakdown of OTP’s investments at December 31:
(in thousands) 2017 2016 Cost Method – Economic Development Loan Pools $ 45 $ 54 Equity Method – Partnership 24 23 Total Investments $ 69 $ 77
Agreements Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases and carried at historical cost in the accompanying balance sheet. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. OTP does not offset assets and liabilities under legally enforceable netting arrangements on the face of its balance sheet.
Fair Value Measurements OTP follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.
Inventories OTP inventories consisting of fuel, materials and supplies are reported at average cost.
Supplemental Disclosures of Cash Flow Information
As of December 31, (in thousands) 2017 2016 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 13,433 $ 13,421 (in thousands) 2017 2016 Cash Paid During the Year for: Interest (net of amount capitalized) $ 25,366 $ 24,322 Income Tax Payments $ 2,348 $ --
New Accounting Standards Pending Adoption
ASU 2014-09—In May 2014 the Financial Accounting Standards Board (FASB) issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
Amendments to the ASC in ASU 2014-09, as amended, are effective for fiscal years beginning after December 15, 2017. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. As of December 31, 2017 OTP had reviewed its revenue streams and contracts. Based on review of OTP’s revenue streams, OTP has not identified any contracts where the timing of revenue recognition will change as a result of the adoption of the updates in ASU 2016-09. OTP will adopt the updates in ASU 2014-09 on a modified retrospective basis on January 1, 2018, the date of initial application, but will not be recording a cumulative effect adjustment to retained earnings on application of the updates because the adoption of the updates in ASU 606 have no impact on the timing of revenue recognition for OTP. Adoption of ASU 2014-09 will result in additional disclosures related to the nature, timing and certainty of revenues.
OTP will report adjustments to Alternative Revenue Program (ARP) revenues as a separate line item within revenue on the face of its statement of income. The ARP revenue adjustments are recorded on the basis of recoverable costs incurred and returns earned under rate riders and are not considered revenue from contracts with customers.
Page 8 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C
ASU 2016-02—In February 2016 the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 is a comprehensive amendment of the ASC, creating Topic 842, which will supersede the current requirements under ASC Topic 840 on leases and require the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Topic 842 affects any entity that enters into a lease, with some specified scope exemptions. The main difference between previous Generally Accepted Accounting Principles in the United States (GAAP) and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Topic 842 also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in ASU 2016-02 is permitted. OTP has developed a list of all current leases outstanding and continues to review ASU 2016-02, identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and is evaluating transition options. OTP does not currently plan to apply the amendments in ASU 2016-02 to its financial statements prior to 2019.
ASU 2017-07—In March 2017 the FASB issued ASU No. 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07), which is intended to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost. ASC Topic 715, Compensation—Retirement Benefits (ASC 715), does not prescribe where the amount of net benefit cost should be presented in an employer’s income statement and does not require entities to disclose by line item the amount of net benefit cost that is included in the income statement or capitalized in assets. The amendments in ASU 2017-07 require that an employer report the service cost component of periodic benefit costs in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost as defined in ASC 715 are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The amendments in ASU 2017-07 also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of internally manufactured inventory or a self- constructed asset). The amendments in ASU 2017-07 are effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The amendments will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit cost in assets.
The amendments in ASU 2017-07 deviate significantly from current prescribed ratemaking and regulatory accounting treatment of postretirement benefit costs, which require the capitalization of a portion of all the components of net periodic benefit costs be included in rate base additions and provide for rate recovery of the non-capitalized portion of all of the components of net periodic pension costs as recoverable operating expenses. OTP has assessed the impact adoption of the amendments in ASU 2017-07 will have on its financial statements, financial position and results of operations and OTP has determined the regulatory assets to be established in order to reflect the effect of the required regulatory accounting treatment of the non-service cost components that cannot be capitalized to plant in service under the ASU 2017-07 amendments to GAAP. The non-service cost components of the affected net periodic benefit costs will be reported below the operating income line on OTP’s income statement upon adoption of the amendments in ASU 2017-07.
OTP does not plan to adopt the updates in ASU 2017-07 prior to the first quarter of 2018, the required effective period for application of the updates by OTP. OTP’s non-service cost components of net periodic post-retirement benefit costs that were capitalized to plant in service in 2017 that would have been recorded as regulatory assets if the amendments in ASU 2017-07 were applicable in 2017 were $0.8 million. OTP’s non-service costs components of net periodic postretirement benefit costs included in operating expense that will be included in other income and deductions on adoption of ASU 2017-07 were $5.6 million in 2017 and $5.1 million in 2016.
2. Rate and Regulatory Matters
Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2017 and 2016.
Page 9 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C
Major Capital Expenditure Projects
Big Stone South–Ellendale Multi-Value Transmission Project (MVP)—This is a 345-kiloVolt (kV) transmission line that will extend 163 miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. Construction began on this line in the second quarter of 2016 and is expected to be completed in 2019. OTP’s capitalized costs on this project as of December 31, 2017 were approximately $90.0 million, which includes assets that are 100% owned by OTP.
Big Stone South–Brookings MVP—This 345-kV transmission line extends approximately 70 miles between a substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Northern States Power–Minnesota, a subsidiary of Xcel Energy Inc., jointly developed this project and the parties have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. Construction began on this line in the third quarter of 2015 and the line was energized on September 8, 2017. OTP’s capitalized costs on this project as of December 31, 2017 were approximately $72.7 million, which includes assets that are 100% owned by OTP.
Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.
Reagent Costs
OTP’s systemwide costs for reagents are expected to increase to approximately $2.2 million annually through May 2021 when Hoot Lake Plant is expected to be retired. The Minnesota, North Dakota and South Dakota share of costs are approximately 50%, 40% and 10%, respectively. Reagent costs for the Big Stone Plant AQCS and Coyote Station and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) were initially incurred in 2015 when projects went into service.
Minnesota
2016 General Rate Case—The MPUC rendered its final decision in OTP’s 2016 general rate case in March 2017 and issued its written order on May 1, 2017. Pursuant to the order, OTP’s allowed rate of return on rate base decreased from 8.61% to 7.5056% and its allowed rate of return on equity decreased from 10.74% to 9.41%. On July 6, 2017 the MPUC denied OTP’s request for reconsideration of certain of the MPUC’s rulings in the rate case and confirmed its May 1, 2017 order.
The MPUC’s order also included: (1) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South–Brookings and Big Stone South–Ellendale MVP projects will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers, and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from Environmental Cost Recovery (ECR) and TCR riders to base rate recovery, with the transition occurring when final rates are implemented. The rate base balances, expense levels and revenue levels existing in the riders at the time of implementation of final rates will be used to establish the amounts transitioned to base rates. Certain MISO expenses and revenues will remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs.
Page 10 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C Information on interim and final rate increases and interim revenue refunds accrued is detailed in the tables below:
Interim Rates Authorized ($ in thousands) April 14, 2016 Final Rates Revenue Increase – Annualized based on Test Year Data $ 16,816 $ 10,471 Revenue Percent Increase 9.56% 5.34% Return on Rate Base 8.07% 7.5056% Jurisdictional Rate Base based on Test Year Data $ 483,000 $ 471,000 Return on Equity 10.40% 9.41% Based on Equity to Total Capital of 52.50% 52.50% Debt to Total Capital 47.50% 47.50%
Interim Revenue (in thousands) April 16, 2016 through October 31, 2017 Billed $ 23,289 Accrued Refund $ 8,779 Net Interim Revenue $ 14,510 Interest on Refundable Amount $ 265 Final Refund $ 9,044
In addition to the interim rate refund, OTP is required to refund the difference between (1) amounts collected under its Minnesota ECR and TCR riders based on the return on equity (ROE) approved in its most recent rider update and (2) amounts that would have been collected based on the lower 9.41% ROE approved in its 2016 general rate case going back to April 16, 2016, the date interim rates were implemented. As of October 31, 2017 the revenues collected under the Minnesota ECR and TCR riders subject to refund due to the lower ROE rate and other adjustments were $0.9 million and $1.4 million, respectively. These amounts will be refunded to Minnesota customers over a 12-month period through reductions in the Minnesota ECR and TCR rider rates in effect November 1, 2017, as approved by the MPUC. The TCR rate is provisional and subject to revision under a separate docket.
OTP accrued interim and rider rate refunds until final rates became effective, for bills rendered on and after November 1, 2017. The final interim rate refund, including interest, of $9.0 million was applied as a credit to Minnesota customers’ electric bills beginning November 17, 2017.
Minnesota Conservation Improvement Programs (MNCIP)—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state's energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota.
The Minnesota Department of Commerce’s (MNDOC) may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC.
On May 25, 2016 the MPUC adopted the MNDOC’s proposed changes to the MNCIP financial incentive. The new model provides utilities an incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. OTP estimates the impact of the new model will reduce the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism. MNCIP incentives included $5.0 million approved for 2016.
Based on results from the 2017 MNCIP program year, OTP recognized a financial incentive of $2.6 million in 2017. The 2017 program resulted in an approximate 10% decrease in energy savings compared to 2016 program results. OTP will request approval for recovery of its 2017 MNCIP program costs not included in base rates, a $2.6 million financial incentive and an update to the MNCIP surcharge from the MPUC by April 1, 2018.
Transmission Cost Recovery Rider—The Minnesota Public Utilities Act (the MPU Act) provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need (CON) proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide
Page 11 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C service to the utility's retail customers, or exempt from the requirement to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under a federally approved tariff that accrue from other transmission owners’ regionally planned transmission projects that have been determined by the MISO to benefit the utility or integrated transmission system. The MPU Act also authorizes TCR riders to recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the MISO to benefit the utility or integrated transmission system. Finally, under certain circumstances, the MPU Act also authorizes TCR riders to recover the costs associated with distribution planning and investments in distribution facilities to modernize the utility grid. Such TCR riders allow a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule. MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from other MISO customers.
In OTP’s 2016 general rate case order issued on May 1, 2017, the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South– Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the MPUC’s order diverts interstate wholesale revenues that have been approved by the FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment will result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns will vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision will vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time. On August 18, 2017 OTP filed an appeal of the MPUC order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to allocate costs between jurisdictions of the FERC MVP transmission projects in the TCR rider. OTP believes the MPUC-ordered treatment conflicts with federal authority over transmission of electricity in interstate commerce and rates for the transmission of electricity subject to the jurisdiction of the FERC as set forth in the Federal Power Act of 1935, as amended (Federal Power Act). A decision is expected in late 2018.
Environmental Cost Recovery Rider— OTP had an ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant Air Quality Control System (AQCS). The ECR rider provided for a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. In its 2016 general rate case order, the MPUC approved OTP’s proposal to transition eligible rate base and expense recovery from the ECR rider to base rate recovery, effective with implementation of final rates in November 2017.
Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider in Minnesota to include recovery of reagent and emission allowance costs. On March 12, 2015 the MPUC denied OTP’s request to revise its FCA rider to include recovery of these costs. These costs were included in OTP’s 2016 general rate case in Minnesota and were considered for recovery either through the FCA rider or general rates. In its 2016 general rate case order issued May 1, 2017 the MPUC again denied OTP’s request for recovery of test-year reagent costs and emission allowances in base fuel costs or through the FCA rider. Instead, the test-year costs will be recovered in general rates and variability of those costs in excess of amounts included in general rates will only be recovered to the extent actual kilowatt-hour (kwh) sales exceed forecasted kwh sales used to establish general rates.
North Dakota
General Rates—On November 2, 2017 OTP filed a request with the NDPSC for a rate review and an effective increase in annual revenues from non-fuel base rates of $13.1 million or 8.72%. In the request, OTP proposed an allowed return on rate base of 7.97% and an allowed rate of return on equity of 10.30%. On December 20, 2017 the NDPSC approved OTP’s request for interim rates to increase annual revenue collections by $12.8 million, effective January 1, 2018. OTP used a lower rate of return on equity in the calculation of interim rates based on the rate of return on equity used in its 2018 test-year rate request. In February 2018, in a proceeding before the NDPSC, OTP’s interim rate increase was reduced from $12.8 million to $8.3 million or from 10.44% to 6.79%, effective March 1, 2018. This was in response to a lower revenue requirement related to a reduction in federal corporate income taxes from 35% to 21% in the TCJA.
OTP’s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%.
Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment which enables OTP to recover its North Dakota jurisdictional share of investments in renewable energy facilities. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment.
Page 12 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C
Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case.
Environmental Cost Recovery Rider—OTP has an ECR rider in North Dakota to recover its North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects. The ECR rider provides for a return on investment at the level approved in OTP’s most recent general rate case and for recovery of OTP’s North Dakota share of reagent and emission allowance costs.
South Dakota
2010 General Rate Case—OTP’s most recent general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued on April 21, 2011 and effective with bills rendered on and after June 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.50%.
Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities.
Environmental Cost Recovery Rider—OTP has an ECR rider in South Dakota to recover its South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects.
Reagent Costs and Emission Allowances—On August 1, 2014 OTP filed a request with the SDPUC to revise its FCA rider in South Dakota to include recovery of reagent and emission allowance costs. On September 16, 2014 the SDPUC approved OTP’s request to include recovery of these costs in its South Dakota FCA rider.
TCJA
The TCJA reduced the federal corporate income tax rate from 35% to 21%. Currently, all OTP rates have been developed using a 35% tax rate. The MPUC, the NDPSC, the SDPUC and the FERC have all initiated dockets or proceedings to begin working with utilities to assess the impact of the lower income tax rates under the TCJA on electric rates, and develop regulatory strategies to incorporate the tax change into future rates, if warranted. The MPUC required its regulated utilities to make filings by January 30, 2018 and February 15, 2018, but has not made a determination on rate treatment. The SDPUC required initial comments by February 1, 2018 and indicated that revenues collected subsequent to December 31, 2017 would be subject to refund, pending determination of the impacts of the TCJA. OTP is still assessing these impacts and will continue to work with the respective commissions to determine if any rate adjustments are necessary, and if so, to determine the appropriate timing and approach for making those adjustments.
Page 13 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C Rate Rider Updates
The following table provides summary information on the status of updates since January 1, 2014 for the rate riders described above:
Effective Date Annual R - Request Date Requested or Revenue Rate Rider A - Approval Date Approved ($000s) Rate Minnesota Conservation Improvement Program 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536/kwh 2015 Incentive and Cost Recovery A – July 19, 2016 October 1, 2016 $ 8,590 $0.00275/kwh 2014 Incentive and Cost Recovery A – July 10, 2015 October 1, 2015 $ 8,689 $0.00287/kwh Transmission Cost Recovery 2017 Rate Reset1 A – October 30, 2017 November 1, 2017 $ (3,311) Various 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 4,736 Various 2015 Annual Update A – March 9, 2016 April 1, 2016 $ 7,203 Various 2014 Annual Update A – February 18, 2015 March 1, 2015 $ 8,388 Various Environmental Cost Recovery 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943) -0.935% of base 2016 Annual Update A – July 5, 2016 September 1, 2016 $11,884 6.927% of base 2015 Annual Update A – March 9, 2016 October 1, 2015 $12,104 7.006% of base North Dakota Renewable Resource Adjustment 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 9,989 7.756% of base 2016 Annual Update A – March 15, 2017 April 1, 2017 $ 9,156 7.005% of base 2015 Annual Update A – June 22, 2016 July 1, 2016 $ 9,262 7.573% of base 2014 Annual Update A – March 25, 2015 April 1, 2015 $ 5,441 4.069% of base Transmission Cost Recovery 2017 Annual Update A – November 29, 2017 January 1, 2018 $ 7,959 Various 2016 Annual Update A – December 14, 2016 January 1, 2017 $ 6,916 Various 2015 Annual Update A – December 16, 2015 January 1, 2016 $ 9,985 Various Environmental Cost Recovery 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 8,537 6.629% of base 2017 Annual Update A – July 12, 2017 August 1, 2017 $ 9,917 7.633% of base 2016 Annual Update A – June 22, 2016 July 1, 2016 $10,359 7.904% of base 2015 Annual Update A – June 17, 2015 July 1, 2015 $12,249 9.193% of base South Dakota Transmission Cost Recovery 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various 2015 Annual Update A – February 12, 2016 March 1, 2016 $ 1,895 Various 2014 Annual Update A – February 13, 2015 March 1, 2015 $ 1,538 Various Environmental Cost Recovery 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483/kwh 2016 Annual Update A – October 26, 2016 November 1, 2016 $ 2,238 $0.00536/kwh 2015 Annual Update A – October 15, 2015 November 1, 2015 $ 2,728 $0.00643/kwh 1Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket.
Page 14 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C Revenues Recorded under Rate Riders
The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the years ended December 31:
Rate Rider (in thousands) 2017 2016 Minnesota Conservation Improvement Program Costs and Incentives1 $ 9,225 $12,920 Environmental Cost Recovery 8,148 12,443 Transmission Cost Recovery 2,973 5,795 North Dakota Environmental Cost Recovery 9,782 11,089 Transmission Cost Recovery 8,729 7,694 Renewable Resource Adjustment 7,620 7,800 South Dakota Environmental Cost Recovery 2,345 2,538 Transmission Cost Recovery 1,843 1,820 Conservation Improvement Program Costs and Incentives 598 468 1Includes MNCIP costs recovered in base rates.
FERC
Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC.
Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit.
On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. A non-binding decision by the presiding Administrative Law Judge (ALJ) was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%. A number of parties requested rehearing of the September 2016 order and the requests are pending FERC action.
On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50- basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016.
On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%. OTP is currently waiting for the issuance of a FERC order on the second complaint.
Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. MISO processed the refund for the FERC-ordered reduction in the MISO Tariff allowed ROE for the first 15-month refund period in its February and June 2017 billings. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, has resulted in a reduction in OTP’s accrued MISO Tariff ROE refund liability from $2.7 million on December 31, 2016 to $1.6 million as of December 31, 2017.
Page 15 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C In June 2014, the FERC adopted a two-step ROE methodology for electric utilities in an order issued in a complaint proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including the two ROE complaints involving MISO transmission owners discussed above. In April 2017 the Court of Appeals for the District of Columbia (D.C. Circuit) vacated and remanded the FERC’s June 2014 ROE order in the NETOs’ complaint. The D.C. Circuit found that the FERC had not properly determined that the ROE authorized for NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. OTP will await the FERC response to the April 2017 action of the D.C. Circuit before determining if an adjustment to its accrued refund liability is required. On September 29, 2017 the MISO transmission owners filed a motion to dismiss the second complaint based on the D.C. Circuit decision in the NETO complaint. If FERC were to act on a motion to dismiss, it would eliminate the refund obligation from the second complaint and the ROE from the first complaint would remain in effect.
3. Regulatory Assets and Liabilities
As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC 980. This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on OTP’s balance sheets:
Remaining December 31, 2017 Recovery/ Refund Period (in thousands) Current Long-Term Total (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 $ 9,090 $ 112,487 $ 121,577 see below Conservation Improvement Program Costs and Incentives2 7,385 2,774 10,159 21 Accumulated ARO Accretion/Depreciation Adjustment1 -- 6,651 6,651 asset lives Deferred Marked-to-Market Losses1 4,063 2,405 6,468 36 Big Stone II Unrecovered Project Costs – Minnesota1 650 1,636 2,286 40 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2 -- 1,985 1,985 24 Debt Reacquisition Premiums1 254 960 1,214 177 Big Stone II Unrecovered Project Costs – South Dakota2 100 442 542 65 North Dakota Renewable Resource Rider Accrued Revenues2 206 236 442 15 North Dakota Deferred Rate Case Expenses Subject to Recovery1 309 -- 309 12 Minnesota Deferred Rate Case Expenses Subject to Recovery1 267 -- 267 4 North Dakota Environmental Cost Recovery Rider Accrued Revenues2 152 -- 152 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues2 75 -- 75 12 Total Regulatory Assets $ 22,551 $ 129,576 $ 152,127 Regulatory Liabilities: Deferred Income Taxes $ -- $ 149,052 $ 149,052 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,100 83,100 asset lives Refundable Fuel Clause Adjustment Revenues 5,778 -- 5,778 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 1,667 -- 1,667 11 Minnesota Transmission Cost Recovery Rider Accrued Refund 802 609 1,411 22 Minnesota Renewable Resource Recovery Rider Accrued Refund 409 -- 409 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 349 -- 349 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota 208 -- 208 4 South Dakota Environmental Cost Recovery Rider Accrued Refund 187 -- 187 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 132 48 180 24 South Dakota Transmission Cost Recovery Rider Accrued Refund 151 -- 151 12 Other 5 84 89 192 Total Regulatory Liabilities $ 9,688 $ 232,893 $ 242,581 Net Regulatory Asset/(Liability) Position $ 12,863 $(103,317) $ (90,454) 1Costs subject to recovery without a rate of return. 2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.
Page 16 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C
Remaining December 31, 2016 Recovery/ Refund Period (in thousands) Current Long-Term Total (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 $ 6,443 $108,267 $114,710 see below Conservation Improvement Program Costs and Incentives2 4,836 5,158 9,994 21 Accumulated ARO Accretion/Depreciation Adjustment1 -- 6,153 6,153 asset lives Deferred Marked-to-Market Losses1 4,063 6,467 10,530 48 Big Stone II Unrecovered Project Costs – Minnesota1 778 2,087 2,865 52 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2 333 -- 333 12 Debt Reacquisition Premiums1 325 1,214 1,539 189 Big Stone II Unrecovered Project Costs – South Dakota2 100 543 643 77 North Dakota Renewable Resource Rider Accrued Revenues2 1,319 482 1,801 15 Minnesota Deferred Rate Case Expenses Subject to Recovery1 1,082 -- 1,082 12 North Dakota Environmental Cost Recovery Rider Accrued Revenues2 113 -- 113 12 Deferred Income Taxes1 -- 1,014 1,014 asset lives Recoverable Fuel and Purchased Power Costs1 1,798 -- 1,798 12 Minnesota Renewable Resource Rider Accrued Revenues2 34 -- 34 9 North Dakota Transmission Cost Recovery Rider Accrued Revenues2 -- 568 568 24 South Dakota Transmission Cost Recovery Rider Accrued Revenues2 73 141 214 14 Total Regulatory Assets $ 21,297 $132,094 $153,391 Regulatory Liabilities: Deferred Income Taxes $ -- $ 818 $ 818 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 80,404 80,404 asset lives Minnesota Environmental Cost Recovery Rider Accrued Refund 139 -- 139 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 757 -- 757 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 1,381 782 2,163 24 Revenue for Rate Case Expenses Subject to Refund – Minnesota 711 208 919 16 South Dakota Environmental Cost Recovery Rider Accrued Refund 285 -- 285 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up -- 132 132 24 Other 21 89 110 204 Total Regulatory Liabilities $ 3,294 $ 82,433 $ 85,727 Net Regulatory Asset Position $ 18,003 $ 49,661 $ 67,664 1Costs subject to recovery without a rate of return. 2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.
The regulatory liability and asset related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes.
The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.
All Deferred Marked-to-Market Losses recorded as of December 31, 2017 relate to forward purchases of energy scheduled for delivery through December 2020.
Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project.
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.
Page 17 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C
Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 177 months.
Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant- related costs incurred by OTP related to its participation in the abandoned Big Stone II project.
North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of December 31, 2017.
North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s current rate case in North Dakota currently being recovered over a 12-month period beginning with the establishment of interim rates in January 2018.
Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 rate case in Minnesota currently being recovered over a 24-month period beginning with the establishment of interim rates in April 2016.
North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that are recoverable from North Dakota customers as of December 31, 2017.
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues relate to revenues recorded for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that are subject to recovery from other Minnesota customers.
The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.
The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to Minnesota customers as of December 31, 2017.
The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of December 31, 2017.
The Minnesota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of December 31, 2017.
The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of December 31, 2017.
Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund over a 24-month period beginning with the establishment of interim rates in April 2016.
The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of December 31, 2017.
The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that had not been billed to South Dakota customers as of December 31, 2016.
The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of December 31, 2017.
Page 18 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from OTP’s balance sheet and included in OTP’s statement of income as an expense or income item in the period in which the application of guidance under ASC 980 ceases.
4. Common Shareholder’s Equity
OTP has issued and outstanding 100 shares of common stock with a par value of $5 per share, with the sole holder of these shares being Otter Tail Corporation. Otter Tail Corporation made cash equity contributions to OTP totaling $0 in 2017 and $37,000,000 in 2016.
5. Retained Earnings and Dividend Restriction
OTP’s credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if OTP did not meet certain financial covenants. As of December 31, 2017 OTP was in compliance with these financial covenants. See note 7 for further information on the covenants.
Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials.
The MPUC indirectly limits the amount of dividends OTP can pay to Otter Tail Corporation by requiring an equity-to-total- capitalization ratio between 47.4% and 58.0% based on OTP’s 2017 capital structure petition approved by order of the MPUC on September 1, 2017. As of December 31, 2017 OTP’s equity-to-total-capitalization ratio including short-term debt was 51.4% and its net assets restricted from distribution totaled approximately $471,000,000. Total capitalization for OTP cannot currently exceed $1,178,024,000.
6. Commitments and Contingencies
Construction and Other Purchase Commitments At December 31, 2017 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019, of approximately $41.0 million.
Electric Utility Capacity and Energy Requirements and Coal Purchase and Delivery Contracts OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2041. OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Big Stone Plant and Coyote Station expire at the end of 2019 and 2040, respectively. OTP has an agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant through December 31, 2023. OTP has no fixed minimum purchase requirements under the agreement, but all of Hoot Lake Plant’s coal requirements for the period covered must be purchased under this agreement. The dollar amounts of OTP’s estimated purchase requirements under this agreement are excluded from the table below because OTP has not committed to any minimum level of purchases under the agreement. Fuel clause adjustment mechanisms lessen the risk of loss from market price changes because they currently provide for recovery of most fuel costs. See table below for schedule of commitments.
Operating Leases OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. Rent expense from operations was $2,540,000 for 2017 and $2,577,000 for 2016.
Page 19 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C The amounts of OTP’s construction program and other commitments and commitments under capacity and energy agreements, coal and coal delivery contracts and operating leases as of December 31, 2017, are as follows:
Construction Capacity and Coal Program and Other Energy Purchase Operating (in thousands) Commitments Requirements Commitments Leases 2018 $ 27,538 $ 24,424 $ 26,021 $ 1,838 2019 13,479 24,925 23,016 1,435 2020 -- 24,844 22,102 1,436 2021 -- 12,988 22,537 1,241 2022 -- 11,827 22,300 761 Beyond 2022 -- 154,310 527,520 8,644 Total $ 41,017 $ 253,318 $ 643,496 $ 15,355
Contingencies OTP had a $2.7 million refund liability on its balance sheet as of December 31, 2016 representing its best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on the likelihood of the FERC reducing the ROE component of the MISO Tariff and ordering MISO to refund amounts charged in excess of the lower rate. In the February and June 2017 MISO billings, MISO processed the refund of the FERC- ordered reduction in the MISO Tariff allowed ROE for the first 15-month refund period. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, resulted in a reduction in OTP’s accrued MISO Tariff ROE refund liability from $2.7 million as of December 31, 2016 to $1.6 million as of December 31, 2017.
Together with as many as 200 utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market’s start on April 1, 2005 until the conclusion of the proceedings on May 2, 2015. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with the FERC to market participants, revisions to the RSG rate based on several FERC orders, and the FERC’s decision to not resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. OTP is an intervenor in these cases. Final briefs were filed on January 26, 2018. Oral arguments will occur in the spring of 2018. A final decision is not expected until late in 2018. MISO has not made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, OTP cannot estimate its exposure at this time from a final order reversing the relevant FERC orders, which could have an adverse effect on OTP’s results of operations.
Contingencies, by their nature, relate to uncertainties that require OTP’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies that could potentially impact OTP’s financial statements are those related to environmental remediation and litigation matters, but no estimates for potential losses have been made at this time, including any liability for RSG charges.
In 2014 the Environmental Protection Agency (EPA) published both proposed standards of performance for carbon dioxide (CO2) emissions from new, reconstructed and modified fossil fuel-fired power plants (New Source Performance Standards), and proposed CO2 emission guidelines for existing fossil fuel-fired power plants (the Clean Power Plan) under section 111 of the Clean Air Act. The EPA published final rules for each of these proposals on October 23, 2015. Both rules were challenged on legal grounds. On February 9, 2016 the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for review in the D.C. Circuit. The D.C. Circuit heard oral argument on challenges to the Clean Power Plan on September 27, 2016 before the full court, and a decision was expected in the first half of 2017. However, pursuant to Executive Order 13783, Promoting Energy Independence and Economic Growth, the EPA was directed to consider suspending, revising or rescinding the CO2 rules discussed above. Thereafter, the EPA issued notices in the Federal Register of its intent to review these rules pursuant to the Executive Order, and it filed motions to stay the pending litigation. The D.C. Circuit subsequently issued orders holding in abeyance the appeals of both the New Source Performance Standards and the Clean Power Plan, pending EPA review. On October 16, 2017 the EPA published a proposed rule to rescind the Clean Power Plan. Therefore, there is uncertainty regarding the future of both rules.
Page 20 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C Other OTP is a party to litigation and regulatory enforcement matters arising in the normal course of business. OTP regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. OTP believes the effect on its results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of December 31, 2017 will not be material.
7. Short-Term and Long-Term Borrowings
Short-Term Debt
The following table presents the status of OTP’s line of credit as of December 31, 2017 and December 31, 2016:
In Use on Restricted due to Available on Available on December 31, Outstanding December 31, December 31, (in thousands) Line Limit 2017 Letters of Credit 2017 2016 OTP Credit Agreement $ 170,000 $ 112,371 $ 300 $ 57,329 $ 127,067
Under the OTP Credit Agreement (as defined below), the maximum amount of debt outstanding in 2017 was $112,371,000 on December 29, 2017 and the average daily balance of debt outstanding during 2017 was $69,391,000. The weighted average interest rate paid on debt outstanding under the OTP Credit Agreement during 2017 was 2.4% compared with 1.8% in 2016. The weighted average interest rate on OTP’s short-term debt outstanding on December 31, 2017 was 2.7%.
On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On October 31, 2017 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2021 to October 31, 2022. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt or the issuer rating if a rating is not provided for the senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.
Long-Term Debt
2018 Note Purchase Agreement On November 14, 2017, OTP entered into a Note Purchase Agreement (the 2018 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue to the purchasers, in a private placement transaction, $100 million aggregate principal amount of OTP’s 4.07% Series 2018A Senior Unsecured Notes due February 7, 2048 (the 2018 Notes). The 2018 Notes were issued on February 7, 2018. Proceeds from the 2018 Notes were used to repay $100 million in outstanding borrowings under the OTP Credit Agreement.
OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount so prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the Note Purchase Agreement, any prepayment made by OTP of all of the Notes then outstanding on or after August 7, 2047 will be made without any make-whole amount. The 2018 Note Purchase Agreement also requires OTP to offer to prepay all outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2018 Note Purchase Agreement) of OTP.
The 2018 Note Purchase Agreement contains a number of restrictions on the business of OTP. These include restrictions on OTP’s abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2018 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2018 Note
Page 21 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2018 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event the OTP Credit Agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2018 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the 2018 Notes than any analogous provision contained in the 2018 Note Purchase Agreement (Additional Covenant), then unless waived by the Required Holders (as defined in the 2018 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2018 Note Purchase Agreement. The 2018 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP Credit Agreement, provided that no default or event of default has occurred and is continuing.
2013 Note Purchase Agreement On August 14, 2013 OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) with the purchasers named therein pursuant to which OTP agreed to issue to the purchasers, in a private placement transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). The Notes were issued on February 27, 2014.
The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states OTP must offer to prepay all of the outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2013 Note Purchase Agreement) of OTP.
The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event the OTP Credit Agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (Additional Covenant), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2013 Note Purchase Agreement. The 2013 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP Credit Agreement, provided that no default or event of default has occurred and is continuing.
2007 and 2011 Note Purchase Agreements On December 1, 2011, OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 2021 pursuant to a Note Purchase Agreement dated as of July 29, 2011 (the 2011 Note Purchase Agreement). OTP also has outstanding its $122 million senior unsecured notes issued in three series consisting of $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement). On August 21, 2017 OTP used borrowings under the OTP Credit Agreement to retire the $33 million 5.95%, Series A Senior Unsecured Notes, which had been issued under the 2007 Note Purchase Agreement and matured on August 20, 2017.
The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. The 2011 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require OTP to repurchase the notes held by them in full, together with accrued
Page 22 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C interest and a make-whole amount, on the terms and conditions specified in the 2011 Note Purchase Agreement. The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each also states that OTP must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP. The note purchase agreements contain a number of restrictions on OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The note purchase agreements also include affirmative covenants and events of default, and certain financial covenants as described below under the heading “Financial Covenants.”
Shelf Registration On May 11, 2015 Otter Tail Corporation filed a shelf registration statement with the SEC under which it may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 11, 2018.
The aggregate amounts of maturities on bonds outstanding and other long-term obligations at December 31, 2017 for each of the next five years are:
(in thousands) 2018 2019 2020 2021 2022 Aggregate Amounts of Debt Maturities $ -- $ -- $ -- $ 140,000 $ 30,000
Financial Covenants
OTP was in compliance with the financial covenants in their debt agreements as of December 31, 2017.
No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.
OTP’s borrowing agreements are subject to certain financial covenants. Specifically: • Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00. • Under the 2007 Note Purchase Agreement and the 2011 Note Purchase Agreement, OTP may not permit the ratio of its Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. • Under the 2013 Note Purchase Agreement and the 2018 Note Purchase Agreement, OTP may not permit its Interest- bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, in each case as provided in the related agreement. OTP had no Priority Indebtedness outstanding as of December 31, 2017.
8. Pension Plan and Other Postretirement Benefits
Pension Plan OTP's noncontributory funded pension plan (the Plan) covers substantially all OTP nonunion employees hired prior to September 1, 2006, and all union employees of OTP hired prior to November 1, 2013, excluding Coyote Station employees. Coyote Station employees hired before January 1, 2009 are covered under the Plan. The Plan provides 100% vesting after five vesting years of service and for retirement compensation at age 65, with reduced compensation in cases of retirement prior to age 62. OTP reserves the right to discontinue the Plan but no change or discontinuance may affect the pensions theretofore vested.
The pension plan has a trustee who is responsible for pension payments to retirees and a separate pension fund manager responsible for managing the Plan's assets. An independent actuary assists in performing the necessary actuarial valuations for the Plan.
The Plan assets consist of common stock and bonds of public companies, U.S. government securities, cash and cash equivalents and alternative investments. None of the Plan assets are invested in common stock or debt securities of OTP or Otter Tail Corporation.
Page 23 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C Components of net periodic pension benefit cost:
(in thousands) 2017 2016 Service Cost–Benefit Earned During the Period $ 5,494 $ 5,386 Interest Cost on Projected Benefit Obligation 13,800 13,854 Expected Return on Assets (18,768) (18,987) Amortization of Prior-Service Cost from Regulatory Asset 120 189 Amortization of Net Actuarial Loss from Regulatory Asset 5,090 5,153 Net Periodic Pension Cost $ 5,736 $ 5,595
Allocation of Costs: 2017 2016 Costs included in OTP Capital Expenditures $ 1,142 $ 1,048 Costs included in Electric Operation and Maintenance Expenses 4,594 4,547
Weighted average assumptions used to determine net periodic pension cost for the year ended December 31:
2017 2016 Discount Rate 4.60% 4.76% Long-Term Rate of Return on Plan Assets 7.50% 7.75% Rate of Increase in Future Compensation Level 3.00% 3.13%
The following table presents amounts recognized in OTP’s balance sheets as of December 31:
(in thousands) 2017 2016 Regulatory Assets: Unrecognized Prior Service Cost $ 21 $ 141 Unrecognized Actuarial Loss 99,360 98,039 Total Regulatory Assets $ 99,381 $ 98,180 Noncurrent Liability $ 65,782 $ 58,845
Funded status as of December 31:
(in thousands) 2017 2016 Accumulated Benefit Obligation $(308,509) $(274,660) Projected Benefit Obligation $(344,253) $(307,086) Fair Value of Plan Assets 278,471 248,241 Funded Status $ (65,782) $ (58,845)
The following tables provide a reconciliation of the changes in the OTP portion of the fair value of the Plan’s assets and the Plan’s benefit obligations over the two-year period ended December 31, 2017:
(in thousands) 2017 2016 Reconciliation of OTP’s Portion of the Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $ 248,241 $ 227,798 Actual Return on Plan Assets 43,312 23,404 Discretionary Company Contributions -- 10,000 Benefit Payments (13,082) (12,961) Fair Value of Plan Assets at December 31 $ 278,471 $ 248,241 Estimated Asset Return 17.8% 10.1% Reconciliation of OTP’s Portion of the Projected Benefit Obligation: Projected Benefit Obligation at January 1 $ 307,086 $ 295,171 Service Cost 5,494 5,386 Interest Cost 13,800 13,854 Benefit Payments (13,082) (12,961) Actuarial Loss 30,955 5,636 Projected Benefit Obligation at December 31 $ 344,253 $ 307,086
Page 24 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C Weighted average assumptions used to determine benefit obligations at December 31:
2017 2016 Discount Rate 3.90% 4.60% Rate of Increase in Future Compensation Level: All participants – prior to 2017 3.00% Participants to Age 39 4.50% Participants Age 40 to Age 49 3.50% Participants Age 50 and Older 2.75%
The assumed rate of return on pension fund assets used for the determination of 2018 net periodic pension cost is 7.50%. The assumed long-term rate of return on plan assets is based primarily on asset category studies using historical market return and volatility data with forward looking estimates based on existing financial market conditions and forecasts of capital markets. Modest excess return expectations versus some market indices are incorporated into the return projections based on the actively managed structure of the investment programs and their records of achieving such returns historically. The rate of return on plan asset assumptions are reviewed annually. The assumptions are largely based on the asset category rate-of- return assumptions developed annually with the pension plan investment advisors, as well as input from actuaries who work with the pension plan and benchmarking to peer companies with similar asset allocation strategies.
Market-related value of plan assets—The expected return on plan assets is determined based on the expected long-term rate of return on plan assets and the market-related value of plan assets.
The actuarial determination of pension plan expense or income on a market-related valuation of assets, which reduces year- to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market- related valuation calculation recognizes gains or losses over a five-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.
Measurement Dates: 2017 2016 Net Periodic Pension Cost January 1, 2017 January 1, 2016 End of Year Benefit Obligations January 1, 2017 projected to January 1, 2016 projected to December 31, 2017 December 31, 2016 Market Value of Assets December 31, 2017 December 31, 2016
The estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized from regulatory assets into the net periodic pension cost in 2018 are:
(in thousands) 2018 Decrease in Regulatory Assets: Amortization of Unrecognized Prior Service Cost $ 16 Amortization of Unrecognized Actuarial Loss 7,142 Total Estimated Amortization $ 7,158
Cash flows—OTP had no minimum funding requirement as of December 31, 2017 but made discretionary plan contributions of $20 million as of February 2018.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid out from plan assets:
Years (in thousands) 2018 2019 2020 2021 2022 2023-2027 $14,245 $14,878 $15,515 $16,180 $16,877 $92,981
Page 25 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C The following objectives guide the investment strategy of the Plan:
• The assets of the Plan will be invested in accordance with all applicable laws in a manner consistent with fiduciary standards including Employee Retirement Income Security Act standards (if applicable). Specifically: o The safeguards and diversity that a prudent investor would adhere to must be present in the investment program. o All transactions undertaken on behalf of the Plan must be in the best interest of plan participants and their beneficiaries. • The primary objective of the Plan is to provide a source of retirement income for its participants and beneficiaries. • The near-term primary financial objective of the Plan is to improve the funded status of the Plan. • A secondary financial objective is to minimize pension funding and expense volatility where possible.
The asset allocation strategy developed by the Retirement Plans Administration Committee (the Committee) is based on the current needs of the Plan and the objectives listed above. An asset/liability review is conducted annually or as often as necessary to assess the impact of various asset allocations on funded status and other financial variables. The current needs of the Plan, the overall investment objectives above, the investment preferences and risk tolerance of the Committee and the desired degree of diversification suggest the need for an investment allocation including multiple asset classes.
The asset allocation in the table below contains guideline percentages, at market value, of the total Plan invested in various asset classes. The Permitted Range is a guide and will at times not reflect the actual asset allocation as this will be dictated by market conditions, the independent actions of the Committee and/or Investment Managers and required cash flows to and from the Plan. The Permitted Range anticipates this fluctuation and provides flexibility for the Investment Managers’ portfolios to vary around the target without the need for immediate rebalancing. The Investment Manager will proactively monitor the asset allocation and will direct the purchases and sales to remain within the stated ranges.
The policy of the Plan is to invest assets in accordance with the allocations shown below:
Permitted Range Asset Class / PBO Funded Status < 85% PBO >=85% PBO >=90% PBO >=95% PBO >=100% PBO Equity 39% - 59% 34% - 54% 24% - 44% 14% - 34% 0% - 20% Investment Grade Fixed Income 22% - 42% 30% - 50% 40% - 60% 53% - 73% 70% - 100% Below Investment Grade Fixed Income* 0% - 15% 0% - 15% 0% - 15% 0% - 10% 0% - 10% Other** 5% - 20% 5% - 20% 5% - 20% 0% - 15% 0% - 15% * Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds. ** Other category may include cash, alternatives, and/or other investment strategies that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund.
OTP’s pension plan asset allocations at December 31, 2017 and 2016, by asset category are as follows:
Asset Allocation 2017 2016 Large Capitalization Equity Securities 23.5% 21.4% International Equity Securities 18.1% 22.0% Small and Mid-Capitalization Equity Securities 8.7% 9.0% Emerging Markets Equity Fund 5.5% 0.0% SEI Dynamic Asset Allocation Fund 5.0% 5.4% Equity Securities 60.8% 57.8% Fixed-Income Securities and Cash 35.2% 34.3% Other – SEI Energy Debt Collective Fund 4.0% 4.1% Other – SEI Special Situation Collective Investment Trust 0.0% 3.8% 100.0% 100.0%
Page 26 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C The following table presents OTP’s pension fund assets measured at fair value and included in Level 1 of the fair value hierarchy and assets measured using the net asset value (NAV) practical expedient to fair valuation as of December 31:
(in thousands) 2017 2016 Assets in Level 1 of the Fair Value Hierarchy $ 267,423 $ 228,680 SEI Energy Debt Collective Fund at NAV 11,048 10,190 SEI Special Situation Collective Investment Trust Fund at NAV -- 9,371 Total Assets $ 278,471 $ 248,241
Fair Value Measurements of Pension Fund Assets ASC 715, Compensation – Retirement Benefits, requires disclosures about pension plan assets identified by the three levels of the fair value hierarchy established by ASC 820-10-35.
The following table presents OTP’s pension fund assets measured at fair value and included in Level 1 of the fair value hierarchy as of December 31:
(in thousands) 2017 2016 Large Capitalization Equity Securities Mutual Fund $ 65,339 $ 53,175 International Equity Securities Mutual Funds 50,397 54,574 Small and Mid-Capitalization Equity Securities Mutual Fund 24,252 22,459 Emerging Markets Equity Fund 15,444 -- SEI Dynamic Asset Allocation Mutual Fund 14,026 13,295 Fixed Income Securities Mutual Funds 97,964 85,174 Cash Management – Money Market Fund 1 3 Total Assets $ 267,423 $ 228,680
The investments held by the SEI Energy Debt Collective Fund on December 31, 2017 and 2016 consist mainly of below investment grade high yielding bonds and loans of U.S. energy companies which trade at a discount to fair value. Redemptions are allowed semi-annually with a 95-day notice period, subject to fund director consent and certain gate, holdback and suspension restrictions. Subscriptions are allowed monthly with a three-year lock up on subscriptions. Fund assets totaling $10.0 million were invested in the SEI Energy Debt Fund in July 2015. The fund’s assets are valued in accordance with valuations reported by the fund’s sub-advisor or the fund’s underlying investments or other independent third party sources, although SEI in its discretion may use other valuation methods, subject to compliance with ERISA (as applicable). The fund’s assets are valued as of the close of business on the last business day of each calendar month and are available 30 days after the end of a calendar quarter. On an annual basis, as determined by the investment manager in its sole discretion, an independent valuation agent is retained to provide a valuation of the illiquid assets of the fund and of any other asset of the fund, as determined by the investment manager in its sole discretion. Otter Tail Corporation reviews and verifies the reasonableness of the year-end valuations.
Executive Survivor and Supplemental Retirement Plan (ESSRP) The ESSRP is an unfunded, nonqualified benefit plan for Otter Tail Corporation and OTP executive officers and certain key management employees. The ESSRP provides defined benefit payments to these employees on their retirements for life or to their beneficiaries on their deaths for a 15-year postretirement period. There are no plan assets in this nonqualified benefit plan due to the nature of the plan.
Page 27 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C The following table lists components of net periodic pension benefit cost for the year ended December 31:
(in thousands) 2017 2016 Service Cost–Benefit Earned During the Period $ 94 $ 87 Interest Cost on Projected Benefit Obligation 763 782 Amortization of Prior Service Cost: From Regulatory Asset 16 16 From Other Comprehensive Income1 15 15 Amortization of Net Actuarial Loss: From Regulatory Asset 285 293 From Other Comprehensive Income1 265 272 Net Periodic Pension Cost2 $ 1,438 $ 1,465 1Amortization of Prior Service Costs and Net Actuarial Loss from Other Comprehensive Income Charged to Electric Operation and Maintenance Expenses 2ESSRP costs are not capitalized
Weighted average assumptions used to determine net periodic pension cost for the year ended December 31:
2017 2016 Discount Rate 4.60% 4.76% Rate of Increase in Future Compensation Level 3.00% 3.25%
The following table presents amounts recognized in OTP’s balance sheets as of December 31:
(in thousands) 2017 2016 Regulatory Assets: Unrecognized Prior Service Cost $ 40 $ 58 Unrecognized Actuarial Loss 3,229 2,890 Total Regulatory Assets $ 3,269 $ 2,948 Projected Benefit Obligation Liability – Net Amount Recognized $(18,380) $(17,263) Accumulated Other Comprehensive Loss: Unrecognized Prior Service Cost $ 40 $ 54 Unrecognized Actuarial Loss 3,229 2,682 Total Accumulated Other Comprehensive Loss $ 3,269 $ 2,736
The following tables provide a reconciliation of the changes in the fair value of plan assets and the plan’s projected benefit obligations over the two-year period ended December 31, 2017 and a statement of the funded status as of December 31 of both years:
(in thousands) 2017 2016 Reconciliation of OTP’s Portion of the Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $ -- $ -- Actual Return on Plan Assets -- -- Employer Contributions 1,175 1,188 Benefit Payments (1,175) (1,188) Fair Value of Plan Assets at December 31 $ -- $ -- Reconciliation of OTP’s Portion of the Projected Benefit Obligation: Projected Benefit Obligation at January 1 $ 17,263 $ 17,107 Service Cost 94 87 Interest Cost 763 782 Benefit Payments (1,175) (1,188) Actuarial Loss 1,435 475 Projected Benefit Obligation at December 31 $ 18,380 $ 17,263
Weighted average assumptions used to determine benefit obligations at December 31:
2017 2016 Discount Rate 3.85% 4.60% Rate of Increase in Future Compensation Level 2.75% 3.00%
Page 28 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C
The estimated amounts of unrecognized net actuarial losses and prior service costs to be amortized from regulatory assets and accumulated other comprehensive loss into the net periodic pension cost for the ESSRP in 2018 are:
(in thousands) 2018 Decrease in Regulatory Assets: Amortization of Unrecognized Prior Service Cost $ 16 Amortization of Unrecognized Actuarial Loss 267 Decrease in Accumulated Other Comprehensive Loss: Amortization of Unrecognized Prior Service Cost 16 Amortization of Unrecognized Actuarial Loss 267 Total Estimated Amortization $ 566
Cash flows—The ESSRP is unfunded and has no assets; contributions are equal to the benefits paid to plan participants. The following benefit payments, which reflect future service, as appropriate, are expected to be paid:
Years (in thousands) 2018 2019 2020 2021 2022 2023-2027 $1,373 $1,416 $1,380 $1,339 $1,297 $5,828
Other Postretirement Benefits OTP provides a portion of health insurance and life insurance benefits for retired OTP employees. Substantially all of OTP's electric utility employees may become eligible for health insurance benefits if they reach age 55 and have 10 years of service. There are no plan assets. The following table lists components of net periodic postretirement benefit cost for the year ended December 31:
(in thousands) 2017 2016 Service Cost–Benefit Earned During the Period $ 1,391 $ 1,270 Interest Cost on Projected Benefit Obligation 2,647 2,443 Amortization of Prior Service Cost from Regulatory Asset (4) 134 Amortization of Net Actuarial Loss from Regulatory Asset 936 379 Net Periodic Postretirement Benefit Cost $ 4,970 $ 4,226 Effect of Medicare Part D Subsidy $ (547) $ (901)
Allocation of Cost: 2017 2016 Cost included in OTP Capital Expenditures $ 989 $ 792 Cost included in Electric Operation and Maintenance Expenses 3,981 3,433
Weighted average assumptions used to determine net periodic postretirement benefit cost for the year ended December 31:
2017 2016 Discount Rate 4.46% 4.57%
The following table presents amounts recognized in OTP’s balance sheets as of December 31:
(in thousands) 2017 2016 Regulatory Asset: Unrecognized Prior Service Cost $ -- $ (4) Unrecognized Net Actuarial Loss 18,927 13,586 Net Regulatory Asset $ 18,927 $ 13,582 Projected Benefit Obligation Liability – Net Amount Recognized $ (68,100) $ (61,070)
Page 29 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C The following tables provide a reconciliation of the changes in the fair value of plan assets and the plan’s projected benefit obligations over the two-year period ended December 31, 2017:
(in thousands) 2017 2016 Reconciliation of OTP’s Portion of the Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $ -- $ -- Actual Return on Plan Assets -- -- Company Contributions 3,284 2,832 Benefit Payments (Net of Medicare Part D Subsidy) (6,512) (5,888) Participant Premium Payments 3,228 3,056 Fair Value of Plan Assets at December 31 $ -- $ -- Reconciliation of OTP’s Portion of the Projected Benefit Obligation: Projected Benefit Obligation at January 1 $ 61,070 $ 47,512 Service Cost (Net of Medicare Part D Subsidy) 1,391 1,270 Interest Cost (Net of Medicare Part D Subsidy) 2,647 2,443 Benefit Payments (Net of Medicare Part D Subsidy) (6,512) (5,888) Participant Premium Payments 3,228 3,056 Actuarial Loss 6,276 12,677 Projected Benefit Obligation at December 31 $ 68,100 $ 61,070
Weighted average assumptions used to determine benefit obligations at December 31:
2017 2016 Discount Rate 3.81% 4.46%
Assumed healthcare cost-trend rates as of December 31:
2017 2016 Healthcare Cost-Trend Rate Assumed for Next Year Pre-65 5.85% 6.01% Healthcare Cost-Trend Rate Assumed for Next Year Post-65 6.03% 6.23% Rate to Which the Cost-Trend Rate is Assumed to Decline 4.50% 4.50% Year the Rate Reaches the Ultimate Trend Rate 2038 2038
Assumed healthcare cost-trend rates have a significant effect on the amounts reported for healthcare plans. A one-percentage- point change in assumed healthcare cost-trend rates for 2017 would have the following effects:
1 Point 1 Point (in thousands) Increase Decrease Effect on the Postretirement Benefit Obligation $ 9,078 $ (7,507) Effect on Total of Service and Interest Cost $ 714 $ (587) Effect on Expense $ 1,551 $ (1,464)
Measurement Dates: 2017 2016 Net Periodic Postretirement Benefit Cost January 1, 2017 January 1, 2016 End of Year Benefit Obligations January 1, 2017 projected to January 1, 2016 projected to December 31, 2017 December 31, 2016
The estimated net amounts of unrecognized accumulated actuarial losses to be amortized from regulatory assets into the net periodic postretirement benefit cost in 2018 is $1,649,000.
Cash flows—OTP expects to contribute $3.9 million net of expected employee contributions for the payment of retiree medical benefits and Medicare Part D subsidy receipts in 2018. OTP expects to receive a Medicare Part D subsidy from the Federal government of approximately $406,000 in 2018. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
Years (in thousands) 2018 2019 2020 2021 2022 2023-2027 $3,890 $4,009 $4,033 $4,116 $4,223 $20,583
Page 30 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C 401K Plan OTP has a 401K plan for the benefit of all its employees. Contributions made to this plan by OTP totaled $2,381,000 for 2017 and $2,229,000 for 2016.
Employee Stock Ownership Plan OTP has a stock ownership plan for the benefit of all its employees. Contributions made by OTP were $612,000 for 2017 and $647,000 for 2016.
9. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash Equivalents—The carrying amount approximates fair value because of the short-term maturity of those instruments.
Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balance outstanding as of December 31, 2017 and 2016 under the OTP Credit Agreement was subject to a variable interest rate of LIBOR plus 1.25%, which approximates a market rate.
Long-Term Debt including Current Maturities—The fair value of OTP’s long-term debt is estimated based on the current market indications of rates available to OTP for the issuance of debt. The fair value measurements of OTP’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.
December 31, 2017 December 31, 2016 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Short-Term Debt $ (112,371) $ (112,371) $ (42,883) $ (42,883) Long-Term Debt including Current Maturities (410,316) (467,496) (443,139) (493,598)
10. Property, Plant and Equipment
December 31, December 31, Service Life Range (in thousands) 2017 2016 (years) Electric Plant Low High Production $ 897,732 $ 891,330 9 82 Transmission 500,352 410,679 42 70 Distribution 482,867 466,285 5 68 General 100,067 92,063 5 50 Electric Plant in Service 1,981,018 1,860,357 Construction Work in Progress 132,556 149,997 Other Property - Land 580 880 Total Plant 2,114,154 2,011,234 Less Accumulated Depreciation and Amortization 662,431 622,657 Net Plant $ 1,451,723 $ 1,388,577
Page 31 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C 11. Income Taxes
The total income tax expense differs from the amount computed by applying the federal income tax rate (35% in 2017 and 2016) to net income before total income tax expense for the following reasons:
(in thousands) 2017 2016 Tax Computed at Federal Statutory Rate $ 23,261 $ 23,168 Increases (Decreases) in Tax from: State Income Taxes Net of Federal Income Tax Benefit 2,769 2,499 Differences Reversing in Excess of Federal Rates 551 77 Federal Production Tax Credit (7,527) (7,175) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (850) (850) Dividend Received/Paid Deduction (509) (537) Investment Tax Credit Amortization (164) (350) Allowance for Funds Used During Construction - Equity (322) (280) Effect of TCJA 458 -- Permanent and Other Differences (654) (186) Total Income Tax Expense $ 17,013 $ 16,366 Overall Effective Federal and State Income Tax Rate 25.6% 24.7% Income Tax Expense Includes the Following: Current Federal Income Taxes $ (291) $ (57) Current State Income Taxes 784 604 Deferred Federal Income Taxes 21,583 20,953 Deferred State Income Taxes 3,478 3,241 Federal Production Tax Credit (7,527) (7,175) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (850) (850) Investment Tax Credit Amortization (164) (350) Total $ 17,013 $ 16,366 Total Income Before Income Taxes $ 66,459 $ 66,195
OTP's deferred tax assets and liabilities were composed of the following on December 31:
(in thousands) 2017 2016 Deferred Tax Assets Federal Production Tax Credits (PTCs) $ 40,625 $ 33,113 Regulatory Tax Liabilities 39,465 2,422 North Dakota Wind Tax Credits 32,962 32,962 Retirement Benefit Liabilities 31,894 38,390 Cost of Removal 21,800 31,636 Benefit Liabilities 19,626 28,332 Differences Related to Property 5,420 8,255 Net Operating Loss Carryforward 3,146 9,035 Vacation Accrual 1,142 1,727 Investment Tax Credits 515 818 Other -- 782 Total Deferred Tax Assets $ 196,595 $ 187,472 Deferred Tax Liabilities Differences Related to Property $(243,760) $(351,366) Retirement Benefit Regulatory Asset (31,894) (38,390) Excess Tax over Book Pension (14,077) (15,509) North Dakota Wind Tax Credits (4,112) (3,654) Other (4,693) (11,559) Impact of State Net Operating Losses on Federal Taxes (483) (888) Total Deferred Tax Liabilities $(299,019) $(421,366) Deferred Income Taxes $(102,424) $(233,894)
Page 32 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C Federal PTCs are earned as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs increased 4.4% in 2017 compared with 2016. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.
Schedule of expiration of tax credits and tax net operating losses available as of December 31, 2017:
(in thousands) Amount 2029-37 2038-43 United States Federal Net Operating Losses $ 845 $ 845 $ -- Federal Tax Credits 40,625 40,625 -- State Net Operating Losses 2,301 2,301 -- State Tax Credits 32,962 -- 32,962
The following table summarizes the activity related to OTP’s unrecognized tax benefits:
(in thousands) 2017 2016 Balance on January 1 $ 411 $ 468 (Decreases) Increases Related to Tax Positions for Prior Years (291) 40 Increases Related to Tax Positions for Current Year -- -- Uncertain Positions Resolved During Year -- (97) Balance on December 31 $ 120 $ 411
The balance of unrecognized tax benefits as of December 31, 2017 would reduce the OTP’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of December 31, 2017 is not expected to change significantly within the next 12 months. OTP classifies interest and penalties on tax uncertainties as components of the provision for income taxes in the statement of income. There was no amount accrued for interest on tax uncertainties as of December 31, 2017.
Otter Tail Corporation and its subsidiaries, including OTP, file a consolidated U.S. federal income tax return and various state income tax returns. As of December 31, 2017, with limited exceptions, Otter Tail Corporation is no longer subject to examinations by taxing authorities for tax years prior to 2014 for federal and North Dakota state income taxes and for years prior to 2013 for Minnesota state income taxes.
TCJA In December 2017 the TCJA was enacted. The TCJA includes a number of changes to existing U.S. tax laws that impact OTP, most notably a reduction of the federal corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017.
OTP measures deferred tax assets and liabilities using enacted tax rates that will apply in the years in which the temporary differences are expected to be recovered or paid. Accordingly, OTP’s deferred tax assets and liabilities were remeasured to reflect the reduction in the U.S. corporate income tax rate from 35% to 21%. The revaluation for OTP required the creation of a regulatory liability and an offsetting reduction in deferred tax liability. This regulatory liability will generally be amortized over the remaining life of the related assets. The revaluation resulted in a one-time, non-cash, income tax expense of approximately $0.5 million in 2017. The impacts of the TCJA adjustments to deferred taxes and regulatory liabilities are provided in the reconciliation below:
Deferred Tax Deferred Tax (in thousands) Liability Regulatory Liability Balance on January 1, 2017 $ 233,894 $ 818 Change due to 2017 Accruals and Amortizations 15,930 376 TCJA Deferred Tax Valuation Adjustment (109,072) 109,072 Tax Effect on TCJA Deferred Tax Valuation Adjustment (38,786) 38,786 TCJA Adjustment to Income Tax Expense 458 -- Balance on December 31, 2017 $ 102,424 $ 149,052
Page 33 of 164 Docket No. EL18-___ Volume 4A Section 2 Footnotes for Statements A, B and C OTP recognized the income tax effects of the TCJA in its 2017 financial statements in accordance with Staff Accounting Bulletin No. 118, which provides SEC staff guidance for the application of ASC Topic 740, Income Taxes, in the reporting period in which the TCJA was signed into law. Current estimates may be revised and are subject to change due, in part, to complexities and uncertainties associated with the TCJA. While OTP is able to make reasonable estimates of the impact of the TCJA for the reduction in the federal corporate tax rate, consequences on OTP’s regulatory liabilities and, the final impact of the TCJA may differ from these estimates due to, among other things, changes in OTP’s interpretations and assumptions and additional guidance that may be issued by the U.S. Internal Revenue Service, rate regulators or the FASB.
12. Asset Retirement Obligations (AROs)
OTP’s AROs are related to its coal-fired generation plants and its 92 wind turbines located in North Dakota. The AROs include items such as site restoration, closure of ash pits, and removal of certain structures, generators, asbestos and storage tanks. OTP has legal obligations associated with the retirement of a variety of other long-lived tangible assets used in electric operations where the estimated settlement costs are individually and collectively immaterial. OTP has no assets legally restricted for the settlement of any of its AROs.
OTP recorded no new AROs in 2017.
Reconciliations of carrying amounts of the present value of OTP’s legal AROs, capitalized asset retirement costs and related accumulated depreciation and a summary of settlement activity for the years ended December 31, 2017 and 2016 are presented in the following table:
(in thousands) 2017 2016 Asset Retirement Obligations Beginning Balance $ 8,341 $ 8,084 New Obligations Recognized -- -- Adjustments Due to Revisions in Cash Flow Estimates -- (103) Accrued Accretion 378 360 Settlements -- -- Ending Balance $ 8,719 $ 8,341 Asset Retirement Costs Capitalized Beginning Balance $ 2,983 $ 3,086 New Obligations Recognized -- -- Adjustments Due to Revisions in Cash Flow Estimates -- (103) Settlements -- -- Ending Balance $ 2,983 $ 2,983 Accumulated Depreciation - Asset Retirement Costs Capitalized Beginning Balance $ 795 $ 673 New Obligations Recognized -- -- Adjustments Due to Revisions in Cash Flow Estimates -- -- Depreciation Expense 120 122 Settlements -- -- Ending Balance $ 915 $ 795 Settlements None None Original Capitalized Asset Retirement Cost - Retired $ -- $ -- Accumulated Depreciation -- -- Asset Retirement Obligation $ -- $ -- Settlement Cost -- -- Gain on Settlement – Deferred Under Regulatory Accounting $ -- $ --
Page 34 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement D Electric Plant In Service Page 1 of 1 For the period January 1, 2017 Through December 31, 2017
(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) Simple 13-Month Line FERC Balance at Transfers and Balance at Average Average Adjusted No. Acct # Description Dec 31, 2016 Additions Retirements Adjustments Dec 31, 2017 Balance Balance Adjustments Balance
1 101 Steam Production Plant $370,097,097 $1,999,739 $ (914,817) $0 $371,182,019 $370,639,558 $370,548,023 5,391,180 $375,939,203 2 106 Steam Production Plant 200,851,623 5,255,258 $ - - 206,106,881 203,479,252 200,790,274 - $200,790,274 3 114 Steam Production Plant 1,588,255 - $ - - 1,588,255 1,588,255 1,588,255 - $1,588,255 4 Total Steam Plant $572,536,975 $7,254,997 $ (914,817) $0 $578,877,155 $575,707,065 $572,926,552 $5,391,180 $578,317,732
5 101 Hydro Generation Plant $7,337,280 $6,783 $ (2,080) $0 $7,341,983 $7,339,632 $7,341,260 $0 $7,341,260 6 106 Hydro Generation Plant - - $ - - - - - 0 - 7 Total Hydro Plant $7,337,280 $6,783 $ (2,080) $0 $7,341,983 $7,339,632 $7,341,260 $0 $7,341,260
8 101 Other Generation Plant $41,542,317 $14,780 $ (7,000) $0 $41,550,097 $41,546,207 $41,545,908 $0 $41,545,908 9 106 Other Generation Plant - - $ ------10 Total Other Plant $41,542,317 $14,780 $ (7,000) $0 $41,550,097 $41,546,207 $41,545,908 $0 $41,545,908
11 101 Wind Generation Plant $268,611,109 $410,547 $ (545,582) $0 $268,476,074 $268,543,592 $268,486,990 $0 $268,486,990 12 106 Wind Generation Plant - 184,706 $ - - 184,706 92,353 24,500 - 24,500 13 Total Wind Plant $268,611,109 $595,253 $ (545,582) $0 $268,660,780 $268,635,945 $268,511,490 $0 $268,511,490
14 107 CWIP Production $7,983,139 $3,091,952 $ - $0 $11,075,091 $9,529,115 $10,152,003 $0 $10,152,003
15 Total Production Plant $898,010,820 $10,963,765 $ (1,469,479) $0 $907,505,106 $902,757,963 $900,477,213 $5,391,180 $905,868,393
16 101 Transmission Plant $391,168,975 $25,450,720 ($1,977,892) $0 $414,641,803 $402,905,389 $403,752,715 $0 $403,752,715 17 105 Transmission Plant 9,038 - - - 9,038 9,038 9,038 0 9,038 18 106 Transmission Plant 19,443,213 66,199,968 - - 85,643,181 52,543,197 35,282,646 0 35,282,646 19 114 Transmission Plant 58,287 - - - 58,287 58,287 58,287 0 58,287 20 107 CWIP Transmission 125,473,732 (28,326,316) - - 97,147,416 111,310,574 125,070,006 - 125,070,006 21 Total Transmission Plant $536,153,245 $63,324,372 ($1,977,892) $0 $597,499,725 $566,826,485 $564,172,692 $0 $564,172,692
22 101 Distribution Plant $463,681,214 $17,376,900 ($2,850,205) $0 $478,207,909 $470,944,562 $471,755,789 $0 $471,755,789 23 105 Distribution Plant 20,619 - - - 20,619 20,619 20,619 0 20,619 24 106 Distribution Plant 2,582,256 2,055,712 - - 4,637,968 3,610,112 1,574,042 0 1,574,042 25 114 Distribution Plant 586 - - - 586 586 586 0 586 26 107 CWIP Distribution 9,135,994 2,988,526 - - 12,124,520 10,630,257 11,040,151 - 11,040,151 27 Total Distribution Plant $475,420,669 $22,421,138 ($2,850,205) $0 $494,991,602 $485,206,136 $484,391,187 $0 $484,391,187
28 101 General Plant $84,855,575 $7,183,870 ($3,162,085) $0 $88,877,360 $86,866,468 $84,918,660 $0 $84,918,660 29 106 General Plant - 1,283,637 - - 1,283,637 641,819 152,836 152,836 30 107 CWIP General 1,915,002 (1,487,947) - - 427,055 1,171,029 3,193,315 - 3,193,315 31 Total General Plant $86,770,577 $6,979,560 ($3,162,085) $0 $90,588,052 $88,679,315 $88,264,811 $0 $88,264,811
32 101 Intangible Plant $8,509,535 $1,396,299 $0 $0 $9,905,834 $9,207,685 $9,040,911 $0 $9,040,911 33 106 Intangible Plant - 1,301,883 - - 1,301,883 650,942 256,695 0 256,695 34 107 CWIP Intangible 5,489,159 6,293,475 - - 11,782,634 8,635,897 9,132,261 - 9,132,261 35 Total Intangible Plant $13,998,694 $8,991,657 $0 $0 $22,990,351 $18,494,523 $18,429,867 $0 $18,429,867
36 Total Electric Plant In Service $2,010,354,005 $112,680,492 ($9,459,661) $1 $2,113,574,836 $2,061,964,421 $2,055,735,770 $5,391,180 $2,061,126,950
Total Electric Plant Included in 37 Rate Base Calculations $2,010,354,005 $112,680,492 ($9,459,661) $1 $2,113,574,836 $2,061,964,421 $2,055,735,770 $5,391,180 $2,061,126,950
Page 35 of 164 Docket No. EL18-___ Volume 4A Section 2 Otter Tail Power Company Schedule D-1 Electric Plant In Service Page 1 of 4 For the period January 1, 2017 Through December 31, 2017
(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) Simple 13-Month Line FERC Plant Balance at Transfers and Balance at Average Average Adjusted No. Acct # Acct # Description Dec 31, 2016 Additions Retirements Adjustments Dec 31, 2017 Balance Balance Adjustments Balance
INTANGIBLE PLANT 1 101 302 Franchises and Consents $1,301,974 $0 $0 $0 $1,301,974 $1,301,974 $1,301,974 $0 $1,301,974 2 101 303 Misc. Intangible Plant 7,207,561 1,396,299 - - 8,603,860 7,905,711 7,738,937 - 7,738,937 3 106 303 Misc. Intangible Plant - 1,301,882 - - 1,301,882 650,941 256,695 - 256,695 4 107 CWIP Intangible 5,489,159 6,293,475 - - 11,782,634 8,635,897 9,132,261 0 9,132,261 5 Total Intangible Plant $13,998,694 $8,991,656 $0 $0 $22,990,350 $18,494,522 $18,429,867 $0 $18,429,867
STEAM GENERATION PLANT 6 101 310 Land and Land Rights $1,654,157 $0 $0 $0 $1,654,157 $1,654,157 $1,654,157 $0 $1,654,157 7 101 311 Structures and Improvements 62,434,862 68,344 (9,004) - 62,494,202 62,464,532 62,453,130 0 62,453,130 8 106 311 Structures and Improvements 63,013,625 269,949 - - 63,283,574 63,148,600 63,071,372 0 63,071,372 9 101 312 Boiler Plant Equipment 201,488,268 1,167,162 (566,140) - 202,089,290 201,788,779 201,731,820 5,391,180 207,123,000 10 106 312 Boiler Plant Equipment 123,895,226 1,419,103 - 125,314,329 124,604,778 124,011,887 0 124,011,887 10 101 312.1 Boiler Plant Equipment 6,695,049 6,605 - 6,701,654 6,698,352 6,701,146 0 6,701,146 10 106 312.1 Boiler Plant Equipment - 3,740,821 - 3,740,821 1,870,411 - 0 0 11 101 314 Turbogenerator Units 65,601,942 304,921 (202,622) - 65,704,241 65,653,092 65,676,646 0 65,676,646 12 106 314 Turbogenerator Units 296,856 (14,514) - - 282,342 289,599 140,258 0 140,258 13 101 315 Accessory Electric Equipment 23,738,368 167,315 (19,379) - 23,886,304 23,812,336 23,753,528 0 23,753,528 13 106 315 Accessory Electric Equipment 12,937,872 (113,686) - - 12,824,186 12,881,029 12,936,641 0 12,936,641 14 101 316 Misc Power Plant Equipment 5,726,301 285,392 (117,671) - 5,894,022 5,810,162 5,819,447 0 5,819,447 15 106 316 Misc Power Plant Equipment 708,044 (46,415) - - 661,629 684,837 630,116 0 630,116 16 101 317 Asset Retirement Obligation 2,758,150 - - - 2,758,150 2,758,150 2,758,150 0 2,758,150 18 114 310 Big Stone Plant Acquisition Adj. 5,965 - - - 5,965 5,965 5,965 0 5,965 19 114 311 Big Stone Plant Acquisition Adj. 301,585 - - - 301,585 301,585 301,585 0 301,585 20 114 312 Big Stone Plant Acquisition Adj. 912,456 - - - 912,456 912,456 912,456 0 912,456 21 114 314 Big Stone Plant Acquisition Adj. 228,914 - - - 228,914 228,914 228,914 0 228,914 22 114 315 Big Stone Plant Acquisition Adj. 112,362 - - - 112,362 112,362 112,362 0 112,362 23 114 316 Big Stone Plant Acquisition Adj. 26,973 - - - 26,973 26,973 26,973 0 26,973 24 Total Steam Generation Plant $572,536,975 $7,254,997 ($914,816) $0 $578,877,156 $575,707,065 $572,926,553 $5,391,180 $578,317,733
HYDRO GENERATION PLANT 25 101 330 Land and Land Rights $299,623 $0 $0 $0 $299,623 $299,623 $299,623 $0 $299,623 26 101 331 Structures and Improvements 351,712 - - - 351,712 351,712 351,712 0 351,712 27 106 331 Structures and Improvements ------0 0 28 101 332 Reservoirs,dam, waterways 4,277,054 - - - 4,277,054 4,277,054 4,277,054 0 4,277,054 29 101 333 Water Wheels, turbines, generators 1,373,867 - - - 1,373,867 1,373,867 1,373,867 0 1,373,867 30 106 333 Water Wheels, turbines, generators ------0 0 31 101 334 Accessory Electric Equipment 592,400 6,783 (2,080) - 597,103 594,752 596,380 0 596,380 32 101 335 Misc Power Plant Equipment 442,624 - - - 442,624 442,624 442,624 0 442,624 33 Total Hydro Generation Plant $7,337,280 $6,783 ($2,080) $0 $7,341,983 $7,339,632 $7,341,260 $0 $7,341,260
Page 36 of 164 Docket No. EL18-___ Volume 4A Section 2 Otter Tail Power Company Schedule D-1 Electric Plant In Service Page 2 of 4 For the period January 1, 2017 Through December 31, 2017
(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) Simple 13-Month Line FERC Plant Balance at Transfers and Balance at Average Average Adjusted No. Acct # Acct # Description Dec 31, 2016 Additions Retirements Adjustments Dec 31, 2017 Balance Balance Adjustments Balance
OTHER GENERATION PLANT 1 101 340 Land and Land Rights $126,762 $0 $0 $0 $126,762 $126,762 $126,762 $0 $126,762 2 101 341 Structures and Improvements 4,947,270 - - - 4,947,270 4,947,270 4,947,270 0 4,947,270 3 106 341 Structures and Improvements ------0 0 4 101 342 Fuel Holders, Producers, Acces 1,748,266 - - - 1,748,266 1,748,266 1,748,266 0 1,748,266 5 101 343 Prime Movers 32,326,159 14,780 (7,000) - 32,333,939 32,330,049 32,329,750 0 32,329,750 6 106 343 Prime Movers ------0 0 7 101 345 Accessory Electric Equipment 1,933,262 - - - 1,933,262 1,933,262 1,933,262 0 1,933,262 8 101 346 Misc Power Plant Equipment 460,598 - - - 460,598 460,598 460,598 0 460,598 9 106 346 Misc Power Plant Equipment ------0 0 10 101 347 Asset Retirement Obligation ------0 0 11 Total Other Generation Plant $41,542,317 $14,780 ($7,000) $0 $41,550,097 $41,546,207 $41,545,908 $0 $41,545,908
WIND GENERATION 12 101 340 Land and Land Rights $0 $0 $0 $0 $0 $0 $0 $0 $0 13 101 341 Structures and Improvements 7,998,939 - - - 7,998,939 7,998,939 7,998,939 0 7,998,939 14 101 344 Generators 241,601,355 276,172 (543,602) - 241,333,925 241,467,640 241,467,052 0 241,467,052 15 106 344 Generators - 184,706 - - 184,706 92,353 14,208 0 14,208 16 101 345 Accessory Electric Equipment 18,618,491 134,375 (1,980) - 18,750,886 18,684,689 18,628,675 0 18,628,675 17 106 345 Accessory Electric Equipment ------10,292 0 10,292 18 101 346 Misc Power Plant Equipment 167,672 - - - 167,672 167,672 167,672 0 167,672 19 101 347 Asset Retirement Obligation 224,652 - - - 224,652 224,652 224,652 0 224,652 20 Total Wind Generation Plant $268,611,109 $595,253 ($545,582) $0 $268,660,780 $268,635,945 $268,511,490 $0 $268,511,490
21 107 CWIP Production 7,983,139 3,091,952 - 11,075,091 9,529,115 10,152,003 0 10,152,003
22 Total Production Plant $898,010,820 $10,963,765 ($1,469,478) $0 $907,505,107 $902,757,963 $900,477,214 $5,391,180 $905,868,394
Note: Column (K) amounts tie to Column (I) on Statement D
Page 37 of 164 Docket No. EL18-___ Volume 4A Section 2 Otter Tail Power Company Schedule D-1 Electric Plant In Service Page 3 of 4 For the period January 1, 2017 Through December 31, 2017
(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) Simple 13-Month Line FERC Plant Balance at Transfers and Balance at Average Average Adjusted No. Acct # Acct # Description Dec 31, 2016 Additions Retirements Adjustments Dec 31, 2017 Balance Balance Adjustments Balance
TRANSMISSION PLANT 1 101 350 Land and Land Rights $438,907 $0 $0 $0 $438,907 $438,907 $438,907 $0 $438,907 2 101 350.1 Land - Easements $13,994,721 ($16,668) $0 $0 $13,978,053 $13,986,387 $13,968,222 $0 $13,968,222 2 106 350.1 Land - Easements $0 $0 $0 $0 $0 $0 $2,887 $0 $2,887 3 101 353 Station Equipment 81,014,658 13,386,826 (1,239,556) (1,594) 93,160,334 87,087,496 86,369,723 - 86,369,723 4 106 353 Station Equipment 14,122,461 14,397,118 - - 28,519,579 21,321,020 16,355,465 - 16,355,465 5 101 354 Towers and Fixtures 81,106,418 349,606 - - 81,456,024 81,281,221 81,139,349 - 81,139,349 5 106 354 Towers and Fixtures - 782,141 - 25,830,245 26,612,386 13,306,193 2,049,540 - 2,049,540 6 101 355 Poles and Fixtures 109,068,632 7,498,428 (423,670) 3,203 116,146,593 112,607,613 113,801,753 - 113,801,753 7 106 355 Poles and Fixtures 3,617,084 23,132,868 - (25,830,245) 919,707 2,268,396 7,442,805 - 7,442,805 8 101 356 Overhead Conductor 105,468,179 4,232,529 (314,666) (1,609) 109,384,433 107,426,306 107,957,300 - 107,957,300 9 106 356 Overhead Conductor 1,703,668 27,887,841 29,591,509 15,647,589 9,431,948 - 9,431,948 10 101 358 Underground Conductor 77,461 - - - 77,461 77,461 77,461 - 77,461 11 106 358 Underground Conductor ------0 12 105 350 Land Held for Future Use 9,037 - - - 9,037 9,037 9,037 - 9,037 13 114 353 Overhead Conductor 21,646 - - - 21,646 21,646 21,646 - 21,646 14 114 355 Overhead Conductor 23,654 - - - 23,654 23,654 23,654 - 23,654 15 114 356 Underground Conductor 12,988 - - - 12,988 12,988 12,988 - 12,988 16 107 CWIP Transmission 125,473,732 (28,326,316) - 97,147,416 111,310,574 125,070,006 - 125,070,006 17 Total Transmission Plant $536,153,246 $63,324,373 ($1,977,892) $0 $597,499,727 $566,826,487 $564,172,691 $0 $564,172,691
DISTRIBUTION PLANT 18 101 360 Land and Land Rights $1,306,581 $0 $0 $0 $1,306,581 $1,306,581 $1,306,581 $0 $1,306,581 19 106 360 Land and Land Rights ------0 20 101 362 Station Equipment 77,863,396 1,702,259 (756,709) (2,579) 78,806,367 78,334,882 78,296,644 - 78,296,644 21 106 362 Station Equipment 260,299 1,514,572 - - 1,774,871 1,017,585 481,837 - 481,837 22 101 364 Poles, Towers, Fixtures 70,596,909 2,168,681 (127,046) - 72,638,544 71,617,727 71,772,988 - 71,772,988 23 106 364 Poles, Towers, Fixtures 252,907 306,889 - - 559,796 406,352 188,864 - 188,864 24 101 365 Overhead Conductor 49,695,480 1,584,121 (222,456) - 51,057,145 50,376,313 50,439,239 - 50,439,239 25 106 365 Overhead Conductor 147,214 709,090 - - 856,304 501,759 265,658 - 265,658 26 101 366 Underground Conductor ------0 27 101 367 Underground Conductors 73,428,327 3,314,102 (296,444) - 76,445,985 74,937,156 75,306,964 - 75,306,964 28 106 367 Underground Conductors 1,270,762 (323,473) - - 947,289 1,109,026 340,128 - 340,128 29 101 368 Line Transformers 93,091,999 5,026,546 (594,326) 2,579 97,526,798 95,309,399 95,621,759 - 95,621,759 30 106 368 Line Transformers 621,429 (171,323) - - 450,106 535,768 289,646 - 289,646 31 101 369 Services 12,990,947 166,923 (13,495) - 13,144,375 13,067,661 13,047,059 - 13,047,059 32 106 369 Services ------0 33 101 369.1 Underground Services 40,988,218 1,351,016 (38,221) - 42,301,013 41,644,616 41,362,296 - 41,362,296 34 101 370 Meters 24,832,623 1,318,714 (544,591) - 25,606,746 25,219,685 25,506,621 - 25,506,621 35 106 370 Meters - 49,602 - - 49,602 24,801 3,816 - 3,816 36 101 370.1 Load Management Switches 8,665,511 - 899 - 8,666,410 8,665,961 8,664,899 - 8,664,899 37 101 371 Installs Customer Premise ------0 38 101 371.2 All Other Private Lighting 4,775,083 407,605 (172,355) - 5,010,333 4,892,708 4,872,020 - 4,872,020 38 106 371.2 All Other Private Lighting 11,782 (11,782) - - - 5,891 2,719 - 2,719 39 101 373 Street Lighting 5,446,141 336,933 (85,462) - 5,697,612 5,571,877 5,558,718 - 5,558,718 40 106 373 Street Lighting & Signal Sys 17,864 (17,864) - - - 8,932 1,374 - 1,374 41 105 360 Plant Held for Future Use 20,619 - - - 20,619 20,619 20,619 - 20,619 42 114 362 Big Stone Plant Acquisition Adj. 586 - - - 586 586 586 - 586 43 107 CWIP Distribution 9,135,994 2,988,526 - - 12,124,520 10,630,257 11,040,151 - 11,040,151 44 Total Distribution Plant $475,420,671 $22,421,137 ($2,850,206) $0 $494,991,602 $485,206,136 $484,391,186 $0 $484,391,186
Page 38 of 164 Docket No. EL18-___ Volume 4A Section 2 Otter Tail Power Company Schedule D-1 Electric Plant In Service Page 4 of 4 For the period January 1, 2017 Through December 31, 2017
(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) Simple 13-Month Line FERC Plant Balance at Transfers and Balance at Average Average Adjusted No. Acct # Acct # Description Dec 31, 2016 Additions Retirements Adjustments Dec 31, 2017 Balance Balance Adjustments Balance
GENERAL PLANT 1 101 389 Land and Land Rights $1,521,896 $0 $0 $0 $1,521,896 $1,521,896 $1,521,896 $0 $1,521,896 2 106 389 Land and Land Rights ------0 3 101 390 Structures and Improvements 19,890,073 484,993 (335,993) - 20,039,073 19,964,573 19,938,486 - 19,938,486 4 106 390 Structures and Improvements ------0 5 101 390.1 General Office Buildings 5,718,958 - - - 5,718,958 5,718,958 5,718,958 - 5,718,958 6 106 390.1 General Office Buildings - 344,578 - - 344,578 172,289 55,177 - 55,177 7 101 390.2 Fleet Service Center Building 937,678 - - - 937,678 937,678 937,678 - 937,678 8 101 390.3 Central Stores Building 4,027,548 83,857 (10,000) - 4,101,405 4,064,477 4,036,864 - 4,036,864 9 101 391 Office Furniture, Equipment 1,177,317 21,809 (332,105) - 867,021 1,022,169 1,053,207 - 1,053,207 10 106 391 Office Furniture, Equipment ------0 11 101 391.1 Office Equipment 807,128 - (332,288) - 474,840 640,984 674,479 - 674,479 12 106 391.1 Office Equipment - 26,699 - - 26,699 13,350 2,054 - 2,054 13 101 391.2 Duplicating Equipment 287,696 22,462 (41,587) - 268,571 278,134 282,812 - 282,812 14 101 391.5 Computer Systems 2,677,295 717,930 (279,187) - 3,116,038 2,896,667 2,790,505 - 2,790,505 15 106 391.5 Computer Systems - 668,796 - - 668,796 334,398 69,109 - 69,109 16 101 391.6 Computer Related Equipment 944,691 193,092 (185,325) - 952,458 948,575 1,047,348 - 1,047,348 17 106 391.6 Computer Related Equipment ------0 18 101 392 Transportation Equipment 30,386,144 3,468,063 (1,412,752) - 32,441,455 31,413,800 30,248,135 - 30,248,135 19 106 392 Transportation Equipment - 13,940 - - 13,940 6,970 - - 0 20 101 392.1 Airplane 2,590,427 - - - 2,590,427 2,590,427 2,590,427 - 2,590,427 21 101 393 Stores Equipment ------0 22 101 394 Tools, Shop, Garage Equipment 3,996,914 213,938 - - 4,210,852 4,103,883 4,118,651 - 4,118,651 23 101 394.2 AMR Equipment 617,570 - - - 617,570 617,570 617,570 - 617,570 24 101 395 Laboratory Equipment ------0 25 101 396 Power Operated Equipment 616,048 33,469 (28,186) - 621,331 618,690 619,555 - 619,555 26 101 397 Communication Equipment 818,647 1,793,758 (15,692) - 2,596,713 1,707,680 944,558 - 944,558 27 106 397 Communication Equipment - 114,812 - - 114,812 57,406 26,495 - 26,495 28 101 397.1 Radio - Tele - Comm Equip 1,184,478 - (81,778) 1,102,700 1,143,589 1,136,532 - 1,136,532 29 101 397.2 Microwave Equipment 4,448,448 124,479 (107,192) 4,465,735 4,457,092 4,432,377 - 4,432,377 30 101 397.3 Radio Load Control Equip 317,859 26,019 - 343,878 330,869 319,860 - 319,860 31 106 397.3 Radio Load Control Equip - 114,812 - 114,812 57,406 - - 0 32 101 397.4 Communication Towers 1,888,762 - - 1,888,762 1,888,762 1,888,762 - 1,888,762 33 107 CWIP General 1,915,002 (1,487,947) - - 427,055 1,171,029 3,193,315 - 3,193,315 34 Total General Plant $86,770,579 $6,979,559 ($3,162,085) $0 $90,588,053 $88,679,316 $88,264,810 $0 $88,264,810
35 TOTAL $2,010,354,009 $112,680,490 ($9,459,661) $0 $2,113,574,839 $2,061,964,424 $2,055,735,768 $5,391,180 $2,061,126,948
Note: Column (K) amounts tie to Column (I) on Statement D
Page 39 of 164 Docket No. EL18-___ Volume 4A Section 2
Schedule D-2 Page 1 of 1
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the period January 1, 2017 Through December 31, 2017
(A) (B) (C) (D)
Date of Line Work Commercial No. Order Description (1) Amount Operation/Retirement
PRODUCTION 1 105673 Hoot Lake Plant - Ash Disposal Site $3,740,821 Jul-17 2 TOTAL MAJOR ADDITIONS $3,740,821
3 TOTAL MAJOR RETIREMENTS There were no major Production retirements during the test year.
TRANSMISSION 4 104393 Big Stone South Substation to Brookings $53,224,771 Sep-17 5 104829 Big Stone Plant to Big Stone South Substation 2,241,161 Sep-17 6 105046 Big Stone South Substation 2,195,843 Sep-17 7 105047 Big Stone South Substation 14,606,091 Sep-17 8 105247 Buffalo Substation 345/114 kV Transformer 5,820,975 Nov-17 9 105866 Rugby 41.6kV Breaker 1,823,736 Jul-17 10 105869 Granville Junction Breaker 997,571 Jul-17 11 104999 Parshall Area 115 kV 986,563 Aug-17 12 105867 Cole Harbor - In-Line Breaker 550,441 Jul-17 13 105870 Drake - In-Line Breaker 539,512 Jul-17 14 129370 Bemidji - 115 kV Additions 729,243 Jul-17 15 TOTAL MAJOR ADDITIONS $83,715,907
16 TOTAL MAJOR RETIREMENTS 17 There were no major Transmission retirements during the test year.
DISTRIBUTION 18 TOTAL MAJOR ADDITIONS 19 There were no major Distribution additions during the test year
20 TOTAL MAJOR RETIREMENTS 21 There were no major Distribution retirements during the test year.
GENERAL 22 129370 Broadband Communication Infrastructure 800,409 Dec-17 23 TOTAL MAJOR ADDITIONS $800,409
24 TOTAL MAJOR RETIREMENTS 25 There were no major General retirements during the test year.
INTANGIBLE 26 105343 GIS Related Software Costs 803,685 Oct-17 27 TOTAL MAJOR ADDITIONS $803,685
28 TOTAL MAJOR RETIREMENTS 29 There were no major Intangible retirements during the test year.
30 TOTAL MAJOR ADDITIONS AND RETIREMENTS 89,060,822
Page 40 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-3 Page 1 of 8
OTTER TAIL POWER COMPANY Plant Account Balances For the Thirteen Months Ended December 31, 2017
(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (D)
Line FERC Plant December January February March April May June July No. Acct # Acct # Description 2016 2017 2017 2017 2017 2017 2017 2017
INTANGIBLE PLANT 1 101 302 Franchises and Consents 1,301,974 1,301,974 1,301,974 1,301,974 1,301,974 1,301,974 1,301,974 1,301,974 2 101 303 Misc. Intangible Plant 7,207,561 7,207,561 7,631,848 7,628,959 7,628,959 7,746,471 7,744,381 7,744,381 3 106 303 Misc. Intangible Plant 0 0 0 0 0 0 0 0 4 107 CWIP 5,489,159 6,585,280 6,845,093 7,326,249 7,811,823 8,737,137 9,358,658 10,079,319 5 TOTAL INTANGIBLE PLANT 13,998,694 15,094,815 15,778,915 16,257,182 16,742,756 17,785,582 18,405,013 19,125,674
STEAM GENERATION PLANT 6 101 310 Land and Land Rights 1,654,157 1,654,157 1,654,157 1,654,157 1,654,157 1,654,157 1,654,157 1,654,157 7 101 311 Structures and Improvements 62,434,862 62,439,462 62,439,462 62,448,562 62,448,562 62,448,562 62,448,562 62,448,562 8 106 311 Structures and Improvements 63,013,625 63,013,625 63,015,122 63,025,505 63,025,505 63,100,090 63,065,680 63,065,681 9 101 312 Boiler Plant Equipment 201,488,268 201,492,223 201,504,042 201,608,239 201,608,239 201,654,793 201,835,856 201,832,196 10 101 312 Boiler Plant Equipment-Coal 6,695,049 6,701,654 6,701,654 6,701,654 6,701,654 6,701,654 6,701,654 6,701,654 11 106 312 Boiler Plant Equipment 123,895,226 123,895,226 123,898,163 123,938,571 123,938,571 123,959,439 123,737,435 123,737,436 12 106 312 Boiler Plant Equipment-Coal 0 0 0 0 0 0 0 3,683,313 13 101 314 Turbogenerator Units 65,601,942 65,601,942 65,601,942 65,680,249 65,680,249 65,701,503 65,703,962 65,703,962 14 106 314 Turbogenerator Units 296,856 296,856 296,856 130,742 130,742 0 0 0 15 101 315 Accessory Electric Equipment 23,738,368 23,738,368 23,738,368 23,738,368 23,738,368 23,738,368 23,744,238 23,744,238 16 106 315 Accessory Electric Equipment - Coal 12,937,872 12,937,872 12,938,176 12,940,286 12,940,286 12,955,440 12,948,449 12,948,449 17 101 316 Misc Power Plant Equipment 5,726,301 5,739,325 5,741,984 5,762,234 5,762,234 5,764,873 5,868,177 5,868,177 18 106 316 Misc Power Plant Equipment 0 0 0 0 0 0 0 0 19 106 316 Misc Power Plant Equipment - Coal 708,044 708,044 708,058 600,243 600,243 600,953 600,626 600,626 20 101 317 Asset Retirement Obligation 2,758,150 2,758,150 2,758,150 2,758,150 2,758,150 2,758,150 2,758,150 2,758,150 21 114 310 Big Stone Plant Acquisition Adjustment 5,965 5,965 5,965 5,965 5,965 5,965 5,965 5,965 22 114 311 Big Stone Plant Acquisition Adjustment 301,585 301,585 301,585 301,585 301,585 301,585 301,585 301,585 23 114 312 Big Stone Plant Acquisition Adjustment 912,456 912,456 912,456 912,456 912,456 912,456 912,456 912,456 24 114 314 Big Stone Plant Acquisition Adjustment 228,914 228,914 228,914 228,914 228,914 228,914 228,914 228,914 25 114 315 Big Stone Plant Acquisition Adjustment 112,362 112,362 112,362 112,362 112,362 112,362 112,362 112,362 26 114 316 Big Stone Plant Acquisition Adjustment 26,973 26,973 26,973 26,973 26,973 26,973 26,973 26,973 27 Total Steam Production Plant 572,536,975 572,565,158 572,584,391 572,575,213 572,575,213 572,626,237 572,655,201 576,334,855
HYDRO GENERATION PLANT 28 101 330 Land and Land Rights 299,623 299,623 299,623 299,623 299,623 299,623 299,623 299,623 29 101 331 Structures and Improvements 351,712 351,712 351,712 351,712 351,712 351,712 351,712 351,712 30 106 331 Structures and Improvements 0 0 0 0 0 0 0 0 31 101 332 Reservoirs,dam, waterways 4,277,054 4,277,054 4,277,054 4,277,054 4,277,054 4,277,054 4,277,054 4,277,054 32 106 332 Reservoirs,dam, waterways 0 0 0 0 0 33 101 333 Water Wheels, turbines, generators 1,373,867 1,373,867 1,373,867 1,373,867 1,373,867 1,373,867 1,373,867 1,373,867 34 106 333 Water Wheels, turbines, generators 0 0 0 0 0 0 0 0 35 101 334 Accessory Electric Equipment 592,400 592,400 597,103 597,103 597,103 597,103 597,103 597,103 36 101 335 Misc Power Plant Equipment 442,624 442,624 442,624 442,624 442,624 442,624 442,624 442,624 37 Total Hydro Generation Plant 7,337,280 7,337,280 7,341,983 7,341,983 7,341,983 7,341,983 7,341,983 7,341,983
OTHER GENERATION INTERNAL COMBUSTION 38 101 340 Land and Land Rights 126,762 126,762 126,762 126,762 126,762 126,762 126,762 126,762 39 101 341 Structures and Improvements 4,947,270 4,947,270 4,947,270 4,947,270 4,947,270 4,947,270 4,947,270 4,947,270 40 106 341 Structures and Improvements 0 0 0 0 0 0 0 0 41 101 342 Fuel Holders, Producers, Acces 1,748,266 1,748,266 1,748,266 1,748,266 1,748,266 1,748,266 1,748,266 1,748,266 42 106 342 Fuel Holders - Gas 0 0 0 0 0 0 0 0 43 101 343 Prime Movers 32,326,159 32,326,159 32,326,159 32,326,159 32,326,159 32,326,159 32,326,159 32,333,939 44 106 343 Prime Movers 0 0 0 0 0 0 0 0 45 101 345 Accessory Electric Equipment 1,933,262 1,933,262 1,933,262 1,933,262 1,933,262 1,933,262 1,933,262 1,933,262 Page 41 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-3 Page 2 of 8
OTTER TAIL POWER COMPANY Plant Account Balances For the Thirteen Months Ended December 31, 2017
(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (D)
Line FERC Plant December January February March April May June July No. Acct # Acct # Description 2016 2017 2017 2017 2017 2017 2017 2017 46 106 345 Accessory Electric Equipment 0 0 47 101 346 Misc Power Plant Equipment 460,598 460,598 460,598 460,598 460,598 460,598 460,598 460,598 48 106 346 Misc Power Plant Equipment 0 0 0 0 0 0 0 0 49 Total Internal Combustion 41,542,317 41,542,317 41,542,317 41,542,317 41,542,317 41,542,317 41,542,317 41,550,097
WIND GENERATION 50 101 341 Structures and Improvements 7,998,939 7,998,939 7,998,939 7,998,939 7,998,939 7,998,939 7,998,939 7,998,939 51 106 341 Structures and Improvements 0 0 0 0 0 0 0 0 52 101 344 Generators 241,601,355 241,601,355 241,601,355 241,601,355 241,601,355 241,411,464 241,411,464 241,411,320 53 106 344 Generators 0 0 0 0 0 0 0 0 54 101 345 Accessory Electric Equipment 18,618,491 18,618,491 18,618,491 18,618,491 18,618,491 18,618,491 18,618,491 18,618,491 55 106 345 Accessory Electric Equipment 0 56 101 346 Misc Power Plant Eq-Gas 167,672 167,672 167,672 167,672 167,672 167,672 167,672 167,672 57 106 346 Misc Power Plant Eq-Gas 0 0 0 0 0 58 101 347 Asset Retirement Obligation 224,652 224,652 224,652 224,652 224,652 224,652 224,652 224,652 59 Total Wind Generation 268,611,109 268,611,109 268,611,109 268,611,109 268,611,109 268,421,217 268,421,217 268,421,074
60 107 CWIP 7,983,139 7,977,689 8,557,771 9,250,040 9,793,622 10,168,680 12,438,167 9,827,933
61 TOTAL PRODUCTION PLANT 898,010,820 898,033,553 898,637,571 899,320,662 899,864,244 900,100,434 902,398,885 903,475,943
TRANSMISSION PLANT 1 101 350 Land and Land Rights 438,907 438,907 438,907 438,907 438,907 438,907 438,907 438,907 2 106 350 Land and Land Rights 0 0 0 0 0 0 0 0 3 101 350 Land - Easements 13,994,721 13,985,707 13,985,707 13,986,521 13,986,523 13,986,523 13,932,933 13,932,933 4 106 350 Land - Easements 0 0 0 0 0 0 0 0 5 101 353 Station Equipment 81,014,658 81,015,368 81,015,368 81,072,915 81,038,501 81,039,723 85,329,088 85,333,268 6 106 353 Station Equipment 14,122,461 14,122,461 14,181,032 14,181,349 14,181,349 14,180,995 8,872,652 12,778,629 7 101 354 Towers and Fixtures 81,106,418 81,042,802 81,042,802 81,029,430 81,029,430 81,029,430 81,018,223 81,018,223 8 106 354 Towers and Fixtures 0 0 0 0 0 0 0 0 9 101 355 Poles and Fixtures 109,068,632 109,481,911 110,987,600 112,634,256 112,935,417 113,620,054 115,322,329 115,440,933 10 106 355 Poles and Fixtures 3,617,084 3,414,961 2,116,545 2,452,785 2,328,693 2,104,843 43,815 428,077 11 101 356 Overhead Conductor 105,468,179 105,793,946 106,104,980 107,218,558 107,516,878 107,760,622 108,602,752 108,724,369 12 106 356 Overhead Conductor 1,703,668 1,356,836 781,573 1,025,955 974,015 506,905 361,894 694,482 13 101 358 Underground Conductor 77,461 77,461 77,461 77,461 77,461 77,461 77,461 77,461 14 106 358 Underground Conductor 0 0 0 0 0 0 0 0 15 105 350 Plant Held for Future Use 9,038 9,038 9,038 9,038 9,038 9,038 9,038 9,038 16 114 353 Big Stone Plant Acquisition Adjustment 21,646 21,646 21,646 21,646 21,646 21,646 21,646 21,646 17 114 355 Big Stone Plant Acquisition Adjustment 23,654 23,654 23,654 23,654 23,654 23,654 23,654 23,654 18 114 356 Big Stone Plant Acquisition Adjustment 12,988 12,988 12,988 12,988 12,988 12,988 12,988 12,988 19 107 CWIP 125,473,732 128,939,486 133,295,745 135,123,478 136,915,031 142,780,734 146,295,406 148,068,229 20 Total Transmission Plant 536,153,245 539,737,171 544,095,044 549,308,940 551,489,531 557,593,521 560,362,785 567,002,835
DISTRIBUTION PLANT 21 101 360 Land and Land Rights 1,306,581 1,306,581 1,306,581 1,306,581 1,306,581 1,306,581 1,306,581 1,306,581 22 106 360 Land and Land Rights 0 0 0 0 0 0 0 0 23 101 362 Station Equipment 77,863,396 77,921,378 77,974,045 78,043,541 78,167,595 78,148,677 78,153,260 78,159,573 24 106 362 Station Equipment 260,299 218,009 181,443 563,952 314,157 313,604 313,742 313,568 25 101 364 Poles, Towers, Fixtures 70,596,909 70,669,666 70,868,679 71,526,361 71,612,050 71,730,148 71,862,156 72,026,085 26 106 364 Poles, Towers, Fixtures 252,907 211,844 176,635 186,403 174,171 174,188 174,112 62,041 27 101 365 Overhead Conductor 49,695,480 49,727,575 49,778,659 50,264,436 50,284,826 50,312,715 50,403,883 50,571,696 28 106 365 Overhead Conductor 147,214 119,259 98,513 249,773 203,924 203,588 203,642 353,395 29 101 366 Underground Conduit 0 0 0 0 0 0 0 0 30 101 367 Underground Conductors 73,428,327 73,982,260 74,438,540 74,991,199 75,085,927 75,175,102 75,408,582 75,651,379 Page 42 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-3 Page 3 of 8
OTTER TAIL POWER COMPANY Plant Account Balances For the Thirteen Months Ended December 31, 2017
(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (D)
Line FERC Plant December January February March April May June July No. Acct # Acct # Description 2016 2017 2017 2017 2017 2017 2017 2017 31 106 367 Underground Conductors 1,270,762 580,633 89,333 227,594 205,321 194,050 193,663 59,738 32 101 368 Line Transformers 93,091,999 93,451,952 94,178,331 95,084,765 95,342,949 95,509,163 95,738,163 95,891,698 33 106 368 Line Transformers 621,429 433,908 108,644 339,405 309,169 298,682 298,453 208,447 34 101 369 Services 12,990,947 12,990,947 12,995,873 12,995,873 12,995,873 12,995,873 13,064,358 13,064,358 35 106 369 Services 0 0 0 0 0 0 0 0 36 101 369 Underground Services 40,988,218 40,988,218 41,029,252 41,029,523 41,029,523 41,029,523 41,341,965 41,341,965 37 106 369 Underground Services 0 0 0 0 0 0 0 0 38 101 370 Meters 24,832,623 24,764,948 25,419,445 25,671,430 25,602,115 25,495,014 25,703,108 25,678,729 39 106 370 Meters 0 0 0 0 0 0 0 0 40 101 370 Load Management Switches 8,665,511 8,665,417 8,661,351 8,661,259 8,660,985 8,660,438 8,668,559 8,668,185 41 106 370 Load Management Switches 0 0 0 0 0 0 0 0 42 101 370 Interruption Monitors 0 0 0 0 0 0 0 0 43 101 371 Installs Customer Premise 0 0 0 0 0 0 0 0 44 101 371 All Other Private Lighting 4,775,083 4,777,692 4,784,809 4,805,950 4,843,759 4,850,220 4,882,593 4,882,393 45 106 371 All Other Private Lighting 11,782 11,782 11,782 0 0 0 0 0 46 101 373 Street Lighting 5,446,141 5,469,550 5,478,043 5,484,944 5,539,554 5,541,766 5,578,206 5,580,148 47 106 373 Street Lighting 17,864 0 0 0 0 0 0 0 48 105 360 Plant Held for Future Use 20,619 20,619 20,619 20,619 20,619 20,619 20,619 20,619 49 114 362 Big Stone Plant Acquisition Adjustment 586 586 586 586 586 586 586 586 50 107 CWIP 9,135,994 11,341,671 11,160,989 7,251,284 7,604,438 9,168,794 10,075,422 11,554,872 51 Total Distribution Plant 475,420,670 477,654,495 478,762,152 478,705,478 479,304,121 481,129,331 483,391,651 485,396,055
GENERAL PLANT 1 101 389 Land 1,521,896 1,521,896 1,521,896 1,521,896 1,521,896 1,521,896 1,521,896 1,521,896 2 106 389 Land 0 0 0 0 0 0 0 0 3 101 390 Structures & Improvements 19,890,073 19,890,073 19,890,073 19,890,073 19,890,073 19,890,073 19,890,073 19,889,386 4 106 390 Structures & Improvements 0 0 0 0 0 0 0 0 5 101 390.1 General Office Buildings 5,718,958 5,718,958 5,718,958 5,718,958 5,718,958 5,718,958 5,718,958 5,718,958 6 106 390.1 General Office Buildings 0 0 0 0 0 0 0 0 7 101 390.2 Fleet Service Center Building 937,678 937,678 937,678 937,678 937,678 937,678 937,678 937,678 8 101 390.3 Central Stores Buildings 4,027,548 4,027,548 4,027,548 4,027,548 4,027,548 4,027,548 4,027,548 4,036,998 9 101 391 Office Furniture 1,177,317 1,170,548 1,170,548 1,164,418 1,164,418 1,186,227 1,139,436 1,115,515 10 106 391 Office Furniture 0 0 0 0 0 0 0 0 11 101 391.1 Office Equipment 807,128 760,398 760,398 663,646 663,646 663,646 662,421 662,421 12 106 391.1 Office Equipment 0 0 0 0 0 0 0 0 13 101 391.2 Duplicating Equipment 287,696 287,696 287,696 294,922 294,922 302,149 302,149 273,046 14 106 391.2 Duplicating Equipment 0 0 0 0 0 0 0 0 15 101 391.3 Engineering Computers 0 0 0 0 0 0 0 0 16 101 391.4 Business Computers 0 0 0 0 0 0 0 0 17 101 391.5 Computer Systems 2,677,295 2,677,295 2,398,108 2,398,108 2,398,108 2,951,525 2,943,347 2,943,347 18 106 391.5 Computer Systems 0 0 0 0 0 0 0 0 19 101 391.6 Computer Related Equipment 944,691 944,691 944,691 944,691 944,691 1,127,778 1,127,778 1,135,357 20 106 391.6 Computer Related Equipment 0 0 0 0 0 0 0 0 21 101 392 & 392.1 Transportation Equipment 32,976,571 32,952,461 32,697,233 32,603,756 32,430,063 32,344,332 32,267,087 32,337,892 22 106 392 Transportation Equipment 0 23 101 393 Stores Equipment 0 0 0 0 0 0 0 0 24 101 394 Tools, Shop & Garage Equipment 3,996,914 4,017,241 4,017,241 4,066,996 4,066,996 4,136,768 4,151,119 4,151,119 25 106 394 Tools, Shop & Garage Equipment 0 0 0 0 0 0 0 0 26 101 394.1 Central Stores Tools 0 0 0 0 0 0 0 0 27 101 394.2 AMR Equipment 617,570 617,570 617,570 617,570 617,570 617,570 617,570 617,570 28 101 395 Laboratory Equipment 0 0 0 0 0 0 0 0 29 101 396 Power-Operated Equipment 616,048 616,048 616,048 597,812 597,812 631,281 631,281 631,281 30 101 397 & 397.4 Communication Equipment & Communications Towers 2,707,409 2,707,409 2,707,409 2,691,717 2,691,717 2,691,717 2,691,717 2,691,717 31 106 397 Communication Equipment 0 0 0 0 0 0 0 0 Page 43 of 164 Docket No. EL18-___ Volume 4A Section 2
Schedule D-3 Page 4 of 8
OTTER TAIL POWER COMPANY Plant Account Balances For the Thirteen Months Ended December 31, 2017
(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (D)
Line FERC Plant December January February March April May June July No. Acct # Acct # Description 2016 2017 2017 2017 2017 2017 2017 2017 32 101 397.1 Radio Tele-Communication Equipment 1,184,478 1,184,478 1,184,478 1,124,308 1,124,308 1,124,308 1,124,308 1,124,308 33 106 397.1 Radio Tele-Communication Equipment 0 0 0 0 0 0 0 0 34 101 397.2 Microwave Equipment 4,448,448 4,451,926 4,464,982 4,465,226 4,465,226 4,465,226 4,465,226 4,409,130 35 101 397.3 Radio Load Control Equipment 317,859 317,859 317,859 317,859 317,859 317,859 317,859 317,859 35 106 397.3 Radio Load Control Equipment 0 0 0 0 0 0 0 0 36 101 397 Miscellaneous Equipment 0 0 0 0 0 0 0 0 37 107 CWIP 1,915,002 1,806,510 2,087,396 2,348,564 3,071,114 2,522,305 4,221,432 4,862,076 38 Total General Plant 86,770,577 86,608,282 86,367,810 86,395,745 86,944,602 87,178,842 88,758,882 89,377,553
39 Total Electric Plant 2,010,354,006 2,017,128,317 2,023,641,491 2,029,988,007 2,034,345,254 2,043,787,710 2,053,317,216 2,064,378,059
Page 44 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-3 Page 5 of 8
OTTER TAIL POWER COMPANY Plant Account Balances For the Thirteen Months Ended December 31, 2017
(A) (B) (C) (E) (F) (G) (H) (I) (J) (J)
Line FERC Plant August September October November December 12 Month 13 Month No. Acct # Acct # Description 2017 2017 2017 2017 2017 Average Average
INTANGIBLE PLANT 1 101 302 Franchises and Consents 1,301,974 1,301,974 1,301,974 1,301,974 1,301,974 1,301,974 1,301,974 2 101 303 Misc. Intangible Plant 7,744,381 7,744,381 7,744,381 8,229,062 8,603,860 7,783,219 7,738,937 3 106 303 Misc. Intangible Plant 0 0 803,685 1,231,464 1,301,883 278,086 256,695 4 107 CWIP 10,754,366 11,394,806 11,317,422 11,237,442 11,782,634 9,435,852 9,132,261 5 TOTAL INTANGIBLE PLANT 19,800,721 20,441,161 21,167,462 21,999,941 22,990,352 18,799,131 9,297,606
STEAM GENERATION PLANT 6 101 310 Land and Land Rights 1,654,157 1,654,157 1,654,157 1,654,157 1,654,157 1,654,157 1,654,157 7 101 311 Structures and Improvements 62,448,562 62,448,562 62,448,562 62,494,202 62,494,202 62,454,652 62,453,130 8 106 311 Structures and Improvements 63,065,681 63,065,681 63,094,034 63,094,034 63,283,574 63,076,184 63,071,372 9 101 312 Boiler Plant Equipment 201,836,149 201,836,149 201,843,833 201,884,379 202,089,290 201,752,116 201,731,820 10 101 312 Boiler Plant Equipment-Coal 6,701,654 6,701,654 6,701,654 6,701,654 6,701,654 6,701,654 6,701,146 11 106 312 Boiler Plant Equipment 123,737,436 123,737,436 123,900,877 124,464,389 125,314,329 124,021,609 124,011,887 12 106 312 Boiler Plant Equipment-Coal 3,709,380 3,740,156 3,740,821 3,740,821 3,740,821 1,862,943 1,719,639 13 101 314 Turbogenerator Units 65,703,962 65,703,962 65,704,240 65,704,240 65,704,240 65,682,871 65,676,646 14 106 314 Turbogenerator Units 0 0 156,511 232,453 282,342 127,209 140,258 15 101 315 Accessory Electric Equipment 23,744,238 23,744,238 23,751,200 23,751,200 23,886,304 23,754,791 23,753,528 16 106 315 Accessory Electric Equipment - Coal 12,948,449 12,948,449 12,954,209 12,954,209 12,824,186 12,936,538 12,936,641 17 101 316 Misc Power Plant Equipment 5,876,248 5,876,248 5,880,514 5,892,471 5,894,022 5,827,209 5,819,447 18 106 316 Misc Power Plant Equipment 0 0 0 0 0 0 0 19 106 316 Misc Power Plant Equipment - Coal 600,626 600,626 600,896 600,896 661,629 623,622 630,116 20 101 317 Asset Retirement Obligation 2,758,150 2,758,150 2,758,150 2,758,150 2,758,150 2,758,150 2,758,150 21 114 310 Big Stone Plant Acquisition Adjustment 5,965 5,965 5,965 5,965 5,965 5,965 5,965 22 114 311 Big Stone Plant Acquisition Adjustment 301,585 301,585 301,585 301,585 301,585 301,585 301,585 23 114 312 Big Stone Plant Acquisition Adjustment 912,456 912,456 912,456 912,456 912,456 912,456 912,456 24 114 314 Big Stone Plant Acquisition Adjustment 228,914 228,914 228,914 228,914 228,914 228,914 228,914 25 114 315 Big Stone Plant Acquisition Adjustment 112,362 112,362 112,362 112,362 112,362 112,362 112,362 26 114 316 Big Stone Plant Acquisition Adjustment 26,973 26,973 26,973 26,973 26,973 26,973 26,973 27 Total Steam Production Plant 576,372,946 576,403,722 576,777,913 577,515,509 578,877,155 574,821,959 574,646,191
HYDRO GENERATION PLANT 28 101 330 Land and Land Rights 299,623 299,623 299,623 299,623 299,623 299,623 299,623 29 101 331 Structures and Improvements 351,712 351,712 351,712 351,712 351,712 351,712 351,712 30 106 331 Structures and Improvements 0 0 0 0 0 0 0 31 101 332 Reservoirs,dam, waterways 4,277,054 4,277,054 4,277,054 4,277,054 4,277,054 4,277,054 4,277,054 32 106 332 Reservoirs,dam, waterways 0 0 0 33 101 333 Water Wheels, turbines, generators 1,373,867 1,373,867 1,373,867 1,373,867 1,373,867 1,373,867 1,373,867 34 106 333 Water Wheels, turbines, generators 0 0 0 0 0 0 0 35 101 334 Accessory Electric Equipment 597,103 597,103 597,103 597,103 597,103 596,711 596,380 36 101 335 Misc Power Plant Equipment 442,624 442,624 442,624 442,624 442,624 442,624 442,624 37 Total Hydro Generation Plant 7,341,983 7,341,983 7,341,983 7,341,983 7,341,983 7,341,592 7,341,260
OTHER GENERATION INTERNAL COMBUSTION 38 101 340 Land and Land Rights 126,762 126,762 126,762 126,762 126,762 126,762 126,762 39 101 341 Structures and Improvements 4,947,270 4,947,270 4,947,270 4,947,270 4,947,270 4,947,270 4,947,270 40 106 341 Structures and Improvements 0 0 0 0 0 0 0 41 101 342 Fuel Holders, Producers, Acces 1,748,266 1,748,266 1,748,266 1,748,266 1,748,266 1,748,266 1,748,266 42 106 342 Fuel Holders - Gas 0 0 0 0 0 0 43 101 343 Prime Movers 32,333,939 32,333,939 32,333,939 32,333,939 32,333,939 32,330,049 32,329,750 44 106 343 Prime Movers 0 0 0 0 0 0 0 45 101 345 Accessory Electric Equipment 1,933,262 1,933,262 1,933,262 1,933,262 1,933,262 1,933,262 1,933,262 Page 45 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-3 Page 6 of 8
OTTER TAIL POWER COMPANY Plant Account Balances For the Thirteen Months Ended December 31, 2017
(A) (B) (C) (E) (F) (G) (H) (I) (J) (J)
Line FERC Plant August September October November December 12 Month 13 Month No. Acct # Acct # Description 2017 2017 2017 2017 2017 Average Average 46 106 345 Accessory Electric Equipment 0 0 0 0 47 101 346 Misc Power Plant Equipment 460,598 460,598 460,598 460,598 460,598 460,598 460,598 48 106 346 Misc Power Plant Equipment 0 0 0 0 0 0 0 49 Total Internal Combustion 41,550,097 41,550,097 41,550,097 41,550,097 41,550,097 41,546,207 41,545,908
WIND GENERATION 50 101 341 Structures and Improvements 7,998,939 7,998,939 7,998,939 7,998,939 7,998,939 7,998,939 7,998,939 51 106 341 Structures and Improvements 0 0 0 0 0 0 0 52 101 344 Generators 241,414,440 241,414,440 241,333,925 241,333,925 241,333,925 241,455,860 241,467,052 53 106 344 Generators 0 0 0 0 184,706 15,392 14,208 54 101 345 Accessory Electric Equipment 18,618,491 18,618,491 18,618,491 18,618,491 18,750,886 18,629,524 18,628,675 55 106 345 Accessory Electric Equipment 133,795 0 11,150 10,292 56 101 346 Misc Power Plant Eq-Gas 167,672 167,672 167,672 167,672 167,672 167,672 167,672 57 106 346 Misc Power Plant Eq-Gas 0 0 0 58 101 347 Asset Retirement Obligation 224,652 224,652 224,652 224,652 224,652 224,652 224,652 59 Total Wind Generation 268,424,194 268,424,194 268,343,678 268,477,473 268,660,779 268,503,188 268,511,490
60 107 CWIP 10,865,881 11,534,790 11,178,218 11,325,019 11,075,091 10,332,742 10,152,003
61 TOTAL PRODUCTION PLANT 904,555,101 905,254,786 905,191,890 906,210,082 907,505,105 902,545,688 902,196,852 0 TRANSMISSION PLANT 0 1 101 350 Land and Land Rights 438,907 438,907 438,907 438,907 438,907 438,907 438,907 2 106 350 Land and Land Rights 0 0 0 0 3 101 350 Land - Easements 13,932,933 13,925,815 13,979,256 13,979,256 13,978,052 13,966,013 13,968,222 4 106 350 Land - Easements 18,767 18,767 0 0 0 3,128 2,887 5 101 353 Station Equipment 93,174,338 93,209,490 93,209,490 93,193,864 93,160,334 86,815,979 86,369,723 6 106 353 Station Equipment 5,107,405 21,875,859 22,250,249 28,247,028 28,519,579 16,541,549 16,355,465 7 101 354 Towers and Fixtures 81,018,223 81,028,042 81,496,247 81,496,247 81,456,024 81,142,094 81,139,349 8 106 354 Towers and Fixtures 0 0 6,091 25,548 26,612,386 2,220,335 2,049,540 9 101 355 Poles and Fixtures 115,736,453 115,841,224 116,060,687 116,146,707 116,146,593 114,196,180 113,801,753 10 106 355 Poles and Fixtures 465,617 25,880,728 26,354,790 26,628,818 919,707 7,761,615 7,442,805 11 101 356 Overhead Conductor 109,061,162 109,126,843 109,300,917 109,381,262 109,384,432 108,164,727 107,957,300 12 106 356 Overhead Conductor 472,610 28,130,401 28,405,918 28,609,558 29,591,509 10,075,971 9,431,948 13 101 358 Underground Conductor 77,461 77,461 77,461 77,461 77,461 77,461 77,461 14 106 358 Underground Conductor 0 0 0 0 0 0 0 15 105 350 Plant Held for Future Use 9,038 9,038 9,038 9,038 9,038 9,038 9,038 16 114 353 Big Stone Plant Acquisition Adjustment 21,646 21,646 21,646 21,646 21,646 21,646 21,646 17 114 355 Big Stone Plant Acquisition Adjustment 23,654 23,654 23,654 23,654 23,654 23,654 23,654 18 114 356 Big Stone Plant Acquisition Adjustment 12,988 12,988 12,988 12,988 12,988 12,988 12,988 19 107 CWIP 153,699,333 89,662,243 94,846,748 93,662,495 97,147,416 125,036,362 125,070,006 20 Total Transmission Plant 573,270,534 579,283,104 586,494,085 591,954,475 597,499,725 566,507,646 564,172,692
DISTRIBUTION PLANT 21 101 360 Land and Land Rights 1,306,581 1,306,581 1,306,581 1,306,581 1,306,581 1,306,581 1,306,581 22 106 360 Land and Land Rights 0 0 0 0 0 0 0 23 101 362 Station Equipment 78,501,142 78,499,789 78,780,956 78,836,650 78,806,368 78,332,748 78,296,644 24 106 362 Station Equipment 389,376 389,376 614,850 616,639 1,774,872 500,299 481,837 25 101 364 Poles, Towers, Fixtures 72,142,883 72,278,884 72,487,696 72,608,781 72,638,543 71,870,994 71,772,988 26 106 364 Poles, Towers, Fixtures 61,972 46,527 164,771 209,859 559,796 183,527 188,864 27 101 365 Overhead Conductor 50,762,373 50,827,254 50,981,579 51,042,492 51,057,145 50,501,219 50,439,239 28 106 365 Overhead Conductor 335,416 241,744 225,892 214,888 856,304 275,528 265,658 29 101 366 Underground Conduit 0 0 0 0 0 0 0 30 101 367 Underground Conductors 75,827,998 76,010,635 76,174,148 76,370,453 76,445,985 75,463,517 75,306,964 Page 46 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-3 Page 7 of 8
OTTER TAIL POWER COMPANY Plant Account Balances For the Thirteen Months Ended December 31, 2017
(A) (B) (C) (E) (F) (G) (H) (I) (J) (J)
Line FERC Plant August September October November December 12 Month 13 Month No. Acct # Acct # Description 2017 2017 2017 2017 2017 Average Average 31 106 367 Underground Conductors 61,194 27,109 245,710 319,273 947,289 262,576 340,128 32 101 368 Line Transformers 96,147,079 96,663,515 97,064,598 97,391,864 97,526,798 95,832,573 95,621,759 33 106 368 Line Transformers 213,463 0 178,571 305,123 450,106 261,998 289,646 34 101 369 Services 13,064,358 13,102,976 13,102,976 13,102,976 13,144,376 13,051,735 13,047,059 35 106 369 Services 0 0 0 0 0 0 0 36 101 369 Underground Services 41,341,965 41,762,894 41,762,894 41,762,894 42,301,013 41,393,469 41,362,296 37 106 369 Underground Services 0 0 0 0 0 0 0 38 101 370 Meters 25,673,951 25,690,541 25,723,529 25,723,896 25,606,746 25,562,788 25,506,621 39 106 370 Meters 0 0 0 0 49,602 4,134 3,816 40 101 370 Load Management Switches 8,666,642 8,666,270 8,666,162 8,666,501 8,666,410 8,664,848 8,664,899 41 106 370 Load Management Switches 0 0 0 0 0 0 0 42 101 370 Interruption Monitors 0 0 0 0 0 0 0 43 101 371 Installs Customer Premise 0 0 0 0 0 0 0 44 101 371 All Other Private Lighting 4,894,874 4,897,210 4,965,015 4,966,335 5,010,333 4,880,099 4,872,020 45 106 371 All Other Private Lighting 0 0 0 0 0 1,964 2,719 46 101 373 Street Lighting 5,580,594 5,581,002 5,640,758 5,645,013 5,697,612 5,568,099 5,558,718 47 106 373 Street Lighting 0 0 0 0 0 0 1,374 48 105 360 Plant Held for Future Use 20,619 20,619 20,619 20,619 20,619 20,619 20,619 49 114 362 Big Stone Plant Acquisition Adjustment 586 586 586 586 586 586 586 50 107 CWIP 13,044,425 13,903,551 12,840,262 14,315,735 12,124,520 11,198,830 11,040,151 51 Total Distribution Plant 488,037,491 489,917,064 490,948,152 493,427,157 494,991,603 485,138,729 484,391,186
GENERAL PLANT 1 101 389 Land 1,521,896 1,521,896 1,521,896 1,521,896 1,521,896 1,521,896 1,521,896 2 106 389 Land 0 0 0 0 0 0 0 3 101 390 Structures & Improvements 20,010,338 20,010,338 20,010,338 20,010,338 20,039,073 19,942,520 19,938,486 4 106 390 Structures & Improvements 0 0 0 0 0 0 0 5 101 390.1 General Office Buildings 5,718,958 5,718,958 5,718,958 5,718,958 5,718,958 5,718,958 5,718,958 6 106 390.1 General Office Buildings 0 0 0 372,729 344,578 59,776 55,177 7 101 390.2 Fleet Service Center Building 937,678 937,678 937,678 937,678 937,678 937,678 937,678 8 101 390.3 Central Stores Buildings 4,036,998 4,036,998 4,036,998 4,036,998 4,101,405 4,037,640 4,036,864 9 101 391 Office Furniture 901,101 901,101 867,022 867,022 867,022 1,042,865 1,053,207 10 106 391 Office Furniture 0 0 0 0 0 0 0 11 101 391.1 Office Equipment 662,421 662,421 662,421 662,421 474,840 663,425 674,479 12 106 391.1 Office Equipment 0 0 0 0 26,699 2,225 2,054 13 101 391.2 Duplicating Equipment 273,046 273,046 265,808 265,808 268,571 282,405 282,812 14 106 391.2 Duplicating Equipment 0 0 0 0 0 0 0 15 101 391.3 Engineering Computers 0 0 0 0 0 0 0 16 101 391.4 Business Computers 0 0 0 0 0 0 0 17 101 391.5 Computer Systems 2,943,347 2,943,347 2,943,347 2,943,347 3,116,039 2,799,939 2,790,505 18 106 391.5 Computer Systems 0 0 114,812 114,812 668,796 74,868 69,109 19 101 391.6 Computer Related Equipment 1,135,357 1,137,783 1,137,783 1,137,783 952,458 1,055,903 1,047,348 20 106 391.6 Computer Related Equipment 0 0 0 0 0 0 0 21 101 392 & 392.1 Transportation Equipment 32,878,982 32,904,898 32,787,492 32,688,664 35,031,882 32,827,062 32,838,562 22 106 392 Transportation Equipment 13,940 1,162 1,072 23 101 393 Stores Equipment 0 0 0 0 0 0 0 24 101 394 Tools, Shop & Garage Equipment 4,151,119 4,182,628 4,182,628 4,210,851 4,210,851 4,128,796 4,118,651 25 106 394 Tools, Shop & Garage Equipment 0 0 0 0 0 0 0 26 101 394.1 Central Stores Tools 0 0 0 0 0 0 0 27 101 394.2 AMR Equipment 617,570 617,570 617,570 617,570 617,570 617,570 617,570 28 101 395 Laboratory Equipment 0 0 0 0 0 0 0 29 101 396 Power-Operated Equipment 631,281 621,330 621,330 621,330 621,330 619,847 619,555 30 101 397 & 397.4 Communication Equipment & Communications Towers 2,691,717 2,691,717 2,691,717 2,691,717 4,485,474 2,843,812 2,833,320 31 106 397 Communication Equipment 0 0 114,812 114,812 114,812 28,703 26,495 Page 47 of 164 Docket No. EL18-___ Volume 4A Section 2
Schedule D-3 Page 8 of 8
OTTER TAIL POWER COMPANY Plant Account Balances For the Thirteen Months Ended December 31, 2017
(A) (B) (C) (E) (F) (G) (H) (I) (J) (J)
Line FERC Plant August September October November December 12 Month 13 Month No. Acct # Acct # Description 2017 2017 2017 2017 2017 Average Average 32 101 397.1 Radio Tele-Communication Equipment 1,124,308 1,124,308 1,124,308 1,124,308 1,102,701 1,132,536 1,136,532 33 106 397.1 Radio Tele-Communication Equipment 0 0 0 0 0 0 0 34 101 397.2 Microwave Equipment 4,409,130 4,370,215 4,370,215 4,370,215 4,465,735 4,431,038 4,432,377 35 101 397.3 Radio Load Control Equipment 317,859 317,859 317,859 317,859 343,878 320,027 319,860 35 106 397.3 Radio Load Control Equipment 0 0 114,812 114,812 114,812 28,703 26,495 36 101 397 Miscellaneous Equipment 0 0 0 0 0 0 0 37 107 CWIP 4,225,962 4,300,027 4,868,684 4,856,970 427,055 3,299,841 3,193,315 38 Total General Plant 89,189,067 89,274,118 90,028,489 90,318,900 90,588,052 88,419,195 88,292,378
39 Total Electric Plant 2,074,852,914 2,084,170,233 2,093,830,078 2,103,910,555 2,113,574,836 2,061,410,389 2,048,350,714
Page 48 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 1 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the period January 1, 2013 Through December 31, 2017
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month 1 PRODUCTION
2 Beginning Balance January 1, 2013 $670,531,248
3 Various $4,253,346 Various Various 4 103934 Dayton Hollow - Improve Dam Spillway Stabiity 466,794 5/9 12/13 5 104200 Hoot Lake Plant - Replace Switchgear 417,190 2/10 7/13 6 104575 Big Stone Plant - Brine Concentrator Waste Water Recycle 1,413,563 2/11 12/13 7 104766 Langdon Wind Farm - Generation Outlet costs 567,518 1/12 12/13 8 104881 Coyote Station - Generator Stator and Rotor Rewind 3,969,285 11/12 11/13 9 104962 Big Stone Plant - Air Heater Cold End Basket Replacement 497,826 1/13 7/13 12 TOTAL MAJOR ADDITIONS $11,585,522
13 104881 Coyote Station - Generator Stator and Rotor Rewind (2,862,616) 11/12 11/13 14 104962 Big Stone Plant - Air Heater Cold End Basket Replacement (606,707) 1/13 7/13 15 Various (2,470,505) Various Various 16 TOTAL MAJOR RETIREMENTS ($5,939,828)
17 Ending Balance December 31, 2013 $676,176,942
Page 49 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 2 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Year Ended December 31, 2013
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month 1 TRANSMISSION
2 Beginning Balance January 1, 2013 $261,379,967
3 Various $1,520,199 Various Various 4 103487 Bemidji-Grand Rapids 230 kV Line 642,264 9/06 12/13 5 104587 Cass Lake - Nary Transmission Line 1,474,958 1/11 2/16 6 104761 Caselton - Buffalo 115 kV Line 6,048,442 1/12 12/13 7 TOTAL MAJOR ADDITIONS $9,685,863
8 Various ($526,669) Various Various 9 TOTAL MAJOR RETIREMENTS ($526,669)
10 Ending Balance December 31, 2013 $270,539,161
11 DISTRIBUTION
12 Beginning Balance January 1, 2013 $405,439,275
13 Various $14,432,314 On-going Various 14 104992 Distribution Substation Transformers - Purchase & Retirement 1,307,695 On-going Various 15 104993 Distribution Voltage Regulator Purchases 1,190,183 On-going Various 16 104995 Distributio Meter Purchases 1,320,216 On-going Various 17 123157 Belcourt - Construct 12.5 kV Line 533,015 4/12 1/13 18 TOTAL MAJOR ADDITIONS $18,783,423
19 6419 Meter Retirements ($533,700) On-going Various 20 Various (1,907,287) Various Various 21 TOTAL MAJOR RETIREMENTS ($2,440,987)
22 Ending Balance December 31, 2013 $421,781,711
Page 50 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 3 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Year Ended December 31, 2013
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month 1 GENERAL
2 Beginning Balance January 1, 2013 $80,064,726
3 Various $3,458,876 Various Various 4 14694 Addition of Transportation Equipment 3,153,690 On-going Various 5 TOTAL MAJOR ADDITIONS $6,612,566
6 6420 Addition & Retirement of Furniture & Office Equipment ($1,114,710) On-going Various 7 6421 Retirement of Transportation & Power Operated Equipment (1,974,867) On-going Various 8 Various (268,699) Various Various 9 TOTAL MAJOR RETIREMENTS ($3,358,276)
10 Ending Balance December 31, 2013 $83,319,016
11 INTANGIBLE
12 Beginning Balance January 1, 2013 $4,210,739
13 Various $1,429,647 Various Various 14 104787 Primary and Backup Control Center $690,611 1/12 6/13 15 104880 Oracle R12 Upgrade $1,359,660 12/12 10/13 16 TOTAL MAJOR ADDITIONS $3,479,918
17 Various (300,040) Various Various 18 TOTAL MAJOR RETIREMENTS ($300,040)
19 Ending Balance December 31, 2013 $7,390,617
20 TOTAL ELECTIC PLANT IN SERVICE DECEMBER 31, 2013 $1,459,207,447
Page 51 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 4 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Year Ended December 31, 2014
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month 1 PRODUCTION
2 Beginning Balance January 1, 2014 $676,176,942
3 Various $4,319,196 Various Various 4 104912 Central Hydro - Concrete Dam Repairs 508,056 6/13 11/14 5 105028 Hoot Lake Plant - MATS Upgrade 5,482,860 3/13 8/14 6 105052 Hoot Lake Plant - Air Heater Basket Replacement 508,212 9/13 11/14 7 105121 Hoot Lake Plant - Unit 3 LP Turbine Blade Replacement 600,112 12/13 11/14 8 105126 Hoot Lake Plant - Ash Pond 794,336 1/14 11/14 9 Asser Retirement Obligations (ARO) changes 1,582,311 1/14 Various 10 TOTAL MAJOR ADDITIONS $13,795,083
11 104575 Big Stone Plant - Brine Concentrator Waste Water Recycle ($621,808) 2/11 3/14 12 Various (2,216,674) Various Various 13 TOTAL MAJOR RETIREMENTS ($2,838,482)
14 Ending Balance December 31, 2014 $687,133,543
15 TRANSMISSION
16 Beginning Balance January 1, 2014 $270,539,161
17 Various $4,948,217 Various Various 18 104566 Fargo - St. Cloud 345 kV Line 26,080,148 11/10 4/14 19 104832 Lyon County - Cedar Mountain 345 kV line 3,991,969 3/12 3/14 20 104833 Helena - Cedar Mountain 345 kV Line 6,592,121 3/12 3/14 21 104834 Helena - Chub Lake 345 kV Line 2,699,811 3/12 4/14 22 104835 Chub Lake - Hamption 345 kV Line 2,604,805 3/12 4/14 23 104858 Monticello - Fargo 345 kV Line Underlying Improvement 3,121,384 7/12 12/14 24 105135 Henning to Silver Lake Line 1,307,666 4/13 8/14 25 105246 Mapleton-Sheyenne - Rebuild Line 2,149,562 7/14 10/14 26 105303 Detroit Lakes - Frazee - 115 kV Replace Poles 503,096 9/13 7/14 27 125830 Camp Grafton - Spirit Lake Casino 622,243 1/14 11/14 28 TOTAL MAJOR ADDITIONS $54,621,022
Page 52 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 5 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Year Ended December 31, 2014
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month
1 Various ($1,133,548) Various Various 2 104761 Casselton - Buffalo 115 kV Line ($597,405) 1/12 9/14 3 TOTAL MAJOR RETIREMENTS ($1,730,953)
4 Ending Balance December 31, 2014 $323,429,230
5 DISTRIBUTION
6 Beginning Balance January 1, 2014 $421,781,711
7 Various $16,846,978 Various Various 8 105185 Addition & Retirement of Meters 1,194,045 On-going Various 9 105196 Distribution Substation Transformers - Purchase & Retirement 1,501,482 On-going Various 10 121362 Bottineau - Convert Distribution to 12.5 kV 541,272 3/11 11/14 11 TOTAL MAJOR ADDITIONS $20,083,777
12 6419 Addition & Retirement of Meters ($527,666) On-going Various 13 6429 Addition & Retirement of Load Management Switches (568,006) On-going Various 14 Various (2,301,936) Various Various 15 TOTAL MAJOR RETIREMENTS ($3,397,608)
16 Ending Balance December 31, 2014 $438,467,880
Page 53 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 6 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Year Ended December 31, 2014
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month
1 GENERAL
2 Beginning Balance January 1, 2014 $83,319,016
3 Various $2,951,761 Various Various 4 Addition of Transportation and Power Operated Equipment $2,749,442 On-going Various 5 TOTAL MAJOR ADDITIONS $5,701,203
6 6420 Addition & Retirement of Furniture & Office Equipment ($1,271,519) On-going Various 7 6421 Retirement of Transportation & Power Operated Equipment (1,413,176) On-going Various 8 Various (203,961) Various Various 9 TOTAL MAJOR RETIREMENTS ($2,888,656)
10 Ending Balance December 31, 2014 $86,131,563
11 INTANGIBLE
12 Beginning Balance January 1, 2014 $7,390,617
13 Various 882,553 Various Various 14 TOTAL MAJOR ADDITIONS $882,553
15 $0 Various Various 16 TOTAL MAJOR RETIREMENTS $0
17 Ending Balance December 31, 2014 $8,273,170
19 TOTAL ELECTIC PLANT IN SERVICE DECEMBER 31, 2014 $1,543,435,386
Page 54 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 7 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Test Year Ended December 31, 2015
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month 1 PRODUCTION
2 Beginning Balance January 1, 2015 $687,133,543
3 Various $4,454,406 Various Various 4 104357 Big Stone Plant - AQCS Project 199,225,862 1/10 12/15 5 104921 Coyote Station - Add Mercury Removal System 747,126 10/13 12/15 6 105028 Hoot Lake Plant - MATS Upgrade 980,130 3/13 8/15 7 105150 Coyote Station - Gas Recirculation Fan VFD 602,095 3/14 12/15 8 105177 Big Stone Plant - Coal Dust Collection Upgrade 2,494,800 1/14 10/15 9 105184 Big Stone Plant - Primary Boiler Superheat Replacement 2,348,885 2/14 10/15 10 105541 Hoot Lake Plant - Landfill expansion and capping 2,722,954 1/15 12/15 11 105634 Big Stone Plant - Boiler Studding and Refractory 1,042,703 3/15 10/15 12 105636 Big Stone Plant - HP/IP Rotor Blanding 1,419,547 4/15 10/15 13 TOTAL MAJOR ADDITIONS $216,038,508
14 104357 Big Stone Plant - AQCS Project ($20,883,482) 1/10 4/15 15 105184 Big Stone Plant - Primary Boiler Superheat Replacement (1,777,457) 2/14 11/15 16 105636 Big Stone Plant - HP/IP Rotor Blanding (649,886) 4/15 11/15 17 Various (3,630,405) Various Various 18 TOTAL MAJOR RETIREMENTS ($26,941,230)
19 Ending Balance December 31, 2015 $876,230,821
20 TRANSMISSION
21 Beginning Balance January 1, 2015 $323,429,230
22 Various $5,926,050 Various Various 23 Various Brookings - SE Twin Cities CapX2020 Project 10,111,913 4/14 Various 24 104566 Fargo - St. Cloud Capx2020 Phase III 41,623,002 11/10 4/15 25 104762 Oakes Area 41.6 kV Upgrades 4,133,877 2/12 2/15 26 105076 Oakes Area 230 kV Substation 2,730,001 8/13 10/15 27 105325 Audubon - Shyenne Line 699,075 5/14 8/15 28 105333 Fergus Falls - Wahpeton Line 1,523,739 4/14 3&12/15 29 105335 Hankinson - Wahpeton Line 797,333 4/14 3&12/15 30 105336 Foreman - Hankinson Line 834,580 7/14 3&12/15 31 105553 Burr Junction - Marietta Line 568,355 11/14 6/15 32 105560 Spiritwood Area Transmission 720,137 10/15 33 TOTAL MAJOR ADDITIONS $69,668,062
34 Various ($1,223,832) Various Various 35 TOTAL MAJOR RETIREMENTS ($1,223,832)
36 Ending Balance December 31, 2015 $391,873,460
Page 55 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 8 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Test Year Ended December 31, 2015
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month
1 DISTRIBUTION
2 Beginning Balance January 1, 2015 $438,467,880
3 Various $15,887,309 Various Various 4 6419 Addition & Retirement of Meters 1,284,430 On-going Various 5 TOTAL MAJOR ADDITIONS $17,171,739
6 6419 Addition & Retirement of Meters ($704,860) On-going Various 7 Various (3,135,661) Various Various 8 TOTAL MAJOR RETIREMENTS ($3,840,521)
9 Ending Balance December 31, 2015 $451,799,098
10 GENERAL 11 Beginning Balance January 1, 2015 $86,131,563
12 Various $1,669,242 Various Various 13 Various Purchase of Transportation and Power Operated Equipment 2,976,470 On-going Various 14 TOTAL MAJOR ADDITIONS $4,645,712
15 Various Retirement of Transportation & Power Operated Equipment (1,276,613) On-going Various 16 Various (591,834) Various Various 17 TOTAL MAJOR RETIREMENTS ($1,868,447)
18 Ending Balance December 31, 2015 $88,908,828
19 INTANGIBLE
20 Beginning Balance January 1, 2015 $8,273,170
21 Various $176,247 Various Various 22 105029 Gather GIS Attributes during LIDAR survey 1,824,607 12/12 10/15 23 TOTAL MAJOR ADDITIONS 2,000,854
24 Various 0 Various Various 25 TOTAL MAJOR RETIREMENTS $0
26 Ending Balance December 31, 2015 $10,274,024
27 TOTAL ELECTIC PLANT IN SERVICE DECEMBER 31, 2015 $1,819,086,231
Page 56 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 9 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Test Year Ended December 31, 2016
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month
1 PRODUCTION
2 Beginning Balance January 1, 2016 $876,230,821
3 Various $3,932,147 Various Various 4 104357 Big Stone Plant - AQCS Project 817,391 1/10 12/15 5 105416 Coyote Station - Replace Air Heater Baskets 514,163 11/15 12/16 6 105422 Coyote Station - Boiler Lower Wall Overlay 4,913,831 1/15 10/16 7 105426 Coyote Station - Add Overfire Air for Nox Control 1,382,251 1/15 12/16 8 105460 Jamestown - Control System Upgrade 578,483 10/15 11/16 9 105488 Coyote Station - Boiler Feed Pump Failure 4,198,802 12/14 7/16 10 105819 Coyote Station - Coal Conveyor from Mine 1,737,769 3/16 7/16 11 TOTAL MAJOR ADDITIONS $18,074,837
12 Various ($4,677,759) Various Various 13 105422 Coyote Station - Boiler Lower Wall Overlay (1,188,471) 12/16 14 TOTAL MAJOR RETIREMENTS ($5,866,230)
15 Ending Balance December 31, 2016 $888,439,428
16 TRANSMISSION
17 Beginning Balance January 1, 2016 $391,873,460
18 Various $6,190,936 Various Various 19 6462 Distribution Substation Transformers - Purchase & Retirement 391,787 On-going Various 20 104998 Summit 115/41.6 kV Transformer Replacement 853,991 11/13 5/16 21 105115 J262/J263 Interconnection for Geronimo Wind 8,881,208 12/13 6/16 22 105526 Purchase of Line along Hwy 34 in SD 1,177,379 5/15 12/16 23 105557 Big Stone - Maretta Line 516,247 11/14 10/16 24 105575 Canby - Granite Falls Line 1,179,140 7/14 12/16 25 TOTAL MAJOR ADDITIONS $19,190,688
Page 57 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 10 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Test Year Ended December 31, 2016
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month
1 Various ($451,960) Various Various 2 TOTAL MAJOR RETIREMENTS ($451,960)
3 Ending Balance December 31, 2016 $410,612,188
4 DISTRIBUTION
5 Beginning Balance January 1, 2016 $451,799,098
6 Various $13,781,115 Various Various 7 6419 Addition & Retirement of Meters 1,346,551 On-going Various 8 6462 Distribution Substation Transformers - Purchase & Retirement 896,027 On-going Various 9 105726 Distribution Regulators - Purchase & Retirement 1,128,455 On-going Various 10 TOTAL MAJOR ADDITIONS $17,152,148
11 Various ($1,944,194) Various Various 12 6419 Addition & Retirement of Meters (743,581) On-going Various 13 TOTAL MAJOR RETIREMENTS ($2,687,775)
14 Ending Balance December 31, 2016 $466,263,471
Page 58 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 11 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Test Year Ended December 31, 2016
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month
1 GENERAL
2 Beginning Balance January 1, 2016 $88,908,828
3 Various $956,546 Various Various 4 Various Addition of Transportation and Power Operated Equipment 1,376,436 On-going Various 5 TOTAL MAJOR ADDITIONS $2,332,982
6 Various ($121,164) Various Various 7 6420 Addition & Retirement of Furniture & Office Equipment (4,447,174) On-going Various 8 103692 Retirement of Transportation & Power Operated Equipment (1,817,897) On-going Various 9 TOTAL MAJOR RETIREMENTS ($6,386,235)
10 Ending Balance December 31, 2016 $84,855,575
11 INTANGIBLE
12 Beginning Balance January 1, 2016 $10,274,024
13 Various 298,788 Various Various 14 TOTAL MAJOR ADDITIONS $298,788
15 Various (2,063,278) Various Various 16 TOTAL MAJOR RETIREMENTS ($2,063,278)
17 Ending Balance December 31, 2016 $8,509,534
18 TOTAL ELECTIC PLANT IN SERVICE DECEMBER 31, 2016 $1,858,680,196
Page 59 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 12 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Test Year Ended December 31, 2017
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month 1 PRODUCTION
2 Beginning Balance January 1, 2017 $888,439,428
3 Various $3,474,323 Various Various 4 105673 Hoot Lake Plant - Ash Pond 3,740,821 12/15 7/17 5 105950 Coyote - Ash Pit Closure 656,666 2/17 12/17 6 TOTAL MAJOR ADDITIONS $7,871,810
7 Various ($1,469,479) Various Various 8 TOTAL MAJOR RETIREMENTS ($1,469,479)
9 Ending Balance December 31, 2017 $894,841,759
10 TRANSMISSION
11 Beginning Balance January 1, 2017 $410,612,188
12 Various (Mainly transfers between functions) $7,934,781 Various Various 13 104393 Big Stone South Substation to Brookings $53,224,771 8/10 9/17 14 104829 Big Stone Plant to Big Stone South Substation 2,241,161 4/12 9/17 15 105046 Big Stone South Substation 2,195,843 4/12 9/17 16 105047 Big Stone South Substation 14,606,091 4/12 9/17 17 105247 Buffalo Substation 345/114 kV Transformer 5,820,975 5/14 11/17 18 105866 Rugby 41.6kV Breaker 1,823,736 6/16 7/17 19 105869 Granville Junction Breaker 997,571 7/16 7/17
Page 60 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 13 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Test Year Ended December 31, 2017
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month
1 104999 Parshall Area 115 kV 986,563 5/13 8/17 2 105867 Cole Harbor - In-Line Breaker 550,441 8/16 7/17 3 105870 Drake - In-Line Breaker 539,512 6/16 7/17 4 129370 Bemidji - 115 kV Additions 729,243 5/16 7/17 5 TOTAL MAJOR ADDITIONS $91,650,688
6 Various ($1,336,419) Various Various 7 105115 MISO J262/J263 Retirements ($641,473) 12/13 8/17 8 TOTAL MAJOR RETIREMENTS ($1,977,892)
9 Ending Balance December 31, 2017 $500,284,984
10 DISTRIBUTION
11 Beginning Balance January 1, 2017 $466,263,471
12 Various $18,064,368 Various Various 13 6419 Addition & Retirement of Meters 1,368,244 On Going Various 14 TOTAL MAJOR ADDITIONS $19,432,612
15 Various ($2,306,837) Various Various 16 6419 Addition & Retirement of Meters (543,368) On Going Various 17 TOTAL MAJOR RETIREMENTS ($2,850,205)
18 Ending Balance December 31, 2017 $482,845,878
Page 61 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-4 Page 14 of 14
Otter Tail Power Company SUMMARY OF MAJOR ADDITIONS AND RETIREMENTS BY FUNCTION For the Test Year Ended December 31, 2017
(A) (B) (C) (D) (E) In-Service/ Line Work Construction Retirement No. Order Description Amount Start Date Month
1 GENERAL
2 Beginning Balance January 1, 2017 $84,855,575
3 Various $4,151,626 Various Various 4 105985 Broadband Communication Infrastructure 800,409 2/17 12 5 103836 Additions of Transportation and Power Operated Equipment 3,515,472 On Going Various 6 TOTAL MAJOR ADDITIONS $8,467,507
7 Various ($345,993) Various Various 8 6420 Addition & Retirement of Furniture & Office Equipment (1,375,153) On Going Various 9 Various Retirement of Transportation and Power Operated Equipment (1,440,939) On Going Various 10 TOTAL MAJOR RETIREMENTS ($3,162,085)
11 Ending Balance December 31, 2017 $90,160,997
12 INTANGIBLE
13 Beginning Balance January 1, 2017 $8,509,534
14 Various $1,894,497 Various Various 15 105343 GIS Related Software Costs 803,685 8/14 12 16 TOTAL MAJOR ADDITIONS $2,698,182
17 6420 Various $0 On Going Various 18 TOTAL MAJOR RETIREMENTS 0
19 Ending Balance December 31, 2017 $11,207,716
20 TOTAL ELECTIC PLANT IN SERVICE DECEMBER 31, 2017 $1,979,341,337
Page 62 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-5 Page 1 of 1
Otter Tail Power Company Policy of Capitalizing Interest For the period January 1, 2013 Through December 31, 2017
Line No. Policy Descripton
1 Allowance for Funds Used During Construction 2 3 AFUDC is calculated on a monthly basis by applying the monthly rate to the sum of the 4 balance of the project at the beginning of the month plus one-half of the current month's 5 charges. Capitalization ceases when the project is placed in service. All capital projects 6 are charged interest except the following: 7 8 A. Projects estimated to cost less than $10,000 9 B. Projects estimated to take less than 30 days to construct 10 C. Customer Service Center blanket distribution projects 11 D. Others as determined by the Fixed Assets Department 12 13 The allowance rate is based on the composite cost of capital as required under Federal 14 Energy Regulatory Commission Order 561. Capitalization ceases when the project is 15 placed in service. 16 17 18 Labor Related Loadings 19 20 Overhead costs (Payroll loading and Warehouse Clearing) related to construction 21 projects are capitalized in accordance with Electric Plant instruction of the FERC 22 Uniform System of Accounts 23 24 25 These methods and procedures have been in place for the last five calendar years.
Page 63 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-6 page 1 of 1
Otter Tail Power Company Changes in Intangible Plant For the period January 1, 2013 Through December 31, 2017
(A) (B) (C) (D) (E)
Beginning Ending Line of Period Period No. Year Balance Additions Retirements Balance
1 2013 $4,210,739 $3,479,918 $300,040 $7,390,617 2 2014 $7,390,617 $882,553 $0 $8,273,170 3 2015 $8,273,170 $2,000,854 $0 $10,274,024 4 2016 $10,274,024 $298,788 $2,063,278 $8,509,534 5 2017 $8,509,534 $2,698,183 $0 $11,207,717
Note: Refer to Schedule D-4 for a detailed listing of the additions and retirements for each respective year.
Page 64 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-7 page 1 of 1
Otter Tail Power Company Plant in Service Which is Not Used or Useful For the period January 1, 2016 Through December 31, 2017
Line No. (A)
1 All plant in service as of December 31, 2017 is used and useful.
Page 65 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-8 page 1 of 1
Otter Tail Power Company Property Records Working Papers For the Test Year Ended December 31, 2017
Line No. Policy Descripton
1 Power Plants: 2 Each power plant is unitized in accordance with the FERC rules and regulations. A record of 3 original cost, vintage and description is maintained for each utility plant location. When a 4 unit of property is retired, the original installed cost of the units is removed from the records 5 of the Company. Salvage value of the unit, if any, is booked at the actual salvage 6 value received. Units that are reusable and put into material and supplies inventory is 7 booked at the average unit price for that item. 8 9 Transmission Plant: 10 A record similar to power plant records is maintained for each transmission substation 11 by location. 12 13 A record for transmission lines 69kv and above are maintained by line. Transmission lines 14 under 69kv are maintained by State location. 15 16 When a unit is retired, it is handled in the same manner described above for power plants. 17 18 Distribution Plant: 19 A record similar to power plant records is maintained for each distribution substation 20 by location. 21 22 The units in the mass distribution accounts are maintained by State in the year installed. 23 When a unit is retired, the State location is determined by the retirement project and the 24 original installed cost is retired based on specific vintage indentification, if available, or 25 based in Iowa Curves through the fixed asset system. 26 27 General and Intangible Plant: 28 Each unit of general and intangible plant is separately identified and the records maintained 29 similar to the power plant records described above. 30 31 Retirements are specifically identified. Some accounts are amortized and the units 32 retired at the end of their average useful life. 33 34 Retirement Units: 35 The Company uses retirement units the conform to FERC guidelines.
Page 66 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule D-9 page 1 of 1
Otter Tail Power Company Plant Acquired for Which Regulatory Approval Has Not Been Obtained For the Test Year Ended December 31, 2017
Line No.
1 There are no operating units or systems that have been acquired without 2 regulatory approval.
Page 67 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement E TOTAL ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION Page 1 of 1 TOTAL COMPANY BY FUNCTION For the Twelve Months Ending December 31, 2017
(A) (B) (C ) (D) (E) (F) (G)
Total Function Accumulated Line Production Transmission Distribution General Intangible Depreciation No. Month Plant Plant Plant Plant Plant and Amortization
1 January 1, 2017 $345,982,651 $115,693,684 $203,148,538 $37,148,031 $4,955,040 $706,927,944 2 February 1, 2017 348,308,243 116,427,294 203,812,535 37,152,162 5,078,653 710,778,887 3 March 1, 2017 350,671,173 116,814,190 204,475,730 36,993,220 5,202,266 714,156,579 4 April 1, 2017 352,836,759 117,300,942 205,184,884 37,045,493 5,332,951 717,701,029 5 May 1, 2017 355,206,822 118,016,775 205,714,208 37,223,774 5,463,587 721,625,166 6 June 1, 2017 357,046,096 118,500,569 206,307,949 37,472,270 5,594,224 724,921,108 7 July 1, 2017 359,394,194 118,527,583 206,986,016 37,693,264 5,726,819 728,327,875 8 August 1, 2017 361,699,515 119,086,670 207,831,640 37,841,436 5,859,379 732,318,641 9 September 1, 2017 363,991,115 118,395,336 208,571,708 37,688,635 5,991,940 734,638,733 10 October 1, 2017 366,366,150 118,996,772 209,138,780 37,906,813 6,124,500 738,533,015 11 November 1, 2017 368,243,513 119,536,031 209,839,309 38,109,734 6,257,060 741,985,647 12 December 1, 2017 370,584,713 120,201,201 210,700,211 38,362,209 6,403,015 746,251,349 13 December 31, 2017 372,880,290 120,845,113 211,375,362 38,590,107 6,564,178 750,255,050
14 2017 Actual Year 13-Month Average $359,477,786 $118,334,012 $207,160,528 $37,632,858 $5,734,893 $728,340,079
15 Adjustments 7,069,556 2,595,564 4,569,181 2,640,970 3,380,763 20,256,034
16 2017 Test Year Average $366,547,342 $120,929,576 $211,729,709 $40,273,828 $9,115,656 $748,596,113
Page 68 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule E-1 TOTAL ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION Page 1 of 1 TOTAL COMPANY BY FUNCTION For the Twelve Months Ending December 31, 2017
(A) (B) (C ) (D) (E) (F) (G)
Total Function Accumulated Line Production Transmission Distribution General Intangible Depreciation No. Month Plant Plant Plant Plant Plant and Amortization
1 Beginning balance 01/01/17 $345,982,651 $115,693,684 $203,148,538 $37,148,031 $4,955,040 $706,927,944 2 3 Add: 2017 Depreciation & Amortization Expense 28,508,690 7,392,819 11,275,012 2,686,821 1,567,291 51,430,633 4 Add: Miscellaneous (18,307) 0 1,771,701 0 1,753,394 5 Less: Retirements (1,469,479) (1,977,892) (2,850,205) (3,162,085) 0 (9,459,661) 6 Add: Salvage 140,343 940,788 1,051,240 164,286 0 2,296,657 7 Less: Cost of Removal (240,068) (1,185,979) (1,249,223) (18,648) 0 (2,693,917) 8 9 Ending Balance - 12/31/17 $372,922,137 $120,845,113 $211,375,362 $38,590,107 $6,522,331 $750,255,049 10 11 2017 Actual Year 13-Month Average ((Statement E; Line 14) $359,477,786 $118,334,012 $207,160,528 $37,632,858 $5,734,893 $728,340,079 12 13 Adjustments 7,069,556 2,595,564 4,569,181 2,640,970 3,380,763 20,256,034 14 15 2017 Test Year Average $366,547,342 $120,929,576 $211,729,709 $40,273,828 $9,115,656 $748,596,113
Page 69 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule E-2 DEPRECIATION and AMORTIZATION METHODS Page 1 of 1 For the Test year Ended December 31, 2017
Line No. (A)
There have been no changes in depreciation methods or procedures since the period covered by the last annual report on 1 FERC Form 1 for 2017.
Page 70 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule E-3 ALLOCATION OF OVERALL ACCOUNTS Page 1 of 1 For the Test year Ended December 31, 2017
Line No. (A)
1 Each FERC account is assigned to only one functional group resulting in no allocation of overall accounts.
Page 71 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement F CASH WORKING CAPITAL - SOUTH DAKOTA Page 1 of 1 2017 Test Year
(A) (B) (C) (D) (E) (F) (G) (H)
EXCESS REVENUE LEAD DAYS OF Test Year EXPENSE 64.3 LINE OPERATING Operating PER DAY AT 365 EXPENSE OVER EXPENSE NET REVENUE NO. Description of Expense EXPENSE Adjustments Expense DAYS PER YEAR LAG DAYS LAG DAYS LAG DOLLARS
1 FUEL - COAL 5,147,885 15,205 5,163,090 $14,145 15.5 48.8 $690,157 2 3 FUEL - OIL 243,173 1,026 244,199 669 11.2 53.1 35,512 4 5 PURCHASED POWER 5,858,042 153,229 6,011,271 16,469 31.6 32.7 538,873 6 7 LABOR AND ASSOCIATED PAYROLL EXPENSE 505,375 7,679 513,054 1,406 15.1 49.2 69,143 8 9 ALL OTHER O&M EXPENSE 12,628,916 475,115 13,104,031 35,901 13.1 51.2 1,838,514 10 11 PROPERTY TAXES (EXCL COAL CONVERSION TAXES) 919,180 3,320 922,500 2,527 300.1 (235.8) (595,870) 12 13 COAL CONVERSION TAXES 46,593 168 46,761 128 33.3 31.0 3,969 14 15 FEDERAL INCOME TAXES (556,439) (464,907) (1,021,346) (2,798) 0.0 64.3 - 16 17 STATE INCOME TAXES 0 - 0.0 64.3 - 18 19 INCREMENTAL FEDERAL INCOME TAXES 0 - 0.0 64.3 - 20 21 INCREMENTAL STATE INCOME TAXES 0 - 0.0 64.3 - 22 23 BANK BALANCES 0 0 64.3 772 24 25 SPECIAL DEPOSITS 0 0 64.3 591 26 27 WORKING FUNDS 0 0 64.3 979 28 29 TAX COLLECTIONS AVAIL - FICA WITHHOLDING (447,782) (6,804) (454,586) (1,245) 0.0 64.3 - 30 31 TAX COLLECTIONS AVAIL - FEDERAL WITHHOLDING (787,646) (11,969) (799,615) (2,191) 0.0 64.3 - 32 33 TAX COLLECTIONS AVAIL - STATE WITHHOLDING- MN 0 - 0.0 64.3 - 34 35 TAX COLLECTIONS AVAIL - STATE WITHHOLDING- ND 0 - 0.0 64.3 - 36 37 TAX COLLECTIONS AVAILABLE - STATE SALES TAX (1,362,584) - (1,362,584) (3,733) 13.7 50.6 (50,994) 38 39 TAX COLLECTIONS AVAILABLE - FRANCHISE TAXES 0 - 23.9 40.4 - 40 41 42 TOTAL CASH WORKING CAPITAL REQUIREMENT - SOUTH DAKOTA $2,531,644
Page 72 of 164 Docket No. EL18-___ Volume 4A Section 2 Otter Tail Power Company Schedule F-1 MATERIALS, SUPPLIES, AND FUEL STOCKS Page 1 of 2 For the 12 Months Ended December 31, 2017
(A) (B) (C)
Materials Line Fuel Stocks and Supplies No. Month / Year (a/c 151) (a/c 154, 155, 163)
1 Dec-2016 $9,830,796 $18,853,894 2 Jan-2017 $8,728,791 $18,968,404 3 Feb-2017 $9,358,676 $19,233,093 4 Mar-2017 $9,004,182 $20,085,292 5 Apr-2017 $8,539,841 $20,257,805 6 May-2017 $9,643,851 $20,179,834 7 Jun-2017 $9,808,851 $20,056,558 8 Jul-2017 $8,706,633 $19,729,888 9 Aug-2017 $9,483,946 $19,771,051 10 Sep-2017 $8,346,703 $19,696,059 11 Oct-2017 $8,582,369 $19,715,539 12 Nov-2017 $9,237,012 $19,750,356 13 Dec-2017 $8,894,145 $19,260,064
Total $118,165,795 $255,557,837
13 Month Average $9,089,677 $19,658,295
Page 73 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule F-1 PREPAYMENTS Page 2 of 2 For the 12 Months Ended December 31, 2017
(A) (B) (C) (D) (E) (F)
Prepaid Post Retirement Post Total Line Month / Insurance and Benefits Other Employement FAS 87 Prepayments No. Year Interest Than Pension Benefits Pension Plan (a/c 165)
1 Dec-2016 $916,587 ($61,069,707) ($1,571,655) $39,344,588 ($22,380,187) 2 Jan-2017 2,289,259 (61,203,731) (1,577,301) 38,866,551 ($21,625,221) 3 Feb-2017 2,155,877 (61,469,926) (1,575,611) 38,866,551 ($22,023,109) 4 Mar-2017 1,800,434 (61,268,430) (1,518,099) 37,910,546 ($23,075,549) 5 Apr-2017 3,186,706 (61,336,287) (1,499,536) 37,432,532 ($22,216,586) 6 May-2017 2,940,258 (61,427,613) (1,481,249) 36,954,518 ($23,014,087) 7 Jun-2017 2,837,204 (61,426,245) (1,468,907) 36,476,504 ($23,581,445) 8 Jul-2017 2,517,786 (61,564,296) (1,429,838) 35,998,490 ($24,477,858) 9 Aug-2017 2,792,046 (61,816,955) (1,426,793) 35,520,476 ($24,931,226) 10 Sep-2017 2,414,120 (61,635,998) (1,416,406) 35,042,462 ($25,595,822) 11 Oct-2017 2,028,680 (61,815,778) (1,407,128) 34,564,448 ($26,629,778) 12 Nov-2017 1,609,191 (61,919,992) (1,389,794) 34,086,434 ($27,614,160) 13 Dec-2017 1,276,704 (68,099,753) (1,065,985) 33,598,853 ($34,290,181) Total $28,764,852 ($806,054,713) ($18,828,302) $474,662,952 ($321,455,211)
13 Month Average $2,212,681 ($62,004,209) ($1,448,331) $36,512,535 ($24,727,324)
Page 74 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule F-2 MATERIALS, SUPPLIES, AND FUEL STOCKS Page 1 of 4 For the Year Ended December 31, 2015
(A) (B) (C)
Materials Fuel Stocks and Supplies Line No. Month / Year (a/c 151) (a/c 154, 155, 163)
1 Dec-2014 $9,624,429 $18,423,124 2 Jan-2015 11,197,316 18,900,552 3 Feb-2015 10,335,570 19,082,200 4 Mar-2015 10,860,831 19,351,521 5 Apr-2015 10,202,250 19,770,255 6 May-2015 10,064,668 19,373,303 7 Jun-2015 10,474,543 19,753,683 8 Jul-2015 11,035,133 19,458,204 9 Aug-2015 10,924,729 19,471,318 10 Sep-2015 10,985,862 19,381,080 11 Oct-2015 10,786,374 19,233,861 12 Nov-2015 12,090,701 19,281,072 13 Dec-2015 12,309,141 19,177,509
Page 75 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule F-2 MATERIALS, SUPPLIES, AND FUEL STOCKS Page 2 of 4 For the Year Ended December 31, 2016
(A) (B) (C)
Materials Fuel Stocks and Supplies Line No. Month / Year (a/c 151) (a/c 154, 155, 163)
1 Dec-2015 $12,309,141 $19,177,509 2 Jan-2016 10,858,664 19,225,060 3 Feb-2016 10,843,922 19,102,574 4 Mar-2016 11,306,666 19,240,929 5 Apr-2016 10,844,635 19,039,347 6 May-2016 10,618,176 19,328,541 7 Jun-2016 9,988,177 19,312,564 8 Jul-2016 9,857,390 19,303,701 9 Aug-2016 9,306,726 19,739,701 10 Sep-2016 9,348,951 19,443,815 11 Oct-2016 9,859,652 19,104,300 12 Nov-2016 10,824,688 19,185,475 13 Dec-2016 9,830,796 18,853,894
Page 76 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule F-2 PREPAYMENTS Page 3 of 4 For the 12 Months Ended December 31, 2015
(A) (B) (C) (D) (E) (F)
Prepaid Post Retirement Post Line Insurance Benefits Other Employement Adjustment for Total No. Month / Year and Interest Than Pension Benefits FAS 87 Prepayments
1 Dec-2014 426,614 (52,337,332) (508,341) 32,798,117 (19,620,942)
2 Jan-2015 1,657,677 (52,588,244) (552,082) 42,221,834 (9,260,815)
3 Feb-2015 1,390,908 (52,683,468) (506,423) 41,531,917 (10,267,066)
4 Mar-2015 1,200,336 (52,772,937) (658,433) 40,898,817 (11,332,217)
5 Apr-2015 2,546,153 (53,025,899) (686,856) 40,260,517 (10,906,085)
6 May-2015 2,269,520 (53,140,735) (721,485) 39,626,117 (11,966,582)
7 Jun-2015 1,993,564 (53,006,823) (786,882) 38,868,861 (12,931,281)
8 Jul-2015 1,755,563 (53,007,945) (815,774) 38,213,985 (13,854,170)
9 Aug-2015 1,477,629 (53,180,194) (806,934) 37,559,109 (14,950,390)
10 Sep-2015 1,199,694 (53,130,915) (880,730) 36,904,233 (15,907,717)
11 Oct-2015 954,642 (53,109,879) (892,199) 36,249,357 (16,798,079)
12 Nov-2015 676,708 (53,362,975) (941,293) 35,594,481 (18,033,079)
13 Dec-2015 932,933 (47,512,183) (964,957) 34,939,605 (12,604,602)
Page 77 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule F-2 PREPAYMENTS Page 4 of 4 For the 12 Months Ended December 31, 2016
(A) (B) (C) (D) (E) (F)
Prepaid Post Retirement Post Line Insurance Benefits Other Employement Adjustment for Total No. Month / Year and Interest Than Pension Benefits FAS 87 Prepayments
1 Dec-2015 932,933 (47,512,183) (964,957) 34,939,605 (12,604,602)
2 Jan-2016 2,296,924 (47,537,707) (922,461) 44,503,048 (1,660,196)
3 Feb-2016 2,315,344 (47,642,663) (928,432) 44,066,492 (2,189,259)
4 Mar-2016 1,857,103 (47,673,509) (912,866) 43,629,935 (3,099,338)
5 Apr-2016 3,540,755 (47,828,720) (884,162) 43,193,378 (1,978,750)
6 May-2016 3,210,378 (47,827,922) (810,065) 42,756,821 (2,670,788)
7 Jun-2016 2,846,255 (48,387,370) (1,001,480) 42,320,264 (4,222,330)
8 Jul-2016 2,517,480 (48,448,061) (1,037,526) 41,679,189 (5,288,918)
9 Aug-2016 2,069,754 (48,684,959) (1,045,186) 42,148,785 (5,511,606)
10 Sep-2016 1,958,009 (48,421,430) (1,049,924) 42,615,036 (4,898,309)
11 Oct-2016 1,554,968 (48,522,536) (1,149,333) 40,277,091 (7,839,810)
12 Nov-2016 1,354,052 (48,614,891) (1,190,764) 39,810,839 (8,640,764)
13 Dec-2016 916,587 (61,069,707) (1,571,655) 39,344,588 (22,380,187)
Page 78 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule F-3 CASH WORKING CAPITAL - SOUTH DAKOTA Page 1 of 1 TEST YEAR ENDING DECEMBER 31, 2017
(A) (B) (C) (D) (E) (F) (G) (H)
EXCESS REVENUE LEAD DAYS OF Test Year EXPENSE 64.3 LINE OPERATING Operating PER DAY AT 365 EXPENSE OVER EXPENSE NET REVENUE NO. Description of Expense EXPENSE Adjustments Expense DAYS PER YEAR LAG DAYS LAG DAYS LAG DOLLARS
1 FUEL - COAL 5,147,885 15,205 5,163,090 14,145 16 48.8 690,157 2 3 FUEL - OIL 243,173 1,026 244,199 669 11 53.1 35,512 4 5 PURCHASED POWER 5,858,042 153,229 6,011,271 16,469 32 32.7 538,873 6 7 LABOR AND ASSOCIATED PAYROLL EXPENSE 505,375 7,679 513,054 1,406 15 49.2 69,143 8 9 ALL OTHER O&M EXPENSE 12,628,916 475,115 13,104,031 35,901 13 51.2 1,838,514 10 11 PROPERTY TAXES (EXCL COAL CONVERSION TAXES) 919,180 3,320 922,500 2,527 300 (235.8) (595,870) 12 13 COAL CONVERSION TAXES 46,593 168 46,761 128 33 31.0 3,969 14 15 FEDERAL INCOME TAXES (556,439) (464,907) (1,021,346) (2,798) 0 64.3 0 16 17 STATE INCOME TAXES 0 0 0 0 0 64.3 0 18 19 INCREMENTAL FEDERAL INCOME TAXES 0 0 0 0 0 64.3 0 20 21 INCREMENTAL STATE INCOME TAXES 0 0 0 0 0 64.3 0 22 23 BANK BALANCES 0 0 0 0 0 64.3 772 24 25 SPECIAL DEPOSITS 0 0 0 0 0 64.3 591 26 27 WORKING FUNDS 0 0 0 0 0 64.3 979 28 29 TAX COLLECTIONS AVAIL - FICA WITHHOLDING (447,782) (6,804) (454,586) (1,245) 0 64.3 0 30 31 TAX COLLECTIONS AVAIL - FEDERAL WITHHOLDING (787,646) (11,969) (799,615) (2,191) 0 64.3 0 32 33 TAX COLLECTIONS AVAIL - STATE WITHHOLDING- MN 0 0 0 0 0 64.3 0 34 35 TAX COLLECTIONS AVAIL - STATE WITHHOLDING- ND 0 0 0 0 0 64.3 0 36 37 TAX COLLECTIONS AVAILABLE - STATE SALES TAX (1,362,584) 0 (1,362,584) (3,733) 14 50.6 (50,994) 38 39 TAX COLLECTIONS AVAILABLE - FRANCHISE TAXES 0 0 0 0 24 40.4 - 40 41 42 TOTAL CASH WORKING CAPITAL REQUIREMENT - SOUTH DAKOTA $2,531,644
Page 79 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement G Cost of Capital Lead Sheet 2017 Test Year Page 1 of 5
(A) (B) (C) (D) (E)
Line Percent of No. Description Amount Total Cost Weighted Cost
1 Long Term Debt $496,615,385 46.90% 5.30% 2.49% 2 Common Equity 562,251,845 53.10% 10.30% 5.47% 3 Total Capitalization $1,058,867,229 100.00% 7.96%
Page 80 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement G Cost of Capital Page 2 of 5 As of December 31, 2017 EOM
(A) (B) (C ) (D) (E)
Line Percent of No. Description Amount Total Cost Weighted Cost
1 Short Term Debt $112,370,691 10.42% 2.79% 0.29% 2 Long Term Debt (1) $412,000,000 38.21% 5.86% 2.24% 3 Preferred Equity - 0.00% - 0.00% 4 Common Equity (2) 553,828,205 51.37% 10.00% 5.14% $1,078,198,896 100.00% 7.67%
(1) Statement G, Page 3.
(2) Common Equity: Common Stock $500 Contributed Capital 376,988,966 Accumulated Other Comprehensive Income/(Loss) (2,419,283) Retained Earnings Unappropriated 661,608 Retained Earnings 178,596,414 Common Equity $553,828,205
Page 81 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement G Cost of Capital Page 3 of 5 For the Year Ended December 31, 2017
(A) (B) (C ) (D) (E) (F) (G) (H) (I) (J) (K)
Line Amount Interest Net Proceeds Yield to Cost of Principal No. Title Issue Maturity Issued Rate Amount Per Unit Maturity Money Outstanding Annual Cost
Long Term Debt: 1 Senior Unsecured Notes - 2021 12/1/2011 12/1/2011 140,000,000 4.630% 139,108,146.00 $0.99 4.630% 4.660% $140,000,000 $6,482,000 2 Series B - 2017 Unsecured Senior Note 10/1/2007 7/1/2017 33,000,000 5.950% 32,584,453.00 $0.99 5.950% 6.026% $0 $1,254,458 3 Series B - 2022 Unsecured Senior Note 10/15/2007 8/20/2022 30,000,000 6.150% 29,613,012.00 $0.99 6.150% 6.230% 30,000,000 1,845,000 4 Series C - 2027 Unsecured Senior Note 8/20/2007 8/20/2027 42,000,000 6.370% 41,459,232.00 $0.99 6.370% 6.453% 42,000,000 2,675,400 5 Series A - 2029 Unsecured Senior Note 2/27/2014 2/27/2029 60,000,000 4.680% 59,804,186.00 $1.00 4.680% 4.695% 60,000,000 3,235,000 6 Series D - 2037 Unsecured Senior Note 8/20/2007 8/20/2037 50,000,000 6.470% 49,334,025.00 $0.99 6.470% 6.557% 50,000,000 2,808,000 7 Series B - 2044 Unsecured Senior Note 2/27/2014 2/27/2044 90,000,000 5.470% 89,705,832.00 $1.00 5.470% 5.488% 90,000,000 4,923,000
8 Loss/Gain on Required Debt (3,675,755) 705,079 9 Total Outstanding $408,324,245 $23,927,937
10 Weighted Average Cost of Debt 5.86%
Page 82 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement G Cost of Preferred Stock Page 4 of 5 For the Year Ended December 31, 2017
(A) (B) (C ) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (P) (Q)
Underwriter's Discount/Commission Issuance Expense Price to Public or Line Date of Call Price Dividend Par Value Public % of Gross Net Net Proceeds Cost of Amount Subscribed No. Description Issuance (If applicable) Convertible Rate of Issue per Share Amount % of Gross Proceeds Amount Proceeds Proceeds Per Unit Money Outstanding Issue
1 Otter Tail Power Company has no Cumulative Preferred Shares outstanding as of December 31, 2017. Otter Tail Corporation has no Cumulative Preferred Shares oustanding as of December 31, 2017.
Page 83 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement G Sale of Common Stock Page 5 of 5 For the Period of January 1, 2013 Through December 31, 2017
(A) (B) (C ) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M)
Offering Closing Mkt Price Dividend Price Per latest Trading Rate at Line Number of Gross Proceeds Underwriter's Proceeds to Issuance Per Share Book Value Date Prior to Date Earnings/Share at Date of Public or No. Title Shares Issued at Offering Price Discount (3) Otter Tail Corp Expense Net Proceeds (1) Per Share of Issuance (2) Date of Issuance Issuance Subscribed Issue
1 2014 At-The-Market Program 519,636 $15,336,351.65 $535,374.36 $14,800,977.29 $137,884.34 $14,663,092.95 $28.48 Varied $29.27 Varied $1.21 Public 2 2015 At-The-Market Program 133,197 $3,785,244.15 $56,484.67 $3,728,759.48 $241,428.28 $3,487,331.20 $27.99 Varied $30.96 Varied $1.23 Public 3 2016 At-The-Market Program 1,014,115 $33,235,081.37 $415,446.64 $32,819,634.73 $146,101.44 $32,673,533.29 $32.36 Varied $26.63 Varied $1.25 Public
Note: These shares were issued by Otter Tail Corporation under a Distribution Agreement with J.P. Morgan Securites under which Otter Tail Corporation may offer and sell its common shares from time to time in an At-the-Market offering program through J.P. Morgan Securities as its distribution agent, up to an aggregate sales price of $75 million.
Otter Tail Power Company did not sell or issue any additional stock during this period. 100 shares of stock have been issued by Otter Tail Power Company and are held by Otter Tail Corporation as the parent company of Otter Tail Power Company.
Page 84 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule G-1 Stock Dividends, Stock Splits, or Changes in Par or Stated Value Page 1 of 1 For the Period January 1, 2013 through December 31, 2017
(A) (B) (C) (D)
Line No. Year Total Stock Dividends Stock Splits Changes in Par Value 1 2013 None None None 2 2014 None None None 3 2015 None None None 4 2016 None None None 5 2017 None None None
Page 85 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule G-2 Common Stock Information Page 1 of 1 For the Periods 2013-2017
Average Dividends OTC Market OTC OTC Line Shares Earnings Per Dividends Per as a % of Price at End of Price/Earnings Dividend No. Year Outstanding Average Share Share Earnings Year Ratio Yield
1 2012 (1) 36,047,984 ($0.17) $1.19 -700% $25.00 -147.1 4.8% 2 2013 36,151,364 $1.39 $1.19 86% $29.27 21.1 4.1% 3 2014 36,514,397 $1.58 $1.21 77% $30.96 19.6 3.9% 4 2015 37,494,986 $1.58 $1.23 78% $26.63 16.9 4.6% 5 2016 38,546,459 $1.62 $1.25 77% $40.80 25.2 3.1% 6 2017 39,457,261 $1.84 $1.28 70% $44.45 24.2 2.9%
7 2012 (2) 100 $384,729.76 $344,147.08 89% na na na 8 2013 100 $382,363.56 $345,053.67 90% na na na 9 2014 100 $436,841.12 $354,082.68 81% na na na 10 2015 100 $483,704.54 $369,507.17 76% na na na 11 2016 100 $498,288.36 $385,528.98 77% na na na 12 2017 100 $494,465.41 $404,564.12 82% na na na
13 Jan-17 (3) 39,296,735 $0.15 $37.85 14 Feb-17 39,353,787 $0.16 $37.60 15 Mar-17 39,401,884 $0.19 $37.90 16 Apr-17 39,442,187 $0.15 $39.50 17 May-17 39,457,344 $0.14 $39.95 18 Jun-17 39,489,064 $0.13 $39.60 19 Jul-17 39,507,155 $0.15 $40.45 20 Aug-17 39,507,793 $0.16 $41.80 21 Sep-17 39,507,796 $0.14 $43.35 22 Oct-17 39,507,796 $0.16 $45.95 23 Nov-17 39,507,796 $0.18 $48.30 24 Dec-17 39,507,796 $0.12 $44.45
25 Jan-17 (4) 100 $59,995.17 NA 26 Feb-17 100 $49,989.02 NA 27 Mar-17 100 $45,608.89 NA 28 Apr-17 100 $33,710.40 NA 29 May-17 100 $36,283.72 NA 30 Jun-17 100 $31,352.84 NA 31 Jul-17 100 $47,370.16 NA 32 Aug-17 100 $39,863.01 NA 33 Sep-17 100 $21,460.30 NA 34 Oct-17 100 $31,461.23 NA 35 Nov-17 100 $56,296.92 NA 36 Dec-17 100 $41,073.75 NA
Page 86 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule G-3 Reaquisition of Bonds or Preferred Stock Page 1 of 1 For the 18 Month Period Prior to Filing February 1, 2017 through July 31, 2018
(A) (B) (C ) (D) (E)
Principal Amounts or Incr/Dec Line Par Value Gain or Loss on Income Taxes due to Gain or No. Title or Series Reaquired Reacquisition Cost Reacquisition Loss (1)
1 Series A 5.95% Senior Unsecured Notes $33,000,000 none none na Notes retired by Otter Tail Power Company on August 21, 2017 at maturity. Notes had been issued on August 20, 2007.
2 Term Loan $12,000,000 none none na Payments made by Otter Tail Corporation on Term Loan during June and August 2017. Loan was paid off in August 2017. Term loan was entered into February 5, 2016.
Page 87 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule G-4 Earnings Per Share for Claimed Rate of Return Page 1 of 1 For the Year Ended December 31, 2017
(A) (B)
Line No. Description Amount
1 Common Equity, Statement G, Lead Sheet $562,251,845
2 Return-Percentage 10.00%
3 Return-Amount $56,225,184
4 Average Common Shares Outstanding 2017 - OTC 39,457,261 (1)
5 Contribution to Earnings Per Share from Otter Tail Power Company $1.42
(1) Average Common Shares outstanding before and after holding company reorganziation for Otter Tail Corporation. Otter Tail Power Company has 100 common shares outstanding which are owned by OtterTail Corporation, parent of Otter Tail Power Company.
Page 88 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement H OPERATING AND MAINTENANCE EXPENSES Page 1 of 2 For the Test Year Ended December 31, 2017
(A) (B) (C) (D) (E) (F) (G)
(1) (1) Actual Year Actual Test Year Line FERC JCOSS Year Test Year Adjusted No. Account Description Per Books Adjustments Per JCOSS Adjustments Total 1 Steam Production Operation: 2 500 Supervision & Engineering $1,651,107 $1,651,107 $1,651,107 3 501 Fuel (Handling and Ash Removal) 58,605,849 58,605,849 58,605,849 4 501.1 Steam Power Fuel - Gas 0 0 0 5 501.2 Steam Power Fuel - Oil 0 0 0 6 501.3 Steam Power Fuel - Coal 0 0 0 7 501.4 Steam Power Fuel - Transportation 0 0 0 8 502 Steam Expense 5,817,946 5,817,946 5,817,946 9 505 Electric Expense 2,441,793 2,441,793 2,441,793 10 506 Miscellaneous 5,061,938 5,061,938 5,061,938 11 507 Rent 1,147 1,147 1,147 12 509 Allowances 15,509 15,509 15,509 13 Total Steam Production Operation $73,595,289 $0 $73,595,289 $0 $73,595,289 14 15 Steam Production Maintenance: 16 510 Supervision & Engineering $842,512 $842,512 $842,512 17 511 Structures 1,202,457 1,202,457 1,202,457 18 512 Boilers 7,207,999 7,207,999 7,207,999 19 513 Electric Plant 797,052 797,052 797,052 20 514 Miscellaneous Plant 1,063,183 1,063,183 1,063,183 21 Total Steam Production Maintenance $11,113,203 $0 $11,113,203 $0 $11,113,203 22 23 Total Steam Production Expense $84,708,492 $0 $84,708,492 $0 $84,708,492 24 25 Hydro Production Operation 26 535 Supervision and Engineering $13,178 $13,178 $13,178 27 538 Electric Expense 31,708 31,708 31,708 28 539 Miscellaneous Expense 22,132 22,132 22,132 29 540 Rents 107 107 107 30 Total Steam Production Operation $67,125 $0 $67,125 $0 $67,125 31 32 Hydro Production Mainentance 33 541 Supervision and Engineering $3,449 $3,449 $3,449 34 542 Structures 5,016 5,016 5,016 35 543 Reservoirs - Dams 277,357 277,357 277,357 36 544 Electric 50,242 50,242 50,242 37 545 Miscellaneous Expense 0 0 0 38 Total Hydro Production Maintenance $336,064 $0 $336,064 $0 $336,064 39 40 Total Hydro Production $403,189 $0 $403,189 $0 $403,189 41 42 Other Production Operation: 43 546 Supervision & Engineering $132,618 $132,618 $132,618 44 546 W Supervision & Engineering - Wind $132,412 132,412 132,412 45 547 Fuel 1,484,624 1,484,624 1,484,624 46 548 Generation Expense 356,444 356,444 356,444 47 548 W Generation Expense - Wind 1,900,757 1,900,757 1,900,757 48 549 Miscellaneous 534,452 534,452 1,791,331 2,325,783 49 549 W Miscellaneous - Wind 33,491 33,491 33,491 50 550 Rents 0 0 0 51 550 W Rents - Wind 593,392 593,392 593,392 52 Total Other Production Operation $5,168,190 $0 $5,168,190 $1,791,331 $6,959,521 53 54 Other Production Maintenance: 55 551 Supervision & Engineering $85,285 $85,285 $85,285 56 551 W Supervision & Engineering - Wind $0 0 0 57 552 Structures 124,923 124,923 124,923 58 553 Generating & Electric 656,222 656,222 656,222 59 553 W Generating & Electric - Wind 12,986 12,986 12,986 60 554 Miscellaneous Plant 26,008 26,008 26,008 61 554 W Miscellaneous Plant - Wind 6,338 6,338 6,338 62 556 System Control and Dispatch 590,724 590,724 590,724 63 557 Other Expenses 50,392 50,392 50,392 64 Total Other Production Maintenance $1,552,878 $0 $1,552,878 $0 $1,552,878 65 66 Total Other Production Expense $6,721,068 $0 $6,721,068 $1,791,331 $8,512,399 67 68 Other Power Supply 69 555.1 Purchased Power - Capacity $0 $0 $0 70 555.2 Purchased Power - Energy 0 0 0 71 Total Other Power Supply $0 $0 $0 $0 $0 72 73 Total Production Expense $91,832,749 $0 $91,832,748 $1,791,331 $93,624,079 74 75 Transmission Operations: 76 560 Supervision & Engineering $419,482 $419,482 $419,482 77 561 Load Dispatch 4,347,331 4,347,331 4,347,331 78 562 Station Equipment 297,518 297,518 297,518 79 563 Overhead Lines 368,841 368,841 368,841 80 565 Transmission of Electricity by Others 20,807,504 20,807,504 20,807,504 81 566 Miscellaneous 619,124 619,124 76,249 695,373 82 567 Rents 30,063 30,063 30,063 83 Total Transmission Operations $26,889,863 $0 $26,889,863 $76,249 $26,966,112 84 85 Transmission Maintenance: 86 568 Supervision & Engineering $207,223 $207,223 $207,223 87 569 Structures 876,627 876,627 876,627 88 570 Station Equipment 1,219,312 1,219,312 1,219,312 89 571 Overhead Lines 1,936,497 1,936,497 1,936,497 90 572 Underground Lines 14 14 14 91 573 Miscellaneous 0 0 0 92 575 Day-Ahead & Real-Time and Transmission Market Expense 793,225 793,225 793,225 93 576 Computer Software 212,635 212,635 212,635 94 Total Transmission Maintenance $5,245,533 $0 $5,245,533 $0 $5,245,533 95 Total Transmission Expense $32,135,396 $0 $32,135,395 $76,249 $32,211,643
(1) Adjustments are made at the Functional level and not at the FERC Account level therefore adjustment amounts are shown in total by function.
Page 89 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement H OPERATING AND MAINTENANCE EXPENSES Page 2 of 2 For the Test Year Ended December 31, 2017
(A) (B) (C) (D) (E) (F) (G)
(1) (1) Actual Year Actual Test Year Line FERC JCOSS Year Test Year Adjusted No. Account Description Per Books Adjustments Per JCOSS Adjustments Total 96 97 Distribution Operations: 98 580 Supervision $279,039 $279,039 $279,039 99 581 Load Dispatch 206,826 206,826 206,826 100 582 Station Equipment 282,504 282,504 282,504 101 583 Overhead Lines 582,917 582,917 582,917 102 584 Underground Lines 1,943,453 1,943,453 1,943,453 103 585 Street Lighting 0 0 0 104 586 Metering 650,182 650,182 650,182 105 587 Customer Installations 198,812 198,812 198,812 106 588 Miscellaneous 3,661,715 3,661,715 141,866 3,803,581 107 589 Rents 228,349 228,349 228,349 108 Total Distribution Operations $8,033,797 $0 $8,033,797 $141,866 $8,175,663 109 110 Distribution Maintenances: 111 590 Supervision $1,022,254 $1,022,254 $1,022,254 112 591 Structures 0 0 0 113 592 Station Equipment 730,319 730,319 730,319 114 593 Overhead Lines 4,884,253 4,884,253 4,884,253 115 594 Underground Lines 1,016,563 1,016,563 1,016,563 116 595 Transformers 93,253 93,253 93,253 117 596 Street Lighting 1,047,827 1,047,827 1,047,827 118 597 Metering 800,588 800,588 800,588 119 598 Miscellaneous 132,993 132,993 132,993 120 Total Distribution Maintenance $9,728,050 $0 $9,728,050 $0 $19,456,100 121 122 Total Distribution Expenses $17,761,845 $0 $17,761,843 $141,866 $17,903,709 123 124 Customer Accounting Expense: 125 901 Supervision $85,144 $85,144 $85,144 126 902 Meter Reading 5,977,246 5,977,246 5,977,246 127 903 Customer Records and Collection Expense 5,579,253 5,579,253 5,579,253 128 904 Uncollectible Accounts 750,000 750,000 750,000 129 905 Miscellaneous 520,483 520,483 94,918 615,401 130 Total Customer Accounting Expense $12,912,126 $0 $12,912,126 $94,918 $13,007,044 131 132 Customer Service Expense: 133 907 Supervision $603,596 $603,596 $603,596 134 908 Customer Assistance 1,247,276 1,247,276 1,247,276 135 908 Conservation Investment Program - SD 463,357 463,357 463,357 136 908 Convervation Investment Program - MN 6,607,891 6,607,891 6,607,891 137 909 Advertisement 414,652 414,652 414,652 138 910 Miscellaneous 21,515 21,515 18,339 39,854 139 Total Customer Service Expense $9,358,286 $0 $9,358,286 $18,339 $9,376,625 140 141 Total Customer Expenses $22,270,412 $0 $22,270,412 $113,257 $22,383,669 142 143 Sales Expenses 144 911 Supervisory Labor & Expenses $106,971 $106,971 $106,971 145 912 Minnesota Economic Development $155,664 155,664 155,664 146 912 North Dakota Economic Development 48,050 48,050 48,050 147 912 South Dakota Economic Development 9,908 9,908 9,908 148 912 Expenses - Sales & Demonstrations 15,520 (1,305) 14,215 14,215 149 913 Advertising 1,305 1,305 1,305 150 916 Miscellaneous Sales Expense 1,569 1,569 1,569 151 152 Total Sales Expense $338,987 ($1,305) $337,682 $0 $337,682 153 154 Administrative & General Expense: 155 920 Administrative Salaries $23,839,398 ($887,093) $22,952,305 $22,952,305 156 921 Office Supplies & Expense 7,875,336 7,875,336 7,875,336 157 922 A&G Expense Transferred (2,103,759) (2,103,759) (2,103,759) 158 923 Outside Services 1,164,187 1,164,187 1,164,187 159 924 Property Insurance 1,062,607 1,062,607 1,062,607 160 924 W Property Insurance - Wind 541,417 541,417 541,417 161 925 Injuries and Damages 2,209,606 2,209,606 559,500 2,769,106 162 926 Pensions & Benefits 3,066,245 3,066,245 3,066,245 163 928 Regulatory Commission 3,043,415 3,043,415 183,333 3,226,748 164 930 Miscellaneous General 2,381,297 (369,628) 2,011,669 319,662 2,331,331 165 931 Rents 281,269 281,269 281,269 166 935 Maintenance of General Plant 1,505,332 1,505,332 1,505,332 167 168 Total Administrative & General Expense $44,866,350 ($1,256,721) $43,609,629 $1,062,495 $44,672,124 169 170 Charitable Contributions $0 $0 $0 $0 $0 171 Total Operating & Maintenance Expense $209,205,739 ($1,258,026) $207,947,713 $3,185,198 $211,132,906
(1) Adjustments are made at the Functional level and not at the FERC Account level therefore adjustment amounts are shown in total by function.
Page 90 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule H-1 Operating and Maintenance Expenses Page 1 of 1 2017 Actual Year
(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) Production Purchased Power Customer Service & Misc Generation Customer & Informational Administrative & 1 Steam Hydro Other Production Expenses Transmission Distribution Accounts Services Sales General Total 2 Jan-17 Labor 1,144,601 9,433 137,328 569,226 877,998 641,619 90,598 17,903 1,693,586 5,182,291 3 Other 1,423,142 1,482 287,503 13,579,162 3,062,261 520,825 455,350 508,049 6,610 1,989,751 21,834,136 4 5 Feb-17 Labor 1,215,764 10,745 162,166 699,427 1,120,844 879,845 123,247 32,292 1,581,096 5,825,424 6 Other 848,844 6,081 333,697 10,484,675 926,534 (38,858) 407,409 653,944 6,833 2,133,761 15,762,920 7 8 Mar-17 Labor 1,151,935 10,327 136,726 618,214 927,490 716,198 95,735 25,782 2,093,999 5,776,406 9 Other 1,248,870 1,330 225,485 11,505,829 2,527,004 281,679 418,828 713,162 6,511 2,135,245 19,063,942 10 11 Apr-17 Labor 1,144,687 13,350 168,887 638,957 1,294,317 706,259 119,799 22,448 1,824,518 5,933,222 12 Other 1,133,579 190 421,579 8,631,702 2,287,575 901,176 391,047 574,842 1,391 1,822,690 16,165,771 13 14 May-17 Labor 1,191,571 15,983 136,185 647,442 1,121,981 680,872 112,544 23,992 1,907,700 5,838,269 15 Other 966,659 6,838 302,615 10,598,968 1,778,139 495,914 403,962 505,156 1,965 1,493,110 16,553,324 16 17 Jun-17 Labor 1,126,904 33,502 145,359 627,581 1,166,076 661,537 98,901 27,184 1,357,186 5,244,229 18 Other 1,005,306 6,287 264,824 9,622,961 2,037,121 323,957 386,962 432,021 3,111 2,617,681 16,700,232 19 20 Jul-17 Labor 1,050,762 23,955 122,993 572,955 1,014,135 582,247 90,515 24,835 1,621,804 5,104,200 21 Other 944,438 19,186 335,499 9,455,310 1,948,434 357,779 399,280 534,417 3,244 1,903,655 15,901,242 22 23 Aug-17 Labor 1,098,420 27,680 145,471 629,174 1,097,649 658,905 118,263 28,236 1,569,813 5,373,612 24 Other 1,238,305 4,534 285,985 10,238,904 2,021,398 491,531 403,600 907,794 4,174 1,971,034 17,567,258 25 26 Sep-17 Labor 1,036,688 33,247 156,262 589,446 1,092,818 639,594 109,059 19,864 1,366,315 5,043,293 27 Other 917,550 34,470 431,461 9,772,103 1,890,842 462,539 448,428 597,151 3,270 2,151,541 16,709,356 28 29 Oct-17 Labor 1,142,469 25,492 140,185 561,281 1,062,259 644,303 104,531 22,496 2,109,505 5,812,520 30 Other 1,187,933 17,772 319,556 8,286,400 2,175,587 428,027 393,090 584,557 3,967 3,034,053 16,430,941 31 32 Nov-17 Labor 1,041,958 41,999 (212,140) 627,230 1,055,563 680,416 125,366 27,486 1,343,478 4,731,357 33 Other 1,057,057 4,777 315,433 10,590,405 1,810,933 318,759 409,981 631,517 2,401 1,854,781 16,996,046 34 35 Dec-17 Labor 1,099,854 26,000 94,294 593,796 1,086,177 697,725 102,465 23,016 1,677,514 5,400,840 36 Other 1,085,086 28,771 379,094 11,731,290 2,294,838 301,211 204,411 1,424,655 263 1,612,509 19,062,128 37 38 Sub total Labor 13,445,614 271,712 1,333,714 0 7,374,728 12,917,306 8,189,519 1,291,023 295,535 20,146,513 65,265,663 39 Other 13,056,768 131,717 3,902,731 124,497,710 24,760,666 4,844,539 4,722,348 8,067,265 43,740 24,719,812 208,747,296 40 26,502,382 403,429 5,236,445 124,497,710 32,135,395 17,761,845 12,911,867 9,358,287 339,275 44,866,325 274,012,959 41 Adjustments (1) Labor - 42 Other $0 $0 $1,791,331 $1,446,006 $76,249 $141,866 $94,918 $18,339 ($1,305) ($194,226) $3,373,178 43 Total Labor 13,445,614 271,712 1,333,714 0 7,374,728 12,917,306 8,189,519 1,291,023 295,535 20,146,513 65,265,663 44 Total Other 13,056,769 131,717 5,694,062 125,943,716 24,836,915 4,986,405 4,817,266 8,085,604 42,435 24,525,586 212,120,474 45 Grand Total 26,502,383 403,429 7,027,776 125,943,716 32,211,644 17,903,711 13,006,785 9,376,626 337,970 44,672,099 277,386,137
(1) Adjustments are explained in more detail in the testimony and supporting work papers included in the initial filing documents.
Page 91 of 164 Docket No. EL18-___ Volume 4A Section 2
Schedule H-2 Otter Tail Power Company Purchased Power Page 1 of 1 For the Test Year Ended December 31, 2017
(A) (B) (C) (D) (E) (F) Line Demand Energy Other Total No. Purchased From Mwh Charges Charges Charges Costs
1 Great River Energy * $1,000,000 $1,000,000 2 Great River Energy * $1,650,250 $1,650,250 3 Minnesota Municipal Power Agency * ($67,500) ($67,500) 4 Minnesota Power * $266,000 $266,000 5 Northern States Power Company 203,200 $3,489,738 $3,489,738 6 Western Area Power Administration (799) ($18,485) ($18,485) 7 Western Area Power Administration - WEC 29,870 $858,273 $858,273 8 Beltrami Electric Cooperative 110,805 $1,102,159 $5,107,986 ** $59,706 $6,269,851 9 Nodak Rural Electric Cooperative 8,253 $87,899 $476,683 $564,582 10 P K M Electric Cooperative 8,580 $108,380 $495,403 $603,782 11 Red Lake Rural Electric Cooperative 8,395 $107,254 $454,925 $562,180 12 Cass County Electric Cooperative $5,789 $5,789 13 Whetstone Valley Electric Cooperative $1,017 $1,017 14 Prairie Lakes Municipal Waste $10,560 $10,560 15 Dakota Magic Casino $29,520 $29,520 16 Kindred School $28,800 $28,800 17 Stevens Community Medical $23,760 $23,760 18 City of Detroit Lakes 939 $1,193 $1,408 $2,601 19 American Crystal Sugar 2,357 $23,571 $23,571 20 Dakota Wind Exchange 17 $574 $574 21 Hendricks Wind I 2,353 $86,845 $86,845 22 Borderline Wind 2,024 $60,716 $60,716 23 Univ. of MN - Morris 4,591 $252,513 $252,513 24 FPL Energy ND II, LLC 53,133 $1,588,678 $1,588,678 25 Langdon Wind, LLC 82,210 $3,224,259 $3,224,259 26 Turtle Mountain Community College 357 $11,856 $11,856 27 LacQui Parle School 28 $932 $932 28 Pembina Border Station 1,344 $44,731 $44,731 29 Lake Region State College 4,247 $134,433 $134,433 30 Ashtabula Wind III LLC 226,978 $6,423,990 $6,423,990 31 Ashtabula Wind III LLC - Curtailment 2,688 $75,949 $75,949 32 MN Co Generation 188 $18,096 $18,096 33 ND Co Generation 80 $1,070 $1,070 34 SD Co Generation 42 $1,497 $1,497 35 Nebraska Public Power District RLA ($2,874) ($2,874) 36 37 Midwest ISO Energy Market 1,606,827 $38,353,238 $38,353,238 38 Southwest Power Pool ISO Energy Market 14,032 ($775,052) ($775,052) 39 Non-Asset Based Cost of Sales $1,477 $1,477 40 41 Total 2,372,739 $4,355,080 $60,392,432 $59,706 $64,807,218
* Great River Energy - Demand Charges are short-term service for January through May 2017 * Great River Energy - Demand Charges are short-term service for June through December 2017 * Minnesota Municipal Power Agency - Demand Charges are short-term service for January through May 2017 * Minnesota Power - Demand Charges are short-term service for June through December 2017
** Nomination charge
Page 92 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule H-3 Otter Tail Power Company Listed Expense Accounts Page 1 of 1 For the Year Ended December 31, 2017
(A) (B) (C) Line Total System No. Description of Accounts for Listed Expenses Amount Allocation to South Dakota
1 Federal Energy Regulatory Commission Account No. 909 2 3 Description Allocators Allocator % SD 4 Conservation $235,843 C1 8.740052% $20,613 5 Financial Services 141 C1 8.740052% 12 6 Information & Instructional 70,014 C1 8.740052% 6,119 7 Safety 108,654 C1 8.740052% 9,496 8 Total Account No. 909 $414,652 $36,241 9 10 Federal Energy Regulatory Commission Account No. 913 11 None 12 13 Federal Energy Regulatory Commission Account No. 930.1 - Advertising Expenses 14 15 Description Allocators Allocator % SD 16 Financial and Informational $35,506 C1 8.740052% $3,103 17 Total Account No. 930 Advertising Expenses $35,506 $3,103 18 19 Federal Energy Regulatory Commission Account No. 909, 913, & 930 Advertising Expenses (1) $450,158 $39,344 20 21 22 Federal Energy Regulatory Commission Account No. 922 23 None 24 25 Federal Energy Regulatory Commission Account No. 926 (2) 26 27 Description Allocators Allocator % SD 28 Community & Public Relations $0 29 Design & Administer Hiring Policies & Procedures 115,953 30 Develop & Administer Employee Benefits 2,785,668 31 Employee Recognition Programs 113,307 32 Employee Relations 20,610 33 Human Resources Development 30,707 34 Total Account No. 926 $3,066,245 35 36 Admin & General - Production; 35.48% Allocation $1,087,965 OXPD 9.343471% $101,654 37 Admin & General - Transmission; 14.77% Allocation 452,946 D2 9.187431% 41,614 38 Admin & General - Distribution; 27.62% Allocation 846,958 OXD 9.490373% 80,379 39 Admin & General - Customer Accounting; 18.53% Allocation 568,237 OXC 8.866368% 50,382 40 Admin & General - Customer Service; 3.49% Allocation 110,140 C1 8.740052% 9,626 41 $3,066,245 $283,655 42 43 44 Federal Energy Regulatory Commission Account No. 928 45 46 Description Allocators Allocator % SD 47 Minnesota $1,633,062 0% $0 48 North Dakota 383,814 Directly 0% 0 49 South Dakota 246,934 Assigned 100% 246,934 50 FERC 962,938 0% 0 51 Federal Assessment 0 0% 0 52 Total Account No. 928 $3,226,749 $246,934 53 54 Federal Energy Regulatory Commission Account No. 929 55 None 56 57 Federal Energy Regulatory Commission Account No. 930 Misc. General Expenses 58 59 Description Allocators Allocator % SD 60 Provide Public Information & Instruction $6,682 P90 9.224266% $616 61 Provide Public Information & Instruction-Labor 8,059 P90 9.224266% 743 62 Community & Public Relations 53,837 P90 9.224266% 4,966 63 Community & Public Relations - Labor 73,495 P90 9.224266% 6,779 64 Conduct Strategic Planning 81,562 P90 9.224266% 7,524 65 Conduct Strategic Planning - Labor 311,751 P90 9.224266% 28,757 66 Research & Development 30,734 P90 9.224266% 2,835 67 Research & Development-Labor 0 P90 9.224266% 0 68 Investor Relations 209,765 P90 9.224266% 19,349 69 Investor Relations - Labor 142,640 P90 9.224266% 13,158 70 Shareholder Services 5,056 P90 9.224266% 466 71 Shareholder Services-Labor 206 P90 9.224266% 19 72 Director Fees & Expenses 802,852 P90 9.224266% 74,057 73 Design Marketing Programs for more Efficient Electricity Use 0 P90 9.224266% 0 74 Industry Association Dues 247,427 P90 9.224266% 22,823 75 Industry Association Dues - Labor 2,385 P90 9.224266% 220 76 Total Account No. 930 $1,976,452 $182,313
(1) Above-the-line amounts only.
(2) FERC Account No.926 is allocated to Admin & General; Salaries, Supplies, Pensions & Benefits by function based on current year labor ratios. The five functional categories include Production, Transmission, Distribution, Customer Accounts, and Customer Service & Information as shown above. Once the costs have been functionalized they are allocated to South Dakota based on their respective allocators. Page 93 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Informational Advertising
INFORMATIONAL ADVERTISING
Page 94 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Informational Advertising
Radio/streaming ad ePay PILOT: We’re at 3,500 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.
Page 95 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Informational Advertising
Radio/streaming ad ePay SFX: Nature ambient to give the sense of an isolated countryside. V.O.: When it comes to security, folks around here say, FOLK: "Ah, nobody's around," V.O.: but thieves say, THIEF: "Ha, nobody's around." V.O.: A check in the mail is exposed and accessible all day long. Digital payments are secure, fast and easy. Try ePay from Otter Tail Power Company. It's free and available online from wherever you are - even if it’s the middle of nowhere. Visit otpco.com/epay.
Page 96 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Informational Advertising
Print ad
Page 97 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Conservation Advertising
CONSERVATION ADVERTISING
Page 98 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Conservation Advertising
Radio/streaming ad Conservation One small habit can save more than money: Unplug it. Turn it down. Turn it off. Electronic devices and chargers draw small amounts of power even when they’re off, so unplug them when not in use. Because one small habit can make a real difference in saving money and energy. Otter Tail Power Company.
Page 99 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Conservation Advertising
Radio/streaming ad CoolSavings – Winter ANNC: It’s cool outside now, but be ready when summer heats up. CoolSavings from Otter Tail Power Company cycles your air conditioner on and off for fifteen minutes 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.
Page 100 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Conservation Advertising
Radio/streaming ad Air source heat pump Audio: Beeping for a truck backing up. SON: Is that an air conditioner?
FATHER: That is an air-source heat pump. It’s an air conditioner and a heater. And because it’s over 100% efficient, it’s going to save us a lot of money.
SON: How does it work?
FATHER: Air goes in and this liquid gets compressed, changing the temperature…
SON: Doesn’t it work by putting it on the house?
FATHER: (laughs) Yeah, it just works.
ANNC: For more information, go to otpco.com/heatpumps.
Page 101 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Conservation Advertising
Television ad
Air source heat pump Scene: A father and son are watching delivery drivers unload a heat pump in a large box or crate.
SON: Is that an air conditioner?
FATHER: That is an air-source heat pump. It’s an air conditioner and a heater. And because it’s over 100% efficient, it’s going to save us a lot of money.
SON: How does it work?
FATHER: Air goes in and this liquid gets compressed, changing the temperature…
SON: Doesn’t it work by putting it on the house?
FATHER: (laughs) Yeah, it just works.
Video: Otter Tail Power Company logo and web address otpco.com/heatpumpswork.
Page 102 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Conservation Advertising
Print ad
Page 103 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Conservation Advertising
Print ad
Page 104 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Safety Advertising
SAFETY ADVERTISING
Page 105 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Safety Advertising
Radio/streaming ad Spring storm prep SFX: Rain and thunder in the background. VO: Storms can cause unpredictable electrical outages. Have a plan and be prepared. Otter Tail Power Company reminds you to assemble a storm kit today. Include:
• A flashlight, radio, and extra batteries. • Drinking water, non-perishable food, and bathroom items. • A first aid kit with essential medicines. • Blankets and sleeping gear.
Staying safe starts with a plan. For more information, visit otpco.com. Otter Tail Power Company
Page 106 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Safety Advertising
Radio/streaming ad Winter storm readiness 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.
Page 107 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Safety Advertising
Radio/streaming ad Harvest safety 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.
Plan ahead for a safe harvest season.
Otter Tail Power Company.
Page 108 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Load Factor Advertising
LOAD FACTOR ADVERTISING
Page 109 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Load Factor Advertising
Radio/streaming ad Water heating SFX: Shower turning on | Shower runs
MAN: (happily sighing) Mmmm
V.O.: When do you think about your electric water heater?
SFX: Toilet flushes
MAN: (shrieking) AHHH!
SFX: Shower continues | Light, happy music bed plays alongside running water
V.O.: Is THAT when you think about it? Otter Tail Power Company’s commitment is to help you make the best choice among more options than ever, giving you the hot water supply you need and helping you save with rebates and off-peak rates. It will make shower time less
MAN: (shrieking) AHHH!
V.O.: And more MAN: Mmm
V.O.: Visit otpco.com/electricwaterheating. Otter Tail Power Company.
Page 110 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Load Factor Advertising
Radio/streaming ad Thermal storage SFX: The hum of a pickup engine and ambient in-car sound plays throughout SFX: Light country music plays as if it’s on the radio in the cab SFX: A metal thermos unscrews GUY: To save a few bucks every day, I bring a thermos of coffee to work. To save far more than that, I heat my home with underfloor heat storage. When we built, I worked with my contractor to install the system. I got an up-front rebate - $1500 bucks - and Otter Tail Power Company’s lowest, stable rate. The system’s cleaner, quieter, and more efficient than others. If you’re building, do what I did. Start at otpco.com/HeatStorage. SFX: The engine shuts off and the music stops SFX: Pickup door opens GUY: Alright. Time to get to it.
Page 111 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Promotional Advertising
PROMOTIONAL ADVERTISING
Page 112 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Promotional Advertising
Radio/streaming ad Reasons I don’t watch my energy use just because it’s good for the environment or just because state rebates save me money or just because I work for a power company. I do it because my commitment is to her. To teach her how to save, to do good work and above all else, to leave a place a little better than you found it. She’s my reason. That’s why I’m proud to work at Otter Tail Power Company.
Page 113 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Promotional Advertising
Television ad
Reasons I don’t watch my energy use just because it’s good for the environment or just because state rebates save me money or just because I work for a power company. I do it because my commitment is to her. To teach her how to save, to do good work and above all else, to leave a place a little better than you found it. She’s my reason. That’s why I’m proud to work at Otter Tail Power Company.
Page 114 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Promotional Advertising
Print ad
Page 115 of 164 Docket No. EL18-___ Volume 1 Section 2 Schedule H-3 Promotional Advertising
Print ad
Page 116 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule H-4 INTERCOMPANY TRANSACTIONS - CORPORATE COSTS Page 1 of 2 For the Test Year Ended December 31, 2017
(A) (B) (C) (D) (E) Amounts Charged to Line FERC OTP from Corporate Allocation Allocation South Dakota No. Acct. # Description (OTC) Factor Percentage Amount
1 912 Demonstrating and Selling Expenses 2 Various Support Groups from OTC 7,351 C1 8.740052% $642 3 4 920 Administrative and General Salaries 5 Various Support Groups from OTC 5,294,364 $489,822 6 Production @ 35.63% 1,886,382 OXPD 9.344498% 176,273 7 Transmission @ 14.81% 784,095 D2 9.187431% 72,038 8 Distribution @ 27.56% 1,459,127 OXD 9.490373% 138,477 9 Customer Accounts @ 18.44% 976,281 OXC 8.866368% 86,561 10 Customer Service & Info @ 3.56% 188,479 C1 8.740052% 16,473 11 12 921 Office Supplies and Expenses 13 Various Support Groups from OTC 2,396,010 $221,673 14 Production @ 35.63% 853,698 OXPD 9.344498% 79,774 15 Transmission @ 14.81% 354,849 D2 9.187431% 32,602 16 Distribution @ 27.56% 660,340 OXD 9.490373% 62,669 17 Customer Accounts @ 18.44% 441,824 OXC 8.866368% 39,174 18 Customer Service & Info @ 3.56% 85,298 C1 8.740052% 7,455 19 20 923 Outside Services Employed 21 Audit, Legal, Consultants, Etc. 889,456 NEPIS 7.873620% $70,032 22 23 924 Property Insurance 24 OTC Insurance Expense 91,661 NEPIS 7.873620% $7,217 25 26 925 Injuries and Damages 27 OTC Insurance Expense 164,110 NEPIS 7.873620% $12,921 28 29 930.1 General Advertising Expenses $9,163 C1 8.740052% $801 30 31 930.2 Miscellaneous General Expenses 1,154,710 P90 9.224266% $106,513 32 33 931 Rents 92,173 P90 9.224266% $8,502 34 35 935 Maintenance of General Plant 177,695 P90 9.224266% $16,391 36 37 TOTAL $10,276,692 $934,515 38 39 Less: Disallowed Incentive Costs (1) 40 Production @ 35.63% $ (287,929) OXPD 9.344498% $ (26,906) 41 Transmission @ 14.81% $ (119,695) D2 9.187431% $ (10,997) 42 Distribution @ 27.56% $ (222,698) OXD 9.490373% $ (21,135) 43 Customer Accounts @ 18.44% $ (149,001) OXC 8.866368% $ (13,211) 44 Customer Service & Info @ 3.56% $ (28,788) C1 8.740052% $ (2,516) 45 Total Dissallowed Incentive Costs $ (808,111) $ (74,764) 46 47 TOTAL $ 9,468,581 $ 859,751 48 (1) Volume 4A, Section B, workpaper B-16
Note: The expenses are a combination of direct charges to OTP and an allocation of costs. All costs are pushed down to OTP at the cost incurred by Otter Tail Corporation without any additional fees. The allocation method used is described in the Corporate Allocation Manual (Exhibit__(SDT-1), Schedule 4 discussed in the Direct Testimony of Mr. Stuart Tommerdahl.
Page 117 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule H-4 INTERCOMPANY TRANSACTIONS Page 2 of 2 For the Test Year Ended December 31, 2017
(A) (B) (C)
Line FERC No. Acct. # Description 2017
1 417 Revenues from nonutility operations $667,131 2 3 417.1 Expenses of nonutility operations 431,062
4 417 Net $236,069
Page 118 of 164 Docket No. EL18-___ Volume 4A Section 2 OTTER TAIL POWER COMPANY Statement I Electric Utility - State of South Dakota Page 1 of 16 OPERATING REVENUES BY REVENUE CLASS 2009 TEST YEAR
Revenue per Retail sales kWh Sales COSS Base Revenue Residential 99,451,813 $9,175,901 $6,164,530 Farms 7,768,791 $669,522 $430,815 General Service 73,031,189 $6,378,987 $4,139,061 Large General Service 211,799,024 $11,967,979 $6,484,885 Irrigation 213,807 $20,270 $14,107 Outdoor Lighting 4,287,770 $593,033 $470,527 OPA 3,987,113 $263,510 $140,786 Controlled Service Water Heating 5,035,904 $341,830 $209,783 Controlled Service Interruptible 21,396,210 $898,267 $353,269 Controlled Service Deferred 7,587,362 $340,716 $148,874 Subtotal Retail 434,558,983 $30,650,015 $18,556,637 Rider Revenue Rolling into Base $2,619,535 Total Current SD Retail Revenue $33,269,550
Minnesota Retail 2,614,227,434 $194,447,181 North Dakota Retail 1,805,283,075 $145,663,342 Subtotal Retail 4,854,069,492 $373,380,073
Sales for Resale 203,412,607 $5,173,104 Total Sales of Electricity 5,057,482,099 $378,553,177 Other Electric Operating Revenue $53,213,582 Total Electric Revenues $431,766,758
Page 119 of 164 Docket No. EL18-___ Volume 4A Section 2 OTTER TAIL POWER COMPANY Statement I Electric Utility - State of South Dakota Page 2 of 2 OPERATING REVENUES BY REVENUE CLASS 2007 TEST YEAR
Otter Tail Power Company 2017 Actual Year Base Revenue by Revenue Class South Dakota Jurisdiction
Class of Service
Total Unbilled Total Base Total Bill Adj Total Present Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Revenue Weather Revenue Revenue Base Revenue Revenues Residential $ 676,584 $ 673,983 $ 548,554 $ 517,365 $ 416,642 $ 413,113 $ 441,206 $ 460,624 $ 426,358 $ 382,479 $ 482,828 $ 525,898 $ 81,093 $ 116,427 1377.28 $ 6,164,530 Farm $ 49,324 $ 43,253 $ 34,501 $ 34,221 $ 26,208 $ 27,865 $ 25,350 $ 26,699 $ 26,972 $ 21,697 $ 52,715 $ 55,497 $ (1,144) $ 7,578 77.17 $ 430,815 General Service $ 417,438 $ 370,330 $ 351,553 $ 347,268 $ 289,374 $ 300,404 $ 303,180 $ 306,696 $ 314,947 $ 299,032 $ 391,663 $ 408,135 $ 1,792 $ 34,128 3119.56 $ 4,139,061 Large General Service $ 552,467 $ 533,871 $ 501,429 $ 512,707 $ 492,852 $ 537,875 $ 547,552 $ 587,176 $ 580,080 $ 525,832 $ 536,519 $ 524,924 $ 18,801 $ 32,799 0 $ 6,484,885 Irrigation $ 825 $ 1,483 $ 3,778 $ 3,358 $ 2,751 $ (454) $ 820 $ 1,545 0 $ 14,107 Lighting $ 39,382 $ 41,608 $ 39,237 $ 39,400 $ 39,180 $ 39,412 $ 39,105 $ 39,086 $ 39,211 $ 38,888 $ 38,764 $ 38,341 $ 301 $ (1,148) -239.35 $ 470,527 OPA $ 14,552 $ 12,371 $ 12,825 $ 12,861 $ 12,166 $ 11,178 $ 10,623 $ 10,423 $ 10,682 $ 9,241 $ 11,154 $ 11,816 $ 409 $ 485 0 $ 140,786 Water Heating $ 20,502 $ 19,775 $ 19,710 $ 20,643 $ 19,474 $ 17,559 $ 15,939 $ 14,937 $ 15,332 $ 15,905 $ 18,069 $ 17,897 $ 128 $ (6,117) 29.81 $ 209,783 Controlled - Interruptible $ 51,145 $ 52,579 $ 40,449 $ 34,862 $ 22,407 $ 14,738 $ 13,899 $ 12,652 $ 12,670 $ 15,421 $ 29,451 $ 38,228 $ 5,085 $ 9,703 -18.61 $ 353,269 Controlled - Deferred $ 23,798 $ 24,750 $ 19,246 $ 15,024 $ 6,528 $ 4,685 $ 4,102 $ 4,148 $ 4,904 $ 5,802 $ 9,546 $ 17,233 $ 2,404 $ 6,725 $ (21) $ 148,874
$ 18,556,637
Otter Tail Power Company 2017 Actual Year KWH by Revenue Class South Dakota Jurisdiction
Class of Service
Total Unbilled Total Base Total Bill Adj Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec kWh Weather kWh kWh Total kWh kWh Residential 11,583,731 11,569,644 9,007,768 8,323,416 6,239,884 6,379,156 6,997,939 7,376,043 6,656,090 5,546,407 7,608,720 8,578,433 718,908 2,839,977 25,697 99,451,813 Farm 918,250 794,859 617,878 610,430 448,297 505,959 452,925 481,388 487,861 355,263 991,370 1,048,921 (15,271) 69,146 1,515 7,768,791 General Service 7,387,416 6,501,307 6,083,921 5,919,844 4,756,782 5,342,702 5,455,902 5,610,995 5,732,340 4,960,909 6,916,605 7,228,343 (9,842) 1,075,354 68,611 73,031,189 Large General Service 18,437,082 17,809,342 16,472,369 16,903,513 16,128,391 17,195,562 17,483,317 18,866,116 18,609,985 17,247,059 18,037,533 17,365,388 648,264 595,103 - 211,799,024 Irrigation - - - - 1,033 17,437 82,183 70,661 52,620 (30,260) 747 - 0 19,386 - 213,807 Lighting 355,350 416,805 353,374 356,716 350,795 359,492 353,018 352,267 355,335 347,614 344,319 342,963 (278) 3,068 (3,068) 4,287,770 OPA 407,992 344,598 357,334 358,269 338,075 323,645 306,583 300,366 308,584 251,134 307,982 327,728 11,999 43,362 (538) 3,987,113 Water Heating 481,247 460,752 457,490 487,205 450,315 439,493 384,360 347,887 362,038 339,049 406,244 406,226 2,481 10,468 649 5,035,904 Controlled - Interruptible 3,533,692 3,581,166 2,623,363 2,162,250 1,166,703 707,786 621,770 500,638 502,547 603,168 1,788,205 2,460,422 376,955 768,209 (664) 21,396,210 Controlled - Deferred 1,304,269 1,395,112 1,031,128 775,385 274,390 183,135 127,514 134,528 178,196 212,951 502,093 928,755 102,614 437,845 (553) 7,587,362
434,558,983
Page 120 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I Page 3 of 16
Comparison of Operating Revenues Under Present and Proposed Base Rates by Rate Schedule
Line Average Annual Operating Revenues Increase Rate Schedule No. Customers kWh Sales Present Proposed Amount Percent Change
1 9.01 Residential Service (Rate 101) 8,536 90,354,410 $ 5,752,686 $ 7,370,258 $ 1,617,572 28.12% 2 9.02 Residential Demand Control (Rate 241) 404 9,097,403 $ 411,843 $ 620,276 $ 208,433 50.61% 3 Total Residential: 99,451,813 $ 6,164,530 $ 7,990,534 $ 1,826,004 29.62% 4 5 9.03 Farm Service (Rate 361) 374 $ 430,815 $ 558,024 $ 127,209 29.53% 6 Total Farm: 7,768,791 $ 430,815 $ 558,024 $ 127,209 29.53% 7 8 10.01 Small General Service - Under 20 kW - Metered Service Secondary (Rate 404) 1,831 18,547,041 $ 1,255,516 $ 1,456,077 $ 200,561 15.97% 9 10.01 Small General Service - Under 20 kW - Metered Service Primary (Rate 405) 1 10,585 $ 694 $ 810 $ 116 10 10.02 General Service - 20 kW or Greater - Secondary Service (Rate 401) 501 52,050,080 $ 2,685,965 $ 3,348,377 $ 662,412 32.50% 11 10.02 General Service - 20 kW or Greater - Primary Service (Rate 403) 4 2,424,702 $ 196,886 $ 471,353 $ 274,467 12 10.03 General Service - Time of Use (Commercial TOU) - (Rates 708, 709, 710) - - $ - $ - -$ 0.00% 13 Total General Service: 73,031,189 $ 4,139,061 $ 5,276,616 $ 1,137,555 27.48% 14 15 10.04 Large General Service - Secondary Service (Rate 603) with RTP Rider (Rate 664) 58 187,352,818 $ 5,673,452 $ 7,954,801 $ 2,281,350 16 10.04 Large General Service - Primary Service (Rate 602) 3 4,117,978 $ 155,923 $ 228,295 $ 72,372 40.38% 17 10.04 Large General Service - Transmission Service (Rate 632) - - $ - $ - -$ 18 10.05 Large General Service Time of Day - Secondary Service (Rates 611, 615, 613) 2 2,278,431 $ 75,529 $ 103,435 $ 27,906 19 10.05 Large General Service Time of Day - Primary Service (Rates 610, 614, 612) - - $ - $ - -$ 36.95% 20 10.05 Large General Service Time of Day - Transmission Service (Rates 639, 637, 640) - - $ - $ - -$ 21 14.02 Real Time Pricing - Secondary Service (Rate 664) 1 18,049,797 $ 579,982 $ 579,982 -$ 0.00% 22 Total Large General Service: 211,799,024 6,484,885 8,866,513 $ 2,381,628 36.73% 23 24 11.02 Irrigation Service - Option 1: Non-Time-of-Use (Rate 703) 5 174,196 $ 10,156 $ 13,657 $ 3,501 34.47% 25 11.02 Irrigation Service - Option 2 (Rates 704, 705, 706) 4 39,611 $ 3,951 $ 5,518 $ 1,567 39.67% 26 Total Irrigation: 213,807 $ 14,107 $ 19,175 $ 5,068 35.92% 27 28 11.03 Outdoor Lighting - Metered - Energy Only (Rate 748) 39 $ 9,241 $ 10,040 $ 799 8.65% 29 11.03 Outdoor Lighting - Non-Metered - Energy Only (Rate 749) 17,842 $ 24,172 $ 26,667 $ 2,495 10.32% 30 11.04 Outdoor Lighting - Street & Area Lighting (Rate 741) 4,165 $ 361,272 $ 455,167 $ 93,895 25.99% 31 11.04 Outdoor Lighting - Flood Lighting (Rate 743) 384 $ 75,841 $ 97,259 $ 21,418 28.24% 32 Total Lighting: 4,287,770 $ 470,527 $ 589,134 $ 118,607 25.21% 33 34 11.05 Municipal Pumping - Secondary Service (Rate 872) 116 3,987,113 $ 140,786 $ 205,126 $ 64,340 45.71% 35 11.06 Civil Defense - Fire Sirens (Rate 843) 21 $ 1,047 $ 1,537 $ 490 36 Total Other Public Authority: 3,987,113 $ 140,786 $ 206,664 $ 65,878 46.79% 37 38 14.01 Water Heating - Controlled Service (Rate 191) 2,124 5,035,904 $ 209,783 $ 278,149 $ 68,366 32.59% 39 Total Water Heating: 5,035,904 $ 209,783 $ 278,149 $ 68,366 32.59% 40 41 14.04 Controlled Service - Interruptible Load Rider CT Metering (Rates 170, 165, 881, 168, 268, 169, 269) 29 6,367,328 $ 67,154 $ 111,280 $ 44,126 50.85% 42 14.05 Controlled Service - Interruptible Load Rider Self-Contained Metering (Rates 190, 185, 882) 12 15,028,882 $ 286,115 $ 421,642 $ 135,527 43 Total Interruptible: 21,396,210 353,269 532,922 $ 179,653 50.85% 44 45 14.06 Controlled Service - Deferred Load Rider (Rates 197, 195, 883) 193 5,137,331 $ 125,583 $ 170,135 $ 44,552 46 14.07 Fixed Time of Service Rider - Self-Contained Metering (Rates 301, 884) 86 1,613,313 $ 15,530 $ 31,522 $ 15,991 45.77% 47 14.07 Fixed Time of Service Rider - CT Metering (Rates 302, 885) 14 836,718 $ 7,760 $ 15,360 $ 7,600 48 Total Deferred Load: 7,587,362 148,874 217,017 $ 68,143 45.77% 49 50 TOTAL REVENUE: 434,558,983 $ 18,556,637 $ 24,534,747 $ 5,978,110 32.22% 51
Page 121 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 4 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual
1 9.01 Residential Service (Rate 101) 2 Customer Charge Bills 102,432 $8.00 $8.00 $ 15.23 $ 15.23 $ 819,456 $ 1,560,039 $ 740,583 3 Seasonal Fixed Charge Bills 132 $32.00 $32.00 $60.92 $ 60.92 $ 4,224 $ 8,041 $ 3,817 4 Energy Tier 1 kWh 14,226,125 28,853,127 43,079,252 $0.05599 $0.05819 $0.07786 $0.05886 $ 2,475,484 $ 5,819,151 $ 890,145 5 Energy Tier 2 kWh 12,143,310 35,131,848 47,275,158 $0.04987 $0.05260 N/A N/A $ 2,453,522 $ - $ - 6 Total Base Revenue: $ 5,752,686 $ 7,387,231 $ 1,634,545 7 Water Heating Control Credit 14.01 (Rate 192) Bills 1,507 -$4.00 -$4.00 -$8.00 -$8.00 $ (6,028) $ (12,056) $ (6,028) 8 Air Conditioning Control Rider 14.08 (Rate 760) Bills 846 -$7.00 -$7.00 -$8.25 -$8.25 $ (5,922) $ (6,979) $ (1,057) 9 TailWinds Program 14.09 kWh 537 $3.84 $3.84 $3.84 $3.84 $ 2,062 $ 2,062 $ - 10 Total Credits: $ (9,888) $ (16,973) $ (7,085) 11 12 9.02 Residential Demand Control (Rate 241) 13 Customer Charge Bills 4,843 $13.00 $13.00 $20.10 $20.10 $ 62,959 $ 97,344 $ 34,385 14 Facilities Charge Bills 4,843 $0.00 $0.00 $0.00 $0.00 $ - $ - $ - 15 Energy - All kWh kWh 1,811,676 7,285,728 9,097,403 $0.02022 $0.02399 $0.04707 $0.03607 $ 211,416 $ 348,037 $ 136,621 16 All kW kW 6,989 14,873 21,862 $7.05 $5.93 $8.00 $8.00 $ 137,468 $ 174,895 $ 37,427 17 Total Base Revenue: $ 411,843 $ 620,276 $ 208,433 18 19 Adjustments for Riders included in Base Rates 20 Transmission Cost Recovery Rider kWh $ 80,984 $ - 21 Environmental Cost Recovery Rider kWh $ 533,941 $ - 22 Riders staying outside of the Base Rate 23 EEP Cost Recovery Rider kWh 99,451,813 $ 103,420 $ 103,420 24 Transmission Cost Recovery Rider kWh 99,451,813 $ 528,196 $ 528,196 25 Environmental Cost Recovery Rider kWh 99,451,813 $ (6,604) $ (6,604) 26 COE kWh 99,451,813 $ 2,386,358 $ 2,386,358 27 Totals: $ 3,011,371 $ 3,011,371 $ - 28 29 Total Base Revenue for the COSS Class: $ 6,164,530 $ 7,990,534 $ 1,842,978 30 Total Adjustments for the COSS Class: $ 3,011,371 $ 3,011,371 $ - 31 Total for the COSS Class: $ 9,175,901 $ 11,001,905 $ 1,826,004 19.90% 32
Page 122 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 5 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 33 9.03 Farm Service (Rate 361) 34 Customer Charge Bills 4,490 $9.00 $9.00 $17.31 $17.31 $ 40,410 $ 77,740 $ 37,330 35 Energy - First 1600 kWh kWh 1,277,902 2,841,726 4,119,628 $0.04918 $0.05119 $0.06657 $0.05481 $ 208,315 $ 448,590 $ 64,563 36 Energy - Excess kWh kWh 659,971 2,989,192 3,649,163 $0.04630 $0.04856 $ 175,712 $ - $ - 37 Single Phase Facilities Charge Bills 3,852 $0.00 $0.00 $6.00 $6.00 $ - $ 23,112 $ 19,924 38 Three Phase Facilities Charge Bills 638 $5.00 $5.00 $10.00 $10.00 $ 3,190 $ 6,380 $ 3,190 39 Fixed Facilities Charges $ $ 3,188 $ 3,188 $ - 40 Total Base Revenue: $ 430,815 $ 559,010 $ 128,195 41 Water Heating Control Credit 14.01 (Rate 192) Bills 48 -$4.00 -$4.00 -$8.00 -$8.00 $ (192) $ (384) $ (192) 42 Air Conditioning Control Rider 14.08 (Rate 760) Bills 73 -$7.00 -$7.00 -$8.25 -$8.25 $ (511) $ (602) $ (91) 43 Total Credits: $ (703) $ (986) $ (283) 44 Total Base Revenue: $ 430,112 $ 558,024 $ 127,912 45 46 Adjustments for Riders included in Base Rates 47 Transmission Cost Recovery Rider kWh $ 6,533 $ - 48 Environmental Cost Recovery Rider kWh $ 42,545 $ - 49 Riders staying outside of the Base Rate 50 EEP Cost Recovery Rider kWh 7,768,791 $ 8,404 $ 8,404 51 Transmission Cost Recovery Rider kWh 7,768,791 $ 42,607 $ 42,607 52 Environmental Cost Recovery Rider kWh 7,768,791 $ (526) $ (526) 53 COE kWh 7,768,791 $ 188,223 $ 188,223 54 Totals: $ 238,707 $ 238,707 $ - 55 Requested % Change in Rates 56 Total Base Revenue for the COSS Class: $ 430,815 $ 558,024 $ 127,209 29.53% 57 Total Adjustments for the COSS Class: $ 238,707 $ 238,707 $ 0 58 Total for the COSS Class: $ 669,522 $ 796,731 $ 127,209 19.00% 59 60 10.01 Small General Service - Under 20 kW - Metered Service Secondary (Rate 404) 61 Customer Charge Bills 21,967 $13.00 $13.00 $20.00 $20.00 $ 287,547 $ 439,340 $ 151,793 62 Energy First 2000 kWh 5,908,565 12,638,476 18,547,041 $0.05235 $0.05445 $0.07023 $0.04751 $ 788,919 $ 1,015,457 $ 405,587 63 Excess Energy kWh - - $0.04476 $0.04685 $ 179,050 $ - $ - 64 Total Base Revenue: $ 1,255,516 $ 1,454,797 $ 199,281 65 Water Heating Control Credit 14.01 (Rate 192) Bills 105 -$4.00 -$4.00 -$8.00 -$8.00 $ (420) $ (840) $ (420) 66 TailWinds Program 14.09 kWh 552 $3.84 $3.84 $3.84 $3.84 $ 2,120 $ 2,120 $ - 67 Total Credits: $ 1,700 $ 1,280 $ (420) 68 Total Base Revenue: $ 1,257,215 $ 1,456,077 $ 198,861 69 70 10.01 Small General Service - Under 20 kW - Metered Service Primary (Rate 405) 71 Customer Charge Bills 12 $13.00 $13.00 $20.00 $20.00 $ 156 $ 240 $ 84 72 Energy First 2000 kWh 3,970 6,615 10,585 $0.04980 $0.05137 $0.06768 $0.04552 $ 538 $ 570 $ 32 73 Excess Energy kWh - - $0.04224 $0.04381 $ - 74 Total Base Revenue: $ 694 $ 810 $ 116 75
Page 123 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 6 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 76 10.02 General Service - 20 kW or Greater - Secondary Service (Rate 401) 77 Customer Charge Bills 6,016 $12.00 $12.00 $25.00 $25.00 $ 72,192 $ 150,400 $ 78,208 78 Energy kWh 15,420,167 36,629,913 52,050,080 $0.04083 $0.04631 $0.03575 $0.03544 $ 2,325,880 $ 1,849,239 $ (476,641) 79 Demand per kW kW 81,819 184,386 266,205 $1.22 $1.02 $3.60 $2.18 $ 287,893 $ 696,581 $ 408,687 80 Facilities Charge kW 399,308 $0.00 $0.00 $1.00 $1.00 $ - $ 401,240 $ 401,240 81 Low Load Factor <15%, Demand Charge kW 70,880 $3.54 $3.54 $ - $ 250,917 $ 250,917 82 Total Base Revenue: $ 2,685,965 $ 3,348,377 $ 662,412 83 84 10.02 General Service - 20 kW or Greater - Primary Service (Rate 403) 85 Customer Charge Bills 48 $12.00 $12.00 $20.00 $20.00 $ 576 $ 960 $ 384 86 Energy kWh 961,490 1,463,212 2,424,702 $0.03880 $0.04374 $0.03458 $0.03409 $ 101,307 $ 83,129 $ (18,178) 87 Demand per kW kW 31,511 59,934 91,445 $1.17 $0.97 $3.46 $2.08 $ 95,004 $ 233,350 $ 138,346 88 Facilities Charge kW 100,589 $0.00 $0.00 $0.67 $0.67 $ - $ 67,721 $ 67,721 89 Low Load Factor <15%, Demand Charge kW 24,348 $3.54 $3.54 $ 86,193 $ 86,193 90 Total Base Revenue: $ 196,886 $ 471,353 $ 274,467 91 92 10.03 General Service - Time of Use (Commercial TOU) - (Rates 708, 709, 710) 93 Customer Charge Bills $19.00 $19.00 $200.00 $200.00 $ - $ - $ - 94 Energy - Declared-Peak kWh $0.17792 $0.19084 $0.28829 $0.30322 $ - $ - $ - 95 Energy - Intermediate kWh $0.05117 $0.04436 $0.03434 $0.03403 $ - $ - $ - 96 Energy - Off-Peak kWh $0.00918 $0.02659 $0.02295 $0.02416 $ - $ - $ - 97 Demand per kW - Declared-Peak kW N/A N/A N/A N/A $ - $ - $ - 98 Demand per kW - Intermediate kW $2.81 $1.45 $4.67 $2.84 $ - $ - $ - 99 Demand per kW - Off-Peak kW $0.00 $0.00 $0.00 $0.00 $ - $ - $ - 100 Facilities Charge kW $0.60 $0.60 $1.00 $1.00 $ - $ - $ - 101 Low Load Factor <15%, Demand Charge kW $3.54 $3.54 $ - $ - $ - 102 Total Base Revenue: $ - $ - $ - 103 104 Adjustments for Riders included in Base Rates 105 Transmission Cost Recovery Rider kWh $ 61,071 $ - 106 Environmental Cost Recovery Rider kWh $ 399,058 $ - 107 Riders staying outside of the Base Rate 108 EEP Cost Recovery Rider kWh 73,032,408 $ 78,354 $ 78,354 109 Transmission Cost Recovery Rider kWh 73,032,408 $ 398,321 $ 398,321 110 Environmental Cost Recovery Rider kWh 73,032,408 $ (4,935) $ (4,935) 111 COE kWh 73,032,408 $ 1,768,187 $ 1,768,187 112 Totals: $ 2,239,926 $ 2,239,926 $ - 113 114 Total Base Revenue for the COSS Class: $ 4,139,061 $ 5,276,616 $ 1,137,555 115 Total Adjustments for the COSS Class: $ 2,239,926 $ 2,239,926 $ - 116 Total for the COSS Class: $ 6,378,988 $ 7,516,542 $ 1,137,554 17.83% 117
Page 124 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 7 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 118 10.04 Large General Service - Secondary Service (Rate 603) 119 Customer Charge Bills 699 $50.00 $50.00 $215.90 $215.90 $ 34,950 $ 150,914 $ 115,964 120 Energy kWh 63,266,665 124,086,153 187,352,818 $0.01696 $0.02046 $0.02462 $0.02440 $ 3,611,805 $ 4,585,260 $ (944,881.89) 121 Demand per kW kW 114,730 233,683 348,413 $7.29 $4.63 $12.30 $6.64 $ 1,918,337 $ 2,962,839 $ 1,044,502 122 Facilities Charge <1,000 kW kW 46,018 92,358 138,377 $0.33 $0.33 $0.77 $0.77 $ 45,664 $ 106,835 $ 61,170 123 Facilities Charge >=1,000 kW kW 86,443 174,789 261,231 $0.24 $0.24 $0.57 $0.57 $ 62,696 $ 148,789 $ 86,093 124 Total Base Revenue: $ 5,673,452 $ 7,954,637 $ 2,281,185 125 Water Heating Control Credit 14.01 (Rate 192) Bills 37 -$4.00 -$4.00 -$8.00 -$8.00 $ (148) $ (296) $ (148) 126 TailWinds Program 14.09 kWh 120 $3.84 $3.84 $3.84 $3.84 $ 461 $ 461 $ - 127 Total Credits: $ 313 $ 165 $ (148) 128 Total Base Revenue: $ 5,673,764 $ 7,954,801 $ 2,281,037 129 130 10.04 Large General Service - Primary Service (Rate 602) 131 Customer Charge Bills 36 $50.00 $50.00 $282.00 $282.00 $ 1,800 $ 10,152 $ 8,352 132 Energy - All kWh kWh 1,332,410 2,785,568 4,117,978 $0.01566 $0.01882 $0.02291 $0.02258 $ 73,290 $ 93,426 $ 20,136 133 Demand per kW kW 4,883 10,094 14,977 $7.00 $4.40 $10.58 $6.34 $ 78,593 $ 115,656 $ 37,063 134 Facilities Charge - All kW kW 6,059 12,604 18,663 $0.12 $0.12 $0.49 $0.49 $ 2,240 $ 9,061 $ 6,821 135 Total Base Revenue: $ 155,923 $ 228,295 $ 72,372 136 137 14.02 Real Time Pricing - Secondary Service (Rate 664) 138 Customer Charge Bills 12 $199.00 $199.00 $282.00 $282.00 $ 2,388 $ 3,384 $ 996 139 Energy - All kWh kWh - - 18,049,797 Real Time Pricing Real Time Pricing $ 577,594 $ 576,598 $ (996) 140 Total Base Revenue: $ 579,982 $ 579,982 $ - 141 142 10.04 Large General Service - Transmission Service (Rate 632) 143 Customer Charge Bills - $50.00 $50.00 $282.00 $282.00 $ - $ - $ - 144 Energy - All kWh kWh - $0.01352 $0.01618 $0.02233 $0.02182 $ - $ - $ - 145 Demand per kW kW - $5.42 $3.79 $8.91 $4.24 $ - $ - $ - 146 Facilities Charge kW - N/A N/A N/A N/A $ - $ - $ - 147 Total Base Revenue: $ - $ - $ - 148 149 10.05 Large General Service Time of Day - Secondary Service (Rates 611, 615, 613) 150 Customer Charge Bills 24 $70.00 $70.00 $215.90 $215.90 $ 1,680 $ 5,182 $ 3,502 151 Facilities Charge <1,000 kW kW 5,413 $0.33 $0.33 $0.76 $0.76 $ 1,786 $ 4,114 $ 2,328 152 Facilities Charge >=1,000 kW kW - $0.24 $0.24 $0.57 $0.57 $ - $ - $ - 153 Energy - On-Peak kWh 156,353 171,839 328,192 $0.04649 $0.03851 $0.03685 $0.03120 $ 22,346 $ 11,122 $ (11,224) 154 Energy - Shoulder kWh 238,498 576,320 814,818 $0.02761 $0.02289 $0.02808 $0.02783 $ 16,533 $ 22,735 $ 6,202 155 Energy - Off-Peak kWh 428,567 706,854 1,135,421 $0.00292 $0.01059 $0.01877 $0.01976 $ 8,526 $ 22,012 $ 13,486 156 Demand per kW - On-Peak kW 1,608 2,791 4,399 $5.59 $3.91 $7.63 $3.80 $ 19,903 $ 22,876 $ 2,973 157 Demand per kW - Shoulder kW 1,651 2,705 4,356 $1.70 $0.72 $4.67 2.84 $ 4,755 $ 15,393 $ 10,639 158 Demand per kW - Off-Peak kW - - - $0.00 $0.00 $0.00 $0.00 $ - $ - $ - 159 Total Base Revenue: $ 75,529 $ 103,435 $ 27,906
Page 125 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 8 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 160 161 10.05 Large General Service Time of Day - Primary Service (Rates 610, 614, 612) 162 Customer Charge Bills - $70.00 $70.00 $282.00 $282.00 $ - $ - $ - 163 Facilities Charge - All kW kW - $0.12 $0.12 $0.48 $0.48 $ - $ - $ - 164 Energy - On-Peak kWh - - - $0.04401 $0.03600 $0.03549 $0.02988 $ - $ - $ - 165 Energy - Shoulder kWh - - - $0.02595 $0.02117 $0.02713 $0.02675 $ - $ - $ - 166 Energy - Off-Peak kWh - - - $0.00221 $0.00943 $0.01822 $0.01906 $ - $ - $ - 167 Demand per kW - On-Peak kW - - - $5.37 $3.72 $6.10 $3.62 $ - $ - $ - 168 Demand per kW - Shoulder kW - - - $1.63 $0.68 $4.48 $2.72 $ - $ - $ - 169 Demand per kW - Off-Peak kW - - - $0.00 $0.00 $0.00 $0.00 $ - $ - $ - 170 171 10.05 Large General Service Time of Day - Transmission Service (Rates 639, 637, 640) 172 Customer Charge Bills - $70.00 $70.00 $282.00 $282.00 $ - $ - $ - 173 Facilities Charge kW - N/A N/A N/A N/A $ - $ - $ - 174 Energy - On-Peak kWh - - - $0.04001 $0.03200 $0.03332 $0.02781 $ - $ - $ - 175 Energy - Shoulder kWh - - - $0.02324 $0.01840 $0.02561 $0.02504 $ - $ - $ - 176 Energy - Off-Peak kWh - - - $0.00100 $0.00752 $0.01733 $0.01794 $ - $ - $ - 177 Demand per kW - On-Peak kW - - - $4.35 $3.23 $5.14 $2.75 $ - $ - $ - 178 Demand per kW - Shoulder kW - - - $1.07 $0.57 $3.77 $1.49 $ - $ - $ - 179 Demand per kW - Off-Peak kW - - - $0.00 $0.00 $0.00 $0.00 $ - $ - $ - 180 Total Base Revenue: $ - $ - $ - 181 182 Adjustments for Riders included in Base Rates 183 Transmission Cost Recovery Rider kWh - $ 87,262 $ - 184 Environmental Cost Recovery Rider kWh - $ 1,172,845 $ - 185 Riders staying outside of the Base Rate 186 EEP Cost Recovery Rider kWh #REF! $ 229,966 $ 229,966 187 Transmission Cost Recovery Rider kWh 211,799,024 $ 569,144 $ 569,144 188 Environmental Cost Recovery Rider kWh #REF! $ (14,506) $ (14,506) 189 COE kWh #REF! $ 4,698,489 $ 4,698,489 190 Totals: $ 5,483,094 $ 5,483,094 $ - 191 192 Total Base Revenue for the COSS Class: $ 6,484,885 $ 8,866,513 $ 2,381,628 193 Total Adjustments for the COSS Class: $ 5,483,094 $ 5,483,094 $ 0 194 Total for the COSS Class: $ 11,967,979 $ 14,349,607 $ 2,381,628 19.90% 195 196
Page 126 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 9 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 197 11.01 Standby Service - Option A: Firm - Secondary Service (Rates 947, 948, 949) 198 Customer Charge Bills - $199.00 $199.00 $215.95 $215.95 199 Facilities Charge per month per kW of Contracted Backup kW - $0.5283 $0.5283 $0.7560 $0.7560 200 Reservation Charge per kW of Contracted Backup kW - $0.16770 $0.05370 $0.42347 $0.10243 201 Metered Demand per day per kW On-Peak Backup kW - $0.71380 $0.07373 $0.52465 $0.41794 202 Energy - On-Peak kWh - $0.04649 $0.03851 $0.03685 $0.03120 203 Energy - Shoulder kWh - $0.02761 $0.02289 $0.02808 $0.02783 204 Energy - Off-Peak kWh - $0.00292 $0.01059 $0.01877 $0.01976 205 206 Total: 207 11.01 Standby Service - Option A: Firm - Primary Service (Rates 944, 945, 946) 208 Customer Charge Bills - $199.00 $199.00 $282.08 $282.08 209 Facilities Charge per month per kW of Backup kW - $0.2543 $0.2543 $0.5730 $0.5730 210 Reservation Charge per kW of Contracted Backup kW - $0.16040 $0.05100 $0.40537 $0.09803 211 Metered Demand per day per kW On-Peak Backup kW - $0.68380 $0.70030 $0.50234 $0.39640 212 Energy - On-Peak kWh - $0.04401 $0.03600 $0.03549 $0.02988 213 Energy - Shoulder kWh - $0.02595 $0.02117 $0.02713 $0.02675 214 Energy - Off-Peak kWh - $0.00221 $0.00943 $0.01822 $0.01906 215 Conservation Improvement Program - 216 Total: 217 11.01 Standby Service - Option A: Firm - Transmission Service (Rates 941, 942, 943) 218 Customer Charge Bills 12 $199.00 $199.00 $282.08 $282.08 219 Facilities Charge per month per kW of Backup kW - - - N/A N/A N/A N/A 220 Reservation Charge per kW of Contracted Backup kW - - - $0.14900 $0.04680 $0.37692 $0.09113 221 Metered Demand per day per kW On-Peak Backup kW - $0.63670 $0.64330 $0.46739 $0.36341 222 Energy - On-Peak kWh - - - $0.04001 $0.03200 $0.03332 $0.02781 223 Energy - Shoulder kWh - - - $0.02324 $0.01840 $0.02561 $0.02504 224 Energy - Off-Peak kWh - - - $0.00100 $0.00752 $0.01733 $0.01794 225 Conservation Improvement Program - 226 Total: 227 11.01 Standby Service - Option B: Non-Firm - Secondary Service (Rates 956, 957, 958) 228 Customer Charge Bills - $199.00 $199.00 $215.95 $215.95 229 Facilities Charge per month per kW of Backup kW - $0.53 $0.53 $0.76 $0.76 230 Energy - On-Peak kWh - N/A N/A N/A N/A 231 Energy - Shoulder kWh - $0.02761 $0.02289 $0.02808 $0.02783 232 Energy - Off-Peak kWh - $0.00292 $0.01059 $0.01877 $0.01976 233 Conservation Improvement Program - 234 Total: 235 11.01 Standby Service - Option B: Non-Firm - Primary Service (Rates 953, 954, 955) 236 Customer Charge Bills - $199.00 $199.00 $282.08 $282.08 237 Facilities Charge per month per kW of Backup kW - $0.25 $0.25 $0.57 $0.57 238 Energy - On-Peak kWh - N/A N/A N/A N/A 239 Energy - Shoulder kWh - $0.02595 $0.02117 $0.02713 $0.02675 240 Energy - Off-Peak kWh - $0.00221 $0.00943 $0.01822 $0.01906
Page 127 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 10 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 241 Conservation Improvement Program - 242 Total: 243 11.01 Standby Service - Option B: Non-Firm - Transmission Service (Rates 950, 951, 952) 244 Customer Charge Bills - $199.00 $199.00 $282.08 $282.08 245 Facilities Charge per month per kW of Backup kW - N/A N/A N/A N/A 246 Energy - On-Peak kWh - N/A N/A N/A N/A 247 Energy - Shoulder kWh - $0.02324 $0.01840 $0.02561 $0.02504 248 Energy - Off-Peak kWh - $0.00100 $0.00752 $0.01733 $0.01794 249 Conservation Improvement Program - 250 Total: 251 252 253 11.02 Irrigation Service - Option 1: Non-Time-of-Use (Rate 703) 254 Customer Charge Bills 63 $2.00 $2.00 $12.00 $12.00 $ 126 $ 756 $ 630 255 Energy kWh 213,281 (39,085) 174,196 $0.03797 $0.01644 $0.05567 $0.03960 $ 7,456 $ 10,326 $ 2,870 256 18% Return of Distribution Facilities - $ 2,575 $ 2,575 $ - 257 Total Base Revenue: $ 10,156 $ 13,657 $ 3,501 258 259 11.02 Irrigation Service - Option 2 (Rates 704, 705, 706) 260 Customer Charge Bills 42 $6.00 $6.00 $18.00 $18.00 $ 252 $ 756 $ 504 261 Energy - Declared-Peak kWh 898 (5) 893 $0.17453 $0.19521 $0.28829 $0.28247 $ 156 $ 257 $ 102 262 Energy - Intermediate kWh 18,606 (693) 17,913 $0.04603 $0.03566 $0.06908 $0.04032 $ 832 $ 1,257 $ 426 263 Energy - Off-Peak kWh 21,428 (623) 20,805 $0.01000 $0.01000 $0.02685 $0.02935 $ 21 $ 557 $ 536 264 Demand per kW - Declared-Peak kW - - - $0.00 $0.00 $0.00 $0.00 $ - $ - $ - 265 Demand per kW - Intermediate kW - - - $0.00 $0.00 $0.00 $0.00 $ - $ - $ - 266 Demand per kW - Off-Peak kW - - - $0.00 $0.00 $0.00 $0.00 $ - $ - $ - 267 18% Return of Distribution Facilities - $ 2,691 $ 2,691 $ - 268 Total Base Revenue: $ 3,951 $ 5,518 $ 1,567 269 270 Adjustments for Riders included in Base Rates 271 Transmission Cost Recovery Rider kWh $ 169 $ - 272 Environmental Cost Recovery Rider kWh $ 1,101 $ - 273 Riders staying outside of the Base Rate 274 EEP Cost Recovery Rider kWh 213,807 $ 228 $ 228 275 Transmission Cost Recovery Rider kWh 213,807 $ 1,101 $ 1,101 276 Environmental Cost Recovery Rider kWh 213,807 $ (14) $ (14) 277 COE kWh 213,807 $ 4,846 $ 4,846 278 Totals: $ 6,163 $ 6,163 $ - 279 280 Total Base Revenue for the COSS Class: $ 14,107 $ 19,175 $ 5,068 281 Total Adjustments for the COSS Class: $ 6,163 $ 6,163 $ - 282 Total for the COSS Class: $ 20,270 $ 25,338 $ 5,068 25.00% 283 284
Page 128 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 11 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 285 11.03 Outdoor Lighting - Metered - Energy Only (Rate 748) 286 Customer Charge Bills 467 $2.50 $2.50 $2.50 $2.50 $ 1,168 $ 1,168 $ - 287 Energy kWh 214,103 $0.03771 $0.03771 $0.04144 $0.04144 $ 8,074 $ 8,873 $ 799 288 Total Base Revenue: $ 9,241 $ 10,040 $ 799 289 290 11.03 Outdoor Lighting - Non-Metered - Energy Only (Rate 749) 291 kWh 596,575 $0.03771 $0.03771 $0.04144 $0.04144 292 Monthly charge for connected KW kW 146 12.88$ 12.88$ $14.16 $14.16 293 Total Base Revenue: $ 22,404 $ 24,724 $ 2,320 294 295 Non Standard Ligting kWh 46,901 $0.03771 $0.03771 $0.04144 $0.04144 $ 1,769 $ 1,944 $ 175 296 297 Total Base Revenue: $1,768.63 $ 33,413.58 $ 36,707.84 298 299 11.04 Outdoor Lighting - Street & Area Lighting (Rate 741) 300 Type: kWh/lt Annual Kwh Quantity 301 MV-6 Lts 70 394,681 5,638 $5.95 $5.95 $ 7.50 $7.50 302 MV-6PT Lts 70 6,544 93 $8.55 $8.55 $ 10.77 $10.77 303 MV-11 Lts 100 - - $10.77 $10.77 $ 13.57 $13.57 304 MV-21 Lts 154 9,245 60 $14.26 $14.26 $ 17.97 $17.97 305 MV-35 Lts 260 - - $20.97 $20.97 $ 26.42 $26.42 306 MV-55 Lts 366 - - $26.83 $26.83 $ 33.80 $33.80 307 MA-8 Lts 41 19,298 471 $6.74 $6.74 $ 8.49 $8.49 308 MA-8PT Lts 41 - - $11.48 $11.48 $ 14.46 $14.46 309 MA-14 Lts 70 - - $12.84 $12.84 $ 16.18 $16.18 310 MA-20 Lts 98 2,359 24 $14.70 $14.70 $ 18.52 $18.52 311 MA-36 Lts 156 - - $14.55 $14.55 $ 18.33 $18.33 312 MA-110 Lts 369 8,891 24 $31.15 $31.15 $ 39.25 $39.25 313 HPS-9 Lts 44 1,651,567 37,536 $6.52 $6.52 $ 8.21 $8.21 314 HPS-9PT Lts 44 18,407 418 $7.91 $7.91 $ 9.97 $9.97 315 HPS-14 Lts 64 136,128 2,127 $10.01 $10.01 $ 12.61 $12.61 316 HPS-14PT Lts 64 8,388 131 $10.17 $10.17 $ 12.81 $12.81 317 HPS-19 Lts 83 8,917 107 $11.53 $11.53 $ 14.53 $14.53 318 HPS-23 Lts 102 146,274 1,434 $13.13 $13.13 $ 16.54 $16.54 319 HPS-44 Lts 156 298,165 1,911 $16.25 $16.25 $ 20.47 $20.47 320 321 UNDERGROUND SERVICE: Lts - - - $1.71 $1.71 $ 2.15 $2.15 322 Seasonal Charge - $17.70 $17.70 $32.79 $32.79 323 Total Base Revenue: 2,708,864 49,975 $ 361,272 $ 455,167 $ 93,895 324 18,632 $25,062.92
Page 129 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 12 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 325 11.04 Outdoor Lighting - Flood Lighting (Rate 743) 326 Type: kWh/lt Annual Kwh Quantity 327 400MV-F Lts 154 49,712 323 $14.79 $14.79 $18.63 $18.63 328 400MA-F Lts 156 292,367 1,874 $15.78 $15.78 $19.88 $19.88 329 400HPS-F Lts 156 328,392 2,105 $16.15 $16.15 $20.35 $20.35 330 1000MV-F Lts 366 - - $25.98 $25.98 $0.00 $0.00 331 1000MA-F Lts 308 90,249 293 $27.30 $27.30 $34.40 $34.40 332 U4CHPSF Lts 371 - - $0.00 $0.00 $0.00 $0.00 333 U400MAF Lts 156 1,879 12 $17.49 $17.49 $22.04 $22.04 334 U4CHPSF Lts 156 5,629 36 $17.86 $17.86 $22.50 $22.50 335 336 Total Base Revenue: 768,228 4,607 $ 75,841 $ 97,259 $ 21,418 337 338 Adjustments for Riders included in Base Rates 339 Transmission Cost Recovery Rider kWh $ 2,077 $ - 340 Environmental Cost Recovery Rider kWh $ 23,932 $ - 341 Riders staying outside of the Base Rate 342 EEP Cost Recovery Rider kWh $ 4,672 $ 4,672 343 Transmission Cost Recovery Rider kWh $ 13,548 $ 13,548 344 Environmental Cost Recovery Rider kWh $ (296) $ (296) 345 COE kWh $ 104,582 $ 104,582 346 Totals: $ 122,505 $ 122,505 $ - 347 348 Total Base Revenue for the COSS Class: $ 470,527 $ 589,134 $ 118,607 349 Total Adjustments for the COSS Class: $ 122,505 $ 122,505 $ - 350 Total for the COSS Class: $ 593,033 $ 711,639 $ 118,606 20.00% 351 352 353 354 11.05 Municipal Pumping - Secondary Service (Rate 872) 355 Customer Charge Bills 1,389 $3.00 $3.00 $12.00 $12.00 356 Facilities Charge (Changing per Month to per KW) kW - $0.14 $0.14 $1.00 $1.00 357 Energy - All kWh kWh 1,224,661 2,762,452 3,987,113 $0.03251 $0.03407 $0.04837 $0.03983 358 Total Base Revenue: $ 140,786 $ 205,126 $ 64,340 359 360 11.05 Municipal Pumping -Primary Service (Rate 874) 361 Customer Charge Bills - $3.00 $3.00 $12.00 $12.00 362 Facilities Charge (Changing per Month to per KW) KW - $0.09 $0.09 $0.67 $0.67 363 Energy - All kWh kWh - $0.03061 $0.03178 $0.04660 $0.03821 364 Total Base Revenue: $ - $ - $ - 365
Page 130 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 13 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 366 11.06 Civil Defense - Fire Sirens (Rate 843) 367 Customer Charge Bills - $1.00 $1.00 $2.50 $2.50 368 Load Charge HP 47 $0.54324 $0.54324 $0.61978 $0.61978 369 Total Base Revenue: $ 1,047 $ 1,537 $ 490 370 Adjustments for Riders included in Base Rates 371 Transmission Cost Recovery Rider kWh $ 3,341 $ - 372 Environmental Cost Recovery Rider kWh $ 21,919 $ - 373 Riders staying outside of the Base Rate 374 EEP Cost Recovery Rider kWh $ 4,252 $ 4,252 375 Transmission Cost Recovery Rider kWh $ 21,792 $ 21,792 376 Environmental Cost Recovery Rider kWh $ (271) $ (271) 377 COE kWh $ 96,951 $ 96,951 378 Totals: $ 122,724 $ 122,724 $ - 379 380 Total Base Revenue for the COSS Class: $ 140,786 $ 206,664 $ 65,878 381 Total Adjustments for the COSS Class: $ 122,724 $ 122,724 $ - 382 Total for the COSS Class: $ 263,510 $ 329,388 $ 65,878 25.00% 383 384 385 14.01 Water Heating - Controlled Service (Rate 191) 386 Customer Charge Bills 25,492 $2.50 $2.50 $4.00 $4.00 $ 63,730 $ 101,968 $ 38,238 387 Facilities Charge Bills 25,492 $0.00 $0.00 $2.00 $2.00 $ - $ 50,984 $ 50,984 388 Energy - All kWh kWh 1,481,730 3,554,173 5,035,904 $0.02776 $0.03143 $0.02762 $0.02371 $ 152,841 $ 125,197 $ (27,644) 389 Total Credits: 1,697 -$4.00 -$4.00 -$8.00 -$8.00 $ (6,788) $ (13,576) 390 Total Base Revenue: $ 209,783 $ 278,149 $ 61,578 391 Adjustments for Riders included in Base Rates 392 Transmission Cost Recovery Rider kWh $ 570 $ - 393 Environmental Cost Recovery Rider kWh $ 27,994 $ - 394 Riders staying outside of the Base Rate 395 EEP Cost Recovery Rider kWh 5,035,904 $ 5,418 $ 5,418 396 Transmission Cost Recovery Rider kWh 5,035,904 $ 3,718 $ 3,718 397 Environmental Cost Recovery Rider kWh 5,035,904 $ (346) $ (346) 398 COE kWh 5,035,904 $ 123,257 $ 123,257 399 Totals: $ 132,048 $ 132,048 $ - 400 401 Total Base Revenue for the COSS Class: $ 209,783 $ 278,149 $ 68,366 402 Total Adjustments for the COSS Class: $ 132,048 $ 132,048 $ - 403 Total for the COSS Class: $ 341,831 $ 410,196 $ 68,365 20.00% 404
Page 131 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 14 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 405 14.02 Real Time Pricing - Secondary Service (Rate 664) 406 Administrative Charge Bills - 199.00$ 199.00$ $282.00 $282.00 407 Consumption Change from CBL kWh - 408 Conservation Improvement Program - 409 Total: 410 14.02 Real Time Pricing - Primary Service (Rate 662) 411 Administrative Charge Bills - 199.00$ 199.00$ $282.00 $282.00 412 Consumption Change from CBL kWh - 413 Conservation Improvement Program - 414 Total: 415 14.02 Real Time Pricing - Transmission Service (Rate 660) 416 Administrative Charge Bills - $199.00 $199.00 $282.00 $282.00 417 Consumption Change from CBL kWh - 418 Conservation Improvement Program - 419 Total: 420 14.03 Large General Service Rider 421 Administrative Charge Bills - $199.00 $199.00 $282.00 $282.00 422 Fixed Rate Energy Pricing (FREP) Peak kWh - 423 Fixed Rate Energy Pricing (FREP) Shoulder kWh - 424 Fixed Rate Energy Pricing (FREP) Off-Peak kWh - 425 Capacity Purchase kW - 426 Conservation Improvement Program - 427 Total: 428 429 14.04 Controlled Service - Interruptible Load Rider CT Metering - Option 1 (Rates 170, 165, 881) 430 Customer Charge Bills 29 $5.00 $5.00 $15.00 $15.00 $ 1,755 $ 5,265 $ 3,510 431 Facilities Charge kW 64,865 $0.12 $0.12 $0.50 $0.50 $ 7,784 $ 32,432 $ 24,648 432 Energy - All kWh kWh 105,778 6,112,793 6,218,570 $0.00629 $0.00895 $0.01346 $0.01128 $ 55,359 $ 70,346 $ 14,987 433 Penalty kWh kWh - 1,756 1,756 $0.15516 $0.15839 $0.26749 $0.17205 $ 294 $ - $ (294) 434 435 Total Base Revenue: $ 65,192 $ 108,042 $ 42,850 436 437 14.04 Controlled Service - Interruptible Load Rider CT Metering - Option 2 (Rates 168, 268, 169, 269) 438 Customer Charge Bills 4 8 12 $6.00 $6.00 $15.00 $15.00 $ 72 $ 180 $ 108 439 Facilities Charge kW 254 2,182 2,436 $0.12 $0.12 $0.50 $0.50 $ 292 $ 1,218 $ 926 440 Energy - All kWh kWh 36,980 111,778 148,758 $0.00856 $0.01142 $0.01346 $0.01128 $ 1,593 $ 1,839 $ 246 441 Control Period Demand kW - 1 1 $7.29 $4.63 $12.30 $6.64 $ 5 $ 3,333 $ 3,327 442 Total Base Revenue: $ 1,962 $ 3,238 $ 1,276 443
Page 132 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 15 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 444 14.05 Controlled Service - Interruptible Load Rider Self-Contained Metering (Rates 190, 185, 882) 445 Customer Charge Bills - $2.00 $2.00 $10.00 $10.00 $ 24,000 $ 120,000 $ 96,000 446 Facilities Charge Bills 12,000 $5.00 $5.00 $9.50 $9.50 $ 60,000 $ 114,000 $ 54,000 447 Energy - All kWh kWh 1,841,040 13,187,842 15,028,882 $0.01050 $0.01386 $0.01456 $0.01220 $ 202,114 $ 187,642 $ (14,472) 448 Penalty kWh kWh - - - $0.16403 $0.17697 $0.26749 $0.17205 $ - $ - 449 Total Base Revenue: $ 286,115 $ 421,642 $ 135,527 450 451 Adjustments for Riders included in Base Rates 452 Transmission Cost Recovery Rider kWh $ 2,279 $ - 453 Environmental Cost Recovery Rider kWh $ 112,324 $ - 454 Riders staying outside of the Base Rate 455 EEP Cost Recovery Rider kWh $ 21,316 $ 21,316 456 Transmission Cost Recovery Rider kWh $ 14,862 $ 14,862 457 Environmental Cost Recovery Rider kWh $ (1,389) $ (1,389) 458 COE kWh $ 510,209 $ 510,209 459 Totals: $ 544,998 $ 544,998 $ - 460 461 Total Base Revenue for the COSS Class: $ 353,269 $ 532,922 $ 179,653 462 Total Adjustments for the COSS Class: $ 544,998 $ 544,998 $ - 463 Total for the COSS Class: $ 898,267 $ 1,077,920 $ 179,653 20.00% 464 465 466 467 14.06 Controlled Service - Deferred Load Rider (Rates 197, 195, 883) 468 Customer Charge Bills 2,318 $3.00 $3.00 $8.50 $8.50 $ 6,954 $ 19,703 $ 12,749 469 Facilities Charge Bills 2,318 $4.00 $4.00 $11.00 $11.00 $ 9,272 $ 25,498 $ 16,226 470 Energy - All kWh kWh 461,706 4,675,625 5,137,331 $0.01852 $0.02156 $0.02646 $0.02411 $ 109,357 $ 124,934 $ 15,577 471 Penalty kWh kWh - - $0.15939 $0.16927 $0.26749 $0.17205 $ - $ - $ - 472 Total Base Revenue: $ 125,583 $ 170,135 $ 44,552 473 474 14.07 Fixed Time of Service Rider - Self-Contained Metering (Rates 301, 884) 475 Customer Charge Bills 342 687 1,029 $1.50 $1.50 $6.70 $6.70 $ 1,544 $ 6,894 $ 5,351 476 Facilities Charge Bills 342 687 1,029 $3.00 $3.00 $6.00 $6.00 $ 3,087 $ 6,174 $ 3,087 477 Energy - All kWh kWh 28,300 1,585,013 1,613,313 $0.00110 $0.00564 $0.01093 $0.01145 $ 8,971 $ 18,453 $ 9,483 478 Penalty kWh kWh 5,557 37,920 $0.04652 $0.03826 $0.06081 $0.04761 $ 1,929 $ (1,929) 479 Total Base Revenue: $ 15,530 $ 31,522 $ 15,991 480 481 14.07 Fixed Time of Service Rider - CT Metering (Rates 302, 885) 482 Customer Charge Bills 56 112 168 $2.00 $2.00 $6.70 $6.70 $ 336 $ 1,126 $ 790 483 Facilities Charge Bills 56 112 168 $16.00 $16.00 $32.00 $32.00 $ 2,688 $ 5,376 $ 2,688 484 Energy - All kWh kWh 78,692 698,709 777,401 $0.00110 $0.00564 $0.01093 $0.01145 $ 4,027 $ 8,858 $ 4,831 485 Penalty kWh kWh 9,100 50,217 59,316 $0.04652 $0.03826 $0.06081 $0.04761 $ 709 $ (709) 486 Total Base Revenue: $ 7,760 $ 15,360 $ 7,600
Page 133 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement I
Page 16 of 16
Proposed Test Year 2018 Present vs Proposed Operating Revenue Detailed Comparison - by Rate Schedule and Billing Units
Present Operating Proposed Operating Line Billing Units Present Rate Proposed Rate Pct Inc. Charge Units Revenues Revenues Increase Annual No. Annual Summer Winter Annual Summer Winter Summer Winter Annual Annual 487 14.07 Fixed Time of Service Rider - Primary CT Metering (Rates 303, 886) 488 Customer Charge Bills - $5.00 $5.00 $6.70 $6.70 489 Facilities Charge Bills - $8.00 $8.00 $16.00 $16.00 490 Energy - All kWh kWh - $0.00100 $0.00552 $0.01089 $0.01140 491 Penalty kWh kWh - $0.04641 $0.03813 $0.06081 $0.04761 492 493 Adjustments for Riders included in Base Rates 494 Transmission Cost Recovery Rider kWh $ 785 $ - 495 Environmental Cost Recovery Rider kWh $ 38,805 $ - 496 Riders staying outside of the Base Rate 497 EEP Cost Recovery Rider kWh 7,587,362 $ 7,326 $ 7,326 498 Transmission Cost Recovery Rider kWh 7,587,362 $ 5,122 $ 5,122 499 Environmental Cost Recovery Rider kWh 7,587,362 $ (480) $ (480) 500 COE kWh 7,587,362 $ 179,875 $ 179,875 501 Totals: $ 191,842 $ 191,842 $ - 502 503 504 Total Base Revenue for the COSS Class: $ 148,873 $ 217,017 $ 68,143 505 Total Adjustments for the COSS Class: $ 191,842 $ 191,842 $ - 506 Total for the COSS Class: $ 340,715 $ 408,859 $ 68,143 20.00% 507 508 509 510 Total Base Revenue: $ 18,556,637 $ 24,534,747 $ 5,978,110 511 Total Adjustments: $ 12,093,378 $ 12,093,378 $ - 512 TOTAL : $ 30,650,015 $ 36,628,125 $ 5,978,110 19.50%
Page 134 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement J Depreciation Expense Page 1 of 2 Actual Year 2017
(A) (B) (C) (D) (E) (F)
Total 2017 Adjusted 2017 13-Month Base Year Test Year Average Annual Line Depreciation Adjustments Depreciation Depreciable Accrual No. Functional Classification Expense (1) Expense Property (2) Rate (3)
1 Production 2 Steam 3 Hoot Lake Plant $3,376,522 $3,376,522 $68,120,895 4.96% 4 Big Stone Plant 9,136,207 1,074,059 10,210,266 327,803,684 2.79% 5 Coyote Station 3,336,240 542,337 3,878,577 174,303,340 1.91%
6 Total Steam $15,848,969 $1,616,396 $17,465,365 $570,227,919 2.78% 7 8 Hydro $557,027 $557,027 $8,343,611 6.68% 9 Internal Combustion 1,012,222 1,012,222 41,419,146 2.44% 10 Wind 11,090,471 11,090,471 268,511,490 4.00%
11 Total Production $28,508,690 $1,616,396 $30,125,086 $888,502,166 3.21% 12 13 Transmission 7,392,819 2,148,892 9,541,711 438,654,741 1.69% 14 15 Distribution 11,287,497 30,837 11,318,334 472,023,836 2.39% 16 17 General Plant 2,674,335 (65,408) 2,608,927 83,577,167 3.20% 18 19 Intangibles 1,567,291 1,366,164 2,933,455 7,995,632 19.60% 20 21 Total $51,430,632 $5,096,882 $56,527,513 $1,890,753,542
(1) The adjustments to depreciation expense by function can be traced to the 2017 Actual and Test Year Input Summaries found in Volume 4A, Tabs - 2017 Actual Year Workpapers and 2017 Test Year Workpapers
(2) The Depreciable Property Balances in Column E above do not include land if trying to tie back to Plant in Service Balances for the Test Year Ending 12/31/17. Total land balances for the Test Year using a 13-month average is $5,377,583.
(3) The Annual Accrual Rate is a composite total system rate.
Page 135 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule J - 1 Depreciation Expense Charged to Other Accounts Page 2 of 2 Actual Year 2017
(A) (B) (C) (D) (E) (F) (G)
Depreciation Expense Depreciable Depreciable Total Charged to Net Line Property Property Depreciation Other Depreciation No. Functional Classification 12/31/2016 12/31/2017 Expense 2017 Accounts Notes Expense
1 Production 2 Steam 3 Hoot Lake Plant $66,362,433 $70,163,201 $3,376,522 $3,376,522 4 Big Stone Plant 327,531,612 328,665,197 9,136,207 9,136,207 5 Coyote Station 174,224,658 175,630,485 3,336,240 3,336,240 6 Total Steam $568,118,703 $574,458,883 $15,848,969 $0 $15,848,969 7 8 Hydro $8,339,631 $8,344,334 $557,027 $557,027 9 Internal Combustion 41,415,555 41,423,335 1,012,222 1,012,222 10 Wind 268,611,109 268,660,779 11,090,471 11,090,471 11 Total Production $886,484,998 $892,887,331 $28,508,690 $0 $28,508,690 12 13 Transmission 410,231,568 499,904,364 7,392,819 7,392,819 14 15 Distribution 464,957,476 481,539,883 11,287,497 11,287,497 16 17 General Plant 83,333,679 88,639,101 4,440,461 1,766,125 (1 & 2) 2,674,335 18 19 Intangibles 7,207,561 9,905,743 1,567,291 1,567,291 20 21 Total $1,852,215,282 $1,972,876,422 $53,196,757 $1,766,125 $51,430,632
1) Depreciation expense of $1,845,271 on transportation equipment is charged to the appropriate account based on vehicle usage. Depreciation is included in the rate per mile or hour established for the use of the vehicle.
2) Depreciation expense of ($79,146) on warehouse property is charged to material as the material moves through the warehouse.
Note 1: The Depreciable Property Balances in Columns B & C above do not include land if trying to tie back to Plant in Service Balances for 12/31/16 and 12/31/17. Total land balances for 12/31/16 and 12/31/17 are $5,377,583 and $5,377,583, respectively. These amounts include $29,657 that is classified as Transmission and Distribution Plant Held for Future Use, most commonly these are held for future substation expansions.
Note 2: ARO Depreciation & Accretion Expense along with its corresponding regulatory credit offset generates a $0 income statement result and are appropriately netted here at the Functional Classification level.
Page 136 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement K Income Tax Page 1 of 2 For the Year Ending December 31, 2017
(A) (B) (C) (D) (E)
TOTAL SYSTEM South Total Claimed Adjusted Dakota Line No. Description System Adjustments Total Amount
1 Income Tax Payable 2 Federal $5,459,784 ($4,737,766) $722,018 ($1,021,346) 3 State 1,582,645 (566,534) 1,016,111 0 4 Deferred Income Tax 5 Federal 12,256,507 (6,811,882) 5,444,625 441,070 6 State 3,113,852 (177,190) 2,936,662 0 7 Investment Tax Credit - Net (8,243,449) 6,772,885 (1,470,564) (123,560)
8 Total Income Tax $14,169,339 ($5,520,487) $8,648,852 ($703,836)
Page 137 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement K Interest Expense - Annualization Adjustment Page 2 of 2 For the Test Year Ended December 31, 2017
(A) (B) (C) (D)
TOTAL SYSTEM
2017 2017 Line Actual Test No. Description Year Adjustments Year
1 (1) Net Operating Income Before Tax (NOIBT) $89,661,800 ($10,360,279) $79,301,521 2 (1) Less: Interest Cost 26,913,527 $625,984 $27,539,511 3 4 Net Income Before Tax $62,748,273 ($10,986,263) $51,762,010 5 6 (2) Federal Schedule M Adjustments: 7 Additional Tax Depreciation $34,438,568 $0 $34,438,568 8 Removal Costs 3,006,569 $0 3,006,569 9 Accrued Vacation Pay (26,010) $0 (26,010) 10 $0 11 Workers' Compensation 281,048 $0 281,048 12 Post Retirement Medical Benefits 3,588,211 $0 3,588,211 13 Post Employment Medical Benefits 362,696 $0 362,696 14 Supplemental Pension Reserve 1,175,712 $0 1,175,712 15 Bad Debts 1,301,140 $0 1,301,140 16 Loan Pools (2) $0 (2) 17 $0 18 Workers' Compensation (296,263) $0 (296,263) 19 Post Retirement Medical Benefits (5,273,460) $0 (5,273,460) 20 Post Employment Medical Benefits (142,974) $0 (142,974) 21 Supplemental Pension Reserve (1,438,129) $0 (1,438,129) 22 Bad Debts (1,575,570) $0 (1,575,570) 23 $0 24 Meal Allowances - 50% Disallowance (47,731) $0 (47,731) 25 Restricted Stock Incentive - (Tax Deduction for Dividends) (175,147) $0 (175,147) 26 Interest Capitalized on Construction (1,251,731) $0 (1,251,731) 27 Highway Reimbursements 242,094 $0 242,094 28 Unicap Adjustment - Section 163A (1,256) $0 (1,256) 29 Leverage ESOP Deduction 1,557,021 $0 1,557,021 30 Pensions (FAS 87 & 88) Non-taxable Book Income (5,736,168) $0 (5,736,168) 31 Pensions Contributions (FAS 87 & 88) 20,000,000 $0 20,000,000 32 Restricted Stock Incentive (Tax dedeuction for Employee Gain) 324,916 $0 324,916 33 Restricted Stock Incentive (Tax dedeuction for Dividends) 6,552 $0 6,552 34 AFUDC (Equity) 986,150 $0 986,150 35 AFUDC (Debt) 740,730 $0 740,730 36 Wind Rider Revenue (Billed in CIS) (9,191,994) $0 (9,191,994) 37 Wind Rider Revenue (Total Revenue Booked) 7,389,492 $0 7,389,492 38 Transmission Rider Revenue (Billed in CIS) (12,144,029) $0 (12,144,029) 39 Transmission Rider Recovery (Total Revenue Booked) 13,689,302 $0 13,689,302 40 Environmental Rider Revenue (Billed in CIS) (21,665,926) $0 (21,665,926) 41 Environmental Rider Revenue (Total Revenue Booked) 20,275,130 $0 20,275,130 42 SPP Rider Cost Tracker (609,468) $0 (609,468) 43 EITE Revenue 75,291 $0 75,291 44 Big Stone II Deferred (998,552) $0 (998,552) 45 Big Stone II Discount 118,092 $0 118,092 46 MN Rate Case Deferred Expense (102,905) $0 (102,905) 47 Prepaid Expense 360,117 $0 360,117 48 Bonus Incentive (572,964) $0 (572,964) 49 50 Federal Empowerment Zone Tax Credit (6,000) $0 (6,000) 51 Sec. 199 Production Activities Deduction 750,037 ($750,037) 52 Income from ACRS & MACRS Property (1,354,836) $0 (1,354,836)
Subtotal Federal Schedule M Adjustments $48,057,753 ($750,037) $47,307,716
Federal Adjusted Income Before Taxes $14,690,520 ($10,236,226) $4,454,294
Less: State Income Taxes 1,582,645 (566,534) 1,016,111
Federal Taxable Income $13,107,875 ($9,669,692) $3,438,183
Federal Tax Rate 35.00% 21.00%
Federal Income Tax Before Credits $4,587,756 ($3,865,738) $722,018 Investment Tax Credit - Debits Utilized - - - Federal Income Taxes before transfer to deferred due to NOL $872,028 $ (872,028) -
FEDERAL INCOME TAXES $5,459,784 ($4,737,766) $722,018
Tax Savings Due to Consolidation: There will be no tax savings as a result of filing a consolidated tax return for the test year ended December 31, 2017.
Abnormalities for Test Period: None
Page 138 of 164 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 1 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 2 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 3 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 4 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 5 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 6 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 7 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 8 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 9 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 10 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 11 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 12 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 13 of 14 Docket No. EL18-___ Volume 4A Section 2 Schedule K-1 Page 14 of 14 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule K-2 Difference Between Book and Tax Depreciation Page 1 of 1 Year Ended December 31, 2017
(A) (B)
Line Total No. Description Company
1 Tax Depreciation on a straight-line basis $39,665,033
2 Book Depreciation 52,941,244
3 Difference between Tax Depreciation on a 4 straight-line basis and Book Depreciation ($13,276,211)
5 Tax Depreciation, as calculated by method 6 MACRS 5 to 20-year Property $88,596,798 7 Buildings - SL - All Vintages 624,992 8 Intangibles 1,189,955 9 ACRS (1981-1986) Property 5,547 10 ADR (1971-1980) Property - 11 DCB (1964-1970) Property 2,178
12 Total Tax Depreciation, as calculated * $90,419,471
13 Tax Depreciation on a straight-line basis $39,665,033
14 Excess of Tax Depreciation, as calculated over Tax 15 Depreciation on a straight-line basis $50,754,438
Page 139 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company PUBLIC - TRADE SECRET DATA HAS BEEN EXCISED Consolidated Federal Income Tax Liability Schedule K-3 Tax Year 2016 Page 1 of 1 Per Tax Return
[PROTECTED DATA BEGINS… (A) (B) (C) (D) (E) (F) (G) (H) (I)
Taxable Income Taxable Income Federal Income Line or (loss) before NOL or (loss) after Income Tax Tax Table Tax Liability No. Company Name NOL Carryfwd Carryforward NOL Carryfwd Tax Rate Before Tax Credits Adjustment Tax Credits (per tax return)
1 Otter Tail Corporation 2 Otter Tail Power Company 3 Varistar Corporation 4 IMD, Inc. 5 BTD Manufacturing, Inc. 6 Northern Pipe Products, Inc. 7 Vinyltech Corporation 8 Otter Tail Energy Services Company 9 T. O. Plastics, Inc. 10 Shrco, Inc. 11 Otter Tail Assurance Limited 12 AEV, Inc. 13 ASI, Inc. 14 Miller Welding & Iron Works, Inc.
Total 0 0 0 0 0 0 0
...PROTECTED DATA ENDS] Notes: 1. There will be no significant savings from filing a consolidated federal tax return.
Page 140 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule K-4 Current Income Tax Page 1 of 1 For the Year Ending December 31, 2017
Line No. Description
1 Current income tax used in the cost of service is calculated on a stand-alone 2 basis. Effective tax rates are applied to regulatory operating income calculated 3 within the Jurisdictional Cost of Service Study (JCOSS), which includes 4 adjustments to items of income or expense based on prior Commission 5 Orders or settlement stipulations, if applicable. Depending on the 6 circumstances that apply in a given year, taxes calculated for regulatory 7 purposes in the JCOSS may be higher or lower than the actual taxes 8 calculated on a consolidated basis in the tax return for any number of 9 varying reasons. For example, items of income and expense considered 10 below-the-line for regulatory purposes contribute to the overall tax calculation 11 on the consolidated tax return. Ratepayers are not exposed to the risks 12 associated with below-the-line revenue and expense activity and thus 13 shouldn't be exposed to the taxes associated with that same activity. In 14 addition, timing differences that arise, such as book versus tax depreciation 15 expense, off-set increases or decreases in current tax expense by a 16 corresponding decrease or increase in deferred tax expense. Deferred taxes 17 are calculated for book/regulatory purposes only and are not part of the 18 consolidated tax return. Deferred tax calculations are included in order to 19 recognize the fact that at some future point in time book/regulatory will incur the 20 same tax expense/liability as calculated in the tax return. 21
Page 141 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Schedule K-5 State Income Taxes Page 1 of 1 For the Test Year Ended December 31, 2017
Line No. Description
1 This schedule is not applicable, as no state income taxes are claimed for South Dakota 2 Cost of Service purposes.
Page 142 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement L Other Taxes Page 1 of 1 2017 Actual Year
(A) (B)
Line 2017 No. Description Actual Year
Federal Taxes 1 Federal Unemployment $35,222 2 Federal FICA 4,887,718 3 4 State and Local Taxes 5 Minnesota 6 Property 9,392,221 7 Unemployment 39,210 8 9 North Dakota 10 Property 2,537,915 11 Unemployment 38,098 12 Foreign Corporation 0 13 Coal Conversion 2,099,595 14 15 South Dakota 16 Property 1,553,833 17 Unemployment 8,299 18 Foreign Corporation 0 19 Coal Conversion 0 20 21 Total Other Taxes $20,592,111
Page 143 of 164 Docket No. EL18-___ Volume 4A Section 2 Otter Tail Power Company Schedule L-1 Working Papers for Adjusted Taxes Page 1 of 1 2017 Test Year Totals
Line No. Description 1 No adjustments were made to General Taxes Docket No. EL18-___ Volume 4A Section 2
OTTER TAIL POWER COMPANY Statement M OVERALL COST OF SERVICE STUDY 2017 ACTUAL YEAR - 10 CLASSES Page 1 of 8
LINE TOTAL SOUTH ALL LINE NO ITEM ALLOC COMPANY DAKOTA OTHER NO
1 RATE BASE 1,096,668,710 83,294,792 1,013,373,918 1 2 2 3 TOTAL AVAILABLE FOR RETURN 77,446,208 4,814,182 72,632,026 3 4 4 5 RATE OF RETURN EARNED 7.06% 5.78% 7.17% 5 6 6 7 RATE OF RETURN REQUESTED 7.74% 7 8 8 9 OPERATING INCOME REQUIRED 6,447,017 9 10 10 11 TOTAL AVAILABLE FOR RETURN 4,814,182 11 12 12 13 OPERATING INCOME DEFECIENCY 1,632,835 13 14 14 15 INCREMENTAL TAXES GRCF = 1.540773 882,992 15 16 16 17 REVENUE INCREASE REQUIRED 2,515,827 17 18 18 19 PERCENTAGE INCREASE 7.64% 19 20 20 21 21 22 22 23 23 24 24 25 6.29% 25 26 26 27 27 28 28 29 29 30 30 31 31 32 32 33 33 34 34 35 35 36 36 37 37 38 38 39 39 40 40 41 41 42 42 43 43 44 44 45 45 46 46 47 47 48 48 49 49 50 50 51 51 52 52 53 53 54 54 55 55 56 56 57 57 58 58 59 59 60 60
Page 144 of 164 Docket No. EL18-___ Volume 4A Section 2
Statement M OTTER TAIL POWER COMPANY OVERALL COST OF SERVICE STUDY Page 2 of 8 ACTUAL YEAR 2017 - 10 CLASSES
LINE TOTAL SOUTH ALL LINE NO ITEM ALLOC COMPANY DAKOTA OTHER NO
1 ELECTRIC PLANT IN SERVICE 1,926,147,002 161,400,619 1,764,746,383 1 2 2 3 ACCUMULATED DEPRECIATION (747,632,742) (68,956,035) (678,676,707) 3 4 4 5 NET PLANT EXCLUDING BIG STONE PLANT CAPITALIZED ITEMS 1,178,514,260 92,444,584 1,086,069,676 5 6 6 7 NET CAPITALIZED ITEMS - BIG STONE PLANT 0 0 0 7 8 8 9 NET ELECTRIC PLANT IN SERVICE 1,178,514,260 92,444,584 1,086,069,676 9 10 10 11 PLANT HELD FOR FUTURE USE 29,657 2,786 26,871 11 12 12 13 CONSTRUCTION WORK IN PROGRESS 158,432,233 0 158,432,233 13 14 14 15 MATERIALS AND SUPPLIES 19,658,295 1,831,014 17,827,281 15 16 16 17 FUEL STOCKS 9,089,677 845,834 8,243,842 17 18 18 19 PREPAYMENTS (24,727,324) (1,939,652) (22,787,672) 19 20 20 21 CUSTOMER ADVANCES (934,625) (73,314) (861,311) 21 22 22 23 CASH WORKING CAPITAL 16,353,385 2,772,420 13,580,965 23 24 24 25 ACCUMULATED DEFERRED INCOME TAXES (260,006,587) (12,637,581) (247,369,006) 25 26 26 27 UNAMORTIZED HOLDING COMPANY FORMATION EXPENSE 0 0 0 27 28 28 29 UNAMORTIZED RATE CASE EXPENSE 0 0 0 29 30 30 31 31 32 TOTAL AVERAGE RATE BASE 1,096,408,971 83,246,093 1,013,162,879 32 33 33 34 34 35 35 36 36 37 37 38 38 39 39 40 40 41 41 42 42 43 43 44 44 45 45 46 46 47 47 48 48 49 49 50 50 51 51 52 52 53 53 54 54 55 55 56 56 57 57 58 58 59 59 60 60
Page 145 of 164 Docket No. EL18-___ Volume 4A Section 2
Statement M OTTER TAIL POWER COMPANY OVERALL COST OF SERVICE STUDY Page 3 of 8 ACTUAL YEAR 2017 - 10 CLASSES
LINE TOTAL SOUTH ALL LINE NO ITEM ALLOC COMPANY DAKOTA OTHER NO
1 OPERATING REVENUES 1 2 SALES OF ELECTRICITY 372,153,628 32,929,872 339,223,756 2 3 OTHER OPERATING REVENUE 58,386,685 2,445,167 55,941,518 3 4 4 5 TOTAL OPERATING REVENUE 430,540,313 35,375,040 395,165,274 5 6 6 7 7 8 OPERATING EXPENSES 8 9 PRODUCTION EXPENSES 156,639,966 14,201,172 142,438,794 9 10 TRANSMISSION EXPENSES 32,135,395 2,936,416 29,198,979 10 11 DISTRIBUTION EXPENSES 17,761,845 1,686,406 16,075,438 11 12 CUSTOMER ACCOUNTING EXPENSES 12,912,128 1,144,837 11,767,291 12 13 CUSTOMER SERVICE AND INFORMATION EXPENSES 9,358,287 663,245 8,695,042 13 14 SALES EXPENSES 230,711 11,402 219,309 14 15 ADMINISTRATIVE AND GENERAL EXPENSES 43,609,630 3,739,913 39,869,717 15 16 CHARITABLE CONTRIBUTIONS 0 0 0 16 17 DEPRECIATION EXPENSE 53,185,267 4,719,228 48,466,039 17 18 AMORTIZATION OF BIG STONE PLANT CAPITALIZED COSTS 0 0 0 18 19 SPIRITWOOD AMORTIZATION 0 0 0 19 20 GENERAL TAXES 15,045,286 965,772 14,079,513 20 21 21 22 TOTAL OPERATING EXPENSES 340,878,513 30,068,391 310,810,122 22 23 23 24 24 25 NET OPERATING INCOME BEFORE INCOME TAXES 89,661,800 5,306,648 84,355,152 25 26 26 27 27 28 INCOME TAX EXPENSE 28 29 INVESTMENT TAX CREDIT (8,997,380) (753,931) (8,243,449) 29 30 DEFERRED INCOME TAXES 18,423,555 779,249 17,644,306 30 31 INCOME TAXES 4,362,156 0 4,362,156 31 32 32 33 TOTAL INCOME TAX EXPENSE 13,788,331 25,318 13,763,013 33 34 34 35 35 36 36 37 NET OPERATING INCOME 75,873,469 5,281,330 70,592,139 37 38 38 39 39 40 ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION 1,726,880 0 1,726,880 40 41 41 42 42 43 TOTAL AVAILABLE FOR RETURN 77,600,349 5,281,330 72,319,019 43 44 44 45 45 46 46 47 47 48 AVERAGE CENTS PER KWH 48 49 49 50 50 51 51 52 52 53 53 54 54 55 55 56 56 57 57 58 58 59 59 60 60
Page 146 of 164 Docket No. EL18-___ Volume 4A Section 2
Statement M OTTER TAIL POWER COMPANY Page 4 of 8 STATEMENT M OVERALL COST OF SERVICE STUDIES 2017 Actual Year
Line No. Description
1 The remaining detail of the 2017 Actual Year Overall Cost of Service Study can be found 2 in Volume 4A, Tab - 2017 Actual Year.
Page 147 of 164 Docket No. EL18-___ Volume 4A Section 2
Statement M Page 5 of 8 OTTER TAIL POWER COMPANY OVERALL COST OF SERVICE STUDY 2017 TEST YEAR - 10 CLASSES
LINE TOTAL SOUTH ALL LINE NO ITEM ALLOC COMPANY DAKOTA OTHER NO
1 RATE BASE 1,108,607,736 84,904,903 1,023,702,833 1 2 2 3 TOTAL AVAILABLE FOR RETURN 72,379,548 2,042,807 70,336,740 3 4 4 5 RATE OF RETURN EARNED 6.53% 2.41% 6.87% 5 6 6 7 RATE OF RETURN REQUESTED 7.96% 7 8 8 9 OPERATING INCOME REQUIRED 6,758,430 9 10 10 11 TOTAL AVAILABLE FOR RETURN 2,042,807 11 12 12 13 OPERATING INCOME DEFECIENCY 4,715,623 13 14 14 15 INCREMENTAL TAXES GRCF = 1.267724 1,262,487 15 16 16 17 REVENUE INCREASE REQUIRED 5,978,110 17 18 18 19 PERCENTAGE INCREASE 19.50% 19 20 20 21 21 22 22 23 23 24 24 25 -0.15% 25 26 26 27 27 28 28 29 29 30 30 31 31 32 32 33 33 34 34 35 35 36 36 37 37 38 38 39 39 40 40 41 41 42 42 43 43 44 44 45 45 46 46 47 47 48 48 49 49 50 50 51 51 52 52 53 53 54 54 55 55 56 56 57 57 58 58 59 59 60 60
Page 148 of 164 Docket No. EL18-___ Volume 4A Section 2
Statement M Page 6 of 8
OTTER TAIL POWER COMPANY OVERALL COST OF SERVICE STUDY 2017 TEST YEAR - 10 CLASSES
LINE TOTAL SOUTH ALL LINE NO ITEM ALLOC COMPANY DAKOTA OTHER NO
1 ELECTRIC PLANT IN SERVICE 1,938,272,718 162,858,425 1,775,414,294 1 2 2 3 ACCUMULATED DEPRECIATION (748,596,113) (69,187,810) (679,408,303) 3 4 4 5 NET PLANT EXCLUDING BIG STONE PLANT CAPITALIZED ITEMS 1,189,676,605 93,670,615 1,096,005,990 5 6 6 7 NET CAPITALIZED ITEMS - BIG STONE PLANT 0 0 0 7 8 8 9 NET ELECTRIC PLANT IN SERVICE 1,189,676,605 93,670,615 1,096,005,990 9 10 10 11 PLANT HELD FOR FUTURE USE 29,657 2,786 26,871 11 12 12 13 CONSTRUCTION WORK IN PROGRESS 158,432,233 0 158,432,233 13 14 14 15 MATERIALS AND SUPPLIES 19,658,295 1,833,976 17,824,319 15 16 16 17 FUEL STOCKS 9,089,677 849,126 8,240,551 17 18 18 19 PREPAYMENTS (24,727,324) (1,946,936) (22,780,388) 19 20 20 21 CUSTOMER ADVANCES (934,625) (73,589) (861,036) 21 22 22 23 CASH WORKING CAPITAL 10,493,890 2,474,563 8,019,327 23 24 24 25 ACCUMULATED DEFERRED INCOME TAXES (253,936,313) (12,421,053) (241,515,260) 25 26 26 27 UNAMORTIZED BALANCE - SPIRITWOOD 0 0 0 27 28 28 29 UNAMORTIZED RATE CASE EXPENSE 458,334 458,334 0 29 30 30 31 31 32 TOTAL AVERAGE RATE BASE 1,108,240,429 84,847,822 1,023,392,607 32 33 33 34 34 35 35 36 36 37 37 38 38 39 39 40 40 41 41 42 42 43 43 44 44 45 45 46 46 47 47 48 48 49 49 50 50 51 51 52 52 53 53 54 54 55 55 56 56 57 57 58 58 59 59 60 60
Page 149 of 164 Docket No. EL18-___ Volume 4A Section 2
Statement M Page 7 of 8
OTTER TAIL POWER COMPANY OVERALL COST OF SERVICE STUDY 2017 TEST YEAR - 10 CLASSES
LINE TOTAL SOUTH ALL LINE NO ITEM ALLOC COMPANY DAKOTA OTHER NO
1 OPERATING REVENUES 1 2 SALES OF ELECTRICITY 369,873,771 30,650,015 339,223,756 2 3 OTHER OPERATING REVENUE 58,386,685 2,453,522 55,933,164 3 4 4 5 TOTAL OPERATING REVENUE 428,260,456 33,103,537 395,156,919 5 6 6 7 7 8 OPERATING EXPENSES 8 9 PRODUCTION EXPENSES 159,877,303 14,543,258 145,334,045 9 10 TRANSMISSION EXPENSES 32,211,644 2,950,883 29,260,761 10 11 DISTRIBUTION EXPENSES 17,903,711 1,699,129 16,204,582 11 12 CUSTOMER ACCOUNTING EXPENSES 13,007,046 1,153,253 11,853,793 12 13 CUSTOMER SERVICE AND INFORMATION EXPENSES 9,376,626 664,545 8,712,081 13 14 SALES EXPENSES 337,682 20,751 316,931 14 15 ADMINISTRATIVE AND GENERAL EXPENSES 44,672,125 4,003,827 40,668,298 15 16 CHARITABLE CONTRIBUTIONS 0 0 0 16 17 DEPRECIATION EXPENSE 54,901,148 4,888,064 50,013,084 17 18 AMORTIZATION OF BIG STONE PLANT CAPITALIZED COSTS 0 0 0 18 19 SPIRITWOOD AMORTIZATION 0 0 0 19 20 GENERAL TAXES 15,045,286 969,399 14,075,886 20 21 21 22 TOTAL OPERATING EXPENSES 347,332,570 30,893,109 316,439,461 22 23 23 24 24 25 NET OPERATING INCOME BEFORE INCOME TAXES 80,927,886 2,210,428 78,717,458 25 26 26 27 27 28 INCOME TAX EXPENSE 28 29 INVESTMENT TAX CREDIT (1,470,564) (123,560) (1,347,004) 29 30 DEFERRED INCOME TAXES 8,381,287 441,070 7,940,217 30 31 INCOME TAXES 1,976,987 (838,041) 2,815,029 31 32 32 33 TOTAL INCOME TAX EXPENSE 8,887,710 (520,532) 9,408,242 33 34 34 35 35 36 36 37 NET OPERATING INCOME 72,040,176 2,730,960 69,309,216 37 38 38 39 39 40 ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION 1,726,880 0 1,726,880 40 41 41 42 42 43 TOTAL AVAILABLE FOR RETURN 73,767,055 2,730,960 71,036,095 43 44 44 45 45 46 46 47 47 48 48 49 49 50 50 51 51 52 52 53 53 54 54 55 55 56 56 57 57 58 58 59 59 60 60
Page 150 of 164 Docket No. EL18-___ Volume 4A Section 2
Statement M OTTER TAIL POWER COMPANY Page 8 of 8 STATEMENT M OVERALL COST OF SERVICE STUDIES 2017 TEST YEAR
Line No. Description
1 The remaining detail of the 2017 Test Year Overall Cost of Service Study can be found 2 in Volume 4A, Tab - 2017 Test Year Work Papers.
Page 151 of 164 Docket No. EL18-___ Volume 4A Section 2
Statement N Page 1 of 9
Otter Tail Power Company Allocated Cost of Service 2017 Actual Year and Test Year
Statement N, pages 2 – 9, are the adjusted and actual test period cost of service allocated to class of customer. The remaining detail for the adjusted and actual test period cost of service allocated to customer classes appears in Volume 4A, Tab – 1 2017 Test Year Workpapers and Tab – 2 2017 Actual Year Workpapers, respectively. Adjustments to the Actual Year to arrive at the 2017 Test Year can also be found in Volume 4A, Tab – 1 2017 Test Year Work Papers. Otter Tail’s Cost Allocation Procedures Manual appears in Exhibit __(SDT-1), Schedule 3.
1. Grouping and allocation of various items of cost and credits to cost of service into functional totals appear in the cost of service study located in Volume 4A, Tab – 1 2017 Test Year Work Papers.
2. Classification of items of cost and credits into demand, energy, customer or other appropriate categories appear in the cost of service study located in Volume 4A, Tab – 1 2017 Test Year Work Papers.
3. Otter Tail does not consider for rate purposes any special facilities to be devoted entirely to the jurisdictional service involved.
4. Computations showing the energy responsibilities of the jurisdictional service, based upon consideration of energy sales under the proposed rate schedules and the kWh delivered from the filing public utility’s supply system, appear in the cost of service study located in Volume 4A, Tab – 1 2017 Test Year Work Papers in the energy allocation factors E1 and E2.
5. Otter Tail’s peak electric hour losses are 11.15%. System energy losses applicable to jurisdictional sales are 3.88% to 9.7% of Otter Tail’s system output depending on the class of service.
6. Details of allocation of general or common or joint costs to various functions appear in Exhibit__(SDT-1), Schedule 3.
7. Sufficient detailed breakdown of operation and maintenance expense accounts and taxes to disclose how component items have been classified among energy, class of customer or other category of cost appears in Exhibit__(SDT-1), Schedule 3.
Page 152 of 164 Docket No. EL18-___ Volume 4A Section 2
OTTER TAIL POWER COMPANY Statement N CLASS COST OF SERVICE STUDY 2017 ACTUAL YEAR - 10 CLASSES Page 2 of 9
LARGE CONTROLLED CONTROLLED CONTROLLED LINE SOUTH GENERAL GENERAL OUTDOOR WATER SERVICE SERVICE NO ITEM ALLOC DAKOTA RESIDENTIAL FARMS SERVICE SERVICE IRRIGATION LIGHTING OPA HEATING INTERRUPT DEFERRED -
1 RATE BASE 83,294,792 24,681,770 1,888,314 15,840,528 33,192,538 106,405 1,835,266 779,894 1,420,014 2,599,134 950,929 2 3 TOTAL AVAILABLE FOR RETURN 4,814,182 1,060,672 117,272 1,558,750 1,938,451 (4,603) 40,023 21,866 (16,525) 186,091 (87,815) 4 5 RATE OF RETURN EARNED 5.78% 4.30% 6.21% 9.84% 5.84% -4.33% 2.18% 2.80% -1.16% 7.16% -9.23% 6 7 RATE OF RETURN REQUESTED 7.74% 7.74% 7.74% 7.74% 7.74% 7.74% 7.74% 7.74% 7.74% 7.74% 7.74% 8 9 OPERATING INCOME REQUIRED 6,447,017 1,910,369 146,156 1,226,057 2,569,102 8,236 142,050 60,364 109,909 201,173 73,602 10 11 TOTAL AVAILABLE FOR RETURN 4,814,182 1,060,672 117,272 1,558,750 1,938,451 (4,603) 40,023 21,866 (16,525) 186,091 (87,815) 12 13 OPERATING INCOME DEFECIENCY 1,632,835 849,697 28,883 (332,694) 630,652 12,838 102,027 38,498 126,435 15,082 161,417 14 15 INCREMENTAL TAXES GRCF = 1.540773 882,992 459,493 15,619 (179,912) 341,039 6,943 55,173 20,819 68,372 8,156 87,290 16 17 REVENUE INCREASE REQUIRED 2,515,827 1,309,190 44,503 (512,605) 971,691 19,781 157,200 59,316 194,807 23,237 248,706 18 19 PERCENTAGE INCREASE 7.64% 13.70% 6.24% -7.54% 7.36% 100.74% 25.38% 20.54% 51.81% 2.11% 103.12% 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 153 of 164 Docket No. EL18-___ Volume 4A Section 2
OTTER TAIL POWER COMPANY Statement N CLASS COST OF SERVICE STUDY 2017 ACTUAL YEAR - 10 CLASSES Page 3 of 9
LARGE CONTROLLED CONTROLLED CONTROLLED LINE SOUTH GENERAL GENERAL OUTDOOR WATER SERVICE SERVICE NO ITEM ALLOC DAKOTA RESIDENTIAL FARMS SERVICE SERVICE IRRIGATION LIGHTING OPA HEATING INTERRUPT DEFERRED -
1 ELECTRIC PLANT IN SERVICE 161,400,619 48,110,926 3,687,860 30,785,233 63,805,845 213,994 3,626,933 1,510,390 2,820,189 5,005,409 1,833,840 2 3 ACCUMULATED DEPRECIATION (68,956,035) (20,732,186) (1,586,481) (13,194,309) (27,009,330) (93,918) (1,581,956) (645,553) (1,226,619) (2,109,751) (775,932) 4 5 NET PLANT EXCLUDING BIG STONE PLANT CAPITALIZED ITEMS 92,444,584 27,378,741 2,101,379 17,590,924 36,796,514 120,077 2,044,976 864,837 1,593,569 2,895,658 1,057,907 6 7 NET CAPITALIZED ITEMS - BIG STONE PLANT 0 0 0 0 0 0 0 0 0 0 0 8 9 NET ELECTRIC PLANT IN SERVICE 92,444,584 27,378,741 2,101,379 17,590,924 36,796,514 120,077 2,044,976 864,837 1,593,569 2,895,658 1,057,907 10 11 PLANT HELD FOR FUTURE USE 2,786 985 75 549 747 8 111 24 90 154 43 12 13 CONSTRUCTION WORK IN PROGRESS 0 0 0 0 0 0 0 0 0 0 0 14 15 MATERIALS AND SUPPLIES 1,831,014 573,001 43,766 354,807 665,548 3,082 48,253 16,855 37,118 66,819 21,766 16 17 FUEL STOCKS 845,834 207,672 16,902 158,208 434,877 0 8,580 8,422 3,841 1,752 5,582 18 19 PREPAYMENTS (1,939,652) (574,455) (44,091) (369,089) (772,056) (2,519) (42,907) (18,146) (33,436) (60,756) (22,197) 20 21 CUSTOMER ADVANCES (73,314) (21,713) (1,667) (13,951) (29,182) (95) (1,622) (686) (1,264) (2,296) (839) 22 23 CASH WORKING CAPITAL 2,772,420 845,481 58,195 514,793 1,106,892 2,229 56,441 26,352 37,288 92,037 32,713 24 25 ACCUMULATED DEFERRED INCOME TAXES (12,637,581) (3,742,794) (287,268) (2,404,757) (5,030,245) (16,415) (279,557) (118,227) (217,848) (395,849) (144,621) 26 27 UNAMORTIZED HOLDING COMPANY FORMATION EXPENSE 0 0 0 0 0 0 0 0 0 0 0 28 29 UNAMORTIZED RATE CASE EXPENSE 0 0 0 0 0 0 0 0 0 0 0 30 31 32 TOTAL AVERAGE RATE BASE 83,246,093 24,666,918 1,887,292 15,831,485 33,173,094 106,366 1,834,275 779,431 1,419,359 2,597,517 950,355 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 154 of 164 Docket No. EL18-___ Volume 4A Section 2
OTTER TAIL POWER COMPANY Statement N CLASS COST OF SERVICE STUDY 2017 ACTUAL YEAR - 10 CLASSES Page 4 of 9
LARGE CONTROLLED CONTROLLED CONTROLLED LINE SOUTH GENERAL GENERAL OUTDOOR WATER SERVICE SERVICE NO ITEM ALLOC DAKOTA RESIDENTIAL FARMS SERVICE SERVICE IRRIGATION LIGHTING OPA HEATING INTERRUPT DEFERRED -
1 OPERATING REVENUES 2 SALES OF ELECTRICITY 32,929,872 9,559,127 713,379 6,801,617 13,207,451 19,637 619,352 288,770 375,980 1,103,386 241,174 3 OTHER OPERATING REVENUE 2,445,167 749,699 54,297 455,314 966,992 2,798 46,315 22,883 37,690 80,231 28,949 4 5 TOTAL OPERATING REVENUE 35,375,040 10,308,826 767,676 7,256,931 14,174,443 22,434 665,667 311,652 413,670 1,183,617 270,122 6 7 8 OPERATING EXPENSES 9 PRODUCTION EXPENSES 14,201,172 3,248,537 261,594 2,440,539 7,047,505 5,345 142,631 132,696 149,052 563,423 209,850 10 TRANSMISSION EXPENSES 2,936,416 919,518 64,054 609,760 1,249,320 0 20,134 28,953 3,252 33,230 8,196 11 DISTRIBUTION EXPENSES 1,686,406 618,965 47,335 325,694 274,980 6,365 197,901 13,599 68,334 103,000 30,233 12 CUSTOMER ACCOUNTING EXPENSES 1,144,837 753,309 30,140 276,234 8,459 1,832 3,552 13,607 35,697 17,185 4,822 13 CUSTOMER SERVICE AND INFORMATION EXPENSES 663,245 503,396 19,331 125,020 3,088 858 2,002 6,577 686 1,659 629 14 SALES EXPENSES 11,402 8,654 332 2,149 53 15 34 113 12 29 11 15 ADMINISTRATIVE AND GENERAL EXPENSES 3,739,913 1,383,613 89,035 748,201 1,151,691 5,188 130,147 36,218 70,914 90,936 33,969 16 CHARITABLE CONTRIBUTIONS 0 0 0 0 0 0 0 0 0 0 0 17 DEPRECIATION EXPENSE 4,719,228 1,381,732 105,524 893,442 1,918,417 5,561 97,250 44,384 77,287 142,153 53,478 18 AMORTIZATION OF BIG STONE PLANT CAPITALIZED COSTS 0 0 0 0 0 0 0 0 0 0 0 19 SPIRITWOOD AMORTIZATION 0 0 0 0 0 0 0 0 0 0 0 20 GENERAL TAXES 965,772 286,027 21,953 183,773 384,415 1,254 21,364 9,035 16,648 30,251 11,052 21 22 TOTAL OPERATING EXPENSES 30,068,391 9,103,751 639,298 5,604,812 12,037,927 26,418 615,015 285,182 421,883 981,866 352,240 23 24 25 NET OPERATING INCOME BEFORE INCOME TAXES 5,306,648 1,205,075 128,378 1,652,119 2,136,516 (3,983) 50,652 26,471 (8,214) 201,751 (82,118) 26 27 28 INCOME TAX EXPENSE 29 INVESTMENT TAX CREDIT (753,931) (224,735) (17,227) (143,803) (298,049) (1,000) (16,942) (7,055) (13,174) (23,381) (8,566) 30 DEFERRED INCOME TAXES 779,249 230,785 17,713 148,280 310,171 1,012 17,238 7,290 13,433 24,409 8,917 31 INCOME TAXES 0 0 0 0 0 0 0 0 0 0 0 32 33 TOTAL INCOME TAX EXPENSE 25,318 6,051 487 4,477 12,123 13 296 235 259 1,027 351 34 35 36 37 NET OPERATING INCOME 5,281,330 1,199,024 127,891 1,647,642 2,124,394 (3,996) 50,357 26,236 (8,473) 200,724 (82,469) 38 39 40 ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION 0 0 0 0 0 0 0 0 0 0 0 41 42 43 TOTAL AVAILABLE FOR RETURN 5,281,330 1,199,024 127,891 1,647,642 2,124,394 (3,996) 50,357 26,236 (8,473) 200,724 (82,469) 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 155 of 164 Docket No. EL18-___ Volume 4A Section 2
Statement N Otter Tail Power Company Page 5 of 9 STATEMENT N CLASS COST OF SERVICE STUDIES 2017 ACTUAL YEAR
Line No. Description
1 The remaining detail for the 2017 Actual Year Class Cost of Service Study can be found 2 in Volume 4A, Tab - 2017 Actual Year.
Page 156 of 164 Docket No. EL18-___ Volume 4A Section 2
OTTER TAIL POWER COMPANY Statement N CLASS COST OF SERVICE STUDY 2017 TEST YEAR - 10 CLASSES Page 6 of 9
LARGE CONTROLLED CONTROLLED CONTROLLED LINE SOUTH GENERAL GENERAL OUTDOOR WATER SERVICE SERVICE NO ITEM ALLOC DAKOTA RESIDENTIAL FARMS SERVICE SERVICE IRRIGATION LIGHTING OPA HEATING INTERRUPT DEFERRED -
1 RATE BASE 84,904,903 25,404,562 1,898,658 16,465,198 33,390,343 134,374 1,780,976 775,274 1,433,739 2,680,432 941,346 2 3 TOTAL AVAILABLE FOR RETURN 2,042,807 486,652 65,252 808,675 670,038 (5,747) 45,461 2,445 (32,424) (20,005) 22,461 4 5 RATE OF RETURN EARNED 2.41% 1.92% 3.44% 4.91% 2.01% -4.28% 2.55% 0.32% -2.26% -0.75% 2.39% 6 7 RATE OF RETURN REQUESTED 7.96% 7.96% 7.96% 7.96% 7.96% 7.96% 7.96% 7.96% 7.96% 7.96% 7.96% 8 9 OPERATING INCOME REQUIRED 6,758,430 2,022,203 151,133 1,310,630 2,657,871 10,696 141,766 61,712 114,126 213,362 74,931 10 11 TOTAL AVAILABLE FOR RETURN 2,042,807 486,652 65,252 808,675 670,038 (5,747) 45,461 2,445 (32,424) (20,005) 22,461 12 13 OPERATING INCOME DEFECIENCY 4,715,623 1,535,552 85,881 501,955 1,987,833 16,443 96,305 59,267 146,550 233,367 52,470 14 15 INCREMENTAL TAXES GRCF = 1.267724 1,262,487 411,105 22,993 134,386 532,191 4,402 25,783 15,867 39,235 62,478 14,048 16 17 REVENUE INCREASE REQUIRED 5,978,110 1,946,656 108,874 636,341 2,520,024 20,845 122,088 75,134 185,785 295,845 66,518 18 19 PERCENTAGE INCREASE 19.50% 21.21% 16.26% 9.98% 21.06% 102.84% 20.59% 28.51% 54.35% 32.94% 19.52% 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 157 of 164 Docket No. EL18-___ Volume 4A Section 2
OTTER TAIL POWER COMPANY Statement N CLASS COST OF SERVICE STUDY 2017 TEST YEAR - 10 CLASSES Page 7 of 9
LARGE CONTROLLED CONTROLLED CONTROLLED LINE SOUTH GENERAL GENERAL OUTDOOR WATER SERVICE SERVICE NO ITEM ALLOC DAKOTA RESIDENTIAL FARMS SERVICE SERVICE IRRIGATION LIGHTING OPA HEATING INTERRUPT DEFERRED -
1 ELECTRIC PLANT IN SERVICE 162,858,425 48,951,508 3,667,538 31,652,996 63,631,037 266,926 3,489,448 1,486,276 2,808,128 5,104,726 1,799,840 2 3 ACCUMULATED DEPRECIATION (69,187,810) (20,930,683) (1,567,995) (13,481,049) (26,839,906) (116,251) (1,516,125) (631,635) (1,210,124) (2,135,798) (758,245) 4 5 NET PLANT EXCLUDING BIG STONE PLANT CAPITALIZED ITEMS 93,670,615 28,020,825 2,099,543 18,171,947 36,791,132 150,675 1,973,323 854,642 1,598,004 2,968,928 1,041,595 6 7 NET CAPITALIZED ITEMS - BIG STONE PLANT 0 0 0 0 0 0 0 0 0 0 0 8 9 NET ELECTRIC PLANT IN SERVICE 93,670,615 28,020,825 2,099,543 18,171,947 36,791,132 150,675 1,973,323 854,642 1,598,004 2,968,928 1,041,595 10 11 PLANT HELD FOR FUTURE USE 2,786 984 73 551 746 10 111 24 89 155 43 12 13 CONSTRUCTION WORK IN PROGRESS 0 0 0 0 0 0 0 0 0 0 0 14 15 MATERIALS AND SUPPLIES 1,833,976 575,808 43,104 360,179 662,101 3,828 47,041 16,452 36,508 67,567 21,388 16 17 FUEL STOCKS 849,126 212,103 16,790 164,034 429,950 0 7,056 8,233 3,880 1,777 5,302 18 19 PREPAYMENTS (1,946,936) (582,410) (43,639) (377,702) (764,700) (3,132) (41,015) (17,764) (33,214) (61,709) (21,649) 20 21 CUSTOMER ADVANCES (73,589) (22,014) (1,649) (14,276) (28,904) (118) (1,550) (671) (1,255) (2,332) (818) 22 23 CASH WORKING CAPITAL 2,474,563 760,281 51,384 470,364 976,115 2,301 46,942 22,976 33,048 83,288 27,865 24 25 ACCUMULATED DEFERRED INCOME TAXES (12,421,053) (3,715,660) (278,407) (2,409,664) (4,878,634) (19,980) (261,670) (113,328) (211,901) (393,690) (138,119) 26 27 UNAMORTIZED HOLDING COMPANY FORMATION EXPENSE 0 0 0 0 0 0 0 0 0 0 0 28 29 UNAMORTIZED RATE CASE EXPENSE 458,334 137,107 10,273 88,916 180,020 737 9,656 4,182 7,819 14,527 5,097 30 31 32 TOTAL AVERAGE RATE BASE 84,847,822 25,387,024 1,897,473 16,454,348 33,367,826 134,321 1,779,894 774,744 1,432,977 2,678,511 940,703 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 158 of 164 Docket No. EL18-___ Volume 4A Section 2
OTTER TAIL POWER COMPANY Statement N CLASS COST OF SERVICE STUDY 2017 TEST YEAR - 10 CLASSES Page 8 of 9
LARGE CONTROLLED CONTROLLED CONTROLLED LINE SOUTH GENERAL GENERAL OUTDOOR WATER SERVICE SERVICE NO ITEM ALLOC DAKOTA RESIDENTIAL FARMS SERVICE SERVICE IRRIGATION LIGHTING OPA HEATING INTERRUPT DEFERRED -
1 OPERATING REVENUES 2 SALES OF ELECTRICITY 30,650,015 9,175,901 669,522 6,378,987 11,967,979 20,270 593,033 263,510 341,830 898,267 340,716 3 OTHER OPERATING REVENUE 2,453,522 759,910 53,818 466,754 956,334 3,429 43,576 22,418 37,526 81,750 28,006 4 5 TOTAL OPERATING REVENUE 33,103,537 9,935,811 723,340 6,845,741 12,924,313 23,699 636,609 285,928 379,356 980,017 368,722 6 7 8 OPERATING EXPENSES 9 PRODUCTION EXPENSES 14,543,258 3,396,854 265,702 2,593,339 7,090,666 6,479 116,934 132,416 153,009 586,338 201,522 10 TRANSMISSION EXPENSES 2,950,883 922,527 62,815 616,938 1,255,370 0 19,913 28,176 3,165 33,803 8,176 11 DISTRIBUTION EXPENSES 1,699,129 623,190 47,100 328,967 276,531 7,755 199,306 13,485 67,827 104,663 30,303 12 CUSTOMER ACCOUNTING EXPENSES 1,153,253 758,847 30,361 278,264 8,521 1,846 3,578 13,707 35,960 17,312 4,857 13 CUSTOMER SERVICE AND INFORMATION EXPENSES 664,545 504,383 19,368 125,265 3,094 860 2,006 6,590 688 1,662 630 14 SALES EXPENSES 20,751 15,750 605 3,912 97 27 63 206 21 52 20 15 ADMINISTRATIVE AND GENERAL EXPENSES 4,003,827 1,470,361 93,909 812,078 1,241,268 6,313 133,126 37,869 73,683 98,811 36,409 16 CHARITABLE CONTRIBUTIONS 0 0 0 0 0 0 0 0 0 0 0 17 DEPRECIATION EXPENSE 4,888,064 1,448,451 107,719 945,862 1,962,438 6,968 93,762 44,906 78,216 146,758 52,983 18 AMORTIZATION OF BIG STONE PLANT CAPITALIZED COSTS 0 0 0 0 0 0 0 0 0 0 0 19 SPIRITWOOD AMORTIZATION 0 0 0 0 0 0 0 0 0 0 0 20 GENERAL TAXES 969,399 289,988 21,728 188,062 380,752 1,559 20,422 8,845 16,538 30,725 10,779 21 22 TOTAL OPERATING EXPENSES 30,893,109 9,430,351 649,308 5,892,687 12,218,737 31,806 589,109 286,200 429,107 1,020,124 345,680 23 24 25 NET OPERATING INCOME BEFORE INCOME TAXES 2,210,428 505,460 74,032 953,055 705,576 (8,107) 47,501 (272) (49,751) (40,108) 23,042 26 27 28 INCOME TAX EXPENSE 29 INVESTMENT TAX CREDIT (123,560) (37,139) (2,783) (24,015) (48,277) (203) (2,647) (1,128) (2,131) (3,873) (1,366) 30 DEFERRED INCOME TAXES 441,070 131,943 9,886 85,567 173,240 709 9,292 4,024 7,525 13,980 4,905 31 INCOME TAXES (838,041) (283,439) (13,615) (52,453) (363,566) (3,784) (17,412) (11,942) (32,575) (49,631) (9,625) 32 33 TOTAL INCOME TAX EXPENSE (520,532) (188,636) (6,511) 9,099 (238,603) (3,277) (10,768) (9,046) (27,180) (39,524) (6,086) 34 35 36 37 NET OPERATING INCOME 2,730,960 694,096 80,544 943,955 944,179 (4,830) 58,268 8,774 (22,570) (583) 29,127 38 39 40 ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION 0 0 0 0 0 0 0 0 0 0 0 41 42 43 TOTAL AVAILABLE FOR RETURN 2,730,960 694,096 80,544 943,955 944,179 (4,830) 58,268 8,774 (22,570) (583) 29,127 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 159 of 164 Docket No. EL18-___ Volume 4A Section 2
Statement N Otter Tail Power Company Page 9 of 9 STATEMENT N CLASS COST OF SERVICE STUDIES 2017 TEST YEAR
Line No. Description
1 The remaining detail of the 2017 Test Year Class Cost of Service Study can be found 2 in Volume 4A, Tab - 2017 Test Year Work Papers.
Page 160 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement O Comparision of Cost of Service Page 1 of 1 2017 Test Year
(A) (B) (C) (D) (E) (F) (G)
Line Net Operating Average Rate % Rate of No. Customer Group Rate Status Revenue Expenses Income Base (1) Return
1 Residential Service Present 9,719,778 9,233,127 486,651 25,404,562 1.92% 2 Proposed 11,545,783 9,617,097 1,928,686 25,344,420 7.61% 3 4 Farm Service Present 707,153 641,901 65,252 1,898,658 3.44% 5 Proposed 834,363 668,618 165,745 1,894,590 8.75% 6 7 General Service Present 6,705,641 5,896,966 808,674 16,465,198 4.91% 8 Proposed 7,843,196 6,135,479 1,707,717 16,427,909 10.40% 9 10 Large General Service Present 12,640,664 11,970,625 670,039 33,390,343 2.01% 11 Proposed 15,022,291 12,471,423 2,550,869 33,313,128 7.66% 12 13 Irrigation Present 22,538 28,285 (5,748) 134,374 -4.28% 14 Proposed 27,605 29,355 (1,750) 134,193 -1.30% 15 16 Outdoor Lighting Present 621,396 575,935 45,461 1,780,976 2.55% 17 Proposed 740,002 600,877 139,125 1,777,263 7.83% 18 19 Other Public Authority Present 279,339 276,894 2,445 775,274 0.32% 20 Proposed 345,217 290,815 54,401 773,465 7.03% 21 22 Controlled Water Heating Present 367,036 399,460 (32,424) 1,433,739 -2.26% 23 Proposed 435,402 413,839 21,563 1,431,125 1.51% 24 25 Controlled Service - Interruptible Present 957,127 977,132 (20,005) 2,680,432 -0.75% 26 Proposed 1,136,780 1,014,918 121,862 2,673,844 4.56% 27 28 Controlled Service Deferred Present 360,692 338,231 22,461 941,346 2.39% 29 Proposed 428,835 352,561 76,274 939,142 8.12% 30 31 Totals Present 32,381,363 30,338,556 2,042,808 84,904,903 2.41% 32 Proposed 38,359,473 31,594,983 6,764,490 84,709,079 7.99%
(1) There is an immaterial change in Average Rate Base when incorporating the proposed revenue increase in each of the customer classes due to changes in the cash working capital calculation.
Page 161 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Statement P Derivation of Base Cost of Energy (Used for Fuel Cost Adjustment Factor) Page 1 of 1 For the Test Year Ended December 31, 2017
(A) (B) (C) (D) (E) (F) (G)
Line Adjusted Actual Cost Actual Cost No. Description Energy KWH Adjustments Energy KWH As Filed Adjustments Adjusted
1 Otter Tail Power Company Generation 2 Steam Plant Generation 2,360,467,677 38,993,828 (1) 2,399,461,505 $58,207,716 $1,022,144 (1) $59,229,860 3 Hydro Plant Generation 25,128,461 25,128,461 0 $0 $0 4 Steam Plant Reagents & Emission Allowance Purchase - 2,152,138 $2,152,138 5 Wind Generation 509,346,434 509,346,434 $0 6 - $0 7 Other Plant Generation 36,702,828 36,702,828 1,484,623 $0 $1,484,623 8 2,931,645,400 38,993,828 2,970,639,228 $61,844,477 $1,022,144 $62,866,621 9 10 Purchased Energy (including purchases from MISO) 2,135,655,325 0 2,135,655,325 59,277,175 $0 59,277,175 11 12 Total Energy and Cost 5,067,300,725 38,993,828 5,106,294,553 $121,121,653 $1,022,144 $122,143,797 13 14 Less Intersystem Sales (199,838,135) (199,838,135) ($4,092,173) $0 ($4,092,173) 15 16 Net Energy and Costs 4,867,462,590 38,993,828 4,906,456,418 $117,029,480 $1,022,144 $118,051,624 17 18 19 Energy Reduced for 8% Average System Loss on Retail Sales 4,478,065,583 4,513,939,905 20
21 Base Rate for Fuel Adjustment Clause - Actual $0.026134 Base Rate for Fuel Adjustment Clause - AdjustedAdjusted $0.026153 22 (Actual is line 8, Column (E)/line 9, Column (B)) (Adjusted is line 8, Column (D)/line 9, Column (G))
Weather Weather Normalized Cost (1) System Weather Normalization Summary Normalized kWhs of Energy $'s Minnesota 15,711,499 $431,471 North Dakota 17,420,410 $457,444 South Dakota 5,861,918 $133,229 (a) Total System 38,993,828 $1,022,144
(a) Operating Income Schedule C-8 Column E Line 4, TY-05
Page 162 of 164 Docket No. EL18-___ Volume 4A Section 2 Statement Q Page 1 of 1
Otter Tail Power Company Description of Utility Operations
Otter Tail Power Company (OTP), a wholly owned subsidiary of Otter Tail Corporation, is an electric utility, whose address is 215 South Cascade Street, Fergus Falls, Minnesota, 56537, and telephone number is (218) 739-8200. OTP is a Minnesota corporation and is duly authorized to do business in the State of South Dakota. OTP owns and operates an integrated electric utility system providing electric utility service at retail in northeastern South Dakota, eastern North Dakota, and western Minnesota. Based on December 31, 2017, OTP serves 132,100 retail electric customers, of which 11,588 are located in South Dakota. OTP’s service territory covers a 70,000 square mile area of Minnesota, North Dakota, and South Dakota.
OTP’s service territory is predominately rural. OTP’s integrated system serves approximately 454 incorporated and unincorporated communities of which 54 are in South Dakota. To illustrate the rural nature of the communities, the average population of the communities we serve is approximately 400, and over one-half of the communities we serve have populations of fewer than 200. Only three of our communities have populations exceeding 10,000: Jamestown, North Dakota (pop. 15,427), Fergus Falls, Minnesota (pop. 13,138), and Bemidji, Minnesota (pop. 13,431). In South Dakota, the largest towns are Milbank (3,353), Sisseton (2,470), Britton (1.241), and Clear Lake (1,273). OTP also serves customers at retail outside of the platted areas of municipalities. OTP owns a total of 5,863 miles of transmission line. To help provide more reliable service at lower cost in the long term, our electric system is interconnected directly with neighboring suppliers.
OTP owns and operates generating stations, which supply a large portion of its power. OTP is the operating agent of two jointly owned generating plants. The first generating plant is the Big Stone Plant in northeastern South Dakota. Big Stone Plant has been in commercial operation since May 1975. The second generating plant known as the Coyote Station is located in western North Dakota. Commercial operation of Coyote Station began on May 1, 1981. OTP has sole ownership and operation of the Hoot Lake Plant located at Fergus Falls, Minnesota. OTP also owns peaking plants that are located in Jamestown, North Dakota, Lake Preston, South Dakota, and Solway, Minnesota. OTP’s most recent generation investments are wind generation near Langdon, Ashtabula and Luverne, North Dakota.
Breakdown of Sales Between Jurisdictional and Nonjurisdictional
Of OTP’s total electric energy sales of 4,241,735,827 kWh, 411,821,658 kWh are under the jurisdiction of the South Dakota Public Utilities Commission. See Statement I, Page 1 of 2.
Status of Latest Rate Proceeding
OTP’s most recent electric rate proceeding (Docket No. EL10-011) was filed with the South Dakota Public Utilities Commission on August 20, 2010. Final rates were approved by the South Dakota Public Utilities Commission and placed into effect on June 1, 2011.
Page 163 of 164 Docket No. EL18-___ Volume 4A Section 2
Otter Tail Power Company Sched R PURCHASES FROM AFFILIATED COMPANIES Page 1 of 1 2017 Test Year
Line No. Description 1 There are no costs associated with purchases from affiliated companies included in this rate case 2 filing.
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