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 2A
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 2A – Section 1
Direct Testimony and Supporting Schedules – Section 1
Volume 2A
Direct Testimony and Supporting Schedules
Bruce G. Gerhardson
Before the South Dakota Public Utilities Commission State of South Dakota
In the Matter of the Application of Otter Tail Power Company For Authority to Increase Rates for Electric Utility Service in South Dakota
Docket No. EL18-___
Exhibit___
POLICY
Direct Testimony and Schedules of
BRUCE GERHARDSON
April 20, 2018
TABLE OF CONTENTS
I. INTRODUCTION AND QUALIFICATIONS...... 1 II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY ...... 1 III. DESCRIPTION OF OTP ...... 10 Summary ...... 10 Facilities ...... 11 Capital Expenditures ...... 12 Service Area ...... 13 Rates and Customer Satisfaction ...... 14 Customer Information System Upgrade ...... 19 IV. CAPITAL INVESTMENTS AND MITIGATION OF CAPITAL COSTS...... 20 V. COST INCREASES AND MITIGATION OF COSTS ...... 24 VI. OTHER PROPOSALS ...... 27 VII. INTRODUCTION OF WITNESSES ...... 28 VIII. CONCLUSION ...... 29
ATTACHED SCHEDULES
Schedule 1 – Qualifications and Experience of Bruce Gerhardson
1 I. INTRODUCTION AND QUALIFICATIONS
2 Q. PLEASE STATE YOUR NAME AND OCCUPATION. 3 A. My name is Bruce Gerhardson. I am employed by Otter Tail Power Company (OTP) as 4 Vice President of Regulatory Affairs. 5 6 Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE. 7 A. I have worked for OTP for over 17 years. During my first 16 years, I worked as Associate 8 General Counsel, representing OTP in numerous regulatory proceedings. In 2012, OTP 9 added management of regulatory services and compliance to my duties. In 2017, I was 10 appointed Vice President, Regulatory Affairs. My current duties include providing 11 direction and supervision for OTP’s Regulatory Services, Regulatory Compliance, 12 Market Planning and Strategic Planning areas. My qualifications and experience are more 13 fully described on Exhibit___(BGG-1), Schedule 1.
14 II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY
15 Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? 16 A. My Direct Testimony gives an overview of OTP’s requests in this case. 17 18 Q. PLEASE PROVIDE A BRIEF OVERVIEW OF YOUR DIRECT TESTIMONY. 19 A. I provide background on OTP and why OTP is requesting a rate increase. I provide a 20 summary of information showing the high levels of customer satisfaction OTP has 21 achieved, and I describe some of our recent capital expenditures, including the very large 22 recent projects that OTP successfully completed under budget. I also discuss some of the 23 significant sources of OTP’s revenue deficiency and introduce OTP’s other witnesses. 24 25 Q. HOW IS YOUR DIRECT TESTIMONY ORGANIZED? 26 A. In Section III, I provide a description of OTP, including: facilities, capital expenditures, 27 OTP’s service area, OTP’s small size, OTP’s rates and customer satisfaction and OTP’s 28 customer information system upgrade. In Section IV, I discuss OTP’s capital investments
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1 and what we’ve done to manage our capital costs. In Section V, I discuss cost increases 2 and mitigation of costs. In Section VI, I discuss other proposals including rate designs. In 3 Section VII, I introduce the other OTP witnesses and Section VIII presents my 4 conclusions. 5 6 Q. PLEASE SUMMARIZE OTP’S REQUEST IN THIS CASE. 7 A. OTP is requesting an increase to non-fuel base revenue. As part of the request, OTP 8 proposes to transition costs currently recovered through OTP’s Environmental Cost 9 Recovery Rider (ECRR) and completed project costs recovered through OTP’s 10 Transmission Cost Recovery Rider (TCRR) into base rates at the commencement of 11 Interim Rates in this case. To facilitate this transition from rider to base rate recovery, 12 OTP proposes to discontinue the associated recoveries through its ECRR and TCRR 13 contemporaneous with Interim Rates going into effect. 14 Excluding the effect of the rider-to-base-rate transition, the increase in non-fuel 15 base revenue is $3,358,574, or 10.10 percent. The effect of the proposed increase to base 16 rates and the transition of rider recoveries to base rates — if considered in isolation, 17 without also taking into consideration the corresponding reduction to rider revenues -- is 18 $5,978,109, or 19.50 percent. The transition of costs from riders to base rates does not 19 increase customer bills, however, as it merely moves recovery from the rider mechanisms 20 to the base rate mechanism. Therefore, the net effect of the requested increase is 10.10 21 percent, as indicated above. 22 23 Q. WHAT IS DRIVING OTP’S NEED FOR A REVENUE INCREASE? 24 A. Our current South Dakota base rates were set in 2011 based on a 2009 Test Year (Docket 25 No. EL10-011). We have made significant system investments since that case, with net 26 plant in service increasing 17 percent. The current income deficiency relating to 27 increased rate base investment since that case is $1.6 million, while net operating income 28 grossed up for taxes and before the effect of rider roll-in has decreased $1.7 million, 29 resulting in a net deficiency of $3.3 million. The deficiency is net of the impacts of the 30 Tax Cuts and Jobs Act which reduced the request by approximately $1.2 million.
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1 Operations and maintenance (O&M) costs have increased since the 2009 Test 2 Year. Despite working to control both capital and O&M costs, including placing the Big 3 Stone Air Quality Control System (AQCS) project in service on-time and over $125 4 million under budget, a rate increase is necessary for OTP to continue providing 5 electricity in a reliable, economic and environmentally responsible manner. 6 OTP’s revenue deficiency reflects a return on equity (ROE) of 10.30 percent, an 7 equity ratio of 53.10 percent, and an overall rate of return on investment (ROR) of 7.96 8 percent. This is a reduction from the currently authorized 8.50 percent ROR. 9 OTP has maintained its base rates without increase (based on the historic Test 10 Year) for 8 years despite the fact OTP’s sales have increased by an annual average of 11 only 0.69 percent over the sales used for setting OTP’s rates in the 2009 Test Year (5.5 12 percent in aggregate over that period). OTP’s overall rates for electric service in South 13 Dakota are the second lowest among South Dakota investor-owned utilities and have 14 been so for several years—MidAmerican Energy is the only such utility with lower rates. 15 OTP has been able to keep rates low by making cost containment a priority for capital 16 projects and O&M costs. Given the passage of time, however, OTP now requires 17 increased base rates to address cost increases that have occurred since our last general 18 rate case, despite our best efforts. 19 20 Q. HAS OTP LOCATED ANY OF ITS SIGNIFICANT RECENT SYSTEM 21 INVESTMENTS IN SOUTH DAKOTA? 22 A. Yes. OTP has been a leader in making beneficial infrastructure investments in South 23 Dakota. For example, OTP is the operator and majority owner of the Big Stone Power 24 Plant, located near Big Stone, South Dakota. Late in 2015, OTP completed a $365.5 25 million AQCS upgrade to the Big Stone Plant. This was the largest single infrastructure 26 investment in OTP’s history, and it was one of the largest single business investments 27 ever made by anyone in the state of South Dakota. OTP served as the construction 28 manager for the project and was very successful in managing costs. The project was 29 completed more than $125 million under budget. The project and cost savings are
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1 described in greater detail later in this testimony and in the Direct Testimony of OTP 2 witnesses Mr. Kirk A. Phinney and Mr. Stuart D. Tommerdahl. 3 OTP has also made some of the largest investments in transmission in South 4 Dakota’s history. OTP is approximately a 50 percent owner in the Big Stone South to 5 Brookings and the Big Stone South to Ellendale 345 kV transmission projects. The Big 6 Stone South to Brookings project was completed and placed into service in 2017. The 7 Big Stone South to Ellendale is currently under construction and scheduled for 8 completion by the end of 2019. These are very large and expensive transmission projects. 9 The total capital costs of these projects are projected at $140 million and $250 million, 10 respectively (Total Project). They are classified as multi-value projects (MVPs) under the 11 MISO tariff, which qualifies them for MISO-wide regional allocation of costs. OTP 12 completed the Big Stone South to Brookings line more than $61.3 million under budget 13 (Total Project), and the Big Stone South to Ellendale line is also currently expected to 14 come in under budget. 15 These completed and planned infrastructure investments demonstrate OTP’s 16 significant commitment to beneficial investment in infrastructure in the state of South 17 Dakota. While South Dakota is home to just 8.8 percent of OTP’s customers, these recent 18 and additional near-term investments in South Dakota (including the Astoria Station 19 Project, discussed below) will count for 36.0 percent of OTP’s total plant in service by 20 2021. The investments have and will continue to provide very significant economic 21 benefits to the State of South Dakota. 22 These projects are not just beneficial from the perspective of economic 23 development in South Dakota. They will contribute to economical electric service to 24 numerous electric customers, for OTP and other utilities. The Big Stone AQCS project 25 will benefit the customers of Montana Dakota Utilities and NorthWestern Energy, in 26 addition to OTP’s customers, as those utilities are co-owners of the Big Stone Plant and 27 their allocated capital costs are lower because of OTP’s exceptional performance on the 28 project. And, the Big Stone Area Transmission projects were designed and constructed to 29 serve 30 million customers in a region that includes fifteen U.S. states and Manitoba, 30 Canada. The substantial cost savings OTP has achieved by bringing the projects to
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1 completion under budget will benefit these millions of customers through lower 2 transmission rates. 3 These beneficial infrastructure investments are very large commitments for a 4 small utility like OTP, and as the Commission considers OTP’s requests in this case, we 5 ask that the Commission also consider the significant investments we have made in South 6 Dakota and our exceptional performance in bringing them to completion. 7 8 Q. IS OTP PLANNING OTHER INFRASTRUCTURE INVESTMENT FOR 9 CONSTRUCTION IN SOUTH DAKOTA? 10 A. Yes. OTP is planning to construct a 250 MW natural gas generation project near Astoria, 11 South Dakota (the Astoria Station Project). The Astoria Station Project is expected to be 12 in service in early 2021 at a cost of approximately $160 million (OTP Total). The 13 Commission is currently evaluating the siting permit application for the Astoria Station 14 Project in Docket No. EL17-042. It is planned to go into service in the spring of 2021. 15 Costs for this project are not included in this rate case. 16 17 Q. DOES OTP HAVE OTHER SYSTEM INFRASTRUCTURE INVESTMENTS 18 PLANNED THAT ARE NOT LOCATED IN SOUTH DAKOTA? 19 A. Yes. OTP is planning to construct a 150 MW wind project near Merricourt, North Dakota 20 (the Merricourt Wind Project). OTP anticipates the Merricourt Wind Project will go into 21 service in 2019. 22 23 Q. WHAT ARE SOME OF THE OTHER FEATURES OF OTP’S RATE PROPOSAL IN 24 THIS CASE? 25 A. OTP’s overall revenue deficiency has been calculated using a 2017 historical Test Year 26 with known and measurable changes. OTP also proposes to transfer certain costs 27 currently being recovered though OTP’s TCRR and ECRR to base rates as indicated 28 above. 29 Rolling the rider costs into base rates will not materially impact customers’ bills, 30 as the base rate revenue requirement increase caused by the transfer of costs will be offset
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1 by a corresponding decrease to the revenue requirements of the TCRR, and ECRR. Other 2 OTP witnesses, including Mr. Tommerdahl, Mr. Tyler A. Akerman and Mr. Bryce C. 3 Haugen, provide more information on OTP’s proposal to transfer TCRR and ECRR costs 4 to base rates. 5 6 Q. HAVE YOU MADE A REQUEST IN THIS CASE TO ADDRESS THE COSTS YOU 7 WILL SPEND ON THE MERRICOURT WIND PROJECT? 8 A. Yes. We are requesting that the Commission authorize a step increase to facilitate 9 recovery for the Merricourt Wind Project when it is placed into service. This step 10 increase in rates is described in the Direct Testimony of Mr. Akerman. The step increase 11 will permit OTP to commence recovery when the project is placed in service and without 12 the cost and regulatory burden of an additional general rate case. 13 As the Commission is aware, the cost of administering a rate case can be 14 significant—both to the utility and the Commission--and when one considers that the 15 costs are generally recoverable from customers, reducing the regulatory costs and 16 burdens is very much in customers’ and the public’s interest. To be specific, if a rate case 17 might cost $550,000, those costs must ultimately be spread across OTP’s 11,700 South 18 Dakota customers, which means a single rate case can cost each South Dakota customer, 19 on average, over $43, just for the costs of administering the case. OTP estimates that the 20 increases expected with the addition of the Merricourt Wind Project will largely be off- 21 set by reductions to fuel and purchased power costs, and those reductions will 22 automatically get reflected in reduced FCA charges. The total changes to bills anticipated 23 by the step increase of the Merricourt Wind Project are just 2 percent, and therefore, it 24 would appear imprudent and impractical to trigger a general rate proceeding that might 25 cost $43 per customer when the effective annual bill increase related to the project is 26 expected to be approximately $20 for Residential customers, on average. 27
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1 Q. ARE THERE OTHER REASONS WHY IT IS REASONABLE TO ADDRESS THE 2 MERRICOURT WIND PROJECT THROUGH A STEP INCREASE? 3 A. Yes. As indicated above, OTP is planning to construct the Astoria Station Project by 4 2021, and it is expected this will necessitate a rate case. OTP believes it is 5 administratively efficient, and consistent with customers’ and the public’s interest to use 6 a step-in mechanism for the Merricourt Wind Project as proposed in this case and to 7 review all costs related to the project in OTP’s next rate case, which is expected by 2021, 8 to accommodate recovery of the Astoria Station Project. 9 The step increase proposed in this case to accommodate recovery for the 10 Merricourt Wind Project is administratively effective and economic for our customers 11 and therefore should be approved. 12 13 Q. ARE YOU MAKING A REQUEST FOR INTERIM RATES IN THIS CASE? 14 A. Yes. We have requested authorization to implement Interim Rates 30 days following 15 submission of this case. The interim rate collections will be refundable to customers to 16 the extent they are more than the Commission’s final determinations in the case. 17 18 Q. PLEASE SUMMARIZE OTP’S INTERIM RATE REQUEST. 19 A. OTP requests authority to implement Interim Rates 30 days following its filing of this 20 request. The Interim Rates have been adjusted to remove any known and measurable 21 changes that will not yet have occurred within the interim rate period. The Interim Rates 22 also provide a vehicle through which OTP will recognize tax rate changes that have 23 occurred under the Tax Cuts and Jobs Act. The Interim Rates will be refundable to ensure 24 that they will be consistent with the ultimate decision of the Commission in this case. For 25 these reasons, OTP’s interim rate request is consistent with and necessary for the 26 establishment of just and reasonable rates and consistent with the public interest. 27 28 Q. PLEASE EXPLAIN THE BASIS FOR YOUR INTERIM RATE REQUEST. 29 A. As indicated above, OTP’s request is based on a 2017 historic Test Year, and therefore 30 the 2017 Test Year demonstrates that OTP has a current revenue deficiency at the time of
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1 the rate case filing. OTP’s Interim Rate Request has also been adjusted to remove any 2 known and measurable changes that are included in the final rate 2017 Test Year but for 3 which the changes will not have yet occurred during the interim rate period. This ensures 4 that known and measurable adjustments for changes occurring beyond the interim period 5 are not the cause of any identified deficiency in the interim period. Also, the Interim 6 Rates will be refundable to the extent they exceed the Commission’s final determinations 7 in this case. These protections ensure that the Interim Rates will apply only to the extent 8 that OTP ultimately demonstrates a deficiency existed during the interim rate period. As a 9 matter of regulatory principle, the rates charged by a utility should be just and reasonable, 10 which means that a utility should be permitted to recover its costs and a fair rate of return 11 on its investments. Regulatory lag caused by limiting a utility to the use of an historical 12 Test Year and without Interim Rates leaves a utility without any reasonable opportunity 13 to recover its prudently incurred costs of providing service. 14 15 Q. IS OTP’S INTERIM RATE REQUEST CONSISTENT WITH SOUTH DAKOTA 16 LAW? 17 A. Yes. OTP’s Transmittal Letter and Application provide an explanation of why the request 18 is consistent with South Dakota Law. 19 20 Q. HAS THE COMMISSION TAKEN STEPS THAT SUPPORT THE 21 IMPLEMENTATION OF INTERIM RATES ON OTP’S PROPOSED TIMELINE? 22 A. Yes. The Commission’s actions relating to recent changes under the Tax Cuts and Jobs 23 Act are an example that it is not reasonable to delay a rate change when it can be 24 demonstrated that the cost of utility service has changed. As the Commission recognized
25 in its December 29, 2017 ORDER REQUIRING COMMENTS; ORDER REQUIRING RATES IN
26 EFFECT JANUARY 1, 2018, ARE SUBJECT TO REFUND; ORDER GRANTING INTERVENTION, in
27 Docket No. GE17-003 (Order), the change to tax rates under the Tax Cuts and Jobs Act 28 (TCJA) would result in a change to utilities’ cost of service, and therefore the Order 29 commenced an examination into the possible cost of service impacts of the change. The 30 Commission ruled that rates charged by utilities on and after January 1, 2018, will be
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1 subject to refund or any other ratemaking treatment which ensures ratepayers receive the 2 benefits of the tax change as of January 1, 2018. The Commission’s Order was issued on 3 December 29, 2017, with an effective date of January 1, 2018, which serves as support 4 that the Commission has previously authorized reasonable measures to prevent 5 procedural lag in the setting of just and reasonable rates. In this case, the Order serves as 6 more than a regulatory precedent, too, given that it is intended to cover the same cost of 7 service period as the period covered by OTP’s interim rate request (the 2018 calendar 8 year). 9 10 Q. HAS OTP REFLECTED THE CHANGE TO TAX RATES IN THE TEST YEAR AND 11 IN THE INTERIM RATE REQUEST? 12 A. Yes. Even though OTP has filed this case using a historic 2017 Test Year, which was 13 prior to the effective date for the TCJA tax changes, OTP has included known and 14 measurable changes in its 2017 Test Year cost of service to reflect the changes to the tax 15 code which took effect on January 1, 2018. In its interim rate request, OTP has retained 16 the known and measurable changes related to the TCJA, as they will be in effect during 17 the proposed interim rate period. This treatment allows a matching up of the tax-related 18 changes to the cost of service with other changes to OTP’s cost of service. 19 20 Q. CAN YOU SUMMARIZE THE PROPOSED EFFECTIVE DATES OF THE 21 COMPONENTS OF THE COMPANY’S RATE PROPOSAL? 22 A. As I noted earlier, OTP proposes that Interim Rates go into effect 30 days after filing the 23 Application. OTP’s proposed rates, sometimes referred to as Final Rates, would then be 24 effective upon the Commission’s final disposition of the Company’s Application, which 25 we would expect to occur approximately January 1, 2019. Under OTP’s proposal, if the 26 Commission suspends or does not authorize Interim Rates, the proposed Final Rates 27 would be effective 180 days from the Application’s filing date and remain in effect 28 pending the Commission’s final disposition of OTP’s Application. Finally, OTP has 29 proposed a Step Increase for the Merricourt Wind Project that would be effective January 30 1, 2020.
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1 III. DESCRIPTION OF OTP
2 Summary 3 Q. PLEASE BRIEFLY DESCRIBE OTP. 4 A. OTP provides retail electric service to approximately 132,100 customers, including 5 approximately 11,700 in South Dakota, 61,700 in Minnesota, and 58,800 in North 6 Dakota. OTP serves 454 communities and rural areas in northeastern South Dakota, 7 western Minnesota and the eastern two-thirds of North Dakota. In South Dakota, OTP 8 serves 54 communities. Our 70,000 square-mile service territory is roughly the size of 9 Wisconsin. OTP is headquartered in Fergus Falls, Minnesota and is a subsidiary of Otter 10 Tail Corporation, which has its headquarters in Fargo, North Dakota. 11 12 Q. HAVE THERE BEEN CHANGES IN OTP’S RELATIONSHIP TO OTTER TAIL 13 CORPORATION SINCE OTP’S LAST SOUTH DAKOTA RATE CASE? 14 A. Yes. Since OTP’s last rate case, Otter Tail Corporation has substantially reduced the 15 number and scope of its non-utility operations and increased its focus on OTP. In 2009, 16 Otter Tail Corporation had 12 non-utility operating companies; it now has just 4. 17 18 Q. HOW MANY PEOPLE DOES OTP EMPLOY? 19 A. In 2017, OTP had an average of 776 full-time equivalent employees, including 20 approximately 390 union employees and 386 non-union employees (not adjusted for 21 employees of jointly owned plants). 22 23 Q. WHAT IS OTP’S MISSION? 24 A. OTP’s mission is: “To produce and deliver electricity as reliably, economically, and 25 environmentally responsibly as possible to the balanced benefit of customers, 26 shareholders, and employees and to improve the quality of life in the areas in which we 27 do business.”
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1 Facilities 2 Q. PLEASE BRIEFLY DESCRIBE OTP’S GENERATION AND TRANSMISSION 3 FACILITIES. 4 A. OTP operates three coal-fired base load generating plants: Coyote at 427 megawatts 5 (MW), located near Beulah, North Dakota, Big Stone at 475 MW, located near Big 6 Stone, South Dakota, and Hoot Lake at 138 MW, located near Fergus Falls, Minnesota, 7 and three peaking plants: Jamestown 1 and 2 at 42.5 MW, located in North Dakota, Lake 8 Preston at 20 MW, located in South Dakota, and Solway at 43.7 MW, located in 9 Minnesota. We also own five hydroelectric stations on the Otter Tail River near Fergus 10 Falls, Minnesota, and one on the Mississippi River near Bemidji, Minnesota. 11 OTP owns three major wind farms, all located in North Dakota: Langdon at 40.5 12 MW, Ashtabula at 48 MW, and Luverne at 49.5 MW. OTP also owns several smaller 13 wind facilities and procures wind energy from other facilities through purchase power 14 agreements. 15 OTP owns a total of 5,863 miles of transmission line. Our electric system is 16 interconnected with the facilities of several neighboring suppliers. 17 18 Q. IS OTP A MEMBER OF A REGIONAL RELIABILITY ORGANIZATION AND 19 REGIONAL INDEPENDENT SYSTEM OPERATOR? 20 A. Yes. OTP is a member of the Midwest Reliability Organization (MRO), the regional 21 reliability council of the North American Electric Reliability Corporation (NERC) that 22 develops and establishes planning and operating reliability standards in the Midwest 23 region with which utilities must comply. OTP is also a member of the Midcontinent 24 Independent System Operator (MISO). MISO serves as the operator of the regional 25 transmission system, performs Balancing Authority functions of the NERC standards, 26 and implements a regional resource adequacy mechanism for the sharing of generation 27 reserves, all with the goal of lowering costs.
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1 Capital Expenditures 2 Q. IS OTP ENGAGED IN AN EXTENSIVE CAPITAL EXPENDITURE PROGRAM? 3 A. Yes. OTP has been engaged in an extensive capital expenditure program since 2012 that 4 is expected to continue through 2021. OTP invested approximately $806 million (OTP 5 Total) between 2012 and 2017 and is expected to invest an additional $901 million (OTP 6 Total) between 2018 and 2021.1 OTP’s investments between 2012 and 2017 have focused 7 on upgrading our facilities and environmental compliance at our generating plants 8 (including the AQCS project at our Big Stone plant) and strengthening our transmission 9 system, along with routine replacements, upgrades and extensions. 10 11 Q. PLEASE BRIEFLY DESCRIBE THE AQCS PROJECT. 12 A. The AQCS project is OTP’s largest ever single capital expenditure. The AQCS project 13 reduces nitrogen oxides and sulfur dioxide emissions at our Big Stone plant by 14 approximately 90 percent and reduces mercury emissions by approximately 80 percent. 15 The AQCS project came on line on December 29, 2015, more than $125 million (Total 16 Project) below budget. 17 The AQCS project also demonstrates the importance safety plays in our mission. 18 Constructing the project took over 2.3 million worker hours and the project had only one 19 lost time accident and an OSHA rate of approximately 0.88. The AQCS project is 20 described in detail in the Direct Testimony of Mr. Phinney. 21 22 Q. HAS OTP ALSO COMPLETED OTHER RECENT CAPITAL EXPENDITURES 23 UNDER BUDGET? 24 A. Yes. For example, OTP was also able to complete its Hoot Lake Plant Mercury and Air 25 Toxics Standards (MATS) project under budget. This project is also described in greater 26 detail in the Direct Testimony of Mr. Phinney.
1 Excluding AFUDC.
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1 Service Area 2 Q. PLEASE DESCRIBE THE COMMUNITIES OTP SERVES. 3 A. OTP serves very small communities. The average population of our communities in our 4 service area is approximately 400 people, and over sixty percent of OTP’s communities, 5 system wide, have populations of fewer than 200 people. Milbank is the largest 6 community OTP serves in South Dakota. It has a population of 3,353. 7 8 Q. DO YOU HAVE AN ILLUSTRATION THAT INCLUDES OTP’S SERVICE AREA 9 AND FACILITY LOCATIONS? 10 A. Yes. Figure 1 provides an overview of OTP’s service area, generating facilities and 11 customer service centers. 12
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1 Figure 1 2 Overview of OTP Service Area, Generation Facilities and Customer Service Centers
3 4 5 Q. HOW DOES OTP COMPARE IN SIZE TO OTHER UTILITIES? 6 A. OTP is very small in terms of number of total retail customers and retail revenues 7 generated. OTP is the second smallest investor-owned utility in the United States. 8
9 Rates and Customer Satisfaction 10 Q. HAS OTP’S SMALL SIZE AND SPARSELY POPULATED SERVICE AREA 11 PREVENTED OTP FROM DELIVERING ELECTRICITY ECONOMICALLY? 12 A. No. Despite the challenges posed by being a very small utility and serving customers in a 13 very large, sparsely populated service territory with very substantial capital expenditures, 14 OTP has been successful in maintaining low electric rates.
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1 Figure 2 compares OTP’s rates to the rates of other South Dakota investor-owned 2 utilities and to the national average since 2011 (the rates reflect an average of all 3 customer classes and include all bill components—i.e. all fuel and purchased power and 4 all riders). 5 Figure 2 6 Rates 2011-2017
South Dakota Rate Comparison All Bills Data 2011 - 2017 13.0
12.0
11.0
10.0
9.0
8.0
Cents Cents per Kilowatt hour 7.0
6.0
5.0 Dec '11 Dec '12 Dec '13 Dec '14 Dec '15 Dec '16 July '17 BHP-SD Mid-Am-SD MDU-SD NWE-SD OTP-SD Xcel-SD National Average
7 8 9 Q. HOW HAS OTP BEEN ABLE TO MAINTAIN THESE LOW RATES? 10 A. These low rates are a direct result of successful execution on our capital project 11 investments and our efficient operations. We have recently completed our extensive 12 AQCS project at the Big Stone Plant on time and we were able to do so more than $125 13 million below budget (Total Project). OTP has also been successful in managing the costs 14 of other capital expenditures. 15
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1 Q. HAS OTP BEEN RECOGNIZED FOR ITS LOW RATES? 2 A. Yes. In May 2017, Regulatory Research Associates recognized Otter Tail Corporation as 3 the 4th lowest price provider among all utility parent companies in the United States with 4 a blended rate for all customers of 8.16 cents/kWh. 5 6 Q. PLEASE SUMMARIZE OTP’S CUSTOMER SATISFACTION LEVELS. 7 A. OTP continues to be recognized in the industry as having the highest levels of customer 8 satisfaction. OTP’s customers’ satisfaction is demonstrated in several ways, including the 9 American Customer Satisfaction Index, transaction surveys and, for the first time in 10 2015, OTP was included in J. D. Power’s study of electric utility residential customer 11 satisfaction. 12 13 Q. HOW WAS OTP RANKED IN THE J.D. POWER STUDY? 14 A. In each of the last three years, OTP has been recognized as one of the top three utilities in 15 customer satisfaction among midsize utilities in the Midwest in the JD Power Electric 16 Utility Residential Customer Satisfaction Study.SM Also, OTP’s scores have increased 17 each year over those three years. 18 19 Q. PLEASE DESCRIBE THE J.D. POWER STUDY. 20 A. The J.D. Power study analyzes the relative performance of major electric utility 21 companies in the United States in terms of how well they satisfy their residential 22 customers. In 2015, J.D. Power changed the criteria of its study to include utilities with as 23 few as 100,000 residential customers, allowing OTP to participate in this study for the 24 first time. 25 The J.D. Power proprietary study results are based on experiences and perceptions 26 of consumers surveyed annually over the period from July through May. The study 27 measures customers’ satisfaction with their electric utility companies by looking at six 28 factors: power quality and reliability, price, billing and payment, corporate citizenship, 29 communications, and customer service. 30
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1 Q. HAS OTP’S HIGH QUALITY OF SERVICE BEEN RECOGNIZED BY ANY OTHER 2 STUDIES? 3 A. Yes. The American Customer Satisfaction Index (ACSI) also reflects OTP’s high 4 achievement in customer service. The ACSI measures the satisfaction of consumers 5 across the U.S. economy. Key metrics include customer satisfaction, customer 6 expectations, and customer perceptions about the value and quality of their actual 7 experiences, customer complaints, and customer retention. ACSI captures customer 8 opinions about critical elements of the residential customer experience including ability 9 to provide reliable electric service as well as ability to restore electric service following a 10 power outage. For investor-owned utilities, the ACSI conducts additional surveys, 11 gathering customer perceptions each quarter and analyzing customer satisfaction on a 12 rolling basis across the entire year. 13 ACSI compares OTP’s customer satisfaction ratings with those of the top electric 14 and gas investor-owned utilities in the country, which together serve more than 15 75 percent of all residential customers in the United States. 16 17 Q. HOW HAS OTP SERVICE BEEN RATED BY ACSI? 18 A. OTP’s 2016 score for customer satisfaction was 84 out of 100, which was well above all 19 classes of utilities, when each is considered as a group. OTP scored high in every key 20 driver that ACSI measures, including satisfaction, meeting customer expectations, 21 quality, perceived value, customer loyalty, reliability, and service restoration. OTP also 22 had top scores in every category of customer satisfaction that was measured. Figure 3 23 shows that OTP’s 2016 ACSI scores are significantly above the average scores of other 24 investor-owned, cooperative and municipal utilities in every rating category.
17 Docket No. EL18-___ Gerhardson Direct
1 Figure 3 2 2016 ACSI Scores 95 Otter Tail Power Company Investor Owned Utilities Cooperative Utilities 91 90 Municipal Utilities ACSI 2016 Scores 87 88 85 8586 84 83 84 8082 82 80 81 80 80 80 80 78 7879 75 76 76 7574 74 74 7372 73 70 71 69 70
65
3 4 5 Q DOES OTP ALSO USE TRANSACTION SURVEYS TO ASSESS ITS CUSTOMER 6 SATISFACTION ACHIEVEMENT? 7 A. Yes. Bellomy Research, Inc. conducts research to measure customer satisfaction among 8 OTP’s Residential and Commercial customers that make transaction contacts with OTP. 9 Specifically, the research measures: 10 • Satisfaction with overall contact experience and contact handling 11 • Satisfaction with service provided by the Customer Service Representative 12 • Satisfaction with service provided by the Field Service Technician (where relevant) 13 • Resolution and number of times called about the same issue 14 • Overall value for the money 15 Since 2012, over 90 percent of both OTP Residential and OTP Commercial 16 customers have rated Overall Quality of Service as “Very Good” or “Excellent.”
18 Docket No. EL18-___ Gerhardson Direct
1 Customers also remain very satisfied with how agents and field service technicians are 2 handling their requests. 3 4 Q. ARE THERE OTHER RECENT INDICATORS OF OTP’S QUALITY SERVICE? 5 A. Yes. In June 2017, the Edison Electric Institute presented OTP with the association's 6 Emergency Recovery Award for its outstanding restoration efforts after a snow and ice 7 storm hit OTP’s territory on Christmas Day, 2016. EEI's Emergency Recovery Award 8 recognizes member companies that faced difficult circumstances as a result of 9 extraordinary events and put forth an outstanding effort to promptly restore service to the 10 public. The Christmas Day storm produced freezing rain that caused one to two inches of 11 ice accumulation on roads and power lines, and loss of power to more than 4,000 12 residences in South Dakota and 2,200 residences in North Dakota. The award recognized 13 the exceptional performance and achievement of OTP’s crews in restoring power to 14 customers despite these challenging conditions.
15 Customer Information System Upgrade 16 Q. IS OTP MAKING ANY CHANGES TO ITS OPERATIONS THAT WILL FURTHER 17 ENHANCE ITS CUSTOMER SERVICE? 18 A. Yes. We are in the process of replacing our Customer Information System (CIS). OTP’s 19 current CIS is an older, internally-built system, which has been in service for over 30 20 years. The capabilities of this legacy system limit OTP’s ability to implement complex 21 rates and provide services our customers are growing to expect. After an extensive 22 analysis of replacement options and a request for proposal process, OTP selected Cayenta 23 Utilities as the vendor for a new CIS. 24 25 Q. PLEASE DESCRIBE THE STATUS AND FEATURES OF THE NEW CIS. 26 A. OTP is 25 months into implementation of its new CIS, which is sometimes referred to as 27 “CISone.” CISone is scheduled to “go-live” in the 4th quarter of 2018. 28 CISone is a foundational system and building block for other technology that OTP 29 has in its future plans, such as automated metering infrastructure (AMI), mobile work
19 Docket No. EL18-___ Gerhardson Direct
1 management (MWM) technologies, and outage management system (OMS) technologies. 2 The CISone will allow OTP to better align business processes with industry best 3 practices, allowing quicker and more thorough access to information for both employees 4 and customers. While the current CIS relies on overnight batch/file runs to complete the 5 desired processes, the CISone will use application programming interfaces (API) to 6 process tasks in real-time. Customers will have better access to information through 7 online and self-service options. Mr. Tommerdahl further describes CISone and OTP’s 8 proposal pertaining to CISone in his Direct Testimony. 9 10 Q. WHAT IS YOUR CONCLUSION REGARDING CISONE? 11 A. It is reasonable and necessary for OTP to replace the current CIS, and CISone will 12 provide substantial customer benefits.
13 IV. CAPITAL INVESTMENTS AND MITIGATION OF CAPITAL 14 COSTS.
15 Q. PLEASE SUMMARIZE THE CHANGES IN NET PLANT IN SERVICE BETWEEN 16 OTP’S LAST SOUTH DAKOTA RATE CASE AND THIS CASE.
17 A. In 2009, OTP had net plant in service of approximately $813.6 million (OTP Total). 18 Through 2017 Test Year, OTP’s net plant in service will grow to approximately $1.19 19 billion (OTP Total), an increase since 2009 of approximately $376 million (OTP Total). 20 21 Q. PLEASE BRIEFLY DESCRIBE OTP’S RECENT INFRASTRUCTURE ADDITIONS. 22 A. In addition to substantial routine capital expenditures, OTP has made significant capital 23 expenditures in its existing generation facilities and in transmission facilities. As I 24 explained earlier, the AQCS project at the Big Stone Plant is the single largest investment 25 ever made by OTP. The AQCS project includes the following equipment: (i) a dry Flue 26 Gas Desulfurization (FGD) system with a new baghouse; (ii) an ammonia-based 27 Selective Catalytic Reduction (SCR) system; (iii) a Separated Overfire Air (SOFA) 28 system; and (iv) an Activated Carbon Injection (ACI) system. The FGD system and 29 baghouse control sulfur dioxide and particulate matter emissions. The SCR and SOFA
20 Docket No. EL18-___ Gerhardson Direct
1 systems control nitrogen oxide compounds emissions. The ACI system controls mercury 2 emissions. 3 OTP also added the MATS project at the Hoot Lake Plant, which involved the 4 upgrade of Electrostatic Precipitators and the installation of an ACI. The Hoot Lake 5 MATS project controls mercury and particulate matter emissions at the plant. Mr. 6 Phinney describes these projects in his Direct Testimony. 7 OTP has also made substantial investments in new transmission facilities and 8 upgrades, including investments in the following transmission projects: (a) the Brookings 9 County-Hampton 345 kV line. OTP is also making investments in two 345 kV lines that 10 connect to the Big Stone generating facility. (b) the Fargo-St. Cloud-Monticello 345 kV 11 line; and (c) the Bemidji-Grand Rapids 230 kV line. 12 13 Q. PLEASE SUMMARIZE OTP’S EXPECTED CAPITAL EXPENDITURES. 14 A. OTP is expecting to make significant capital expenditures in generation and transmission 15 facilities and in routine projects. Specifically, OTP expects to invest an additional $901 16 (Total Company) million between 2018 and 2021. 17 18 Q. WHAT GENERATION INVESTMENTS IS OTP EXPECTING TO MAKE? 19 A. OTP expects to make significant capital expenditures for the Astoria Station Project and 20 Merricourt Wind Projects, as I described earlier in my testimony. 21 22 Q. WHAT TRANSMISSION INVESTMENTS IS OTP EXPECTING TO MAKE? 23 A. In addition to several smaller transmission projects, OTP has completed the Big Stone 24 South to Brookings 345-kV line in 2017 and will complete the Big Stone South to 25 Ellendale 345-kV line by the end of 2019. 26 27 Q. PLEASE DESCRIBE THE BROOKINGS AND ELLENDALE PROJECTS. 28 A. The Big Stone South to Brookings 345-kV line extends approximately 70 miles, was put 29 in service in September 2017, and is estimated to cost approximately $140 million (Total 30 Project)/ $73.2 million (OTP Total). Xcel Energy and OTP are joint owners. The Big
21 Docket No. EL18-___ Gerhardson Direct
1 Stone South to Ellendale 345-kV line will extend approximately 160 to 170 miles and is 2 estimated to cost approximately $250 million (Total Project)/$124.5 million (OTP Total) 3 and be in service in 2019. OTP and Montana-Dakota Utilities Co. will jointly own the 4 Big Stone South to Ellendale project. 5 6 Q. ARE EITHER OF THESE PROJECTS INCLUDED IN THE 2018 TEST YEAR OR 7 PROPOSED RATES IN THIS CASE? 8 A. Yes. The South Dakota retail share of the Big Stone South to Brookings 345 kV line is 9 included in the 2017 Test Year, consistent with the ratemaking approach approved by the 10 Commission in Docket Nos. EL16-035 and EL12-054 for FERC-approved MVP projects. 11 12 Q. DO YOU HAVE AN ILLUSTRATION THAT SHOWS OTP’S PRIOR AND 13 EXPECTED INVESTMENTS BY SEGMENT? 14 A. Yes. Figure 4 shows OTP’s prior investments from 2010 through 2017 and OTP 15 projected investments from 2018 through 2021, by segment. We currently expect this 16 period of significant investment to taper off after 2021, but given the changing 17 technology in the electric industry, it is possible that this period of investment could 18 continue. 19
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1 Figure 4 2 OTP Prior and Projected Investments by Segment (2008 – 2021) 3 Total Company Costs $350,000,000
$300,000,000
$250,000,000
$200,000,000
$150,000,000
$100,000,000
$50,000,000
$- 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Routine Capital Cap X 2020 Wind Big Stone Plant - AQCS Big Stone Area Transmission HLP MATS Gas Plant Depreciation 4 5 6 Q. WILL THE COMMISSION’S DECISION IN THIS CASE HAVE SIGNIFICANT 7 IMPACTS ON OTP’S COST OF CAPITAL NEEDED FOR THESE INVESTMENTS? 8 A. Yes. As OTP witness Mr. Kevin G. Moug explains in his Direct Testimony, OTP will 9 need access to significant levels of external debt and equity financing, as well as 10 internally generated equity, to complete these significant infrastructure investments. The 11 costs of these external sources of debt and equity financing will be directly affected by 12 investors’ confidence in OTP and in OTP’s regulatory environment. Mr. Moug further 13 explains OTP’s capital needs and the importance of this case to meeting those needs in 14 his Direct Testimony.
23 Docket No. EL18-___ Gerhardson Direct
1 V. COST INCREASES AND MITIGATION OF COSTS
2 Q. HAS OTP TAKEN STEPS TO MANAGE AND CONTAIN COST INCREASES 3 RELATED TO INCREASED CAPITAL EXPENDITURES? 4 A. Yes. In this period of significant capital investment, OTP has paid close attention to the 5 completion of its large infrastructure projects. By managing these projects well, OTP has 6 helped to keep its costs low, with customer benefits extending for the full life of the 7 projects. A good example of this focus is the AQCS project, which was completed over 8 $125 million (Total Project) under budget. It has a 30-year life. The under-budget 9 completion of the AQCS Project reduced the 2017 Test Year revenue requirement for 10 South Dakota customers by approximately $17.2 million over the life of the project, as 11 Mr. Tommerdahl discusses in his Direct Testimony, and it will similarly reduce OTP’s 12 revenue requirement each year for the entire life of the project. Mr. Phinney provides 13 more information on how the AQCS project was managed in his Direct Testimony. He 14 also discusses the Hoot Lake Plant MATS project, which was also completed under 15 budget. 16 17 Q. HAVE OTP’S O&M COSTS ALSO INCREASED SINCE OTP’S LAST RATE CASE? 18 A. Yes. OTP’s Total O&M costs have increased by approximately $6.4 million (OTP SD), 19 which amounts to a 26 percent increase since 2009, or about a 3.2 percent increase 20 annually. Non-fuel O&M costs have increased 46 percent over the same period, or about 21 5.8 percent annually. The main cost increases are due to reagents for the Big Stone Air 22 Quality Control system, transmission costs (SPP and MISO), EEP costs and depreciation 23 expense for the plant additions. More than half of the cost drivers have been covered 24 through rider revenue in the Environmental Cost Recovery Rider, the EEP rider and the 25 Transmission Cost Recovery rider. Without rider revenues OTP’s retail revenues have 26 actually been relatively flat since 2009. OTP’s sales have decreased in every class except 27 Large General Service, Farms, Controlled Service Interruptible and Deferred since 2009. 28 The sales increases have been in classes that have much lower average rates than the 29 classes that have grown. While sales have increased 0.6 percent annually, the base
24 Docket No. EL18-___ Gerhardson Direct
1 revenues have only increased at 0.2 percent annually or just over $500,000 since OTP’s 2 last case. The other, non-rider cost increases since the last case have grown at just one 3 and a half percent per year but the one percent equates to approximately $2.5 million over 4 the period. Adding the return on the growth in rate base of $800,000 and other Test Year 5 adjustments, which offset the small base revenue growth, results in a net deficiency of 6 $3.3 million. The expiration of the Production Tax Credits from OTP’s Langdon and 7 Ashtabula Wind projects and other tax changes since the 2009 Test Year increases the 8 revenue requirement, but, the change in income taxes due to the Tax Cuts and Jobs Act 9 reduces the revenue requirement reduced taxes by a comparable amount. In sum, there 10 are several O&M cost increases that have occurred incrementally over the eight years that 11 has passed between the Test Year in the last rate case and the Test Year in this one. In 12 combination with flat revenue growth, they are driving the OTP’s current need for a rate 13 increase. 14 15 Q. HAS OTP TAKEN STEPS TO ADDRESS RISING EMPLOYEE BENEFIT COSTS? 16 A. Yes. OTP has taken several steps to manage employee benefit costs. For example, in 17 2012 OTP moved all employees to a consumer-driven High Deductible Health Plan 18 (HDHP). OTP also instituted a mechanism that triggers higher employee premiums when 19 OTP’s healthcare spending increases more than six percent over the prior year. In 2017 20 OTP refined the HDHP with three options and introduced coinsurance. The employer 21 share/employee share for gross health costs for non-union employees, which includes 22 total spend for both OTP and employees, moved from approximately 80 percent 23 employer/20 percent employee to 70 percent employer/30 percent employee on all three 24 of the new HDHPs. OTP also eliminated health care eligibility for spouses who can 25 obtain health care insurance from their own employer. OTP also negotiated an increase to 26 the premiums paid for dental coverage by union employees. OTP witness Mr. Peter E. 27 Wasberg explains these actions and other actions OTP has taken to manage employee 28 benefit costs in his Direct Testimony. 29
25 Docket No. EL18-___ Gerhardson Direct
1 Q. HAS OTP ALSO TAKEN STEPS TO CONTROL ITS PENSION AND POST- 2 RETIREMENT BENEFITS COSTS? 3 A. Yes. As further described by Mr. Wasberg in his Direct Testimony, in 2006 OTP closed 4 eligibility for defined benefit pension and post-retirement medical benefits to non-union 5 employees hired after fixed dates, which varied by categories of employees. The pension 6 plan was closed after 2010 for bargaining unit employees. These steps are often referred 7 to as “soft freezes” and have been used by many other employers as well. 8 9 Q. HAS OTP TAKEN OTHER STEPS TO CONTROL ITS PENSION COSTS? 10 A. Yes. As further described by Mr. Wasberg in his Direct Testimony, OTP has prefunded 11 its obligations under its defined pension plan. The prefunding reduces pension expenses 12 by providing additional pension plan earnings which reduce total pension expense. The 13 prefunding also protects OTP and its customers from the risks of facing a large and 14 unexpected pension funding obligation at some time in the future when conditions for 15 providing funding may be unfavorable. 16 17 Q. CAN YOU GIVE SOME OTHER EXAMPLES OF STEPS OTP HAS TAKEN TO 18 MANAGE ITS O&M COSTS? 19 A. Yes. We have taken many other actions to manage costs. Some examples of process 20 improvements we have made in the last several years are: the implementation of a new 21 workforce planning system to efficiently deploy employees; the implementation of a 22 financial data warehouse system to monitor labor and non-labor expenditures and 23 variances from budgets; the implementation of a monthly operating report system to 24 coordinate among operations managers and customers service center managers to review 25 reliability, infrastructure issues and labor plans; and the implementation of a new project 26 management initiative to increase focus on effective execution on capital projects. 27 Some examples of changes to facilities and facility operations we have made are 28 the installation of variable frequency drives on gas recirculation fan motors at Coyote 29 Station that have reduced the station service load by 2 to 2.5 MWs and negotiating with 30 the union to reduce the number of operators required at Hoot Lake Plant to match lower
26 Docket No. EL18-___ Gerhardson Direct
1 anticipated generation levels. Finally, OTP was able to engineer the AQCS project to 2 operate without any derate due to load caused by the AQCS system. These initiatives are 3 not all of what OTP has done to manage costs, but they exemplify other steps that OTP 4 has taken over the past few years to manage costs.
5 VI. OTHER PROPOSALS
6 Q. PLEASE DESCRIBE OTP’S PROPOSAL TO TRANSFER RIDER RECOVERIES TO 7 BASE RATES IN THIS CASE. 8 A. OTP’s proposal is to transfer in-service transmission and environmental project costs 9 from its TCRR and ECRR to base rates. OTP proposes that rider recoveries be 10 discontinued during the current proceeding and the interim rate adjustment includes the 11 revenue requirement associated with costs previously recovered through riders. OTP 12 proposes to continue the inclusion of the retail share of MISO Schedule 26 and 26A 13 revenues and expenses in the TCRR (due to the variability of Schedule 26 and 26A). Mr. 14 Haugen and Mr. Akerman discuss our proposal to move ECRR, and TCRR costs from the 15 riders to base rates in their Direct Testimonies. 16 17 Q. IS OTP PROPOSING TO CHANGE ITS CUSTOMER CHARGES IN THIS CASE? 18 A. Yes. OTP witness Mr. David G. Prazak explains in his Direct Testimony that OTP is 19 proposing increases to customer charges in order to better reflect marginal costs. 20 Aligning rates with marginal costs is especially important given the nature of OTP’s 21 system and how our customers use electricity. 22 23 Q. IS OTP’S SYSTEM SOMEWHAT UNIQUE IN THIS REGARD? 24 A. Yes. As I described earlier in my Direct Testimony, OTP’s service area is predominately 25 rural and lacks significant customer density. Mr. Prazak also explains that many of our 26 customers use electricity for heating, which impacts system design in a way that increases 27 the kinds of costs a customer charge is intended to recover. Finally, Mr. Prazak explains 28 that the proposed rate design promotes equity among customers within a class. Promoting
27 Docket No. EL18-___ Gerhardson Direct
1 intra-class equity is of particular concern on OTP’s system, where low-income customers 2 are more likely to use electricity for heating. 3 4 Q. IS OTP MAKING ANY NEW RATE DESIGN PROPOSALS? 5 A. Yes. Mr. Prazak discusses a Residential Time of Day pilot, an LED street lighting rate, an 6 Economic Development Rider rate, an Air Conditioning Rider rate and a Super Large 7 General Service rate.
8 VII. INTRODUCTION OF WITNESSES
9 Q. PLEASE IDENTIFY THE WITNESSES OTP IS SPONSORING IN THIS 10 PROCEEDING. 11 A. The following individuals will be presenting testimony in this proceeding: 12 • Kevin G. Moug addresses OTP’s costs of debt and overall cost of capital and rate of 13 return, the financial requirements related to OTP’s prior and planned capital 14 expenditures, OTP’s recent levels of reinvestment in its operations, the significant 15 differences between OTP and most other investor-owned utilities, and OTP’s credit 16 ratings. 17 • Stuart D. Tommerdahl addresses the ratemaking treatment of several capital and 18 expense items, jurisdictional and class allocation factors, corporate cost allocations, 19 OTP’s proposal for a step-in rate change when the Merricourt Wind Project goes 20 into service in 2019, numerous miscellaneous items and compliance items. 21 • Bryce C. Haugen addresses rider roll into base rates, the class cost of service study, 22 and specific regulatory compliance items. 23 • Tyler A. Akerman addresses the selection and development of the 2017 Test Year, 24 the development of the Test Year rate base, the development of the Test Year 25 operating statement with regulatory adjustments, pension expense, prepaid pension 26 and other post-employment benefit expense. He also addresses the impact of Tax 27 Cuts and Jobs Act.
28 Docket No. EL18-___ Gerhardson Direct
1 • Peter E. Wasberg addresses matters relating to employee compensation, benefits, 2 and costs. 3 • Bradley E. Tollerson addresses the need for the Merricourt Wind Project. 4 • Kirk A. Phinney describes the capital project costs and operating and maintenance 5 costs of the Big Stone and Hoot Lake environmental compliance projects. 6 • David G. Prazak sponsors proposed rate design changes and general tariff changes. 7 • Robert B. Hevert explains OTP’s cost of equity and presents OTP’s recommended 8 10.30 percent rate of return.
9 VIII. CONCLUSION
10 Q. PLEASE SUMMARIZE YOUR TESTIMONY. 11 A. As reflected in our Mission Statement, we take seriously our responsibility to deliver 12 electricity as reliably, economically and environmentally responsibly as possible and to 13 improve the quality of life in the areas we serve. We take pride in fulfilling that mission. 14 Continuing to fulfill that mission requires adequate financial strength. To maintain that 15 strength, we require an increase to non-fuel base revenue of $5,978,9109 or 19.50 16 percent. This increase is based in part on an ROE of 10.3 percent and an equity ratio of 17 53.09 percent. As I previously noted, excluding the effect of the rider-to-base-rate 18 transition, the increase in non-fuel base revenue is $3,358,574, or 10.10 percent. 19 OTP is facing a growing need to invest in additional infrastructure over at least 20 the next five years and will need to go to the market to raise additional capital. 21 Consequently, we need to have reasonable earnings and a competitive ROE. 22 23 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 24 A. Yes.
29 Docket No. EL18-___ Gerhardson Direct
Docket No. EL18-___ Exhibit ___(BGG-1), Schedule 1 Page 1 of 2
Qualifications, Duties and Responsibilities of Bruce Gerhardson
EMPLOYMENT
Vice President, Regulatory Affairs – Otter Tail Power Company October 2017-Present Executive leadership over regulatory affairs, market planning and strategic planning
Director, Regulatory Affairs and Compliance – Otter Tail Power Company April 2017-October 2017 Executive Leadership over regulatory economics, administration, proceedings and compliance
Associate General Counsel - Otter Tail Power Company, Fergus Falls, MN 2000-April 2017 Lead Counsel for regulatory affairs and administrative proceedings. Chief Compliance Counsel. Staff of eight advocacy and compliance personnel, including the Manager of Regulatory Economics and the Manager of Regulatory Proceedings and Compliance.
Partner - Svingen, Athens, Russell and Hagstrom Law Firm, Fergus Falls, MN 1995-2000 Comprehensive legal representation of individual clients, with public utility and agribusiness focus. Regulatory proceedings, project development and other transactions.
EDUCATION
University of Minnesota Law School JD Cum Laude 1995. Judicial Extern for the Mille Lacs Band of Ojibwe Tribal Court; Summer Associate at Pemberton, Sorlie, Rufer & Kershner Law Firm, Fergus Falls, Minnesota
University of Minnesota-Duluth Graduate Work, English Literature and Writing 1990-1992; Fellowships and Teaching Assistantships in Writing and Literature
St. Olaf College BA Cum Laude, English 1988; Semester Abroad at University of Aberdeen, Scotland
Fergus Falls Community College AA Liberal Arts 1985
INDUSTRY CERTIFICATIONS Law licenses in Minnesota, North Dakota and South Dakota
1 Docket No. EL18-___ Exhibit ___(BGG-1), Schedule 1 Page 2 of 2
PROFESSIONAL AFFILIATIONS
• Minnesota State Bar Assn. Public Utility Law Section Council • Fergus Area College Foundation Board-Past President • Otter Tail County United Way-Past Campaign Co-Chair • Fergus Falls Sister City Commission (Sister City relationship with Nordhordland, Norway)
2
Volume 2A
Direct Testimony and Supporting Schedules
Tyler A. Akerman
Before the South Dakota Public Utilities Commission State of South Dakota
In the Matter of the Application of Otter Tail Power Company For Authority to Increase Rates for Electric Utility Service in South Dakota
Docket No. EL18-___
Exhibit___
RATE BASE, REVENUE REQUIREMENT AND ADJUSTMENTS
Direct Testimony and Schedules of
TYLER A. AKERMAN
April 20, 2018
Docket No. EL18-___ Akerman Direct TABLE OF CONTENTS
I. INTRODUCTION AND QUALIFICATIONS...... 1 II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY ...... 1 III. TEST YEAR AND SCHEDULES PROVIDED ...... 3 IV. TEST YEAR REVENUE DEFICIENCY ...... 5 V. JURISDICTIONAL COST OF SERVICE STUDY ...... 7 VI. IMPACTS OF TAX CUTS AND JOBS ACT ON OTP’S FILING ...... 9 VII. RATE BASE ...... 15 A. NET UTILITY PLANT IN SERVICE ...... 17 B. CONSTRUCTION WORK IN PROGRESS ...... 19 C. WORKING CAPITAL ...... 19 D. ACCUMULATED DEFERRED INCOME TAXES ...... 20 E. RIDER ROLL-IN ...... 21 VIII. ADJUSTMENTS TO RATE BASE ...... 21 A. TRADITIONAL ADJUSTMENTS TO RATE BASE ...... 22 1. AFUDC on Short-Term CWIP ...... 22 2. BSP II Generation Recovery ...... 23 3. Rider CWIP ...... 23 4. Transmission Recovery ...... 23 B. TEST YEAR ADJUSTMENTS TO RATE BASE ...... 24 1. Normalize CISone Project...... 24 2. New Depreciation Rates...... 24 3. Rate Case Expense Amortization ...... 25 4. Adjustment to ADIT for TCJA ...... 25 5. Effect of Test Year Adjustments on Allocations ...... 26 IX. INCOME STATEMENT ...... 26 A. SUMMARY OF FINANCIAL SCHEDULES ...... 27 B. SUMMARY OF TEST YEAR INCOME STATEMENT ...... 27 C. TEST YEAR REVENUES ...... 28 1. Retail Revenues ...... 29 2. Other Electric Operating Revenue ...... 29 D. O&M EXPENSES ...... 33 1. Production Expenses ...... 34 2. Transmission Expenses ...... 34 3. Distribution Expenses ...... 34 4. Customer Accounting Expenses ...... 35 5. Customer Service and Information Expenses ...... 35 6. Sales Expense ...... 35 7. Administrative and General Expenses ...... 36 E. DEPRECIATION EXPENSE ...... 36 F. INCOME TAXES ...... 37 X. ADJUSTMENTS TO INCOME STATEMENT ...... 37 A. TRADITIONAL ADJUSTMENTS TO INCOME STATEMENT ...... 39 1. Advertising Expense ...... 39
i Docket No. EL18-___ Akerman Direct 2. AFUDC on Short-Term CWIP ...... 39 3. BSP II Generation Recovery ...... 40 4. Emission Allowances ...... 40 5. Incentive Compensation ...... 40 6. REC Sales ...... 40 7. Transmission Recovery ...... 41 B. TEST YEAR ADJUSTMENTS TO THE INCOME STATEMENT ...... 41 1. Normalize CISone Project...... 41 2. BSP II Transmission Amortization ...... 41 3. New Depreciation Rates ...... 42 4. Weather Normalization ...... 42 5. Revenue Normalization ...... 42 6. Wages, KPA, and Management Incentive ...... 43 7. Medical / Dental, FAS 87, 106, 112...... 43 8. Rate Case Expenses...... 46 9. Storm Damage ...... 46 10. Removal of Production Tax Credits ...... 46 11. Plant Outage Normalization ...... 47 12. Removal of TCRR Revenues ...... 47 13. Removal of ECRR Revenues ...... 48 14. Adjust Deferred Tax Expense for TCJA ...... 48 15. Allocation of Changes due to Test Year Allocation ...... 48 XI. MERRICOURT STEP ...... 48 A. RATE BASE IMPACT ...... 49 B. INCOME STATEMENT IMPACT ...... 49 XII. CONCLUSION...... 50
ii Docket No. EL18-___ Akerman Direct ATTACHED SCHEDULES
Schedule 1 – Akerman Qualifications and Responsibilities Schedule 2 – Summary of 2017 Test Year Revenue Deficiency Schedule 3 – Jurisdictional Financial Summary (2016-2017) Schedule 4 – JCOSS, COSS and Rate Design Process Overview Manual Schedule 5 – Tax Cut and Jobs Act Impacts Schedule 6 – Test Year Rate Base Schedule 7 – Traditional Adjustments to Rate Base Schedule 8 – Test Year Rate Base Adjustments Schedule 9 – Test Year Income Statement Schedule 10 – Test Year O&M by Function Schedule 11 – Traditional Adjustments to Income Statement Schedule 12 – Test Year Income Statement Adjustments Schedule 13 – Big Stone II Amortization Schedule 14– Merricourt Step Rate Base Adjustments Schedule 15 – Merricourt Step Income Statement Adjustments
iii Docket No. EL18-___ Akerman Direct 1 I. INTRODUCTION AND QUALIFICATIONS
2 Q. PLEASE STATE YOUR NAME AND OCCUPATION. 3 A. My name is Tyler Akerman. I am employed by Otter Tail Power Company (OTP) as 4 Manager of the Business Planning/Regulatory Accounting department. 5 6 Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE. 7 A. I graduated from Minnesota State University Moorhead with a Bachelor of Science 8 degree with majors in finance and accounting. I started my current position as Manager, 9 Business Planning/Regulatory Accounting in October 2015. My primary responsibilities 10 include being accountable for all budgeting, financial planning, and forecasting as 11 required by OTP and Otter Tail Corporation for use in strategic planning and decision 12 making. In addition, I am responsible for managing the production of official company 13 budgets and monthly forecasts, for leading the work group that prepares the jurisdictional 14 cost of service studies for the three jurisdictions in which OTP provides service (South 15 Dakota, Minnesota and North Dakota) and providing other regulatory and financial 16 analysis on an as needed basis. I have been employed by OTP since October 2012. Prior 17 to beginning my current position in October 2015, I was a Financial Analyst in the 18 Business Planning/Regulatory Accounting Department. A copy of my resume is included 19 as Exhibit___(TAA-1), Schedule 1.
20 II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY
21 Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? 22 A. My Direct Testimony supports OTP’s financial schedules and the determination of a 23 revenue deficiency for the 2017 Test Year, including known and measurable changes. 24 More specifically, I have determined that OTP has a revenue deficiency of $5,978,109 for 25 the 2017 Test Year, as shown in Exhibit___(TAA-1), Schedule 2, which includes current 26 rider revenues that are being transitioned into base rates, as I note later in my Direct 27 Testimony. I support the additional financial data provided as part of this Application. I 28 will also discuss the development of the Rate Base and Income Statement which is being
1 Docket No. EL18-___ Akerman Direct 1 proposed for use in setting rates in this proceeding, including explaining the financial 2 impact of all Test Year adjustments and providing support for some of the Test Year 3 adjustments. 4 5 Q. PLEASE PROVIDE A BRIEF OVERVIEW OF YOUR DIRECT TESTIMONY. 6 A. I explain the Jurisdictional Cost of Service Study (JCOSS), Test Year Revenue 7 Deficiency, Financial Data Provided, Tax Cuts and Jobs Act, Rate Base, Adjustments to 8 Rate Base, Income Statement, and Adjustments to the Income Statement. 9 10 Q. HOW IS YOUR DIRECT TESTIMONY ORGANIZED? 11 A. In Section III, I discuss the Test Year and identify the Financial Schedules being 12 provided. Section IV provides a discussion of the 2017 Test Year revenue deficiency, 13 and Section V includes a discussion of the JCOSS. Section VI includes a discussion of 14 the Tax Cuts and Jobs Act. Section VII includes a discussion of Rate Base, and Section 15 VIII includes a discussion of adjustments to Rate Base. In Section IX, I discuss the 16 Income Statement and Section X includes a discussion of adjustments to the Income 17 Statement. Section XI provides a discussion of the proposed Merricourt Step Increase. 18 Section XII presents my conclusions. 19 20 Q. DID YOU USE ANY LABELING CONVENTIONS IN YOUR DIRECT 21 TESTIMONY? 22 A. Yes. There are certain power plant and transmission projects where OTP is only a part 23 owner. I distinguish among total project costs, OTP’s share of the total and the South 24 Dakota Jurisdictional share as follows: total project costs, labeled as (Total Plant or Total 25 Project), the OTP ownership allocation of the project amounts, labeled as (OTP Total), 26 and the South Dakota Jurisdictional share, labeled as (OTP SD). 27
2 Docket No. EL18-___ Akerman Direct 1 III. TEST YEAR AND SCHEDULES PROVIDED
2 Q. WHAT TEST YEAR IS USED IN THE COST OF SERVICE STUDY? 3 A. The test year period is based on the 2017 calendar year with Traditional and Test Year 4 Adjustments, including known and measurable changes. 5 6 Q. FOR WHAT PERIODS IS FINANCIAL INFORMATION BEING PROVIDED? 7 A. Following the Commission’s rules, financial data is provided for the most recent fiscal 8 year (2017 Actual Year) and the 2017 Test Year. 9 10 Q. IN ADDITION TO THE SCHEDULES INCLUDED WITH THIS TESTIMONY, ARE 11 THERE ADDITIONAL SCHEDULES YOU ARE SPONSORING? 12 A. Yes. I am sponsoring the following Statements and supporting Schedules, which are 13 required by South Dakota Public Utilities Commission (“Commission”) Rules (Sections 14 20:10:13:51 through 20:10:13:102. These Statements and Schedules are in Volume 4 of 15 the Application: 16 A. Balance sheet 17 B. Income statement 18 C. Earned surplus statements 19 D. Cost of plant 20 D-1. Detailed plant accounts 21 D-2. Plant addition and retirement for test period 22 D-3. Working papers showing plant accounts on average basis for test period 23 D-4. Plant account working papers for previous years 24 D-5. Working papers on capitalizing interest and other overheads during 25 construction 26 D-6. Changes in intangible plant working papers 27 D-7. Working papers on plant in service not used and useful 28 D-8. Property records working papers 29 D-9. Working papers for plant acquired for which regulatory approval has not 30 been obtained
3 Docket No. EL18-___ Akerman Direct 1 E. Accumulated depreciation 2 E-1. Working papers on record changes to accumulated depreciation 3 E-2. Working papers on depreciation and amortization method 4 E-3. Working papers on allocation of overall accounts 5 F. Working capital 6 F-1. Monthly balances for materials, supplies, fuel stocks, and prepayments 7 F-2. Monthly balances for two years immediately preceding pro forma year 8 F-3. Data used in computing working capital 9 H. Operating and maintenance expenses 10 H-1. Adjustments to operating and maintenance expenses 11 H-2. Cost of power and gas 12 H-3. Working papers for listed expense accounts 13 H-4. Working papers for Interdepartmental Transactions 14 I. Operating revenue 15 J. Depreciation expense 16 J-1. Expense charged other than prescribed depreciation 17 K. Income taxes 18 K-1. Working papers for federal income taxes 19 K-2. Differences in book and tax depreciation 20 K-3. Working papers for consolidated federal income tax 21 K-4. Working papers for an allowance for current tax greater than tax 22 calculated at consolidated rate 23 K-5. Working papers for claimed allowances for state income taxes 24 L. Other taxes 25 L-1. Working papers for adjusted taxes 26 M. Overall cost of service 27 N. Allocated cost of service 28 O. Comparison of cost of service 29 P. Fuel cost adjustment factor 30 R. Purchases from affiliated companies
4 Docket No. EL18-___ Akerman Direct 1 Any discussion of the content of a Schedule that is required under the Commission’s Rules 2 is provided with the required Schedule. OTP witness Mr. Bruce Gerhardson provides the 3 information regarding utility operations for required Schedule Q in his Direct Testimony. 4 OTP witness Mr. Kevin G. Moug sponsors the information regarding cost of capital and 5 related topics for required Schedules G through G-4.
6 IV. TEST YEAR REVENUE DEFICIENCY
7 Q. WHAT IS THE BASIS OF OTP’S 2017 TEST YEAR JURISDICTIONAL REVENUE 8 REQUIREMENT AND REVENUE DEFICIENCY? 9 A. OTP’s 2017 Test Year jurisdictional revenue requirement and revenue deficiency are 10 based on OTP’s 2017 Actual Year results, with Traditional and Test Year Adjustments, 11 including known and measurable changes. 12 13 Q. ARE KNOWN AND MEASUREABLE CHANGES DESCRIBED IN THE 14 COMMISSION’S RULES? 15 A. Yes. Commission Rule 20:10:13:44 provides in part that “[N]o adjustments shall be 16 permitted unless they are based on changes in facilities, operations, or costs which are 17 known with reasonable certainty and measurable with reasonable accuracy at the time of 18 the filing ….” 19 20 Q. WHAT IS THE 2017 TEST YEAR JURISDICTIONAL REVENUE REQUIREMENT 21 AND REVENUE DEFICIENCY? 22 A. OTP’s overall jurisdictional revenue requirement for the 2017 Test Year is $36,628,124 23 (including $1,598,410 of revenue requirements that will be left in the Transmission Cost 24 Recovery Rider (TCRR), and the 2017 Test Year revenue deficiency is $5,978,109. The 25 2017 Test Year revenue deficiency represents a 19.5 percent overall increase in retail 26 revenues compared to 2017 retail revenues at current rates, including the transition of 27 cost recovery from riders to base rates. The transition of costs from riders to base rates 28 does not increase customer bills, however. It merely moves recovery from the rider 29 mechanisms to the base rate mechanism. The actual increase for customers, excluding
5 Docket No. EL18-___ Akerman Direct 1 the effect of the rider-to-base-rate transition, is an increase in non-fuel base revenue of 2 $3,358,574, or 10.10 percent. 3 4 Q. HAVE YOU PREPARED A SUMMARY OF THE 2017 REVENUE DEFICIENCY? 5 A. Yes. Exhibit___(TAA-1), Schedule 2 is a summary of the 2017 Test Year revenue 6 deficiency. Line 1 shows average total Rate Base of $84.9 million. Line 4 shows the 7 total amount available for return of $2.0 million, which is determined at present rate 8 levels. Line 5 shows the 2.41 percent overall rate of return (ROR) earned before any rate 9 increase. Line 6 shows the 7.96 percent required ROR, which is the basis for the 10 requested rate increase. Line 7 shows the required operating income of $6.8 million, 11 which was determined by multiplying the 7.96 percent required ROR by the $84.9 12 million Rate Base. Line 8 shows the $4.7 million income deficiency which is the 13 difference between the required operating income of $6.8 million (on Line 7) less the 14 $2.0 million of available return (on Line 4). The $5.98 million revenue deficiency on 15 Line 10 is determined by multiplying the $4.7 million income deficiency (on Line 8) by 16 the 1.2677244 gross-revenue conversion factor that reflects the effects of the TCJA. The 17 calculation of the gross revenue conversion factor is provided in Volume 4A, Schedule F- 18 2. 19 20 Q. HAVE YOU COMPARED OTP'S EARNED OVERALL ROR TO ITS REQUIRED 21 OVERALL ROR SINCE 2016? 22 A. Yes. OTP’s earned ROR was lower than OTP’s required ROR in 2016 and lower than 23 OTP’s required ROR in 2017 at current rates. Exhibit___(TAA-1), Schedule 3 is a 24 Jurisdictional Financial Summary for 2017 Actual Year and the 2017 Test Year. 25 Exhibit___(TAA-1), Schedule 3 shows: (1) the overall ROR for 2017 Actual Year was 26 5.78 percent and the required ROR (reflecting actual 2017 cost of debt and the return on 27 equity granted in OTP’s last rate case) was 7.74 percent; (2) the overall ROR for the 2017 28 Test Year is 2.41 percent and the required ROR is 7.96 percent; and (3) the overall ROR 29 for the Merricourt Step Increase (labeled 2017 Test Year Step on Schedule 3) is 7.50 30 percent and the required ROR is 7.96 percent.
6 Docket No. EL18-___ Akerman Direct 1 V. JURISDICTIONAL COST OF SERVICE STUDY
2 Q WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? 3 A. The purpose of this section of my Direct Testimony is to explain OTP’s JCOSS. 4 5 Q. WHAT IS THE PURPOSE OF A JCOSS? 6 A. A JCOSS determines the portion of a multijurisdictional utility’s total company costs and 7 revenues that should be recognized in a specific jurisdiction. In this case, the JCOSS 8 determined the portion of OTP’s total company costs and revenues that should be 9 recognized in the South Dakota jurisdiction in the 2017 Test Year. 10 11 Q. WHY IS A JCOSS NECESSARY FOR OTP? 12 A. OTP serves retail customers in South Dakota, Minnesota, and North Dakota. In addition, 13 OTP provides wholesale transmission services to load serving entities and provides 14 wholesale transmission and wheeling service to some municipal utilities, and those 15 services are regulated by the Federal Energy Regulatory Commission (FERC). Costs that 16 are incurred to meet the requirements of a particular jurisdiction are directly assigned to 17 that jurisdiction. Costs that cannot be directly assigned to a specific jurisdiction are 18 allocated to jurisdictions based upon allocation factors included in the JCOSS. In this 19 way, the JCOSS is used to determine what portion of the total costs incurred by OTP 20 should be recovered from our South Dakota customers. 21 22 Q. IS IT IMPORTANT THAT ALL OF A UTILITY’S STATE JURISDICTIONS USE 23 THE SAME JURISDICTIONAL ALLOCATION PROCEDURES FOR THE JCOSS? 24 A. Yes. By having uniform jurisdictional allocation procedures in all its state jurisdictions, 25 OTP is able to recover its cost of providing retail service across its entire service territory, 26 no more, and no less. The allocation procedures used by OTP were approved by the 27 Commission in OTP’s last South Dakota rate case, Docket No. EL10-011. 28
7 Docket No. EL18-___ Akerman Direct 1 Q. DO ALL OTP’S JURISDICTIONS USE THE SAME JURISDICTIONAL 2 ALLOCATION PROCEDURES FOR OTP’S JCOSS? 3 A. Yes. The Commission, the Minnesota Public Utilities Commission (MPUC), and North 4 Dakota Public Service Commission (ND PSC) have approved the same jurisdictional 5 allocation procedures for OTP’s JCOSS that the Commission has approved for OTP’s 6 JCOSS. 7 8 Q. HOW WAS OTP’S JCOSS DEVELOPED? 9 A. The JCOSS was developed using procedures contained in the OTP Jurisdictional and 10 Class Cost of Service Study and Rate Design Process Overview Manual, a copy of which 11 is attached as Exhibit __ (TAA-1), Schedule 4. 12 13 Q. WHAT ARE THE GENERAL STEPS FOR PREPARING OTP’S JCOSS? 14 A. The JCOSS involves the following steps: functionalization, classification and allocation. 15 Functionalization is the process by which costs are arranged according to the utility 16 function they serve, such as production, transmission, distribution, etc. Classification is 17 the arrangement of costs within a function by the service characteristic to which they 18 most closely apply or relate, in order to facilitate their allocation based on these service 19 characteristics. Allocation, in the JCOSS, is the process of distributing costs to each 20 jurisdiction. I discuss the functionalization and classification steps in more detail below. 21 22 Q. IS FUNCTIONALIZATION OF COSTS REQUIRED? 23 A. Yes. The assignment of costs to each function: Production, Transmission, Distribution, 24 Customer Service, Administrative and General generally follow the accounting categories 25 defined in the FERC Uniform System of Accounts (USOA). At times, however, there are 26 exceptions. When there are exceptions, the purpose of functionalization, not the 27 accounting treatment, determines the distribution of the functional costs for the cost of 28 service study. For example, lines and substations can fulfill production, transmission or 29 distribution functions. Additional details regarding OTP’s functionalization procedures
8 Docket No. EL18-___ Akerman Direct 1 are included in the Cost Allocations Procedure Manual (CAPM) explained by OTP 2 witness Mr. Stuart Tommerdahl in his Direct Testimony. 3 4 Q. HOW WERE COSTS CLASSIFIED IN THE JCOSS? 5 A. Classification approaches differ across different functional categories. For example, 6 fixed production plant is classified into energy-related and demand-related subcategories 7 using the equivalent peaker method. OTP has used the equivalent peaker method to 8 classify fixed production plant costs since 1980. Additional details regarding 9 classification procedures are available in the CAPM. 10 11 Q. WHAT IS YOUR CONCLUSION RELATED TO OTP’S JCOSS? 12 A. The results of the JCOSS are appropriate for determining the 2017 Test Year revenue 13 requirement.
14 VI. IMPACTS OF TAX CUTS AND JOBS ACT ON OTP’S FILING
15 Q. WHAT TOPICS WILL YOU DISCUSS IN THIS SECTION? 16 A. This section addresses the impacts of the federal Tax Cuts and Jobs Act (TCJA), which 17 was signed into law on December 22, 2017, on the Company’s revenue deficiency for 18 OTP’s proposed 2017 Test Year. I first provide an overview of the TCJA. I then address 19 both the broader impacts of the TCJA on OTP and the aspects we know now that can be 20 addressed as part of this rate case. I will also explain OTP’s reasoning behind, and 21 proposed mechanism for, addressing some of those TCJA impacts on customer rates in 22 this rate case. Finally, I discuss the impacts of the TCJA in terms of appropriate 23 regulatory accounting treatment. 24 25 Q. PLEASE PROVIDE AN OVERVIEW OF THE TCJA? 26 A. The TCJA made several significant changes, including a reduction in the maximum U.S. 27 federal corporate income tax rate from 35 percent to a flat 21 percent tax rate, effective 28 January 1, 2018. This means that all public utilities subject to federal corporate income 29 taxes will compute those taxes based on a 21 percent tax rate. The TCJA also contains
9 Docket No. EL18-___ Akerman Direct 1 certain provisions specific to public utilities, including the continuation of certain interest 2 expense deductibility and relief from 100 percent expensing of capital investments. 3 4 Q. DOES THE TCJA HAVE IMPACTS ON OTP’S 2017 TEST YEAR COST OF 5 SERVICE? 6 A. Yes. The TCJA will have three primary impacts on cost of service: (1) current income 7 tax expense will be reduced; (2) bonus depreciation is eliminated for utilities such as 8 OTP; and (3) there will be an amortization of “excess” Accumulated Deferred Income 9 Tax (ADIT). In addition, the tax gross up factor will be reduced for OTP, with the tax 10 gross-up factor of 1.540773 times the short fall being reduced to 1.267724. 11 12 Q. ARE THE EFFECTS OF THE TCJA SUFFICIENTLY KNOWN TO MAKE 13 ADJUSTMENTS IN THIS RATE CASE? 14 A. Yes. Although OTP is still evaluating the impacts of the TCJA, OTP believes the major 15 impacts are sufficiently known and we can provide some further information on the 16 effects of the TCJA on the Company’s cost of service in this rate case proceeding. Any 17 additional impacts of the TCJA will be evaluated and addressed in the process for setting 18 final rates and subsequent rider true-ups. 19 20 Q. PLEASE SUMMARIZE THE EFFECTS OF THE TCJA ON CURRENT ADIT 21 BALANCES. 22 A. The TCJA requires the revaluation of federal ADIT assets and liabilities balances using 23 the new lower tax rate. The changes result in the recording of regulatory assets and 24 liabilities for the excess portion of ADIT, with no estimated income statement impact. 25 The ADIT due to excess tax over book depreciation is “protected” under the TCJA, 26 which means the amount is to be amortized over the remaining life of the property that 27 created the ADIT in order to avoid a violation of normalization tax requirements. 28
10 Docket No. EL18-___ Akerman Direct 1 Q WHAT IS THE IMPACT OF “UNPROTECTED” ADIT ON OTP? 2 A. For OTP, only a small net amount of ADIT (less than one half of a percent) is not 3 “protected” under the new tax law, which means the amount is to be amortized over the 4 remaining life of the property that created the ADIT. The changes are expected to result 5 in the recording of regulatory assets and liabilities for the non-protected portion of ADIT, 6 with no estimated income statement impact. 7 8 Q. PLEASE FURTHER EXPLAIN THE EFFECTS OF NORMALIZATION 9 REQUIREMENTS ON OTP’S DEFERRED ADIT ASSETS AND LIABILITIES. 10 A. OTP is required to revalue its deferred tax assets and liabilities, including federal income 11 tax net operating losses, as of the enactment date of the TCJA. Most of OTP’s ADIT 12 assets and liabilities are subject to a normalization method of accounting. As a result, the 13 revaluation of most of OTP’s net ADIT is expected to result in the establishment of 14 regulatory liabilities, which would then be creditable to the cost of service over the 15 remaining lives of the related assets. 16 17 Q. PLEASE FURTHER EXPLAIN THE EFFECTS OF THE TAX RATE REDUCTION IN 18 THE TCJA ON OTP’S ADIT. 19 A. Due to the reduction of the tax rate in the TCJA, the current balance of ADIT on OTP’s 20 regulatory books does not accurately reflect the current (post-TCJA) tax liability. As a 21 result, OTP needs to re-measure ADIT balances at the 21% rate. OTP’s ADIT due to the 22 lower tax rate (causing an increase to rate base) will be offset with a regulatory liability in 23 ADIT. Pre-2018 ADIT will amortize (deferred tax expense) at the rates upon which the 24 ADIT was created. Since rates were set with the higher tax rate, ratepayers will continue 25 to receive the benefit of the ADIT offset through calculating pre-2018 ADIT reversals at 26 a 35 percent rate. 27 28 Q. PLEASE FURTHER EXPLAIN THE EFFECTS OF THE TCJA ON FUTURE ADIT. 29 A. The elimination of bonus depreciation and the reduction in the federal tax rate in the 30 TCJA will lead to utilities having lower ADIT liabilities going forward (but including
11 Docket No. EL18-___ Akerman Direct 1 past ADIT net of regulatory liabilities). The reduction in future deferred taxes will, in 2 turn, increase rate base growth for the same level of expected capital expenditures due to 3 lower forecasted deferred tax liabilities. 4 5 Q. PLEASE FURTHER EXPLAIN HOW THE TCJA IMPACTS BONUS 6 DEPRECIATION. 7 A. “Bonus depreciation” is a form of tax incentive given to companies to encourage certain 8 types of investment, whereby a company that purchases a qualified business property and 9 places it into service within a taxable year can take a first-year deduction in addition to 10 any depreciation deduction available. Beginning in 2018, the TCJA prohibits the use of 11 bonus depreciation for assets acquired in the trade or business of the furnishing or sale of 12 electrical energy. As a result, going forward, OTP will be adding less ADIT, as the 13 difference between book depreciation and tax depreciation in future periods will be less 14 in the early years of a project even though both total tax and book depreciation will 15 remain unchanged over the asset’s life. OTP continues to assess the effect of the bonus 16 depreciation change under the TCJA. 17 18 Q. HAS THE COMMISSION BEGUN ADDRESSING THE TCJA? 19 A. Yes. On December 27, 2017, following a request by South Dakota Public Utilities Staff 20 (Staff), the Commission issued its Order initiating an investigation of the impacts of the 21 TCJA on South Dakota rate regulated utilities (Order) and requiring OTP and other 22 utilities to file initial comments on the TCJA’s impacts on or before February 1, 2018 23 (Order). 1 .OTP filing initial comments as required by the Order (OTP’s Initial 24 Comments). The Commission’s Order sought initial comments from rate-regulated 25 utilities regarding the general effects of the TCJA on each utility’s cost of service in 26 South Dakota as well as potential possible regulatory mechanisms for adjusting rates. In
1 In the Matter of Staff’s Request To Investigate the Tax Cuts and Jobs Act on South Dakota Utilities, Commission Docket No. GE17-003, Order dated December 27, 2017.
12 Docket No. EL18-___ Akerman Direct 1 OTP’s instance, those impacts include revaluation of ADIT assets and liabilities, which 2 OTP briefly addressed in its Initial Comments. 3 In its Order, the Commission also required the utilities to work with Staff to 4 determine a deadline for additional comments to address proposals and impacts, and 5 including: (1) an estimate of the Company’s determination of the TCJA’s effects on its 6 South Dakota cost of service, inclusive of all elements; (2) an explanation of these 7 effects, and (3) proposals for procedures for changing rates to reflect these impacts. The 8 Commission also required the utilities to provide information on any FERC proceedings 9 addressing how federal income taxes will be adjusted for FERC transmission tariff rates. 10 In addition to this rate case proceeding, OTP also looks forward to working with the 11 Commission and Staff to determine the next steps for additional comments in Docket 12 GE17-003. 13 14 Q. ARE THERE OTHER POSSIBLE IMPACTS OF THE TCJA ON UTILITIES, 15 INCLUDING OTP? 16 A. There are other areas of impact or potential impact as well, which regulators and utilities 17 alike continue to study and sort out. For instance, although the TCJA contains many 18 provisions that have broad applicability to energy sector companies, it is intentionally 19 silent on the disposition of many energy-related tax incentives. There are also changes to 20 the expensing of certain capital investments, limitations on deductions for interest 21 expense and modification to the capital contribution rules and net operating loss 22 deductions, to name just a few examples. 23 24 Q. DOES OTP SUPPORT MAKING ADJUSTMENTS TO REFLECT THE TCJA IN THIS 25 RATE CASE PROCEEDING? 26 A. Yes, as indicated in its February 1, 2018 Initial Comments in Docket GE17-003, OTP 27 believes this rate case proceeding is the most efficient mechanism for identifying and 28 passing on the known beneficial financial impacts of the TCJA to our customers. 29
13 Docket No. EL18-___ Akerman Direct 1 Q. HAVE YOU PREPARED A SCHEDULE WHICH REFLECTS CHANGES TO THE 2 2017 TEST YEAR RESULTING FROM THE TCJA? 3 A. Yes. As shown in Exhibit___(TAA-1), Schedule 5, page 1 of 3, for the South Dakota 4 jurisdiction: (1) rate base increased by $263,985; (2) total available for return decreased 5 by $32,096; (3) the gross revenue conversion factor decreased by 0.273 (reflecting the 6 lower income tax rate); and (4) the 2017 Test Year revenue deficiency decreased by 7 $1,205,765. The impacts on the ADIT is shown on Exhibit___(TAA-1), Schedule 5, page 8 2 of 3, and the impacts on the components of the Income Statement are shown on 9 Exhibit___(TAA-1), Schedule 5, page 3 of 3. 10 11 Q. WILL THE TCJA HAVE IMPACTS ON THE UTILIZATION OF PRODUCTION TAX 12 CREDITS? 13 A. Yes. The TCJA decreases income tax expense for 2018 (resulting in lower rates for 14 OTP’s South Dakota customers as shown in Exhibit___(TAA-1), Schedule 5). The lower 15 income tax rate and associated income tax expense will delay the time when OTP can use 16 the PTCs on future tax returns and will result in an increase in rate base through the 17 creation of a deferred tax asset. 18 19 Q. IS OTP PLANNING TO TAKE THE SAME OR SIMILAR APPROACH IN ITS 20 OTHER STATE JURISDICTIONS? 21 A. Not necessarily. It is correct that OTP is assessing our current cost of providing service 22 in each of the three states where it has retail customers, North Dakota, Minnesota and 23 South Dakota. In Minnesota, the Company’s rates are based on our cost of providing 24 service in 2016. In this proceeding, OTP’s rates are based primarily on an historical test 25 year cost of service (i.e., the 2017 calendar year) with Traditional and Test Year 26 Adjustments and with known and measurable changes. In North Dakota, the rates are 27 being set based on a 2018 forecasted test year. Because of these different fundamental 28 approaches to ratemaking, especially in terms of test years being used, a different 29 approach will be needed in each of these three states in order to best assess and properly
14 Docket No. EL18-___ Akerman Direct 1 account for the impact of the TCJA and address those impacts in terms of our current and 2 going-forward cost of providing service. 3 4 Q. DOES OTP ALSO ANTICIPATE REFLECTING THE IMPACTS OF THE TCJA IN 5 OTHER DOCKETS IN SOUTH DAKOTA? 6 A. Yes. OTP would propose addressing other relevant Commission dockets where TCJA 7 impacts may manifest themselves at appropriate times to those specific cases, other 8 proceedings, or as otherwise directed by the Commission. OTP has already noted in its 9 February TCJA Submission that it will continue to make appropriate filings in that 10 investigation proceeding as required by the Commission. Those forthcoming filings in 11 the investigation docket, however, would be largely derived from calculations made and 12 filed in this general rate case proceeding. 13 14 Q. SHOULD THE COMMISSION ALSO CONTINUE TO ALLOW FLEXIBILITY AS 15 ADDITIONAL ISSUES RELATED TO THE TCJA BECOME CLEARER? 16 A. Yes, such flexibility would help ensure all the benefits to customers are properly 17 addressed. At a minimum, utilities should be permitted to evaluate their change in rates in 18 six months and make any corrections to the calculations of reduced rates for any issues 19 discovered in the calculations as more becomes known about the specific impacts of the 20 TCJA.
21 VII. RATE BASE
22 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? 23 A. In this section of my Direct Testimony, I will discuss the components of Rate Base for 24 the 2017 Actual Year and the 2017 Test Year. I will also address the Rate Base effects of 25 transferring recovery of certain environmental, renewable, and transmission project costs 26 from riders into base rates, as further discussed by OTP witness Mr. Bryce Haugen in his 27 Direct Testimony. 28
15 Docket No. EL18-___ Akerman Direct 1 Q. WHAT IS THE SOURCE OF THE 2017 ACTUAL YEAR RATE BASE 2 INFORMATION CONTAINED IN THE FINANCIAL SCHEDULES? 3 A. The 2017 Actual Year is based on OTP’s 2017 actual data and reflects Traditional 4 Adjustments described in Section VIII. 5 6 Q. WHAT IS THE AMOUNT OF THE 2017 ACTUAL YEAR RATE BASE AND 2017 7 TEST YEAR RATE BASE? 8 A. As shown in Exhibit___(TAA-1), Schedule 6, the 2017 Actual Year South Dakota 9 Jurisdictional Rate Base is $83.3 million, and the 2017 Test Year Rate Base is $84.9 10 million. I will explain the differences between the 2017 Base South Dakota Jurisdictional 11 Rate Base and the 2017 Test Year Rate Base in Section VIII of my Direct Testimony. 12 13 Q. PLEASE BRIEFLY DESCRIBE THE COMPONENTS OF THE RATE BASE. 14 A. Rate Base consists primarily of the capital expenditures made by a utility to obtain or 15 construct plant, equipment, materials, supplies and other assets necessary for the 16 provision of utility service, reduced by amounts recovered from depreciation expense and 17 non-investor sources of capital, such as ADIT. 18 19 Q. HOW WERE THE 2017 ACTUAL YEAR AND 2017 TEST YEAR RATE BASE 20 AMOUNTS DEVELOPED? 21 A. OTP developed the 2017 Actual Year and 2017 Test Year based on 13-month averages, 22 with the only exception being ADIT which is calculated based on a simple beginning-of- 23 year and end-of-year average. OTP made “Traditional” regulatory adjustments to arrive 24 at the 2017 Actual Year. These adjustments were made to reflect recognized regulatory 25 requirements and to “normalize” the financial information for one-time events that will 26 not be recurring on an on-going basis. Other Rate Case Adjustments were made to 27 develop the 2017 Test Year. I will discuss those adjustments in Section VIII of my 28 Direct Testimony. 29
16 Docket No. EL18-___ Akerman Direct 1 Q. WHAT ARE THE MAJOR COMPONENTS OF THE 2017 TEST YEAR RATE BASE? 2 A. The 2017 Test Year Rate Base is generally comprised of the following major items: 3 • Net utility plant in service (which reflects accumulated depreciation); 4 • Cash working capital items; and 5 • ADIT.
6 A. NET UTILITY PLANT IN SERVICE 7 Q. WHAT DOES EXHIBIT___(TAA-1), SCHEDULE 6 INCLUDE? 8 A. Exhibit___(TAA-1), Schedule 6 provides a summary showing Electric Plant In Service, 9 Accumulated Depreciation, and Net Electric Utility Plant In Service for OTP South 10 Dakota Jurisdiction for the 2017 Actual Year, the 2017 Test Year, and the Merricourt 11 Step Increase. I will explain the proposed increase in 2019 to reflect the in-service date of 12 the Merricourt Wind Generation Facility in Section XI of this Direct Testimony. 13 Exhibit___(TAA-1), Schedule 6 shows OTP’s South Dakota Jurisdictional Net Electric 14 Plant in Service is $92.4 million for the 2017 Actual Year, $93.7 million for the 2017 15 Test Year and $117.3 million for the proposed Merricourt Step Increase. Exhibit 16 ___(TAA-1), Schedule 6 reflects Traditional Adjustments to Rate Base included in 17 Exhibit___(TAA-1), Schedule 7 (which I will explain in Section VIII of my Direct 18 Testimony) and Rate Case adjustments to Rate Base included in Exhibit___(TAA-1), 19 Schedule 8 (which I will also in Section VIII of my Direct Testimony). 20 21 Q. WHAT DOES “ELECTRIC PLANT IN SERVICE” REPRESENT? 22 A. Electric Plant in Service is based upon the original cost of property from the books and 23 records of OTP, subject to adjustments. 24 25 Q. WHAT DOES “NET ELECTRIC PLANT IN SERVICE” REPRESENT? 26 A. Net Electric Plant in Service represents OTP’s investment in plant and equipment that is 27 used and useful in providing retail electric service to its customers, net of accumulated 28 depreciation. 29
17 Docket No. EL18-___ Akerman Direct 1 Q. PLEASE EXPLAIN THE METHOD USED TO CALCULATE NET ELECTRIC 2 PLANT IN SERVICE IN THIS CASE. 3 A. The Net Electric Plant in Service is included in Rate Base at depreciated original cost, 4 reflecting a 13-month average based on monthly balances from December 2016 through 5 December 2017. 6 7 Q. DOES EXHIBIT___(TAA-1), SCHEDULE 6 INCLUDE ALL COMPONENTS OF NET 8 UTILITY PLANT? 9 A. Yes. Exhibit___(TAA-1), Schedule 6 include all components of Utility Plant in Service 10 (Production, Transmission, Distribution, General, and Intangible) and related 11 Accumulated Depreciation. The net of Electric Plant in Service and Accumulated 12 Depreciation is the Net Electric Plant in Service. 13 14 Q. DOES EXHIBIT___(TAA-1), SCHEDULE 6 REFLECT THE RATE BASE 15 COMPONENTS DISCUSSED BY OTHER OTP WITNESSES? 16 A. Yes. Exhibit___(TAA-1), Schedule 6 includes all the Rate Base components discussed 17 by the other OTP witnesses, including the Big Stone AQCS and Hoot Lake MATS 18 projects discussed in the Direct Testimony of OTP witness Mr. Kirk A. Phinney, and the 19 investments currently recovered in riders that are being rolled into base rates discussed in 20 the Direct Testimony of Mr. Haugen. 21 22 Q. PLEASE BRIEFLY DESCRIBE ACCUMULATED DEPRECIATION. 23 A. Exhibit___(TAA-1), Schedule 6 includes Accumulated Depreciation for all the Electric 24 Plant in Service components. The sum of the 2017 Actual Year South Dakota 25 Jurisdiction Accumulated Depreciation for these components is negative ($69.0 million), 26 negative ($69.2 million) for the 2017 Test Year, and negative ($70.2 million) for the 27 Merricourt Step Increase.
18 Docket No. EL18-___ Akerman Direct 1 B. CONSTRUCTION WORK IN PROGRESS 2 Q. WHAT IS THE AMOUNT OF CONSTRUCTION WORK IN PROGRESS (CWIP) 3 INCLUDED IN EXHIBIT___(TAA-1), SCHEDULE 6? 4 A. Exhibit___(TAA-1), Schedule 6 shows that OTP’s South Dakota Jurisdictional CWIP is 5 $0 for the 2017 Actual Year, for the 2017 Test Year, and for the Merricourt Step 6 Increase.
7 C. WORKING CAPITAL 8 Q. PLEASE EXPLAIN THE WORKING CAPITAL INCLUDED IN EXHIBIT___(TAA- 9 1), SCHEDULE 6. 10 A. Exhibit___(TAA-1), Schedule 6 shows all the working capital elements, including 11 materials and supplies, fuel stocks, prepayments and customer advances/deposits, and 12 cash working capital, including OTP’s South Dakota Jurisdictional amounts for the 2017 13 Actual Year and 2017 Test Year. 14 15 Q. PLEASE EXPLAIN MATERIALS AND SUPPLIES. 16 A. Exhibit___(TAA-1), Schedule 6 shows OTP’s South Dakota Jurisdictional Materials and 17 Supplies for the 2017 Actual Year, the 2017 Test Year, and the Merricourt Step Increase 18 (referred to as the 2017 Test Year Step on Schedule 6) are each $1.8 million and are 19 based on a 13-month average. 20 21 Q. PLEASE EXPLAIN FUEL STOCKS. 22 A. Exhibit___(TAA-1), Schedule 6 shows OTP’s South Dakota Jurisdictional Fuel Stocks 23 for the 2017 Actual Year is $845,834 and for 2017 Test Year and Merricourt Step 24 Increase is $849,126. Fuel Stocks is based on the 13-month average. 25 26 Q. PLEASE DESCRIBE THE PREPAYMENTS. 27 A. Exhibit___(TAA-1), Schedule 6 shows OTP’s South Dakota Jurisdictional Prepayments 28 for the 2017 Actual Year are negative ($1.9 million), 2017 Test Year are negative ($1.9 29 million), and the Merricourt Step Increase are negative ($2.0 million). Four separate 30 items are grouped together under the line item of Prepayments. The four items are: 1)
19 Docket No. EL18-___ Akerman Direct 1 pre-paid insurance; 2) pre-paid pension; 3) post-retirement benefits liability; and 4) post- 2 employment benefits liability. The amounts for each item are developed using simple 3 averages. 4 5 Q. PLEASE DESCRIBE CASH WORKING CAPITAL. 6 A. Exhibit___(TAA-1), Schedule 6 show OTP’s South Dakota Jurisdictional Cash Working 7 Capital for the 2017 Actual Year is $2.8 million, the 2017 Test Year is $2.5 million, and 8 the Merricourt Step Increase is $2.2 million. Cash Working Capital represents a 9 determination of cash working capital requirements for operation, maintenance, and other 10 expenses. I will explain the adjustment to Cash Working Capital in Section VIII of my 11 Direct Testimony. 12 13 Q. HOW WERE CASH WORKING CAPITAL REQUIREMENTS DETERMINED? 14 A. The cash working capital requirements included in Rate Base is based on a Lead Lag 15 Study prepared by OTP using calendar year 2014 financial data. This study analyzes the 16 lapse of time between the average day on which OTP incurs expenses to serve its 17 customers and the average day on which cash is received from customers in payment of 18 that service. Mr. Tommerdahl discusses the Lead Lag Study in his Direct Testimony.
19 D. ACCUMULATED DEFERRED INCOME TAXES 20 Q. WHAT IS THE AMOUNT OF ADIT INCLUDED IN EXHIBIT___(TAA-1), 21 SCHEDULE 6? 22 A. Exhibit___(TAA-1), Schedule 6 shows OTP’s South Dakota Jurisdictional ADIT for the 23 2017 Actual Year is ($12.6 million), ($12.4 million) for the 2017 Test Year, and ($12.8) 24 for the Merricourt Step Increase. These amounts reflect a simple average of the 25 beginning-of-year and end-of-year ADIT balances.
20 Docket No. EL18-___ Akerman Direct 1 E. RIDER ROLL-IN 2 Q. IS OTP PROPOSING TO MOVE ANY PROJECTS FROM RIDER RECOVERY TO 3 BASE RATE RECOVERY IN THIS FILING? 4 A. Yes. OTP proposes to transfer recovery of certain costs presently recovered in the 5 Environmental Cost Recovery Rider (ECRR) and in the TCRR to base rates in this case. 6 The Direct Testimony of Mr. Haugen provides additional information regarding OTP’s 7 proposal to roll the ECRR and TCRR projects into base rates. 8 9 Q. WHAT IS THE AMOUNT OF THE 2017 TEST YEAR PLANT IN SERVICE 10 INCLUDED IN RATE BASE CURRENTLY RECOVERED IN THE ECRR? 11 A. The 2017 Test Year Utility Plant in Service included in Rate Base for the environmental 12 projects currently recovered in the ECRR is $19.7 million (OTP SD). 13 14 Q. WHAT IS THE 2017 TEST YEAR PLANT IN SERVICE INCLUDED IN RATE BASE 15 CURRENTLY RECOVERED IN THE TCRR? 16 A. The 2017 Test Year Utility Plant in Service included in Rate Base for the transmission 17 projects currently recovered in the TCRR is $2.3 million (OTP SD).
18 VIII. ADJUSTMENTS TO RATE BASE
19 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? 20 A. In this section of my Direct Testimony, I will identify and explain the Traditional 21 Adjustments (necessary to arrive at the 2017 Actual Year Rate Base) and Rate Base 22 Adjustments that are made to the 2017 Actual Year Rate Base to arrive at the 2017 Test 23 Year Rate Base. 24 25 Q. HAVE YOU PREPARED A LIST OF THE ADJUSTMENTS TO RATE BASE? 26 A. Yes. The Traditional Adjustments to Rate Base reflected in Exhibit___(TAA-1), 27 Schedule 7. The Rate Case Adjustments to Rate Base are reflected in Exhibit___(TAA- 28 1), Schedule 8. The following is a list of the adjustments to Rate Base: 29
21 Docket No. EL18-___ Akerman Direct 1 Traditional Adjustments to Rate Base 2 1. Allowance for Funds Used During Construction (AFUDC) on Short-Term CWIP 3 2. Big Stone Phase II (BSP II) Generation Recovery 4 3. Rider CWIP 5 4. Transmission Recovery 6 7 Test Year Adjustments to Rate Base 8 1. Normalize CISone Project 9 2. New Depreciation Rates 10 3. Rate Case Expense Amortization 11 4. Adjust Deferred Tax for Tax Reform 12 5. Effect of Test Year Adjustments on Allocations 13 14 Q. HOW IS THE INFORMATION IN EXHIBIT___(TAA-1), SCHEDULES 7 AND 8 15 AND IN THIS SECTION OF YOUR DIRECT TESTIMONY PRESENTED? 16 A. All the information in Exhibit___(TAA-1), Schedules 7 and 8 and in this section of my 17 Direct Testimony is presented in terms of South Dakota jurisdictional amounts.
18 A. TRADITIONAL ADJUSTMENTS TO RATE BASE
19 1. AFUDC on Short-Term CWIP 20 Q. PLEASE SUMMARIZE THE ADJUSTMENT FOR AFUDC FOR SHORT TERM 21 CWIP. 22 A. The capitalization of AFUDC on Short-term CWIP is the result of previous South Dakota 23 Commission orders which did not allow Short Term CWIP to be included in rate base 24 and which were upheld in the South Dakota Supreme Court. However, since Short-term 25 CWIP is not included in Rate Base, OTP has added AFUDC attributable to Short-term 26 CWIP to rate base since January 1, 1976. Because OTP does not include AFUDC on 27 Short Term CWIP for book purposes, and adjustment for AFUDC is needed, which is 28 depreciated and affects Depreciation Expense and Accumulated Depreciation in addition 29 to Plant in Service. This treatment of AFUDC for Short-term CWIP: (1) increases Total
22 Docket No. EL18-___ Akerman Direct 1 Plant in Service by $2,038,412; (2) increases Accumulated Depreciation by $1,799,027; 2 and (3) increases Total Average Rate Base by $239,386, as shown on Exhibit___(TAA- 3 1), Schedule 7.
4 2. BSP II Generation Recovery 5 Q. PLEASE SUMMARIZE THE ADJUSTMENT FOR BIG STONE PHASE II 6 RECOVERY. 7 A. The Commission allowed unamortized Big Stone II costs to be fixed in rates for the 8 entire 10-year recovery period ending February 16, 2021 per order in Docket No. EL 10- 9 011. This treatment of Big Stone Phase II cost recovery: (1) increases Total Plant in 10 Service by $501,662; (2) increases Total Average Rate Base by $501,662, as shown on 11 Exhibit___(TAA-1), Schedule 7.
12 3. Rider CWIP 13 Q. PLEASE SUMMARIZE THE ADJUSTMENT FOR RIDER CWIP. 14 A. The adjustment for Rider CWIP conforms to the ratemaking approach approved by the 15 Commission in Docket EL-13-029 with respect OTP’s investments in FERC-approved 16 Multi Value Projects (MVP) transmission projects. There is no impact to South Dakota 17 jurisdictional rate base or revenue requirements because these OTP investments in MVP 18 projects are included in the FERC jurisdiction (and are not included in South Dakota rate 19 base) and because these adjustments pertain solely to OTP Total Company balances, 20 which include FERC jurisdictional balances. This treatment of Rider CWIP: (1) 21 decreases CWIP by $10,754,628; and (2) decreases Total Average Rate Base by 22 $10,754,628, as shown on Exhibit___(TAA-1), Schedule 7.
23 4. Transmission Recovery 24 Q. PLEASE SUMMARIZE THE ADJUSTMENT FOR TRANSMISSION RECOVERY. 25 A. This adjustment also conforms to the ratemaking approach approved by the Commission 26 in Docket EL-13-029 with respect to OTP’s investments in FERC-approved MVP 27 transmission projects. This adjustment: (1) decreases Total Plant in Service by 28 $17,402,180; (2) decreases Accumulated Depreciation by $582,545 (3) decreases ADIT
23 Docket No. EL18-___ Akerman Direct 1 by $2,248,323; and (4) decreases Total Average Rate Base by $14,571,312, as shown on 2 Exhibit___(TAA-1), Schedule 7.
3 B. TEST YEAR ADJUSTMENTS TO RATE BASE
4 1. Normalize CISone Project 5 Q. DID YOU NORMALIZE 2017 TEST YEAR PLANT IN SERVICE FOR THE CISONE 6 PROJECT? 7 A. Yes. Exhibit___(TAA-1), Schedule 8 shows the adjustment to Plant in Service for OTP’s 8 CISone project that will go into service in 2018. Mr. Tommerdahl explains the basis for 9 the adjustment for the CISone project in his Direct Testimony. 10 11 Q. PLEASE SUMMARIZE THE ADJUSTMENTS FOR THE CISONE PROJECT. 12 A. The adjustments for the CISone project are set forth in Exhibit___(TAA-1), Schedule 8 13 and include: (1) a $1,118,659 increase to Intangible Plant in Service; (2) a $66,654 14 increase to Intangible Accumulated Depreciation; (3) a $1,052,006 increase to Intangible 15 Net Plant in Service; and (4) a $1,052,006 increase to Total Average Rate Base. The 16 corresponding impacts on the 2017 Test Year Income Statement are explained in Section 17 IX of my Direct Testimony.
18 2. New Depreciation Rates. 19 Q. PLEASE BRIEFLY EXPLAIN THE BASIS FOR THE ADJUSTMENT FOR NEW 20 DEPRECIATION RATES. 21 A. OTP’s electric generating, and delivery system is fully integrated and has similar 22 characteristics throughout its service territory. OTP conducts its annual depreciation 23 reviews and the five-year depreciation studies, required by Minnesota Rules,2 on the 24 property and equipment in its entire system. Therefore, it is reasonable, and in fact
2 Minnesota Statutes § 216B.11 and Minnesota Rules 7825.0600 through 7825.0900 give authority to the MPUC to review and approve proper and adequate rates and methods for depreciation used by regulated electric utilities in that state. These Rules require utilities to review their depreciable rates annually and conduct depreciation studies at least every five years.
24 Docket No. EL18-___ Akerman Direct 1 desirable, to use consistent depreciation parameters and methods in all three states 2 covered by OTP’s service territory. By using a single set of depreciation parameters for 3 our contiguous, fully integrated system, OTP’s regulatory and accounting costs are lower, 4 and the Commission and its Staff may consider depreciation issues on an as needed basis. 5 The adjustment to the 2017 Test Year depreciation expense and accumulated depreciation 6 to reflects the MPUC’s approval of the depreciation parameters and rates for use in 2018 7 in MPUC Docket No. E017/D-17-652. Those parameters are used to calculate 8 depreciation rates for Minnesota, South Dakota, and North Dakota. 9 10 Q. PLEASE SUMMARIZE THE ADJUSTMENT FOR NEW DEPRECIATION RATES. 11 A. The new depreciation rates: (1) reduces Net Utility Plant in Service by $22,111; and (2) 12 reduces Total Average Rate Base by $22,111, as shown on Exhibit___(TAA-1), Schedule 13 8.
14 3. Rate Case Expense Amortization 15 Q. PLEASE SUMMARIZE THE ADJUSTMENT FOR RATE CASE EXPENSE 16 AMORTIZATION. 17 A. Mr. Tommerdahl explains the basis for the Rate Case expense adjustment in his Direct 18 Testimony. The adjustment for Rate Case expense amortization: (1) increases 19 Unamortized Rate Case expense by $458,334; and (2) increases Total Average Rate Base 20 by $458,334, as shown on Exhibit___(TAA-1), Schedule 8.
21 4. Adjustment to ADIT for TCJA 22 Q. PLEASE SUMMARIZE THE ADJUSTMENT TO ADIT RESULTING FROM THE 23 TCJA. 24 A. I discussed the need for an adjustment to ADIT that results from the TCJA earlier in my 25 Direct Testimony. The necessary adjustment: (1) decreases ADIT by $482,272; and (2) 26 increases Rate Base by $482,272.
25 Docket No. EL18-___ Akerman Direct 1 5. Effect of Test Year Adjustments on Allocations 2 Q. DO THE 2017 TEST YEAR ADJUSTMENTS CAUSE IMPACTS TO 3 ALLOCATIONS? 4 A. Yes. The impacts are due to changes in the allocators that result from the other financial 5 adjustments made to the 2017 Test Year. They are the result of calculations within the 6 Cost of Service model itself. For example, any adjustment to Net Plant in Service will 7 have a direct impact on the Net Electric Plant in Service (NEPIS) allocation factor 8 calculated as a percentage of total system Net Plant. The allocation percentage is 9 simultaneously recalculated each time an adjustment to Net Plant in Service occurs, 10 thereby providing the most up-to-date factor possible. As a result, anything that is 11 allocated on NEPIS is simultaneously re-calculated on a jurisdictional basis as well. 12 13 Q. PLEASE SUMMARIZE THE IMPACTS FROM THE CHANGES IN ALLOCATIONS. 14 A. The impacts from changes in allocations include: (1) several changes to Utility Plant in 15 Service accounts (resulting in a net increase of $339,141 to Total Utility Plant in 16 Service); (2) several changes to Accumulated Depreciation accounts (resulting in a net 17 increase of $143,008 Total Accumulated Depreciation); and (3) several changes to Net 18 Utility Plant in Service accounts (resulting in a net increase of $196,133 to Net Utility 19 Plant in Service); and (4) several changes to Average Rate Base accounts. The net effect 20 is a $360,393 decrease to Total Average Rate Base, as shown in Exhibit___(TAA-1), 21 Schedule 8. 22 23 Q. DOES EXHIBIT___(TAA-1), SCHEDULE 8 ALSO REFLECT ADJUSTMENTS FOR 24 THE MERRICOURT STEP INCREASE? 25 A. Yes. I explain those adjustments in Section XI of my Direct Testimony.
26 IX. INCOME STATEMENT
27 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? 28 A. In this section of my Direct Testimony, I will discuss the Income Statement and explain 29 the Income Statement schedules for the 2017 Actual Year and the 2017 Test Year. I will
26 Docket No. EL18-___ Akerman Direct 1 also address the Income Statement effects of rolling certain ECRR and TCRR costs into 2 base rates. Mr. Haugen discusses the substance of this proposal in his Direct Testimony. 3 4 Q. HOW IS THE INFORMATION IN EXHIBIT___(TAA-1), SCHEDULES 9 AND 10 5 AND IN THIS SECTION OF YOUR DIRECT TESTIMONY PRESENTED? 6 A. All the information in Exhibit___(TAA-1), Schedules 9 and 10 and in this section of my 7 Direct Testimony is presented in terms of South Dakota jurisdictional amounts.
8 A. SUMMARY OF FINANCIAL SCHEDULES 9 Q. WHAT TIME PERIODS ARE SHOWN ON THESE SCHEDULES? 10 A. Those Income Statement schedules show information for: (1) the 2017 Actual Year; and 11 (2) the 2017 Test Year. 12 13 Q. WHAT IS THE SOURCE OF THE 2017 ACTUAL YEAR INCOME STATEMENT 14 INFORMATION? 15 A. The source of the 2017 Actual Year Income Statement information is OTP’s South 16 Dakota JCOSS, which is the basis for reporting the earned ROR and Return on Equity 17 included in the 2017 South Dakota Jurisdictional Report which will be filed with the 18 Commission.
19 B. SUMMARY OF TEST YEAR INCOME STATEMENT 20 Q. WHAT ARE THE 2017 ACTUAL YEAR AND 2017 TEST YEAR TOTALS 21 AVAILABLE FOR RETURN? 22 A. As shown in Exhibit___(TAA-1), Schedule 3, the 2017 Actual Year Total Available for 23 Return (Net Income) for South Dakota is $4.8 million and the 2017 Test Year Total 24 Available for Return for South Dakota is $2.0 million. 25 26 Q. PLEASE BRIEFLY DESCRIBE WHAT IS INCLUDED IN THE INCOME 27 STATEMENT. 28 A. The Income Statement is composed primarily of: (1) Operating Revenues (which 29 includes both retail revenues and other operating revenues); (2) Operating Expenses
27 Docket No. EL18-___ Akerman Direct 1 (which includes Operating and Maintenance (O&M) expenses for the various operating 2 segments, Administrative and General expenses, depreciation expense, and general taxes, 3 including property taxes); (3) Income Tax Expense; and (4) Total Available for Return. 4 5 Q. HOW WAS THE 2017 ACTUAL YEAR INCOME STATEMENT DEVELOPED? 6 A. The 2017 Actual Year Income Statement was adjusted by removing revenues and 7 expenses that are part of “Traditional” regulatory adjustments. These adjustments reflect 8 recognized regulatory requirements and to “normalize” the 2017 Actual Year financial 9 information for one-time events that will not be recurring on an on-going basis. Other 10 Rate Case Adjustments were made to develop the 2017 Test Year. I will discuss those 11 adjustments in Section X of my Direct Testimony. 12 13 Q. WHAT ARE THE MAJOR COMPONENTS OF THE INCOME STATEMENT THAT 14 YOU WILL DISCUSS? 15 A. The major components of the Income Statement I will discuss are: 16 • Revenues; 17 • O&M Expenses; 18 • Depreciation Expense; 19 • Taxes; and 20 • Net Income. 21 I will provide the primary explanation of the Revenues, O&M Expenses, Depreciation 22 Expense included in the 2017 Test Year.
23 C. TEST YEAR REVENUES 24 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? 25 A. This section describes how revenues were determined for purposes of calculating the 26 2017 Test Year base rate revenue requirement. The major components of Revenues are 27 Retail Revenues and Other Revenues.
28 Docket No. EL18-___ Akerman Direct 1 1. Retail Revenues 2 Q. WHAT IS THE AMOUNT OF RETAIL REVENUE INCLUDED IN 3 EXHIBIT___(TAA-1), SCHEDULE 9? 4 A. Exhibit___(TAA-1), Schedule 9 shows that OTP’s South Dakota Jurisdictional Retail 5 Revenue is $32.9 million for the 2017 Actual Year, and $30.7 million for the 2017 Test 6 Year, and $36.6 million for the Merricourt Step Increase. 2017 Test Year revenues are 7 also detailed in pages 1 and 2 of Statement I. 8 9 Q. HOW WAS RETAIL REVENUE DETERMINED? 10 A. Retail revenue in the 2017 Test Year was determined on a calendar month basis using the 11 actual sales (as described in the Direct Testimony of Mr. Tommerdahl) applied to current 12 tariffs. The same revenue calculation was used to determine the revenue requirement 13 deficiency filed in the JCOSS for this rate case filing.
14 2. Other Electric Operating Revenue 15 Q. WHAT IS THE AMOUNT OF OTHER ELECTRIC OPERATING REVENUE 16 INCLUDED IN EXHIBIT___(TAA-1), SCHEDULE 9? 17 A. Exhibit___(TAA-1), Schedule 9 shows that OTP’s South Dakota Jurisdictional Other 18 Electric Operating Revenue Retail Revenue is $1.7 million for 2017 Actual Year, $1.7 19 million for 2017 Test Year, and $1.8 million for the Merricourt Step Increase. 20 21 Q. WHAT ARE THE COMPONENTS OF OTHER ELECTRIC OPERATING REVENUE? 22 A. Other Electric Operating Revenue includes items such as: 1) Midcontinent Independent 23 System Operator (MISO) transmission related revenues; 2) revenue from Integrated 24 Transmission Agreements; 3) revenues from plant operations and steam sales; 4) Asset 25 Based Revenues; and 5) other miscellaneous revenues.
26 a) MISO Revenues 27 Q. ARE MISO REVENUES INCLUDED IN THE 2017 TEST YEAR? 28 A. Yes. Pursuant to MISO’s Transmission and Energy Market Tariff and the MISO 29 Transmission Owners Agreement, OTP receives revenues from several sources for use of
29 Docket No. EL18-___ Akerman Direct 1 its transmission system and related services that it provides. These sources of revenue 2 include, but are not limited to, the following: (1) Schedule 1 - Scheduling, System 3 Control & Dispatch; (2) Schedule 2 - Reactive Supply & Voltage Control; (3) Schedule 7 4 - Firm Transmission Service; (4) Schedule 8 - Non-Firm Transmission Service; (5) 5 Schedule 9 - Network Integrated Transmission Service; and (6) Schedule 11 - Pass- 6 Through Revenue. 7 8 Q. IS THE REVENUE FROM THESE MISO SCHEDULES INCLUDED IN THE 2017 9 TEST YEAR? 10 A. Yes. Revenue from these MISO services in the amount of $522,521 is included in the 11 2017 Test Year. Table 1 below provides a breakdown by each MISO Schedule. 12 Table 1 13 2017 Test Year MISO Revenues by Schedule 14 (OTP SD)
MISO Schedule Revenue Amount
Schedule 1 $71,664 Schedule 2 70,749 Schedule 7 121,923 Schedule 8 (2,175) Schedule 9 190,591 Schedule 11 (1,662) Schedule 24 47,567 Schedule 26 116,083 Schedule 26A (92,219) Total MISO Schedule $522,521 Revenue
30 Docket No. EL18-___ Akerman Direct 1 b) Integrated Transmission Agreement Revenues 2 Q. WHAT IS AN INTEGRATED TRANSMISSION AGREEMENT (ITA)? 3 A. An ITA is an agreement to jointly plan and construct a common transmission system with 4 discrete ownership of individual facilities with reciprocal usage rights granted to each 5 party. OTP has ITAs with the following entities: Minnkota Power Cooperative 6 (Minnkota), Great River Energy (Great River), and East River Electric Power 7 Cooperative (East River). Each of these agreements has been approved by FERC. 8 9 Q. PLEASE DESCRIBE THE ITA REVENUES THAT OTP RECEIVES. 10 A. OTP receives transmission revenue from other utilities through ITAs for joint use of 11 defined transmission systems. Revenues received from Minnkota, Great River and East 12 River for the scheduling and dispatch services provided by OTP under the ITAs are based 13 on OTP’s costs associated with system control and dispatching, including operating, 14 maintenance, and fixed costs. Minnkota, Great River, and East River each pay their pro 15 rata share of the system control and dispatching, operating, and maintenance expenses 16 based on the respective joint use facilities owned by each party and OTP. 17 18 Q. ARE COSTS AND USAGE BALANCED UNDER THE ITAS? 19 A. Yes. One of the objectives of each ITA is to make sure each utility shares in the costs of 20 the transmission system proportionate to usage. The proportion of investment to usage of 21 the joint transmission system is determined each year for each of the ITAs. If a utility is 22 deficient in its investment relative to the investment by the other party, it makes 23 deficiency payments until the investment is equalized. The deficiency payments are 24 payments by the underinvested utility of the carrying cost of the utility that is more than 25 fully invested. 26
27 Q. IS THE REVENUE FROM THESE ITAS INCLUDED IN THE 2017 TEST YEAR? 28 A. Yes. Revenue from ITAs in the amount of $111,730 is included in the 2017 Test Year.
31 Docket No. EL18-___ Akerman Direct 1 c) Plant Operator and Steam Revenues 2 Q. DOES OTP RECEIVE COMPENSATION FOR LOAD DISPATCH EXPENSES FOR 3 BIG STONE AND COYOTE? 4 A. Yes. OTP operates the Big Stone Plant and Coyote Station on behalf of itself and its 5 ownership partners (Minnkota, Northwestern, and Montana-Dakota Utilities for Big 6 Stone and Minnkota, Northwestern, Montana-Dakota Utilities, and Northwestern 7 Municipal Power Agency for Coyote Station). As the plant operator, OTP provides 8 services for which it is compensated by its partners. The services include: (1) scheduling 9 and operations of the plants for both the day-ahead and real-time market; (2) acting as the 10 meter data management agent for all partners of the plants; (3) settlement reconciliation 11 of unit dispatches and actual generation; (4) providing accounting reports and records to 12 the partners; scheduling generator outages; (5) communicating directly with the MISO 13 generator dispatch desk; and (6) providing and maintaining reliable communications 14 between MISO, the plants, and the OTP control center. 15 16 Q. IS LOAD DISPATCH REVENUE INCLUDED IN THE 2017 TEST YEAR? 17 A. Yes. Plant operation revenue in the amount of $31,124 is included in the 2017 Test Year. 18 19 Q. DOES OTP RECEIVE REVENUE FROM THE SALE OF STEAM? 20 A. Yes. Big Stone supplies steam to an ethanol plant near the Big Stone Plant. 21 22 Q. IS REVENUE FROM STEAM SALES INCLUDED IN THE 2017 TEST YEAR? 23 A. Yes. Steam sales revenue in the amount of $158,774 is included in the 2017 Test Year.
24 d) Asset Based Revenues 25 Q. DOES OTP RECEIVE REVENUE FROM ASSET BASE REVENUES? 26 A. Yes. Asset based Revenue is included in the 2017 Test Year, as required in our last 27 South Dakota rate case. The corresponding expenses are also included, and any margins 28 are credited to customers through the fuel clause. 29
32 Docket No. EL18-___ Akerman Direct 1 Q. ARE ASSET BASED REVENUE INCLUDED IN THE 2017 TEST YEAR? 2 A. Asset Based Revenues in the amount of $448,767 are included in the 2017 Test Year.
3 e) Other Revenues 4 Q. ARE ALL OTHER SOURCES OF OTHER ELECTRIC OPERATING REVENUES 5 ALSO INCLUDED IN THE 2017 TEST YEAR? 6 A. Yes. Other sources of Other Electric Operating Revenues, they are summarized below in 7 Table 2 and included in the 2017 Test Year in the amount of $458,432. 8 Table 2 9 2017 Test Year Other Revenues 10 (OTP SD)
Other Revenue Revenue Amount
Generator Interconnection $91,802 Load Control and Dispatch 71,002 Late Fees direct assign to SD 95,929 Other Misc. Revenues $199,699 Total Other Revenues $458,432
11 D. O&M EXPENSES 12 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? 13 A. In this section of my Direct Testimony, I will briefly describe the components in the 14 Schedule of OTP’s O&M expenses for the 2017 Test Year, including unadjusted and 15 adjusted amounts. I will identify each category of O&M Expense and briefly list the 16 types of expenses included in each category. Also, I will explain the difference between 17 the unadjusted and adjusted amounts in Section X of my Direct Testimony. 18 19 Q. HAVE YOU ALSO PROVIDED A SCHEULE WHICH INCLUDES ALL O&M 20 EXPENSES? 21 A. Yes. Exhibit___(TAA-1), Schedule 10, the Schedule of O&M Expenses, includes all 22 O&M expenses, including the O&M expenses levels from OTP’s last South Dakota rate 23 case (Docket No. EL 10-011), for the 2017 Actual Year, and for the 2017 Test Year.
33 Docket No. EL18-___ Akerman Direct 1 1. Production Expenses 2 Q WHAT IS THE AMOUNT OF PRODUCTION EXPENSE INCLUDED IN 3 Exhibit___(TAA-1), SCHEDULE 10? 4 A. Exhibit___(TAA-1), Schedule 10 shows that OTP’s South Dakota Jurisdictional 5 Production Expense is $14.2 million for the 2017 Actual Year before adjustments and 6 $14.5 million for the 2017 Test Year after adjustments. 7 8 Q. WHAT IS INCLUDED IN PRODUCTION EXPENSE? 9 A. The most significant Production Expense is Fuel and Purchased Power. Production 10 Expense also includes maintenance costs of OTP’s generation plants.
11 2. Transmission Expenses 12 Q. WHAT IS THE AMOUNT OF TRANSMISSION EXPENSE INCLUDED IN 13 EXHIBIT___(TAA-1), SCHEDULE 10? 14 A. Exhibit___(TAA-1), Schedule 10 shows that OTP’s South Dakota Jurisdictional 15 Transmission Expense is $2.94 million for the 2017 Actual Year before adjustment and 16 $2.95 million for the 2017 Test Year after adjustments. 17 18 Q. WHAT IS INCLUDED IN TRANSMISSION EXPENSE? 19 A. Transmission expense includes: (1) Load dispatching: (2) Substation expense; (3) 20 Maintenance of transmission lines and substations; (4) Transmission of electricity by 21 others; (5) Rents for transmission property; (6) Engineering; (7) Computer Hardware and 22 Software for operation of the transmission system; and (8) Transmission Market Costs.
23 3. Distribution Expenses 24 Q. WHAT IS THE AMOUNT OF DISTRIBUTION EXPENSE INCLUDED IN 25 EXHIBIT___(TAA-1), SCHEDULE 10? 26 A. Exhibit___(TAA-1), Schedule 10 shows that OTP’s South Dakota Jurisdictional 27 Distribution Expense is $1.7 million for the 2017 Actual Year before adjustments and 28 $1.7 million for the 2017 Test Year after adjustments.
34 Docket No. EL18-___ Akerman Direct 1 Q. WHAT IS INCLUDED IN DISTRIBUTION EXPENSE? 2 A. Distribution Expense includes: expenses for operation and maintenance of the 3 distribution system, including substations, wires, transformers, meters and lighting.
4 4. Customer Accounting Expenses 5 Q. WHAT IS THE AMOUNT OF CUSTOMER ACCOUNTING EXPENSE INCLUDED 6 IN EXHIBIT___(TAA-1), SCHEDULE 10? 7 A. Exhibit___(TAA-1), Schedule 10 shows that OTP’s South Dakota Jurisdictional 8 Customer Accounting Expense is $1.14 million before and $1.15 million for the 2017 9 Test Year after adjustments. 10 11 Q. WHAT IS INCLUDED IN CUSTOMER ACCOUNTING EXPENSE? 12 A. Customer Accounting Expense includes: Meter Reading, billing and maintenance of 13 customer records (customer information systems).
14 5. Customer Service and Information Expenses 15 Q. WHAT IS THE AMOUNT OF CUSTOMER SERVICE AND INFORMATION 16 EXPENSE INCLUDED IN EXHIBIT___(TAA-1), SCHEDULE 10? 17 A. Exhibit___(TAA-1), Schedule 10 shows that OTP’s South Dakota Jurisdictional 18 Customer Accounting Expense is $663,000 for the 2017 Actual Year before and 19 $664,000 for the 2017 Test Year after adjustments. 20 21 Q. WHAT IS INCLUDED IN CUSTOMER SERVICE AND INFORMATION EXPENSE? 22 A. Customer Service and Information Expense includes customer assistance expenses.
23 6. Sales Expense 24 Q. WHAT IS THE AMOUNT OF SALES EXPENSE INCLUDED IN EXHIBIT___ (TAA- 25 1), SCHEDULE 10? 26 A. Exhibit___(TAA-1), Schedule 10 shows that OTP’s South Dakota Jurisdictional Sales 27 Expense is $11,000 for the 2017 Actual Year before adjustments and $20,000 for the 28 2017 Test Year after adjustments.
35 Docket No. EL18-___ Akerman Direct 1 Q. WHAT IS INCLUDED IN SALES EXPENSE? 2 A. Sales Expense include Selling and Advertising Expenses, as well as Economic 3 Development Costs.
4 7. Administrative and General Expenses 5 Q. WHAT IS THE AMOUNT OF ADMINISTRATIVE AND GENERAL EXPENSE 6 INCLUDED IN EXHIBIT___(TAA-1), SCHEDULE 10? 7 A. Exhibit___(TAA-1), Schedule 10 shows that OTP’s South Dakota Jurisdictional 8 Administrative and General Expense is $3.7 million for the 2017 Actual Year before 9 adjustments and $4.0 million for the 2017 Test Year after adjustments. 10 11 Q. WHAT IS INCLUDED IN ADMINISTRATIVE AND GENERAL EXPENSE? 12 A. Administrative and General Expense includes: (1) Salaries; (2) Office Supplies & 13 Expenses; (3) Various Admin & General Expenses; (4) Outside Services Employed; (5), 14 Property Insurance; (6) Injuries & Damage; (7) Employee Pensions & Benefits; (8) 15 Regulatory Commission Expenses; (9) Miscellaneous General Expenses; (10) 16 Informational Advertising; (11) Rents; and (12) Building Maintenance Expenses.
17 E. DEPRECIATION EXPENSE 18 Q. WHAT IS THE AMOUNT OF DEPRECIATION EXPENSE INCLUDED IN 19 EXHIBIT___(TAA-1), SCHEDULE 9? 20 A. Exhibit___(TAA-1), Schedule 9 shows OTP’s South Dakota Jurisdictional Depreciation 21 Expense is $4.7 million for the 2017 Actual Year, $5.0 million for the 2017 Test Year, 22 and $6.0 million for the Merricourt Step Increase (referred to as the 2017 Test Year Step 23 on Schedule 9). 24 25 Q. HOW WERE TEST YEAR DEPRECIATION EXPENSES DETERMINED? 26 A. As I explained earlier in my Direct Testimony, the depreciation expense in the 2017 Test 27 Year reflects the remaining lives and salvage percentage parameters as determined in our 28 2016 depreciation study and approved by the MPUC.
36 Docket No. EL18-___ Akerman Direct 1 F. INCOME TAXES 2 Q. WHAT IS THE AMOUNT OF INCOME TAX EXPENSE INCLUDED IN 3 EXHIBIT___(TAA-1), SCHEDULE 9? 4 A. Exhibit___(TAA-1), Schedule 9 shows OTP’s South Dakota Jurisdictional Income Tax 5 Expense is $0 for the 2017 Actual Year, ($1,021,346) for the 2017 Test Year, and 6 $46,847 for the Merricourt Step Increase. 7 8 Q. HOW WERE OTP’S INCOME TAX EXPENSES CALCULATED? 9 A. OTP’s Federal and South Dakota income tax expenses are based solely on the regulated 10 income and expense items included in the revenue requirement calculation using the 11 “stand-alone” method. The stand-alone method determines the jurisdictional regulated 12 income tax expense based solely on allowable regulated income and expense items. The 13 current income tax expense calculation utilizes straight-line depreciation rates to 14 determine depreciation expense as part of the current income tax expense calculation.
15 X. ADJUSTMENTS TO INCOME STATEMENT
16 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY? 17 A. In this section of my Direct Testimony, I will describe the Traditional Adjustments and 18 Rate Case Adjustments that have been made to determine the 2017 Actual Year Income 19 Statement and the 2017 Test Year Income Statement. 20 21 Q. HAVE YOU PREPARED A LIST OF THE ADJUSTMENTS TO THE INCOME 22 STATEMENT MADE FOR THE 2017 TEST YEAR? 23 A. Yes. The following is a list of Traditional Adjustments (necessary to arrive at the 2017 24 Actual Year) and Rate Case Adjustments (necessary to arrive at the 2017 Test Year): 25 26 Traditional Adjustments to Income Statement: 27 1. Advertising Expense 28 2. AFUDC on Short-Term CWIP 29 3. BSP II Generation Recovery
37 Docket No. EL18-___ Akerman Direct 1 4. Emission Allowances 2 5. Incentive Compensation 3 6. Renewable Energy Credit (REC) Sales 4 7. Transmission Recovery 5 6 Test Year Adjustments to Income Statement 7 1. Normalize CISOne Project 8 2. BSP II Transmission Amortization 9 3. New Depreciation Rates 10 4. Weather Normalization 11 5. Revenue Normalization 12 6. Wages, KPA, and Management Incentive 13 7. Medical/Dental, FAS 87, 106, 112 14 8. Rate Case Expense Amortization 15 9. Storm Damage 16 10. Removal of Production Tax Credits 17 11. Plant Outage Normalization 18 12. Removal of TCRR Revenues 19 13. Removal of ECRR Revenues 20 14. Adjust Deferred Tax for Tax Reform 21 15. Allocation Changes due to Test Year Adjustments 22 23 Q. HAVE YOU PREPARED A SCHEDULE SHOWING ALL TRADITIONAL 24 ADJUSTMENTS TO REACH THE 2017 ACTUAL YEAR INCOME STATEMENT? 25 A. Yes. All Traditional Adjustments to the 2017 Actual Year Income Statement are 26 reflected in Exhibit___(TAA-1), Schedule 11 attached to my Direct Testimony. 27
38 Docket No. EL18-___ Akerman Direct 1 Q. HAVE YOU PREPARED A SCHEDULE SHOWING ALL TEST YEAR 2 ADJUSTMENTS TO REACH THE 2017 TEST YEAR INCOME STATEMENT? 3 A. Yes. All Test Year Adjustments to the Income Statement are reflected in 4 Exhibit___(TAA-1), Schedule 12 attached to my Direct Testimony. 5 6 Q. HOW HAVE YOU PRESENTED THE INFORMATION IN EXHIBIT___(TAA-1), 7 SCHEDULES 11 AND 12? 8 A. All the information in Exhibit___(TAA-1), Schedules 11 and 12 and in this section of my 9 Direct Testimony is presented in terms of South Dakota jurisdictional amounts.
10 A. TRADITIONAL ADJUSTMENTS TO INCOME STATEMENT
11 1. Advertising Expense 12 Q. PLEASE DESCRIBE ADVERTISING EXPENSE. 13 A. Advertising expenditures that are reasonable in amount and purpose are included as 14 operating expenses in the cost of service determination for ratemaking purposes. The 15 types of advertising included are those designed to encourage energy conservation, 16 promote safety, inform and educate consumers on the utility’s financial services, 17 disseminate information on a utility’s corporate affairs to its owners. 18 19 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO ADVERTISING 20 EXPENSES. 21 A. The adjustment for Advertising Expenses: (1) decreases Total O&M Expenses by 22 $32,306; (2) increases Total Income Taxes by $6,808; and (3) increases Net Operating 23 Income by $25,612, as shown on Exhibit___(TAA-1), Schedule 11. Mr. Haugen 24 discusses the basis for this adjustment in his Direct Testimony.
25 2. AFUDC on Short-Term CWIP 26 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO AFUDC ON 27 SHORT-TERM CWIP. 28 A. I explained the basis for an adjustment for AFUDC on Short-Term CWIP earlier in my 29 Direct Testimony. The adjustment for AFUDC on Short-Term CWIP: (1) increases Total
39 Docket No. EL18-___ Akerman Direct 1 Depreciation Expense by $62,939; (2) decreases Total Income Tax by $13,217; and (3) 2 decreases Net Operating Income by $49,721, as shown on Exhibit___(TAA-1), Schedule 3 11.
4 3. BSP II Generation Recovery 5 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO BSP II 6 AMORTIZATION. 7 A. I explained the basis for this adjustment earlier in my Direct Testimony. The adjustment 8 for BSP II generation recovery: (1) increases Depreciation Expense by $100,332; (2) 9 decreases OTP Total Income Tax by $21,070; and (3) decreases OTP Net Operating 10 Income by $79,262 as shown on Exhibit___(TAA-1), Schedule 11.
11 4. Emission Allowances 12 Q. PLEASE SUMMARIZE THE ADJUSTMENT FOR EMISSIONS ALLOWANCES. 13 A. The adjustment for emissions allowances has virtually no effect, increasing Net 14 Operating Income by $1, as shown on Exhibit___(TAA-1), Schedule 11.
15 5. Incentive Compensation 16 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO INCENTIVE 17 COMPENSATION. 18 A. The adjustments with respect to Incentive Compensation reflect the cap of 25 percent of 19 salary for each employee and are described in the Direct Testimony of OTP witness Mr. 20 Peter E. Wasberg. The adjustment for incentive compensation: (1) decreases Total O&M 21 Expenses by $82,059; (2), increases Total Income Taxes by $17,232; and (3) increases 22 Net Operating Income by $64,826, as shown on Exhibit___(TAA-1), Schedule 11.
23 6. REC Sales 24 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO REC SALES. 25 A. An adjustment for REC sales shares 90 percent of the SD REC revenue to SD customers 26 per Commission Decision EL09-029. The adjustment for REC sales: (1) increases Total 27 Operating Revenue by $575; (2) increases Total Income Tax by $121; (3) increases Net 28 Operating Income by $455, as shown on Exhibit___(TAA-1), Schedule 11.
40 Docket No. EL18-___ Akerman Direct 1 7. Transmission Recovery 2 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO TRANSMISSION 3 RECOVERY. 4 A. The adjustment for Transmission recovery conforms to the ratemaking approach 5 approved by the Commission in Docket EL-16-035 with respect to OTP’s investments in 6 FERC-approved MVPs. The adjustment: (1) decreases Total Operating Revenues by 7 $2,993,155 (2) decreases Total O&M Expenses by $8,540; (3) decreases Total 8 Depreciation Expense by $209,891; (4) decreases Total Income Taxes by $536,224; and 9 (5) decreases Net Operating Income by $2,017,224, as shown on Exhibit___(TAA-1), 10 Schedule 11.
11 B. TEST YEAR ADJUSTMENTS TO THE INCOME STATEMENT
12 1. Normalize CISone Project 13 Q. PLEASE SUMMARIZE THE ADJUSTMENTS TO THE INCOME STATEMENT 14 ADJUSTMENT FOR THE CISONE PROJECT. 15 A. Yes. Mr. Tommerdahl has explained the basis for the adjustments for the CISone Project 16 in his Direct Testimony. The adjustment to the Income Statement for the CISone Project: 17 (1) increases Depreciation Expense by $121,188; (2) decreases Total Income Taxes by 18 $25,490; and (3) decreases Total Available for Return by $95,698, as shown in 19 Exhibit___(TAA-1), Schedule 12.
20 2. BSP II Transmission Amortization 21 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO BSP II 22 TRANSMISSION AMORTIZATION. 23 A. The Commission authorized recovery through amortization of Big Stone II project costs 24 in the 2010 OTP rate case, Docket No. EL10-011.3 Exhibit___(TAA-1), Schedule 13 25 provides the amortization schedule. The adjustment for BSP II transmission
3 Docket No. EL10-001 Page 3 provides for amortization of cancelled Big Stone II generating plant costs over ten years.
41 Docket No. EL18-___ Akerman Direct 1 amortization: (1) increases Depreciation Expense by $164,538; (2) decreases Total 2 Income Tax Expense by $34,553, and (3) decreases Total Available for Return by 3 $129,985 as shown in Exhibit___(TAA-1), Schedule 12. 4
5 3. New Depreciation Rates 6 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO NEW 7 DEPRECIATION RATES. 8 A. I explained the basis for an adjustment for new depreciation rates earlier in my Direct 9 Testimony. The adjustment for the new depreciation rates: (1) increases Depreciation 10 Expense by $22,111; (2) decreases Total Income Taxes by $4,635; and (2) decreases 11 Total Available for Return by $17,476, as shown in Exhibit___(TAA-1), Schedule 12.
12 4. Weather Normalization 13 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO WEATHER 14 NORMALIZATION. 15 A. The basis for OTP’s weather normalization adjustment is explained in Mr. Tommerdahl’s 16 Direct Testimony. The adjustment for weather normalization: (1) increases Total 17 Operating Revenues by $335,353; (2) increases Total O&M Expenses by $133,229; (3) 18 increases Total Income Taxes by $42,446; and (4) increases Net Operating Income by 19 $159,679, as shown on Exhibit___(TAA-1), Schedule 12.
20 5. Revenue Normalization 21 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO REVENUE 22 NORMALIZATION. 23 A. The basis for OTP’s revenue normalization adjustment is explained in the Direct 24 Testimony of Mr. Tommerdahl. The adjustment for revenue normalization: (1) increases 25 Total Operating Revenues by $4,325; (2) increases Total O&M Expenses by $2,179; (3) 26 increases Total Income Taxes by $451; and (4) increases Net Operating Income by 27 $1,695, as shown on Exhibit___(TAA-1), Schedule 12.
42 Docket No. EL18-___ Akerman Direct 1 6. Wages, KPA, and Management Incentive 2 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO WAGES, KPA, 3 AND MANAGEMENT INCENTIVE. 4 A. Mr. Wasberg explains the basis for OTP’s adjustment for wages, KPA, and management 5 incentive. Wages is based on a 3% growth factor increase. KPA and management 6 incentive are based on a five-year average. The adjustment for wages, KPA, and 7 management incentive: (1) increases Total O&M Expenses by $4,781; (2) decreases 8 Total Income Taxes by $1,004; and (3) decreases Net Operating Income by $3,777, as 9 shown on Exhibit___(TAA-1), Schedule 12.
10 7. Medical / Dental, FAS 87, 106, 112 11 Q. HAVE YOU MADE ADJUSTMENTS ASSOCIATED WITH MEDICAL, POST 12 RETIREMENT MEDICAL AND PENSION COSTS? 13 A. Yes. Table 3 provides the differences between the 2017 costs and the 2018 costs 14 explained by Mr. Wasberg. 15 16 Table 3 17 (OTP Total) 18 ($ millions) Percent Costs 2017 2018 Change Medical & Dental $ 11,683 $11,267 (3.56%)
FAS 112 Post Employment Medical 164 753 360.27%
FAS 106 Post-Retirement Medical 4,970 5,654 13.77%
FAS 87 Pension 5,736 5,895 2.78%
Total $22,552 $23,569 4.5% 19 20 Q. WHAT ARE THE OTP SD 2017 TEST YEAR PORTIONS OF THESE COSTS? 21 A. The 2017 Test Year FAS 112 cost is $68,992 (OTP SD EST). The 2017 Test Year FAS 22 106 cost is $518,292 (OTP SD EST). The 2017 Test Year Pension cost is $540,416 (OTP 23 SD EST). 24
43 Docket No. EL18-___ Akerman Direct 1 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO MEDICAL / 2 DENTAL AND FAS 87, 106, AND 112. 3 A. The adjustment for Medical / Dental and FAS 87, 106, and 112 expenses: (1) increases 4 Total O&M Expenses by $72,109; (2) decreases Total Income Taxes by $15,143; and (3) 5 decreases Net Operating Income by $56,966, as shown on Exhibit___(TAA-1), Schedule 6 12. 7 8 Q. DOES OTP HAVE BOTH A PREPAID FAS 87 PENSION ASSET AND PREPAID 9 FAS 106 AND 112 LIABILITIES? 10 A. Yes. OTP has paid more into its pension trust than has been reflected in FAS 87 11 expenses, leading to a prepaid pension asset, and has reflected more FAS 106 and FAS 12 112 expenses than it has paid out for the related benefits, leading to prepaid liabilities. 13 14 Q. HAS OTP BEEN CONSISTENT IN ITS TREATMENT OF THE RATE BASE 15 IMPACTS OF BOTH ITS PREPAID FAS 106 AND FAS 112 LIABILITIES AND 16 PREPAID PENSION ASSET? 17 A. Yes. OTP has been consistent in reflecting the prepaid pension asset as an increase to 18 rate base (net of associated ADIT) and has reflected the prepaid FAS 106 and 112 19 liabilities as decreases to rate base (net of associated ADIT). 20 21 Q. WHAT IS THE 2017 TEST YEAR NET RATE BASE IMPACT OF INCLUDING THE 22 PREPAID PENSION ASSET AND 106 AND FAS 112 LIABILITIES? 23 A. Table 4 below shows the net rate base impact of including the 2017 Test Year prepaid 24 pension asset, FAS 106 and FAS 112 balances is a $20.8 million (OTP Total)/$1.6 25 million (OTP SD) decrease to OTP’s 2017 Test Year rate base.
44 Docket No. EL18-___ Akerman Direct 1 Table 4 2 2017 Test Year Rate Base Impact of 3 Prepaid Pension Asset, FAS 106 and FAS 112 Liabilities 4 (OTP SD) 5 ($millions) Associated Net Rate Base Non-Plant Rate Base ADIT Impact Component Asset/ (Liability) Asset/(Liability) Asset/(Liability) Prepaid Pension Asset $2,875 ($984) $ 1,891 FAS 106 Liability (4,882) 1,434 (3,448) FAS 112 Liability (114) 27 (87) Total Net Impact ($2,121) $ 477 ($1,644) 6 7 Q. WHAT IS THE SIGNIFICANCE OF THE NET IMPACT BEING A REDUCTION TO 8 RATE BASE? 9 A. The $1.6 million Net Impact reduction in rate base will reduce the 2017 Test Year 10 revenue requirement by approximately $66,000 (OTP SD), as shown on Table 5. 11 Table 5 12 2017 Test Year Revenue Requirement Impact of 13 Prepaid Pension Asset, FAS 106 and FAS 112 Liabilities 14 (OTP SD) 15 ($millions)
Net Rate Base Impact Asset/(Liability) Total Net Impact ($1,644) Revenue Requirement 7.96% ROR (55) Tax Impact (11) Total Net Impact ($66)
45 Docket No. EL18-___ Akerman Direct 1 8. Rate Case Expenses 2 Q. WHAT IS THE AMOUNT OF RATE CASE EXPENSE INCLUDED IN THE 2017 3 TEST YEAR? 4 A. The total amount of rate case expense is $550,000 amortized over three years for a 2017 5 Test Year 13-month average amount of $458,334. The basis for that expense in 6 explained in Mr. Tommerdahl’s Direct Testimony. 7 8 Q. PLEASE SUMMARIZE THE ADJUSTMENT FOR THE RATE CASE EXPENSES? 9 A. The adjustment for rate case expense: (1) increases Total Operating Expenses by 10 $183,333; (2) decreases Total Income Taxes by $38,500; and (3) decreases Total 11 Available for Return by $144,833, as shown in Exhibit___(TAA-1), Schedule 12.
12 9. Storm Damage 13 Q. HAVE YOU MADE ANY ADJUSTMENTS TO STORM REPAIR EXPENSE? 14 A. Yes. This adjustment brings this expense up to the five-year average amount. The 2017 15 Actual Year storm repair expense was much lower than average, and therefore not 16 representative of the normal cost of this activity. 17 18 Q. PLEASE SUMMARIZE THE ADJUSTMENT WITH RESPECT TO STORM 19 DAMAGE. 20 A. The adjustment for Storm Damage expenses: (1) increases Total O&M Expenses by 21 $45,266; (2) decreases Total Income Taxes by $9,251; and (3) decreases Net Operating 22 Income by $36,015, as shown on Exhibit___(TAA-1), Schedule 12.
23 10. Removal of Production Tax Credits 24 Q. PLEASE SUMMARIZE THE ADJUSTMENT TO THE INCOME STATEMENT TO 25 REFLECT THE REMOVAL OF PRODUCTION TAX CREDITS (PTC)? 26 A. The adjustment for PTC removal: (1) increases Total Income Taxes by $638,677; and (2) 27 decreases Total Available for Return by $638,677, as shown in Exhibit___(TAA-1), 28 Schedule 12. This adjustment is explained in the Direct Testimony of Mr. Haugen.
46 Docket No. EL18-___ Akerman Direct 1 11. Plant Outage Normalization 2 Q. DESCRIBE HOW OTP PLANS FOR O&M EXPENSES RESULTING FROM MAJOR 3 PLANT OUTAGES AT ITS GENERATION FACILITIES? 4 A. OTP has two generating facilities (Big Stone Plant and Coyote Station) that are on three- 5 year schedules for major plant outages. These outages facilitate larger repairs and allow 6 for other maintenance. Having a three-year schedule for larger repairs and maintenance 7 is necessary to maintain a reliable system. 8 9 Q. WAS AN ADJUSTMENT MADE RELATED TO THE PLANT OUTAGE O&M 10 EXPENSES? 11 A. Yes. An adjustment was made because O&M expenses would be understated for a 12 normal year if left unadjusted. The adjustment considers the actual 2016 Coyote Station 13 plant outage expenses as well the budgeted 2018 Big Stone Plant outage expenses. One 14 third of the total for the two plant outages is compared to 2017 plant outage expense. The 15 adjustment normalizes the 2017 plant outage expense to the level it would be if the plant 16 outage costs were expensed each year. 17 18 Q. PLEASE SUMMARIZE THE ADJUSTMENT TO NORMALIZE PLANT OUTAGE 19 EXPENSE. 20 A. The adjustment for plant outage expense: (1) increases Total Operating Expenses by 21 $145,434; (2) decreases Total Income Taxes by $30,541; and (3) decreases Total 22 Available for Return by $114,893, as shown in Exhibit___(TAA-1), Schedule 12.
23 12. Removal of TCRR Revenues 24 Q. PLEASE SUMMARIZE THE ADJUSTMENT TO REFLECT THE REMOVAL OF 25 TCRR REVNUES? 26 A. The adjustment for the removal of TCRR revenues: (1) decreases Total Operating 27 Revenue by $245,070; (2) decreases Total Income Tax by $51,465; and (3) decreases 28 Total Available for Return by $193,605. Mr. Haugen discusses this adjustment in his 29 Direct Testimony.
47 Docket No. EL18-___ Akerman Direct 1 13. Removal of ECRR Revenues 2 Q. PLEASE SUMMARIZE THE ADJUSTMENT TO REFLECT THE REMOVAL OF 3 ECRR REVNUES? 4 A. The adjustment for the removal of ECRR revenues: (1) decreases Total Operating 5 Revenue by $2,374,465; (2) decreases Total Income Tax by $498,638; and (3) decreases 6 Total Available for Return by $1,875,827. Mr. Haugen discusses the ECRR revenues in 7 his Direct Testimony.
8 14. Adjust Deferred Tax Expense for TCJA 9 Q. PLEASE SUMMARIZE THE ADJUSTMENT TO DEFERRED INCOME TAX 10 EXPENSE RESULTING FROM THE TCJA 11 A. I explained the basis for an adjustment to the deferred income tax expense earlier in my 12 Direct Testimony. The necessary adjustment: (1) decreases Total Income Tax by 13 $664,300; and (2) increases Total Available for Return by $664,300.
14 15. Allocation of Changes due to Test Year Allocation 15 Q. PLEASE SUMMARIZE THE ADJUSTMENT TO REFLECT THE EFFECT OF TEST 16 YEAR ADJUSTMENTS ON ALLOCATIONS? 17 A. The adjustment for the effects of Test Year adjustments on allocations include: (1) 18 increases Other Electric Operating Revenue (resulting in an increase in Total Operating 19 Revenue of $5,653; (2) several increases in operating expenses (resulting in an increase 20 in Total Operating Expenses of $79,969; (3) increases Total Income Tax expense of 21 $214,979; and (4) decreases Total Available for Return of $289,296, as shown in 22 Exhibit___(TAA-1), Schedule 12.
23 XI. MERRICOURT STEP
24 Q. WHAT WILL YOU ADDRESS IN THIS SECTION OF YOUR DIRECT 25 TESTIMONY? 26 A. In this section of my Direct Testimony, I address the rate base and income statement 27 impacts of OTP’s Merricourt project step-in rate proposal. OTP witness Mr. Bradley E.
48 Docket No. EL18-___ Akerman Direct 1 Tollerson, Mr. Gerhardson, and Mr. Tommerdahl provide additional detail supporting the 2 Merricourt Step Increase in their Direct Testimonies.
3 A. Rate Base Impact 4 Q. DID YOU NORMALIZE 2017 TEST YEAR PLANT IN SERVICE FOR THE 5 MERRICOURT STEP? 6 A. Yes. Exhibit___(TAA-1), Schedule 14 shows the adjustments to Plant in Service for the 7 Merricourt Step Increase. The adjustments to Plant in Service for the Merricourt Step 8 Increase are also shown on Exhibit___(TAA-1), Schedule 8. 9 10 Q. PLEASE SUMMARIZE THE CUMULATIVE ADJUSTMENTS MADE FOR THE 11 MERRICOURT STEP INCREASE. 12 A. The adjustments made for the Merricourt Step Increase are set forth in Exhibit___(TAA- 13 1), Schedule 14 and Exhibit___(TAA-1), Schedule 8 and include: (1) a $24,590,337 14 increase to Utility Plant in Service; (2) a $983,613 increase to Accumulated Depreciation; 15 (3) a $23,606,724 increase to Net Utility Plant in Service; (4) a $68,730 increase to 16 ADIT; and (5) a $23,537,994 increase to Total Average Rate Base. The corresponding 17 impacts on the 2017 Test Year Income Statement are explained below. 18
19 B. INCOME STATEMENT IMPACT 20 Q. DID OTP ASSUME FULL RECOVERY OF REVENUES AT THE END OF THE 21 CASE FOR THE MERRICOURT STEP INCREASE COST OF SERVICE STUDY? 22 A. Yes. OTP assumed that at the end of the case we would receive all proposed Test Year 23 revenues and then applied the Test Year Adjustment for the Merricourt Wind Project. 24 25 Q. PLEASE SUMMARIZE THE ADJUSTMENTS TO REVENUES FOR THE 26 MERRICOURT STEP INCREASE. 27 A. The adjustment for revenue for the Merricourt Step Increase: (1) increases Retail 28 Revenue by $5,978,110; (2) increases tax expense by $1,255,403 and (3) increases Total
49 Docket No. EL18-___ Akerman Direct 1 Available for Return by $4,722,707, as shown in Exhibit___(TAA-1), Schedule 15 and 2 Exhibit___(TAA-1), Schedule 12. 3 Q. PLEASE SUMMARIZE THE ADJUSTMENTS TO EXPENSES FOR THE 4 MERRICOURT STEP INCREASE. 5 A. The adjustment to the Income Statement for the Merricourt Step Increase: (1) decreases 6 Production Expense by $854,834; (2) increases Administrative and General Expenses by 7 $30,258; (3) increases Depreciation Expense by $983,613; (4) increases General Tax 8 Expense by $57,288; (5) increases Production Tax Credits by $1,356,702 (6) decreases 9 current Income Tax by $45,429 and (7) increases Total Available for Return by 10 $1,185,804, as shown in Exhibit___(TAA-1), Schedule 15 and Exhibit___(TAA-1), 11 Schedule 12. 12
13 XII. CONCLUSION.
14 Q. WHAT ARE YOUR CONCLUSIONS? 15 A. OTP has demonstrated the 2017 Test Year revenue deficiency of $5,978,109 has been 16 appropriately determined and all necessary adjustments have been made. Similarly, the 17 basis for the Merricourt Step Increase has been appropriately determined and all 18 necessary adjustments have been made. As a result, the 2017 Test Year revenue 19 deficiency of $5,978,109 and the Merricourt Step Increase should be recovered in base 20 rates. 21 22 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 23 A. Yes, it does.
50 Docket No. EL18-___ Akerman Direct Docket No. EL18-___ Exhibit__(TAA-1), Schedule 1 Page 1 of 1
Mr. Tyler A. Akerman, CPA, CGMA Manager, Business Planning/Regulatory Accounting Otter Tail Power Company 215 South Cascade Street Fergus Falls, Minnesota 56537 218-739-8298
CURRENT RESPONSIBILITIES: (October 2015 to Present)
Provide leadership in budgeting, financial planning, and forecasting as required by OTP and Otter Tail Corporation for use in strategic planning and decision making. In addition, this position is responsible for managing the production of official company budgets and monthly forecasts, for leading the work group which prepares the jurisdictional cost of service studies for the three jurisdictions in which OTP provides service (Minnesota, North Dakota, and South Dakota) and providing any other regulatory and financial analysis on an as needed basis.
PREVIOUS POSITIONS:
Otter Tail Power Company 2015 – Present Manager, Business Planning/Regulatory Accounting 2012 – 2015 Financial Analyst, Business Planning/Regulatory Accounting
City of Fergus Falls 2006 – 2012 Accountant, Finance
EDUCATIONAL / CERTIFICATIONS Moorhead State University-Moorhead, B.S. Majors in Accounting and Finance Minor in Business and Professional Communications
Certified Public Accountant (CPA) Chartered Global Management Accountant (CGMA)
OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 2 JURISDICTIONAL FINANCIAL SUMMARY SCHEDULES Page 1 of 1 SUMMARY OF REVENUE REQUIREMENTS - 2017 TEST YEAR
( A ) Line 2017 No. Description Test Year
1 Average Rate Base $84,904,901
2 Operating Income (Before AFUDC) $2,042,808
3 Allowance for Funds Used During Construction (AFUDC) $0
4 Total Available for Return (Line 2 + Line 3 + Rounding) $2,042,808
5 Overall Rate of Return (Line 4 / Line 1) 2.41%
6 Required Rate of Return 7.96%
7 Operating Income Requirement (Line 1 x Line 6) $6,758,430
8 Income Deficiency (Line 7 - Line 4) $4,715,622
9 Gross Revenue Conversion Factor 1.2677244
10 Revenue Deficiency (Line 8 x Line 9) $5,978,109
11 Retail Related Revenues Under Present Rates $30,650,015
12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 19.50% OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 3 JURISDICTIONAL FINANCIAL SUMMARY SCHEDULES Page 1 of 1 SUMMARY OF REVENUE REQUIREMENTS - JURISDICTIONAL
( A ) ( B ) ( C ) Line 2017 2017 2017 No. Description Actual Year Test Year Test Year Step
1 Average Rate Base $83,294,793 $84,904,901 $107,706,522
2 Operating Income (Before AFUDC) $4,814,182 $2,042,808 $8,077,190
3 Allowance for Funds Used During Construction (AFUDC) $0 $0 $0
4 Total Available for Return (Line 2 + Line 3 + Rounding) $4,814,182 $2,042,808 $8,077,190
5 Overall Rate of Return (Line 4 / Line 1) 5.78% 2.41% 7.50%
6 Required Rate of Return 7.74% 7.96% 7.96%
7 Operating Income Requirement (Line 1 x Line 6) $6,447,017 $6,758,430 $8,573,439
8 Income Deficiency (Line 7 - Line 4) $1,632,835 $4,715,622 $496,249
9 Gross Revenue Conversion Factor 1.5407727 1.2677244 1.267724
10 Revenue Deficiency (Line 8 x Line 9) $2,515,827 $5,978,109 $629,106
11 Retail Related Revenues Under Present Rates $32,929,872 $30,650,015 $36,628,125
12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 7.64% 19.50% 1.72% Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 1 of 14
Otter Tail Power Company
Jurisdictional and Class Cost of Service Study
And
Rate Design
Process Overview Manual
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 2 of 14 1. Introduction: The purpose of this document is to provide an overview of the various inputs of data which feed into Otter Tail Power’s (OTP) Jurisdictional Cost of Service Study (JCOSS) and Class Cost of Service Study (CCOSS) models to determine OTP’s revenue requirement upon which subsequent customer class revenue requirements and related rate designs are completed. Flow charts are provided along with descriptive narratives and tables to provide further clarity in how information included in OTP’s rate case filing flows from one step in the process to the next. Below is a high-level overview of key components within the overall process that leads to the determination of revenue requirements and corresponding rates necessary to collect the required revenues from the respective customer classes.
The balance of this document will review in general terms, the various components identified above, describing the flow of data between those components. The descriptions provided are assumed in the context of a forecast test year.
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 3 of 14
Retail Sales & Revenue Forecast In summary, the development of the kWh sales forecast at a class and jurisdictional level is the initial step in determining the retail base rate revenue forecast. The kWh sales forecasts and associated billing determinants then serve as inputs into the process which derives forecasted class and jurisdictional revenues based on existing base rate design. Additional revenues from various rate riders make up the balance of revenues associated with kWh sales, as itemized in Work Paper B-1. Total Jurisdictional revenues flow into the Input Summary, which subsequently feeds into the JCOSS. Class Revenues serve as an input in the CCOSS. Billing determinants developed in the process of creating the sales and revenue forecasts, ultimately serve as inputs into the final rate design models used to develop rates to collect the required revenues. These steps will be explained in more detail later in this document.
Other Electric Revenues and Sales for Resale are listed in Work Papers B-2 and B-3 and also flow into the Input Summary. These revenues, combined with the forecasted retail revenues, yield total jurisdictional and company revenues.
Jurisdictional/Class Jurisdictional/Class Sales Forecasts Retail Revenues Forecast
Other Electric Lead/Lag Jurisdictional Costof Class Cost of Revenues Study Service Study (JCOSS) Service Study (CCOSS)
Normal Adjustments
Class Revenue Requirements Jurisdictional and Input Summary Class Allocation Rate Code Billing Factors Determinants from Test Year Sales & Revenue Adjustments Forecast
Minimum Rate Code Level Functionalization Current System Study Rate Design Rates Models
Rate Base Expense Final Revenues by Proposed Forecast Forecast Rate Code, Class = Rates Class Revenue Req. E-Schedules
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 4 of 14
Functionalization (Volume 4A) The Functionalization Schedule, found in Volume 4A of the rate case filing, is the schedule which takes total company rate base and expense information as accounted for under Federal Energy Regulatory Commission (FERC) accounting rules, and aggregates those amounts into functional cost categories: production; transmission; distribution; customer accounting and collecting, and customer service and information. In addition, this schedule further “classifies” the information within each function, based on key service characteristics: demand, energy, customers and meters. These classifications have further sub-characteristics such as type of demand or energy, voltage level, or type of customer or meter. These service characteristics or sub-characteristics provide the basis for further cost allocations within the JCOSS and CCOSS. OTP’s Cost Allocation Procedures Manual (CAPM) provides further detail on how each class of costs gets allocated jurisdictionally and subsequently to the various classes within each jurisdiction.
Jurisdictional/Class Jurisdictional/Class Sales Forecasts Retail Revenues Forecast
Other Electric Lead/Lag Jurisdictional Costof Class Cost of Revenues Study Service Study (JCOSS) Service Study (CCOSS)
Normal Adjustments
Class Revenue Requirements Jurisdictional and Input Summary Class Allocation Rate Code Billing Factors Determinants from Test Year Sales & Revenue Adjustments Forecast
Minimum Rate Code Level Functionalization Current System Study Rate Design Rates Models
Rate Base Expense Final Revenues by Proposed Forecast Forecast Rate Code, Class = Rates Class Revenue Req. E-Schedules
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 5 of 14
Functionalization Pages:
Pages 1-3 is the input section of the Functionalization schedule, where the FERC account balances are entered and amounts are aggregated based on functional area.
Page 4 of the Functionalization schedule takes the distribution rate base and distribution expense balances from pages 1-3 of the Functionalization schedule and allocates those costs to the following classifications for distribution rate base and expenses:
- Primary Demand - Secondary Demand - Primary Customer - Secondary Customer - Street Lights - Area Lights - Meters - Load Management
The classifications of these costs are based on allocation factors developed from the Minimum System Study. Details of the process to develop the Minimum System Study are found in Appendix A-1 of OTP’s CAPM.
Page 4 of the Functionalization schedule also includes an input section on lines 2 and 3 for the Base/Peak split allocation factors which allocate Production Plant rate base and expense amounts between Base Demand and Peak Demand, Base Demand and Base Energy Categories. The calculation of the Base/Peak split factors is found in Cost of Service Workpapers C-1 and C-1a, following the methodology described in pages 3 and 4 of OTP’s CAPM.
Pages 5 and 6 of the Functionalization schedule summarize the allocations of costs from pages 1-4, into the respective cost categories that align with the categorical breakdowns ultimately included in OTP’s JCOSS and CCOSS. The Rate Base and Expense amounts are first entered into the JCOSS Input Summary, which is described in the next section below.
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 6 of 14
Input Summary (Volume 4A) The purpose of the Input Summary, found in Volume 4A is to aggregate Total Company cost information (operating statement as well as rate base items) that has been categorized in the Functionalization schedule, as well as incorporate Total Company Revenue amounts and other Company data quantified in other Workpapers, into a single schedule. This schedule serves as the staging schedule from which much of the company financial information is entered into the JCOSS model.
The amounts which have been functionalized and classified by service characteristics are included in Column A of the Input Summary, as well as revenues and certain other rate base items computed in their respective source document workpapers. All data in the Input Summary is footnoted to the source document / work paper of origin. The Input Summary then incorporates into the adjacent columns to the right, adjustments which are necessary for computation of the JCOSS.
A more detailed description of the various sections of the Input Summary is included following the graphic below.
Jurisdictional/Class Jurisdictional/Class Sales Forecasts Retail Revenues Forecast
Other Electric Lead/Lag Jurisdictional Costof Class Cost of Revenues Study Service Study (JCOSS) Service Study (CCOSS)
Normal Adjustments
Class Revenue Requirements Jurisdictional and Input Summary Class Allocation Rate Code Billing Factors Determinants from Test Year Sales & Revenue Adjustments Forecast
Minimum Rate Code Level Functionalization Current System Study Rate Design Rates Models
Rate Base Expense Final Revenues by Proposed Forecast Forecast Rate Code, Class = Rates Class Revenue Req. E-Schedules
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 7 of 14 Input Summary Schedules
The Input Summary is divided into two primary sections; Rate Base components and Operating Statement components. Further breakdowns of the Input Summary schedules are identified below:
1. A – Summary Schedules - These pages include all the rate base related accounts and associated adjustments. The A-Summary schedules are broken down further into two sections: a. A-Summary 1 - This is a bridge schedule which starts with Total Company Simple Average rate base amounts in Column A. These amounts originate from the Functionalization schedule as well as amounts from work paper schedules, as footnoted in the Input summary schedule. Subsequent columns in the schedule incorporate the Normal Adjustments necessary to determine OTP’s Total Company Unadjusted amounts in the last column of the schedule. These amounts reflect the values that would be input into the JCOSS Model to compute OTP’s Unadjusted JCOSS based on currently approved methodologies and normal adjustments.
b. A-Summary 2 - This is a bridge schedule which starts with Total Company Unadjusted amounts in Column A as computed in the A-Summary 1. Subsequent columns in the A- Summary 2 schedule incorporate the Test Year Adjustments necessary to determine OTP’s Total Company Adjusted amounts in the last column of the schedule. These amounts reflect the values that would be input into the JCOSS Model to compute OTP’s Test Year JCOSS.
2. B - Summary – These pages include all operating statement amounts and associated adjustments. The B-Summary schedules are broken down further into two sections:
a. B-Summary 1 - This is a bridge schedule which starts with Total Company annual Operating Statement amounts in Column A. These amounts originate from the Functionalization schedule as well as amounts from work paper schedules, as footnoted in the Input summary schedule. Subsequent columns in the B-Summary-1 schedule incorporate the Normal Adjustments necessary to determine OTP’s Total Company Unadjusted amounts in the last column of the schedule. These operating statement amounts reflect the values that would be input into the JCOSS Model to compute OTP’s Unadjusted JCOSS based on currently approved methodologies and normal adjustments.
b. B-Summary 2 - This is a bridge schedule which starts with Total Company Unadjusted Operating Statement amounts in Column A as computed in the A-Summary-1. Subsequent columns in the B-Summary 2 schedule incorporate the Test Year Adjustments necessary to determine OTP’s Total Company Adjusted amounts in the last column of the schedule. These amounts reflect the values that would be input into the JCOSS Model to compute OTP’s Test Year JCOSS.
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 8 of 14
Jurisdictional Cost of Service Study Model (JCOSS) The purpose of JCOSS model is to compute OTP’s total Available for Return and compare that amount to the current authorized/proposed return and computes incremental amount of revenue surplus or deficiency necessary to meet that authorized return. The key Inputs into the JCOSS are:
1. Input Summary Amounts 2. Lead-Lag Study Amounts 3. Jurisdictional Allocation Factors
Jurisdictional/Class Jurisdictional/Class Sales Forecasts Retail Revenues Forecast
Other Electric Lead/Lag Jurisdictional Costof Class Cost of Revenues Study Service Study (JCOSS) Service Study (CCOSS)
Normal Adjustments
Class Revenue Requirements Jurisdictional and Input Summary Class Allocation Rate Code Billing Factors Determinants from Test Year Sales & Revenue Adjustments Forecast
Minimum Rate Code Level Functionalization Current System Study Rate Design Rates Models
Rate Base Expense Final Revenues by Proposed Forecast Forecast Rate Code, Class = Rates Class Revenue Req. E-Schedules
The JCOSS is found in Volume 4A for the Test Year. The following table aligns the JCOSS Pages to the respective Input Summary, Lead-Lag, and Allocation Factor Schedules. All Summary pages in the JCOSS model have references to the respective detailed sections of the JCOSS.
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 9 of 14
JCOSS Description Source Source Pages Page 1-1 JCOSS Summary of Deficiency JCOSS Detail Pages Pages 2, 7, 17 2-1 Rate Base Summary JCOSS Detail Pages Pages 3, 4, 5, 6 3-1 Total Plant in Service Input Summary A-2 Page 1 4-1 Accumulated Depreciation Input Summary A-2 Page 2 Plant Held for Future Use Page 2 5-1 CWIP Input Summary A-2 Page 3 Materials & Supplies, Page 4 Fuel Stocks Page 4 Prepayments Page 4 Customer Advances Page 4 Cash Working Capital Page 4 6-1 Accumulated Deferred Income Taxes Input Summary A-2 Page 4 7-1 Operating Statement Summary JCOSS Detail Pages Pages 8,9,10,11,12 8-1 Operating Revenues Input Summary B-2 Page 1 9-1 Production Expenses Input Summary B-2 Page 2 Transmission Expenses Page 2 Distribution Expenses Page 2 Customer Accounting Expenses Page 2 10-1 Customer Service & Information Expenses Input Summary B-2 Page 2 Sales Expenses Page 3 Admin & General Expenses Page 3 11-1 Depreciation Expense Input Summary B-2 Page 4 12-1 General Taxes Input Summary B-2 Page 4 Investment Tax Credits Input Summary B-2 Page 4 Deferred Income Taxes Input Summary B-2 Page 4 Current Income Taxes- Federal JCOSS Detail Page 13-1 Current Income Taxes –MN JCOSS Detail Page 14-1 Current Income Taxes – ND JCOSS Detail Page 14-1 AFDC Input Summary Page 5 13-1 Federal Income Taxes JCOSS Calculation Page 13-a 14-1 Minnesota State Income Tax Expense JCOSS Calculation Page 14-a North Dakota State Income Tax Expense 15-1 Jurisdictional Allocation Factors Required Schedules C-9 Page 4 16-1 Secondary Allocation Factors JCOSS Calculation Page 16-a Required Schedules – C-9 Page 5 17-1 Capital Structure – Requested Required Schedules – D-1-a Page 17-1 Page 17-a 18-1 Cash Working Capital Lead Lag Study Summary – Page 1 Revenue Lead Days Required Schedules – B-2-e Page 1 19-1 Cash Working Capital - MN Calculation Lead Lag Study Required See Reference tables on next page Expense Lag Days Schedules – B-2-e Page 3 20-1 Cash Working Capital - ND Calculation Lead Lag Study See Reference tables on next page Expense Lag Days Required Schedules – B-2-e Page 3 21-1 Cash Working Capital - SD Calculation Lead Lag Study See Reference tables on next page Expense Lag Days Required Schedules – B-2-e Page 3 22-1 Cash Working Capital - FERC Calculation Lead Lag Study See Reference tables on next page Expense Lag Days Required Schedules – B-2-e Page 3 23-1 Cash Working Capital- Total Company JCOSS Calculation Sum of Jurisdictional totals 19-1 to 22-1
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 10 of 14 Lead-Lag Study Reference Table
The following table provides a cross reference of the various Lead-Lag study values found in the JCOSS to the respective page in the Lead-Lag Study.
JCOSS Page 18-1 Revenue Line Lead Lead Lag No. Revenue Lead Days from Service to Collection Days Study Page Notes: 23 Computer Maintained Billings 43.4 1 24 Manually Maintained Billings 41.3 1 25 Cost of Energy Adjustment Revenues 127.7 37 26 Sales for Resale 23.1 40 27 Rent from Electric Property -92.4 42 28 Miscellaneous 34.9 51 29 ITA Deficiency Payments 48.4 56 30 Wheeling 35.8 60 31 Load Control and Dispatch 27.9 1 Line 21 32 Rent from Electric Property - Big Stone 39.9 Calculated in COSS 33 Rent from Electric Property - Coyote 39.9 Calculated in COSS 34 Profit on Materials and Supplies 39.9 Calculated in COSS 35 Miscellaneous Services 39.9 Calculated in COSS 36 Loan Pool Interest 39.9 Calculated in COSS
JCOSS Page 20-1 Line Expense Lead Lag Study No. Item Lag Days Page Notes: 3 Fuel - Coal 15.5 69 5 Fuel - Oil 11.2 69 7 Purchased Power 31.6 69 9 Labor and Associated Payroll Expense 15.1 69 11 All Other O&M Expense 13.1 69 Line 19 13 Property Taxes (Excl Coal Conversion Taxes) 299.5 157 Calculated in COSS 15 Coal Conversion Taxes 33.3 171 17 Federal Income Taxes 0.0 172 19 State Income Taxes 0.0 172 21 Incremental Federal Income Taxes 0.0 172 23 Incremental State Income Taxes 0.0 172 25 Bank Balances n/a 27 Special Deposits n/a 29 Working Funds n/a 31 Tax Collections Avail - FICA Withholding 0.0 175 33 Tax Collections Avail - Federal Withholding 0.0 175 35 Tax Collections Avail - State Withholding- MN 1.9 175 37 Tax Collections Avail - State Withholding- ND 69.1 175 39 Tax Collections Available - State Sales Tax 23.8 175 41 Tax Collections Available - Franchise Taxes 0 175 JCOSS pages 1-a to 18-a contain the jurisdictional breakdowns of the JCOSS information as listed on pages 1-1 to 18-1 on the table above.
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 11 of 14 Allocation Factors
As reflected in the flow chart and listed on page 15-1 of the CCOSS, jurisdictional allocation factors are applied to various costs (rate base and expense) to allocate total company costs to the jurisdiction. Details on both jurisdictional and class allocation factors are outlined in OTP’s Cost Allocation Procedures Manual and in OTP’s Forecast Cost Allocation Procedures Manual Supplement. Required schedules C-9 and Work Papers Volume 4, C-3 provide additional detail as well.
JCOSS Summary
The results of the JCOSS, as summarized on page 1-1, is the determination of a (surplus) or deficiency in revenue needed to achieve the rate of return authorized or requested within the jurisdiction. The respective jurisdictional amounts within the study serve as the primary inputs into the CCOSS model, with allocations of those costs and associated class revenue requirements distributed to each customer class.
Class Cost of Service (Volume 4A) OTP’s CCOSS model establishes the revenue requirements for each of OTP’s 10 customer classes based on the allocation of jurisdictional costs using the class allocation factors detailed on page 15-2 and the secondary class allocation factors detailed on page 16-2.
Jurisdictional/Class Jurisdictional/Class Sales Forecasts Retail Revenues Forecast
Other Electric Lead/Lag Jurisdictional Costof Class Cost of Revenues Study Service Study (JCOSS) Service Study (CCOSS)
Normal Adjustments
Class Revenue Requirements Jurisdictional and Input Summary Class Allocation Rate Code Billing Factors Determinants from Test Year Sales & Revenue Adjustments Forecast
Minimum Rate Code Level Functionalization Current System Study Rate Design Rates Models
Rate Base Expense Final Revenues by Proposed Forecast Forecast Rate Code, Class = Rates Class Revenue Req. E-Schedules
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 12 of 14 The key inputs into the CCOSS model are:
1. Current South Dakota Class Revenues 2. JCOSS South Dakota results – Pages 1-1 to 16-1 3. Class Allocation Factors a. Primary Allocators by class (D Factors, E8760 Factors, C Factors) Page 15-2 b. Secondary – Page 16-2
The CCOSS pages 1-2 to 16-2 align with the pages 1-1 to 1-16 of the JCOSS.
The key output of the CCOSS is the determination of class revenue requirements based on the embedded costs and revenues attributable to each class. The CCOSS serves as a guide in the determination of proposed class rate increases necessary to collect the jurisdictional revenue increase required. The Summary of each class’s deficiency is provided on page 1-2 of the CCOSS.
Class CCOSS Output Source Residential Class Revenue Deficiency CCOSS Page 1-2 Farms Class Revenue Deficiency CCOSS Page 1-2 General Service Class Revenue Deficiency CCOSS Page 1-2 Large General Service Class Revenue Deficiency CCOSS Page 1-2 Irrigation Class Revenue Deficiency CCOSS Page 1-2 Outdoor Lighting Class Revenue Deficiency CCOSS Page 1-2 OPA Class Revenue Deficiency CCOSS Page 1-2 Controlled Service Water Heating Class Revenue Deficiency CCOSS Page 1-2 Controlled Service Interruptible Class Revenue Deficiency CCOSS Page 1-2 Controlled Service Deferred Class Revenue Deficiency CCOSS Page 1-2 Total Jurisdiction Sum of Class Revenue Deficiencies Ties to JCOSS Deficiency Page 1-1
Rate Design (Volume 3 Section E) The JCOSS determines the jurisdictional revenue requirement and related deficiency in revenue. The CCOSS determines each class’s responsibility for that deficiency based on the embedded costs included in the studies. Ultimately, the company develops a proposal for each class’s share of the overall jurisdictional revenue requirement to eliminate the deficiency and develops proposed rates within each class to collect that deficiency. Total Test Year Current and Proposed Revenues by Class are provided in Volume 3 Schedule E-1.
Current Class Source Proposed Revenues Source Class Revenue Increase Revenues Class Proposed Company Difference between Current and Residential Class Revenue CCOSS Revenue Proposal Proposed Revenues Class Proposed Company Difference between Current and Farms Class Revenue CCOSS Revenue Proposal Proposed Revenues Class Proposed Company Difference between Current and General Service Class Revenue CCOSS Revenue Proposal Proposed Revenues Class Proposed Company Difference between Current and Large General Service Class Revenue CCOSS Revenue Proposal Proposed Revenues Class Proposed Company Difference between Current and Irrigation Class Revenue CCOSS Revenue Proposal Proposed Revenues
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 13 of 14 Class Proposed Company Difference between Current and Outdoor Lighting Class Revenue CCOSS Revenue Proposal Proposed Revenues Class Proposed Company Difference between Current and OPA Class Revenue CCOSS Revenue Proposal Proposed Revenues Controlled Service Class Proposed Company Difference between Current and Class Revenue CCOSS Water Heating Revenue Proposal Proposed Revenues
Controlled Service Class Proposed Company Difference between Current and Class Revenue CCOSS Interruptible Revenue Proposal Proposed Revenues Controlled Service Class Proposed Company Difference between Current and Class Revenue CCOSS Deferred Revenue Proposal Proposed Revenues Total Current Total Revenue Total Jurisdictional JCOSS JCOSS Total Increase in Revenue Revenue Required
Following the development of proposed class revenue responsibilities, the next step in the process is rate design.
Key Components / Inputs in the Rate Design Process The purpose of the rate design process is to develop new rates and associated rate structures that result in the collection of the proposed class revenue requirement based on the billing determinants included in the forecast. Rate design is completed at a rate code level. Class revenue requirements are distributed to the rate code level. The allocation of class revenue to rate code level is completed using an Equivalent Percent of Marginal Cost (EPMC) allocation.
The following inputs are key to completing rate design in the rate design models at a rate code level:
1. Billing Determinants – These are the various billing determinants which were developed and included in the Sales and Revenue forecast process. Billing determinants include such things as forecasted kWhs, kW, number of customers, and number of meters. The sales and revenue forecast process develops billing determinates at a rate group level and then further allocates those determinants to a rate code level. 2. Current Rates- Current rates applied to the billing determinants yield the current level of revenues for the particular rate code. The result of this is the calculation of current revenues from existing rates. 3. Proposed Rates- Based on forecasted billing determinants described above, proposed rates are adjusted to yield the total revenue required from that rate to meet its contribution to the class revenue requirement.
Docket No. EL18-___ Exhibit__(TAA-1), Schedule 4 Page 14 of 14
Jurisdictional/Class Jurisdictional/Class Sales Forecasts Retail Revenues Forecast
Other Electric Lead/Lag Jurisdictional Costof Class Cost of Revenues Study Service Study (JCOSS) Service Study (CCOSS)
Normal Adjustments
Class Revenue Requirements Jurisdictional and Input Summary Class Allocation Rate Code Billing Factors Determinants from Test Year Sales & Revenue Adjustments Forecast
Minimum Rate Code Level Functionalization Current System Study Rate Design Rates Models
Rate Base Expense Final Revenues by Proposed Forecast Forecast Rate Code, Class = Rates Class Revenue Req. E-Schedules
Key Outputs of Rate Design Process:
The key output of the Rate Design process is a new set of proposed rates that within their respective customer class, collects the amount of revenue equal to the proposed class revenue requirement. The sum of revenues derived by all rates across all classes equals the total jurisdictional revenue requirement. As noted earlier, the results of the rate design process are summarized in Volume 3 Schedule E-1. Details of the changes from current rates to proposed rates are found in Volume 3 Schedule E-2.
OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 5 JUR. FINANCIAL SUMMARY SCHEDULES 1 of 3 SUMMARY OF REVENUE REQUIREMENTS - 2017 TEST YEAR
( A ) ( B ) ( C ) 2017 Line Test Year TCJA 2017 No. Description with Old Tax Rate Impact Test Year
1 Average Rate Base $84,640,917 $263,984 $84,904,901
2 Operating Income (Before AFUDC) $2,074,904 ($32,096) $2,042,808
3 Allowance for Funds Used During Construction (AFUDC) $0 $0 $0
4 Total Available for Return (Line 2 + Line 3 + Rounding) $2,074,904 ($32,096) $2,042,808
5 Overall Rate of Return (Line 4 / Line 1) 2.45% (0.05%) 2.41%
6 Required Rate of Return 7.96% 0.00% 7.96%
7 Operating Income Requirement (Line 1 x Line 6) $6,737,417 $21,013 $6,758,430
8 Income Deficiency (Line 7 - Line 4) $4,662,513 $53,109 $4,715,622
9 Gross Revenue Conversion Factor 1.5407730 (0.2730486) 1.2677244
10 Revenue Deficiency (Line 8 x Line 9) $7,183,874 ($1,205,765) $5,978,109
11 Retail Related Revenues Under Present Rates $30,650,015 $0 $30,650,015
12 Percent Increase Needed in Overall Revenue (Line 10 / Line 11) 23.44% (3.93%) 19.50% OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 5 RATE BASE SCHEDULES 2 of 3 RATE BASE SUMMARY
(A) (B) (C) (D) 2017 Line Test Year TCJA 2017 No. Description with Old Tax Rate Impact Test Year
1 Electric Plant in Service $162,858,420 $0 $162,858,420
2 Less: Accumulated Depreciation (69,187,808) $0 (69,187,808)
3 Net Electric Plant in Service $93,670,613 $0 $93,670,613
4 Other Rate Base Components:
5 Plant Held for Future Use 2,786 $0 2,786
6 Construction Work in Progress 0 $0 0
7 Materials and Supplies 1,833,976 $0 1,833,976
8 Fuel Stocks 849,126 $0 849,126
9 Prepayments (1,946,936) $0 (1,946,936)
10 Customer Advances (73,589) $0 (73,589)
11 Cash Working Capital 2,531,644 $0 2,531,644
12 Accumulated Deferred Income Taxes (12,685,038) $263,985 (12,421,053)
13 Unamortized Rate Case Expense 458,334 $0 458,334
14 TOTAL AVERAGE RATE BASE $84,640,917 $263,984 $84,904,901 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 5 OPERATING INCOME SCHEDULES 3 of 3 STATEMENT OF OPERATING INCOME - 2017 TEST YEAR
(A) (B) (C)
2017 Test Year Line SD Jurisdiction TCJA 2017 Test Year No. Description with Old Tax Rate Impact SD Jurisdiction OPERATING REVENUES 1 Retail Revenue $30,650,015 $0 $30,650,015 2 Other Electric Operating Revenue $1,731,348 $0 $1,731,348 3 TOTAL OPERATING REVENUE $32,381,363 $0 $32,381,363
OPERATING EXPENSES 4 Production Expenses $14,543,258 $0 $14,543,258 5 Transmission Expenses $2,950,883 $0 $2,950,883 6 Distribution Expenses $1,699,129 $0 $1,699,129 7 Customer Accounting Expenses $1,153,253 $0 $1,153,253 8 Customer Service and Information Expenses $664,545 $0 $664,545 9 Sales Expenses $20,751 $0 $20,751 10 Administration and General Expenses $4,003,827 $0 $4,003,827 11 Charitable Contributions $0 $0 $0 12 Depreciation Expense $5,037,485 $0 $5,037,485 13 General Taxes $969,261 $0 $969,261 14 TOTAL OPERATING EXPENSES $31,042,391 $0 $31,042,391
15 NET OPERATING INCOME BEFORE INCOME TAXES $1,338,972 $0 $1,338,972
INCOME TAX EXPENSE 16 Investment Tax Credit ($123,560) $0 ($123,560) 17 Deferred Income Taxes $1,087,571 ($646,501) $441,070 18 Current Income Taxes ($1,699,942) $678,597 ($1,021,346) 19 TOTAL INCOME TAX EXPENSE ($735,932) $32,096 ($703,836)
20 NET OPERATING INCOME $2,074,904 ($32,096) $2,042,808 21 Allowance for Funds Used During Construction 0 $0 0 22 TOTAL AVAILABLE FOR RETURN $2,074,904 ($32,096) $2,042,808 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 6 RATE BASE SCHEDULES Page 1 of 1 RATE BASE SUMMARY
(A) (B) (C) (D) Line 2017 2017 2017 No. Description Actual Year Test Year Test Year Step
1 Electric Plant in Service $161,400,621 $162,858,420 $187,432,670
2 Less: Accumulated Depreciation (68,956,036) (69,187,808) (70,164,373)
3 Net Electric Plant in Service $92,444,586 $93,670,613 $117,268,297
4 Other Rate Base Components:
5 Plant Held for Future Use 2,786 2,786 2,786
6 Construction Work in Progress 0 0 0
7 Materials and Supplies 1,831,014 1,833,976 1,831,227
8 Fuel Stocks 845,834 849,126 849,126
9 Prepayments (1,939,652) (1,946,936) (2,000,539)
10 Customer Advances (73,314) (73,589) (75,615)
11 Cash Working Capital 2,821,120 2,531,644 2,204,665
12 Accumulated Deferred Income Taxes (12,637,582) (12,421,053) (12,831,760)
13 Unamortized Rate Case Expense 0 458,334 458,334
14 TOTAL $83,294,793 $84,904,901 $107,706,522 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__ (TAA-1), Schedule 7 TRADITIONAL ADJUSTMENTS TO RATE BASE SCHEDULE 1 of 2
(A) (B) (C) (D)
BSP II Transmission Line AFUDC on Recovery Rider CWIP Recovery No. Description Short-Term CWIP Adjustment Adjustment Adjustment
1 Plant in Service 2 A/C 101 & 106 - Direct MN 3 A/C 101 & 106 - Direct ND 4 A/C 101 & 106 - Direct SD 5 6 Production Plant 7 A/C 101 & 106 - Base Demand (E1) 290,770 408,905 8 A/C 101 & 106 - Peak Demand (D1) 78,742 92,757 9 A/C 101 & 106 - Base Energy (E2) (153) 10 Subtotal A/C 101 & 106 369,360 501,662 - - 11 12 A/C 114 - Base Demand (E1) 13 A/C 114 - Peak Demand (D1) 14 A/C 114 - Base Energy (E1) 15 Subtotal A/C 114 - - - - 16 17 Total Production Plant 369,360 501,662 - - 18 19 Transmission Plant 20 A/C 101 & 106 (D2) 591,865 (17,402,180) 21 A/C 101 & 106 (Direct FERC) 22 A/C 114 (D2) 23 Total Transmission Plant 591,865 - - (17,402,180) 24 25 Distribution Plant 26 Primary Demand (D3) 324,450 27 Secondary Demand (D4) 91,940 28 Primary Customer (C2) 94,083 29 Secondary Customer (C3) 125,986 30 Streetlighting (C4) 26,493 31 Area Lighting (C5) 6,614 32 Meters (C6) 55,397 33 Load Management (C9) 17,203 34 Total Distribution Plant 742,166 - - - 35 36 General Plant 37 Production (P10) 86,260 38 Transmission (D2) 37,523 39 Distribution (P60) 83,438 40 Customer Accounts (OXC) 56,132 41 Customer Service & Info (OXI) 11,490 42 Load Management (C9) 7,838 43 Total General Plant 282,681 - - - 44 45 Intangible Plant (P90) 52,341 - - - 46 47 Total Plant in Service 2,038,412 501,662 - (17,402,180) 48 49 Accumulated Depreciation 50 Production Plant 51 Base Demand (E1) (578,974) 52 Peak Demand (D1) (43,753) 53 Base Energy (E2) 51 54 Total Production Plant (622,675) - - - 55 56 Transmission Plant (D2) (216,267) 582,545 57 Transmission Plant - Direct FERC 58 Total Transmission Plant (216,267) - - 582,545 59 60 Distribution Plant (P60) (447,564) - - - 61 62 General Plant (P90) (263,963) - - - 63 64 Intangible Plant (P90) (248,558) - - - 65 66 Total Accumulated Depreciation (1,799,027) - - 582,545 67 68 Total Net Plant in Service 239,386 501,662 - (16,819,635) 69 70 Plant Held for Future Use 71 Production Plant (P10) 72 Transmission Plant (D2) 73 Distribution Plant (P60) 74 General Plant (P90) 75 Intangible Plant (P90) 76 Total Plant Held for Future Use - - - - OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__ (TAA-1), Schedule 7 TRADITIONAL ADJUSTMENTS TO RATE BASE SCHEDULE 2 of 2
(A) (B) (C) (D)
BSP II Transmission Line AFUDC on Recovery Rider CWIP Recovery No. Description Short-Term CWIP Adjustment Adjustment Adjustment 77 78 Const Work-in-Progress - Direct Assigned 79 Production Plant - Dierct MN 80 Production Plant - Dierct ND 81 Production Plant - Direct SD 82 Production Plant - Direct FERC 83 Transmission Plant - Direct MN 84 Transmission Plant - Direct ND 85 Transmission Plant - Direct SD 86 Transmission Plant - Direct FERC 87 Distribution Plant - Direct MN 88 Distribution Plant - Direct ND 89 Distribution Plant - Direct SD 90 Distribution Plant - Direct FERC 91 General Plant - Direct MN 92 General Plant - Direct ND 93 General Plant - Direct SD 94 General Plant - Direct FERC 95 Intangible Plant - Direct MN 96 Intangible Plant - Direct ND 97 Intangible Plant - Direct SD 98 Intangible Plant - Direct FERC 99 Total CWIP - Major Projects - Direct Assigned - - - - 100 101 Const Work-in-Progress - Short-Term 102 Production Plant (P10) 103 Transmission Plant (D2) 104 Distribution Plant (P60) 105 General Plant (P90) 106 Intangible Plant (P90) 107 Total CWIP - Short-Term - - - - 108 109 Const Work-in-Progress - Long Term 110 Production Plant (AFUDC Projects P10) 111 Production Plant (Rider Projects) 112 Transmission Plant (AFUDC Projects) (10,754,628) 113 Transmission Plant (Rider Projects) 114 Distribution Plant (P60) 115 General Plant (P90) 116 Intangible Plant (P90) 117 Total CWIP - Long Term AFUDC Projects - - (10,754,628) -
118 Total CWIP - Long Term Rider Projects - 119 120 Total Construction Work-in-Progress - - (10,754,628) - 121 122 Materials & Supplies 123 Production (P10) 124 Transmission (D2) 125 Distribution (P60) 126 Total Materials and Supplies - - - - 127 128 Fuel Stocks 129 Coal Stocks (E1) 130 Fuel Oil Stocks (D1) 131 Total Fuel Stocks - - - - 132 133 Prepayments (NEPIS) - - - - 134 135 Customer Advances & Deposits 136 Customer Advances & Deposits (NEPIS) 137 Customer Deposits (Direct MN) 138 Total Customer Advances & Deposits - - - - 139 140 Cash Working Capital - - - - 141 142 Accumulated Deferred Income Taxes 143 Items SD Flows Through 144 Federal (NPMNR) 145 Minnesota (NPISM) 146 North Dakota (NPISN) 147 Subtotal - - - - 148 All Other 149 Federal (NEPIS) 2,248,323 150 Federal (Direct FERC) 151 Minnesota (NPISM) 152 North Dakota (NPISN) 153 Subtotal - - - 2,248,323 154 155 Total Accumulated Deferred Income Taxes - - - 2,248,323 156 157 Unamortized Rate Case Expenses 158 Minnesota 159 North Dakota 160 South Dakota 161 FERC 162 Total Unamortized Rate Case Expenses - - - - 163 164 Total Average Rate Base $ 239,386 $ 501,662 $ (10,754,628) $ (14,571,312) OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 8 RATE BASE SCHEDULES Page 1 of 1 RATE BASE ADJUSTMENTS 2017 Actual Year versus 2017 Test Year
TY-01 TY-03 TY-09 TY-15 (A) (B) (C) (D) (E) (F) (G) (H) (I) Changes in Rate Case Adjust Allocations due to Test Year 2017 Line 2017 Normalize New Depreciation Expense Deferred Tax Effect of Test Year 2017 Merricourt Test Year No. Description Actual Year CISone Project Rate Amortization for Tax Reform Adjustments Test Year Step In Step
Utility Plant in Service: 1 Production $83,221,206 $296,409 $83,517,615 $24,590,337 $108,107,952 2 Transmission $23,471,468 $59,641 $23,531,109 $0 $23,531,109 3 Distribution $45,678,085 -$31,720 $45,646,364 ($1) $45,646,364 4 General $8,121,115 $11,725 $8,132,840 ($12,874) $8,119,967 5 Intangible $908,747 $1,118,659 $3,086 $2,030,492 ($3,214) $2,027,278 6 TOTAL Utility Plant in Service $161,400,621 $1,118,659 $0 $0 $0 $339,141 $162,858,421 $24,574,249 $187,432,670 Accumulated Depreciation 7 Production ($33,959,567) ($38,626) ($123,922) ($34,122,115) ($983,613) ($35,105,729) 8 Transmission ($10,478,951) ($22,199) ($26,627) ($10,527,776) $0 ($10,527,776) 9 Distribution ($20,113,236) $14,121 $13,967 ($20,085,148) $0 ($20,085,148) 10 General ($3,730,350) $20,738 ($5,353) ($3,714,965) $5,880 ($3,709,085) 11 Intangible ($673,931) ($66,654) $3,854 ($1,073) ($737,803) $1,168 ($736,635) 12 TOTAL Accumulated Depreciation ($68,956,036) ($66,654) ($22,111) $0 $0 ($143,008) ($69,187,808) ($976,565) ($70,164,373) 13 NET Utility Plant in Service 14 Production $49,261,638 $0 ($38,626) $0 $0 $172,488 $49,395,500 $23,606,724 $73,002,224 15 Transmission $12,992,518 $0 ($22,199) $0 $0 $33,014 $13,003,333 $0 $13,003,333 16 Distribution $25,564,848 $0 $14,121 $0 $0 ($17,754) $25,561,216 ($0) $25,561,216 17 General $4,390,765 $0 $20,738 $0 $0 $6,372 $4,417,875 ($6,993) $4,410,882 18 Intangible $234,816 $1,052,006 $3,854 $0 $0 $2,013 $1,292,689 ($2,046) $1,290,643 19 NET Utility Plant in Service $92,444,586 $1,052,006 ($22,111) $0 $0 $196,133 $93,670,613 $23,597,684 $117,268,297
20 Big Stone Plant capitalized items $0 $0 $0 $0 $0 21 Utility Plant Held for Future Use $2,786 $0 $2,786 $0 $2,786 22 Construction Work in Progress $0 $0 $0 $0 $0 23 Materials and Supplies $1,831,014 $2,962 $1,833,976 ($2,749) $1,831,227 24 Fuel Stocks $845,834 $3,292 $849,126 $0 $849,126 25 Prepayments ($1,939,652) ($7,284) ($1,946,936) ($53,603) ($2,000,539) 26 Customer Advances ($73,314) ($275) ($73,589) ($2,026) ($75,615) 27 Cash Working Capital $2,821,120 ($289,476) $2,531,644 ($326,979) $2,204,665 28 Accumulated Deferred Income Taxes ($12,637,582) $482,272 ($265,744) ($12,421,053) ($410,707) ($12,831,760) 29 Unamortized Rate Case Expense $0 $458,334 $0 $458,334 $0 $458,334 30 Total Average Rate Base $83,294,793 $1,052,006 ($22,111) $458,334 $482,272 ($360,393) $84,904,901 $22,801,620 $107,706,521
Column references to adjustment workpapers: (B) W/P 2017 SD TY-01 (C) W/P 2017 SD TY-03 (D) W/P 2017 SD TY-09 (E) W/P 2017 SD TY-15 OTTER TAIL POWER COMPANY Docket No. E18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 9 OPERATING INCOME SCHEDULES Page 1 of 1 STATEMENT OF OPERATING INCOME - 2017 TEST YEAR
(A) (B) (C) (D) (E) (F) 2017 Test Year 2017 2017 2017 2017 Line Actual Year Actual Year Test Year Step In TY Step No. Description Total Utility SD Jurisdiction Adjustments SD Jurisdiction Adjustments SD Jurisdiction OPERATING REVENUES 1 Retail Revenue $372,153,628 $32,929,872 ($2,279,857) $30,650,015 $5,978,110 $36,628,125 2 Other Electric Operating Revenue $58,386,685 $1,725,695 5,653 $1,731,348 $31,873 $1,763,221 3 TOTAL OPERATING REVENUE $430,540,313 $34,655,568 ($2,274,204) $32,381,363 $6,009,983 $38,391,347
OPERATING EXPENSES
4 Production Expenses $156,639,966 $14,201,172 $342,086 $14,543,258 -$854,833 $13,688,425 5 Transmission Expenses $32,135,395 $2,936,416 14,467 $2,950,883 $0 $2,950,883 6 Distribution Expenses $17,761,845 $1,686,406 12,723 $1,699,129 $0 $1,699,129 7 Customer Accounting Expenses $12,912,128 $1,144,837 8,416 $1,153,253 $0 $1,153,253 8 Customer Service and Information Expenses $9,358,287 $663,245 1,300 $664,545 $0 $664,545 9 Sales Expenses $230,711 $11,402 9,349 $20,751 $0 $20,751 10 Administration and General Expenses $43,609,630 $3,739,913 263,914 $4,003,827 $41,246 $4,045,072 11 Charitable Contributions $0 $0 0 $0 $0 $0 12 Depreciation Expense $53,185,267 $4,719,228 318,257 $5,037,485 $982,804 $6,020,289 13 General Taxes $15,045,286 $965,635 3,626 $969,261 $83,974 $1,053,235 14 TOTAL OPERATING EXPENSES $340,878,513 $30,068,254 $974,137 $31,042,391 $253,190 $31,295,581
15 NET OPERATING INCOME BEFORE INCOME TAXES $89,661,800 $4,587,314 ($3,248,342) $1,338,972 $5,756,793 $7,095,765
INCOME TAX EXPENSE 16 Investment Tax Credit ($8,997,380) ($753,931) $630,371 ($123,560) ($1,357,924) ($1,481,485)
17 Deferred Income Taxes $20,783,440 $527,063 -85,993 $441,070 $12,144 $453,213 18 Income Taxes $2,161,831 $0 (1,021,346) ($1,021,346) $1,068,192 $46,847 19 TOTAL INCOME TAX EXPENSE $13,947,891 ($226,868) ($476,968) ($703,836) ($277,588) ($981,425)
20 NET OPERATING INCOME $75,713,909 $4,814,182 ($2,771,374) $2,042,808 $6,034,382 $8,077,190
21 Allowance for Funds Used During Construction 1,726,880 0 0 0 $0 0 22 TOTAL AVAILABLE FOR RETURN $77,440,789 $4,814,182 ($2,771,374) $2,042,808 $6,034,382 $8,077,190 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit __(TAA-1), Schedule 10 SCHEDULE OF OPERATIONS AND MAINTENACE EXPENSE Page 1 of 1
(A) (B) (C) (D)
2010 Per Order in Line Docket No. 2017 Actual Year 2017 Test Year No. Description EL10-011 SD Jurisdiction Adjustments SD Jurisdiction OPERATING EXPENSES 1 Production Expenses $12,737,956 $14,201,172 $342,086 $14,543,258 2 Transmission Expenses $1,108,035 2,936,416 14,467 2,950,883 3 Distribution Expenses $1,461,533 1,686,406 12,723 1,699,129 4 Customer Accounting Expenses $1,006,759 1,144,837 8,416 1,153,253 5 Customer Service and Information Expenses $191,592 663,245 1,300 664,545 6 Sales Expenses $40,602 11,402 9,349 20,751 7 Administration and General Expenses $3,230,243 3,739,913 263,914 4,003,827 8 Charitable Contributions $0 $0 $0 $0 9 Depreciation Expense $3,959,069 4,719,228 318,257 5,037,485 10 General Taxes $939,184 965,635 3,626 969,261 11 TOTAL OPERATING EXPENSES $24,674,973 $30,068,254 $974,137 $31,042,391 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 11 TRADITIONAL ADJUSTMENTS TO INCOME STATEMENT SCHEDULE Page 1 of 4
(A) (B) (C) (D) (E) (F) (G)
AFUDC on BSP II Transmission Line Advertising Short-term Recovery Emission Incentive REC Recovery No. Description Expenses CWIP Adjustment Allowances Compensation Sales Adjustment 1 Operating Revenues 2 Sales of Electricity - Minnesota (Direct MN/R10) 3 Sales of Electricity - North Dakota (Direct ND/R10) 4 Sales of Electricity - South Dakota (Direct SD/R10) 5 Sales of Electricity - FERC (Direct SD/R10) 6 Total Retail Sales ------7 8 Other Operating Revenues 9 Other Sales for Resale 10 Municipalities (Direct FERC) 11 Non-Asset Wholesale Transactions (D2) 12 All Other Transactions 13 Base Demand (E1) 14 Peak Demand (D1) 15 Base Energy (E2) 16 Peak Energy (D1) 17 Total Other Sales for Resale ------18 19 Other Electric Revenues 20 Late Fees - Minnesota (Direct MN/C1) 21 Late Fees - North Dakota (Direct ND/C1) 22 Late Fees - South Dakota (Direct SD/C1) 23 Subtotal Late Fees ------24 Connection Fees - Minnesota (Direct MN/C1) 25 Connection Fees - North Dakota (Direct ND/C1) 26 Connection Fees - South Dakota (Direct SD/C1) 27 Subtotal Connection Fees ------28 Rent from Electric Property (NEPIS) 29 Rent from Electric Property - Big Stone (NEPIS) 30 Rent from Electric Property - Coyote (NEPIS) 31 Subtotal Rent from Electric Property ------32 Other Miscellaneous Electric Revenue (NEPIS) 1 (51) 33 Other Miscellaneous Electric Revenue (Direct MN/C1) 34 Other Miscellaneous Electric Revenue (Direct ND/C1) 35 Other Miscellaneous Electric Revenue (Direct SD/C1) 626 36 Subtotal Other Miscellaneous Electric Revenue - - - 1 - 575 - 37 Integrated Transmission Deficiency Payments (NEPIS) 38 Miscellaneous Services (NEPIS) 39 Wheeling - All Jurisdictions (NEPIS) 40 Subtotal Miscellanous Services ------41 Load Control & Dispatching, MAPP & MISO (NEPIS) (2,993,155) 42 Load Control & Dispatching, MAPP & MISO (Direct FERC) - 43 Subtotal Load Control & Dispatching, MAPP & MISO ------(2,993,155) 44 Loan Pool Interest - Minnesota (Direct MN/C1) 45 Loan Pool Interest - North Dakota (Direct ND/C1) 46 Loan Pool Interest - South Dakota (Direct SD/C1) 47 Subtotal Loan Pool Interest ------48 Total Other Electric Revenues - - - 1 - 575 (2,993,155) 49 50 Total Other Operating Revenues - - - 1 - 575 (2,993,155) 51 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 11 TRADITIONAL ADJUSTMENTS TO INCOME STATEMENT SCHEDULE Page 2 of 4
(A) (B) (C) (D) (E) (F) (G)
AFUDC on BSP II Transmission Line Advertising Short-term Recovery Emission Incentive REC Recovery No. Description Expenses CWIP Adjustment Allowances Compensation Sales Adjustment 52 Total Operating Revenues - - - 1 - 575 (2,993,155) 53 54 Operating Expenses 55 Production Expenses 56 Production Expenses Excl Purchased Power 57 Base Demand (E1) 58 Peak Demand (D1) 59 Base Energy (E2) 60 Peak Energy (D1) 61 Total Excluding Purchased Power ------62 63 Purchased Power 64 Base Demand (E1) 65 Peak Demand (D1) 66 Base Energy (E2) 67 Peak Energy (D1) 68 Total Purchased Power ------69 Total Production Expenses ------70 71 Transmission Expenses (D2) (8,540) 72 Transmission Expenses (Direct FERC) - 73 Total Transmission Expenses ------(8,540) 74 75 Distribution Expenses 76 Primary Demand (D3) 77 Secondary Demand (D4) 78 Primary Customer (C2) 79 Secondary Customer (C3) 80 Streetlighting (C4) 81 Area Lighting (C5) 82 Meters (C6) 83 Load Management (C9) 84 Total Distribution ------85 86 Customer Accounting Expenses 87 Meter Reading (C7) 88 Other (C8) 89 Total Customer Accounts ------90 91 Customer Service & Info Expenses 92 Conservation & DSM Rebates - MN (Direct MN/E2) 93 Conservation & DSM Rebates - ND (Direct ND/E2) 94 Conservation & DSM Rebates - SD (Direct SD/E2) 95 Other (C1) 96 Total Customer Serv & Infomation Exp ------97 98 Sales Expenses 99 Off-Peak Development - MN (Direct MN/C1) 100 Off-Peak Development - ND (Direct ND/C1) 101 Off-Peak Development - SD (Direct SD/C1) 102 Other (C1) (114) 103 Total Sales Expenses (114) ------OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 11 TRADITIONAL ADJUSTMENTS TO INCOME STATEMENT SCHEDULE Page 3 of 4
(A) (B) (C) (D) (E) (F) (G)
AFUDC on BSP II Transmission Line Advertising Short-term Recovery Emission Incentive REC Recovery No. Description Expenses CWIP Adjustment Allowances Compensation Sales Adjustment 104 105 Administrative & General Expenses 106 Salaries, Supplies, Pensions & Benefits 107 Production (OXPD) (29,522) 108 Transmission (D2) (12,072) 109 Distribution (OXD) (23,201) 110 Customer Accounts (OXC) (14,502) 111 Customer Service & Info (C1) (2,762) 112 Total A&G Salaries, Supp, Pensions & Benefits - - - - (82,059) - - 113 Load Management (C9) 114 Outside Services (A/C 923) (NEPIS) 115 Property Insurance (A/C 924) (NEPIS) 116 Injuries & Damages (A/C 925) (NEPIS) 117 Regulatory Commission Exp (A/C 928) - MN (Direct MN/R10) 118 Regulatory Commission Exp (A/C 928) - ND (Direct ND/R10) 119 Regulatory Commission Exp (A/C 928) - SD (Direct SD/R10) 120 Regulatory Commission Exp (A/C 928) - FERC (Direct FERC/R10) 121 Total Regulatory Commission Expense (2) ------122 General Advertising (A/C 930.1) (C1) (1) (32,306) 123 Misc, Rents, Maintenance (P90) (1) 124 Total Administrative & General Expense (32,306) - - - (82,059) - - 125 126 Charitable Contributions (& Cust Dep Int) 127 Minnesota Only (Direct MN/C1) 128 North Dakota Only (Direct ND/C1) 129 South Dakota Only (Direct SD/C1) 130 Total Charitable Contributions (& Cust Dep Int) ------131 132 Total O & M Expenses (32,420) - - - (82,059) - (8,540) 133 134 Depreciation Expense 135 Production 136 Base Demand (E1) 7,420 81,781 137 Peak Demand (D1) 4,553 18,551 138 Base Energy (E2) (6) 139 Total Production - 11,967 100,332 - - - - 140 Transmission (D2) 10,691 (209,891) 141 Transmission (Direct FERC) - - 142 Total Transmission (2) - 10,691 - - - - (209,891) 143 Distribution (P60) 18,231 144 General (P90) 13,564 145 Intangible (P90) 8,485 146 Total Depreciation Expense - 62,939 100,332 - - - (209,891) 147 148 Big Stone Expense Offsets 149 Minnesota (Direct MN) 150 North Dakota (Direct ND) 151 South Dakota (Direct SD) 152 FERC (Direct FERC) 153 Total Big Stone Expense Offsets ------154 155 General Taxes (NEPIS) (221,276) OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 11 TRADITIONAL ADJUSTMENTS TO INCOME STATEMENT SCHEDULE Page 4 of 4
(A) (B) (C) (D) (E) (F) (G)
AFUDC on BSP II Transmission Line Advertising Short-term Recovery Emission Incentive REC Recovery No. Description Expenses CWIP Adjustment Allowances Compensation Sales Adjustment 156 General Taxes (Direct FERC) - 157 Total General Taxes ------(221,276) 158 159 Total Operating Expense Before Tax (32,420) 62,939 100,332 - (82,059) - (439,707) 160 161 Net Operating Income Before Tax 32,420 (62,939) (100,332) 1 82,059 575 (2,553,448) 162 163 Wind Investment Tax Credit & Production Tax Credit 164 Amortization of Prior Year' Credit (EPIS) (4) 165 Production Tax Credits (EPIS) (5) 166 Investment Tax Credits (EPIS) 167 Debits Utilized (EPIS) 168 Total Wind Investment Tax Credit & Production Tax Credit ------169 170 Federal (NEPIS) 171 Minnesota (NPISM) 172 North Dakota (NPISN) 173 Subtotal ------174 Total Deferred Income Taxes ------175 176 Current Income Taxes 177 Federal Income Taxes 178 Minnesota Income Taxes (Direct MN) 179 North Dakota Income Taxes (Direct ND) 180 Total Current Income Taxes 6,808 (13,217) (21,070) 0 17,232 121 (536,224) 181 182 Total Income Taxes 6,808 (13,217) (21,070) 0 17,232 121 (536,224) 183 184 Net Operating Income 25,612 (49,721) (79,262) 1 64,826 455 (2,017,224) 185 186 Allowance for Funds Used During Construction 187 Allowance for Funds Used During Construction - MN Only 188 Allowance for Funds Used During Construction - SD Only 189 Total Allowance for Funds Used During Construction (7) ------190 191 Total Available for Return $ 25,612 $ (49,721) $ (79,262) $ 1 $ 64,826 $ 455 $ (2,017,224)
Tax Rate 21.000% 21.000% 21.000% 21.000% 21.000% 21.000% 21.000% OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 12 OPERATING INCOME SCHEDULES 1 of 2 OPERATING INCOME STATEMENT ADJUSTMENTS SCHEDULE
TY-01 TY-02 TY-03 TY-05 TY-06 TY-07 TY-08 TY-09 (A) (B) (C) (D) (E) (F) (G) (H) (I)
New Medical/Dental Rate Case Line 2017 Normalize BSP II Depreciation Weather Revenue Wages, KPA FAS 87, Expense No. Description Actual Year CISone Project Amortization Rates Normalization Normalization and Mang Inc. 106, 112 Amorization OPERATING REVENUES 1 Retail Revenue $32,929,872 $335,353 $4,325 2 Other Electric Operating Revenue $1,725,695 3 TOTAL OPERATING REVENUE $34,655,568 $0 $0 $0 $335,353 $4,325 $0 $0 $0 OPERATING EXPENSES 4 Production Expenses $14,201,172 $133,229 $2,179 $1,065 $16,069 5 Transmission Expenses $2,936,416 435 6,570 6 Distribution Expenses $1,686,406 837 12,627 7 Customer Accounting Expenses $1,144,837 523 7,894 8 Customer Service and Information Expenses $663,245 81 1,219 9 Sales Expenses $11,402 10 Administration and General Expenses $3,739,913 1,838 27,731 183,333 11 Charitable Contributions $0 12 Depreciation Expense $4,719,228 121,188 164,538 22,111 13 General Taxes $965,635 14 TOTAL OPERATING EXPENSES $30,068,254 $121,188 $164,538 $22,111 $133,229 $2,179 $4,781 $72,109 $183,333 15 NET OPERATING INCOME BEFORE INCOME TAXES $4,587,314 ($121,188) ($164,538) ($22,111) $202,124 $2,146 ($4,781) ($72,109) ($183,333) 16 INCOME TAX EXPENSE 17 Investment Tax Credit ($753,931) 18 Deferred Income Taxes $527,063 19 Income Taxes $0 (25,490) (34,553) (4,635) 42,446 451 (1,004) (15,143) (38,500) 20 TOTAL INCOME TAX EXPENSE ($226,868) ($25,490) ($34,553) ($4,635) $42,446 $451 ($1,004) ($15,143) ($38,500) 21 NET OPERATING INCOME $4,814,182 ($95,698) ($129,985) ($17,476) $159,679 $1,695 ($3,777) ($56,966) ($144,833) 22 Allowance for Funds Used During Construction 0 0 0 0 0 0 0 0 0 23 TOTAL AVAILABLE FOR RETURN $4,814,182 ($95,698) ($129,985) ($17,476) $159,679 $1,695 ($3,777) ($56,966) ($144,833)
$0
Column references to adjustment workpapers: (B) W/P 2017 SD TY-01 (H) W/P 2017 SD TY-08 (N) W/P 2017 SD TY-14 (C) W/P 2017 SD TY-02 (I) W/P 2017 SD TY-09 (O) W/P 2017 SD TY-15 (D) W/P 2017 SD TY-03 (J) W/P 2017 SD TY-10 (E) W/P 2017 SD TY-05 (K) W/P 2017 SD TY-11 (F) W/P 2017 SD TY-06 (L) W/P 2017 SD TY-12 (G) W/P 2017 SD TY-07 (M) W/P 2017 SD TY-13 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 12 OPERATING INCOME SCHEDULES 2 of 2 OPERATING INCOME STATEMENT ADJUSTMENTS SCHEDULE
TY-10 TY-11 TY-12 TY-13 TY-14 TY-15 (J) (K) (L) (M) (N) (O) (Q) (R) (P) Changes in Allocations due TCRR ECRR to Effect of 2017 Line Storm Removal of Plant Outage Revenue Revenue Test Year 2017 Merricourt Test Year No. Description Damages PTC's Normalization Removal Removal Tax Impact Adjustments Test Year Step-In Step In OPERATING REVENUES 1 Retail Revenue ($245,070) (2,374,465) ($0) $30,650,015 5,978,110 36,628,125 2 Other Electric Operating Revenue $5,653 $1,731,348 31,873 1,763,221 3 TOTAL OPERATING REVENUE $0 $0 $0 ($245,070) ($2,374,465) $0 $5,653 $32,381,363 $6,009,983 $38,391,347 OPERATING EXPENSES 0 4 Production Expenses $145,434 $44,109 $14,543,258 (854,833) 13,688,425 5 Transmission Expenses $7,461 $2,950,883 0 2,950,883 6 Distribution Expenses ($741) $1,699,129 0 1,699,129 7 Customer Accounting Expenses ($1) $1,153,253 (0) 1,153,253 8 Customer Service and Information Expenses ($1) $664,545 (0) 664,545 9 Sales Expenses $9,349 $20,751 (0) 20,751 10 Administration and General Expenses 45,266 $5,745 $4,003,827 41,246 4,045,072 11 Charitable Contributions $0 $0 - 0 12 Depreciation Expense $10,420 $5,037,485 982,804 6,020,289 13 General Taxes $3,626 $969,261 83,974 1,053,235 14 TOTAL OPERATING EXPENSES $45,266 $0 $145,434 $0 $0 $0 $79,969 $31,042,391 $253,190 31,295,581 15 NET OPERATING INCOME BEFORE INCOME TAXES ($45,266) $0 ($145,434) ($245,070) ($2,374,465) $0 ($74,316) $1,338,972 $5,756,793 $7,095,765 16 INCOME TAX EXPENSE 0 17 Investment Tax Credit $638,677 ($8,306) ($123,560) ($1,357,924) ($1,481,485) 18 Deferred Income Taxes (664,300) $578,307 $441,070 $12,144 453,213 19 Income Taxes (9,251) 0 (30,541) (51,465) (498,638) 0 ($355,023) ($1,021,346) $1,068,192 46,847 20 TOTAL INCOME TAX EXPENSE ($9,251) $638,677 ($30,541) ($51,465) ($498,638) ($664,300) $214,979 ($703,836) ($277,588) ($981,425) 21 NET OPERATING INCOME ($36,015) ($638,677) ($114,893) ($193,605) ($1,875,827) $664,300 ($289,296) $2,042,808 $6,034,382 $8,077,190 22 Allowance for Funds Used During Construction 0 0 0 0 0 0 0 0 0 0 23 TOTAL AVAILABLE FOR RETURN ($36,015) ($638,677) ($114,893) ($193,605) ($1,875,827) $664,300 ($289,296) $2,042,808 $6,034,382 $8,077,190
$0 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 13 SD BSP II Settlement 1 of 2
South Dakota Big Stone II Settlement Monthly Journal Entries
Transmission Amortization Return on Rate Debit FERC Transfer of Base Allowed Regulatory Date 4070 Asset Cost Recovered AFUDC 8.5% Asset Balance Total
1 Sep-09 - 2 Oct-09 - 3 Nov-09 - 4 Dec-09 - 5 Jan-10 - 6 Feb-10 - 7 Mar-10 - 8 Apr-10 - 9 May-10 - 10 Jun-10 - 11 Jul-10 - 12 Aug-10 - 13 Sep-10 - 14 Oct-10 - 15 Nov-10 - 16 Dec-10 - 17 Jan-11 - - 18 Feb-11 - 994,959 19 Mar-11 - 986,598 20 Apr-11 - 978,237 21 May-11 - 969,876 22 Jun-11 - 961,515 23 Jul-11 - 953,154 24 Aug-11 - 944,793 25 Sep-11 - 936,432 26 Oct-11 - 928,071 27 Nov-11 - 919,710 28 Dec-11 - 911,349 29 Jan-12 - 902,988 30 Feb-12 - 894,627 31 Mar-12 - 886,266 32 Apr-12 - 877,905 33 May-12 - 869,544 34 Jun-12 - 861,183 35 Jul-12 - 852,822 36 Aug-12 - 844,461 37 Sep-12 - 836,100 38 Oct-12 - 827,739 39 Nov-12 - 819,378 40 Dec-12 - 811,017 41 Jan-13 - 802,656 42 Feb-13 - 794,295 43 Mar-13 - 785,934 44 Apr-13 - 777,573 45 May-13 259,898.00 (80,237.00) 56,001.00 235,662 1,004,874 46 Jun-13 1,669.27 237,331 998,182 47 Jul-13 1,669.27 239,001 991,491 48 Aug-13 1,669.27 240,670 984,799 49 Sep-13 1,669.27 242,339 978,107 50 Oct-13 1,669.27 244,008 971,415 51 Nov-13 1,669.27 245,678 964,724 52 Dec-13 1,669.27 247,347 958,032 53 Jan-14 1,752.04 249,099 951,423 54 Feb-14 1,752.04 250,851 944,814 55 Mar-14 1,752.04 252,603 938,205 56 Apr-14 1,752.04 254,355 931,596 57 May-14 1,752.04 256,107 924,987 58 Jun-14 1,752.04 257,859 918,378 59 Jul-14 1,752.04 259,611 911,769 60 Aug-14 1,752.04 261,363 905,160 61 Sep-14 1,752.04 263,115 898,551 62 Oct-14 1,752.04 264,867 891,942 63 Nov-14 1,752.04 266,619 885,333 64 Dec-14 1,752.04 268,371 878,724 65 Jan-15 1,900.96 270,272 872,264 66 Feb-15 1,900.96 272,173 865,804 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 13 SD BSP II Settlement 2 of 2
South Dakota Big Stone II Settlement Monthly Journal Entries
Transmission Amortization Return on Rate Debit FERC Transfer of Base Allowed Regulatory Date 4070 Asset Cost Recovered AFUDC 8.5% Asset Balance Total
67 Mar-15 1,900.96 274,074 859,344 68 Apr-15 1,900.96 275,975 852,884 69 May-15 1,900.96 277,876 846,424 70 Jun-15 1,900.96 279,777 839,964 71 Jul-15 1,900.96 281,678 833,504 72 Aug-15 1,900.96 283,579 827,044 73 Sep-15 1,900.96 285,480 820,584 74 Oct-15 1,900.96 287,381 814,124 75 Nov-15 1,900.96 289,282 807,664 76 Dec-15 1,900.96 291,183 801,204 77 Jan-16 2,062.55 293,246 794,906 78 Feb-16 2,062.55 295,308 788,607 79 Mar-16 2,062.55 297,371 782,309 80 Apr-16 2,062.55 299,433 776,010 81 May-16 2,062.55 301,496 769,712 82 Jun-16 2,062.55 303,558 763,413 83 Jul-16 2,062.55 305,621 757,115 84 Aug-16 2,062.55 307,683 750,816 85 Sep-16 2,062.55 309,746 744,518 86 Oct-16 2,062.55 311,808 738,219 87 Nov-16 2,062.55 313,871 731,921 88 Dec-16 2,062.55 315,934 725,623 89 Jan-17 2,237.86 318,171 719,499 90 Feb-17 2,237.86 320,409 713,376 91 Mar-17 2,237.86 322,647 707,253 92 Apr-17 2,237.86 324,885 701,130 93 May-17 2,237.86 327,123 695,007 94 Jun-17 2,237.86 329,361 688,884 95 Jul-17 2,237.86 331,599 682,761 96 Aug-17 2,237.86 333,836 676,637 97 Sep-17 2,237.86 336,074 670,514 98 Oct-17 2,237.86 338,312 664,391 99 Nov-17 2,237.86 340,550 658,268 100 Dec-17 2,237.86 342,788 652,145 101 Jan-18 342,788 643,784 102 Feb-18 342,788 635,423 103 Mar-18 342,788 627,062 104 Apr-18 342,788 618,701 105 May-18 342,788 610,340 106 Jun-18 342,788 601,979 107 Jul-18 342,788 593,618 108 Aug-18 342,788 585,257 109 Sep-18 342,788 576,896 110 Oct-18 342,788 568,535 111 Nov-18 342,788 560,174 112 Dec-18 342,788 551,813 113 Jan-19 13,711.51 329,076 529,740 114 Feb-19 13,711.51 315,365 507,668 115 Mar-19 13,711.51 301,653 485,595 116 Apr-19 13,711.51 287,942 463,523 117 May-19 13,711.51 274,230 441,450 118 Jun-19 13,711.51 260,519 419,378 119 Jul-19 13,711.51 246,807 397,305 120 Aug-19 13,711.51 233,096 375,233 121 Sep-19 13,711.51 219,384 353,160 122 Oct-19 13,711.51 205,673 331,088 123 Nov-19 13,711.51 191,961 309,015 124 Dec-19 13,711.51 178,250 286,943 125 Jan-20 13,711.51 164,538 264,870 126 Feb-20 13,711.51 150,827 242,798 127 Mar-20 13,711.51 137,115 220,725 128 Apr-20 13,711.51 123,404 198,653 129 May-20 13,711.51 109,692 176,580 130 Jun-20 13,711.51 95,981 154,508 131 Jul-20 13,711.51 82,269 132,435 132 Aug-20 13,711.51 68,558 110,363 133 Sep-20 13,711.51 54,846 88,290 134 Oct-20 13,711.51 41,135 66,218 135 Nov-20 13,711.51 27,423 44,145 136 Dec-20 13,711.51 13,712 22,073 137 Jan-21 13,711.51 (0) (0) OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 14 RATE BASE SCHEDULES Page 1 of 1 RATE BASE ADJUSTMENTS 2017 Test Year Versus 2017 Test Year Step
TY-16 (A) (B) (F) (G) Changes in Allocations due to Line 2017 Effect of Test Year 2017 No. Description Test Year Merricourt Step-In Adjustments Test Year Step
Utility Plant in Service: 1 Production $83,517,615 $24,590,337 $0 $108,107,952 2 Transmission $23,531,109 $0 $23,531,109 3 Distribution $45,646,364 -$1 $45,646,364 4 General $8,132,840 ($12,874) $8,119,967 5 Intangible $2,030,492 ($3,214) $2,027,278 6 TOTAL Utility Plant in Service $162,858,421 $24,590,337 ($16,088) $187,432,670 Accumulated Depreciation 7 Production ($34,122,115) ($983,613) ($0) ($35,105,729) 8 Transmission ($10,527,776) $0 ($10,527,776) 9 Distribution ($20,085,148) $0 ($20,085,148) 10 General ($3,714,965) $5,880 ($3,709,085) 11 Intangible ($737,803) $1,168 ($736,635) 12 TOTAL Accumulated Depreciation ($69,187,808) ($983,613) $7,049 ($70,164,373) 13 NET Utility Plant in Service 14 Production $49,395,500 $23,606,724 ($0) $73,002,224 15 Transmission $13,003,333 $0 $0 $13,003,333 16 Distribution $25,561,216 $0 ($0) $25,561,216 17 General $4,417,875 $0 ($6,993) $4,410,882 18 Intangible $1,292,689 $0 ($2,046) $1,290,643 19 NET Utility Plant in Service $93,670,613 $23,606,724 ($9,040) $117,268,297
20 Big Stone Plant capitalized items $0 $0 $0 21 Utility Plant Held for Future Use $2,786 $0 $2,786 22 Construction Work in Progress $0 $0 $0 23 Materials and Supplies $1,833,976 ($2,749) $1,831,227 24 Fuel Stocks $849,126 $0 $849,126 25 Prepayments ($1,946,936) ($53,603) ($2,000,539) 26 Customer Advances ($73,589) ($2,026) ($75,615) 27 Cash Working Capital $2,531,644 ($326,979) $2,204,665 28 Accumulated Deferred Income Taxes ($12,421,053) ($68,730) ($341,977) ($12,831,760) 29 Unamortized Rate Case Expense $458,334 $0 $458,334 30 Total Average Rate Base $84,904,901 $23,537,994 ($736,375) $107,706,521
Column references to adjustment workpapers: (B) W/P 2017 SD TY-16 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit__(TAA-1), Schedule 15 OPERATING INCOME SCHEDULES Page 1 of 1 OPERATING INCOME STATEMENT ADJUSTMENTS SCHEDULE 2017 Test Year Versus 2017 Test Year Step
TY-16 TY-17 (A) (B) (C) (D) (E) Changes in Allocations due to Effect of Line 2017 Merricourt Step- Proposed Test Test Year 2017 No. Description Test Year In Year Revenues Adjustments Test Year Step OPERATING REVENUES 1 Retail Revenue $30,650,015 $5,978,110 $0 $36,628,125 2 Other Electric Operating Revenue $1,731,348 $31,873 $1,763,221 3 TOTAL OPERATING REVENUE $32,381,363 $0 $5,978,110 $31,874 $38,391,347 OPERATING EXPENSES 4 Production Expenses $14,543,258 (854,834) 0 $13,688,425 5 Transmission Expenses $2,950,883 0 $2,950,883 6 Distribution Expenses $1,699,129 0 $1,699,129 7 Customer Accounting Expenses $1,153,253 0 $1,153,253 8 Customer Service and Information Expenses $664,545 0 $664,545 9 Sales Expenses $20,751 0 $20,751 10 Administration and General Expenses $4,003,827 30,258 10,987 $4,045,072 11 Charitable Contributions $0 0 $0 12 Depreciation Expense $5,037,485 983,613 -809 $6,020,289 13 General Taxes $969,261 57,288 26,686 $1,053,235 14 TOTAL OPERATING EXPENSES $31,042,391 $216,327 $0 $36,863 $31,295,581 15 NET OPERATING INCOME BEFORE INCOME TAXES $1,338,972 ($216,327) $5,978,110 ($4,990) $7,095,765 16 INCOME TAX EXPENSE 17 Investment Tax Credit ($123,560) ($1,356,702) ($1,223) ($1,481,485) 18 Deferred Income Taxes $441,070 $12,143 $453,213 19 Income Taxes ($1,021,346) (45,429) 1,255,403 ($141,782) $46,847 20 TOTAL INCOME TAX EXPENSE ($703,836) ($1,402,131) $1,255,403 ($130,862) ($981,425) 21 NET OPERATING INCOME $2,042,808 $1,185,804 $4,722,707 $125,872 $8,077,190 22 Allowance for Funds Used During Construction 0 0 0 23 TOTAL AVAILABLE FOR RETURN $2,042,808 $1,185,804 $4,722,707 $125,872 $8,077,190
Column references to adjustment workpapers: (B) W/P 2017 SD TY-16 (C) Test Year Revenue Requirement
Volume 2A
Direct Testimony and Supporting Schedules:
Stuart D. Tommerdahl
Before the South Dakota Public Utilities Commission State of South Dakota
In the Matter of the Application of Otter Tail Power Company For Authority to Increase Rates for Electric Utility Service in South Dakota
Docket No. EL18-___
Exhibit___
MAJOR PROJECTS, TEST YEAR REVENUES, ALLOCATION FACTORS & OTHER REGULATORY MATTERS
Direct Testimony and Schedules of
STUART D. TOMMERDAHL
April 20, 2018
TABLE OF CONTENTS
I. INTRODUCTION AND QUALIFICATIONS ...... 1 II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY ...... 1 III. MAJOR CAPITAL PROJECTS SINCE LAST RATE CASE ...... 3 A. BIG STONE AQCS PROJECT ...... 3 B. HOOT LAKE MATS PROJECT ...... 7 C. TRANSMISSION PROJECTS ...... 8 D. CUSTOMER INFORMATION SYSTEM ...... 10 IV. 2017 NORMALIZED RETAIL REVENUES ...... 14 A. 2017 ACTUAL RETAIL REVENUES ...... 15 B. WEATHER NORMALIZATION ...... 16 C. BILLING ADJUSTMENTS ...... 17 D. TOTAL 2017 NORMALIZED RETAIL REVENUES ...... 17 V. JURISDICTIONAL AND CLASS ALLOCATORS...... 18 A. TEST YEAR JCOSS AND CCOSS ALLOCATORS ...... 19 B. E8760 ALLOCATOR ...... 21 VI. FUEL ADJUSTMENT CLAUSE RIDER ...... 22 VII. CORPORATE COST ALLOCATIONS...... 24 VIII. ECONOMIC DEVELOPMENT RATES ...... 28 IX. LEAD LAG STUDY ...... 31 X. MERRICOURT WIND PROJECT STEP INCREASE RATE PROPOSAL ...... 32 XI. MISCELLANEOUS ITEMS ...... 34 A. NON-ASSET BASED TRADING ...... 34 B. RATE CASE EXPENSES ...... 35 C. HOLDING COMPANY FORMATION EXPENSES ...... 36 XII. CONCLUSION ...... 36
ATTACHED SCHEDULES
Schedule 1 – Tommerdahl Resume
Schedule 2 – Savings Impacts from Big Stone AQCS Project
Schedule 3 – Cost Allocations Procedures Manual (Redline and Clean)
Schedule 4 – Corporate Cost Allocation Manual (Redline and Clean)
1 I. INTRODUCTION AND QUALIFICATIONS
2 Q. PLEASE STATE YOUR NAME AND OCCUPATION. 3 A. My name is Stuart D. Tommerdahl. I am employed by Otter Tail Power Company (OTP) 4 as Manager, Regulatory Administration. 5 6 Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE. 7 A. I graduated from Moorhead State University, now Minnesota State University, 8 Moorhead, Minnesota, in 1983 with a B.S. degree in Accounting and a minor in 9 Economics. I am a Certified Public Accountant (Inactive) in Minnesota. From 1983 to 10 1992, I worked in several accounting, budgeting and financial reporting positions. In 11 1993, I joined OTP as Regulatory/Economic Analyst. From 1997 to 2003 I worked at 12 Otter Tail Energy Services as Manager, Financial Planning /Analysis and subsequently 13 Director, Financial Services. 14 In 2004, I returned to OTP as Manager, Risk Management. In March of 2012, I 15 started my current position as Manager, Regulatory Administration. My primary 16 responsibilities are to provide leadership in areas of revenue requirements analysis, 17 pricing and rate design, tariff administration, load research, cost allocation methodologies 18 to be used in cost of service studies, long range revenue forecasting, wholesale energy 19 accounting, cost of energy, and unbilled revenue. A copy of my resume is included as 20 Exhibit___(SDT-1), Schedule 1.
21 II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY
22 Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? 23 A. My Direct Testimony describes a number of revenue requirement and regulatory issues 24 associated with this case. 25 26 Q. PLEASE PROVIDE A BRIEF OVERVIEW OF YOUR DIRECT TESTIMONY. 27 A. My Direct Testimony focuses on the following items: 28 • Overview of major capital projects since our last South Dakota rate case; 1 Docket No. EL18-___ Tommerdahl Direct
1 • 2017 normalized retail revenues; 2 • Jurisdictional and class cost allocation factors; 3 • Fuel Adjustment Clause Rider; 4 • Corporate cost allocations; 5 • New economic development rates; 6 • Lead Lag Study; and 7 • Merricourt project step increase rates 8 Lastly, my Direct Testimony also addresses a few miscellaneous regulatory issues. 9 10 Q. HAVE YOU INCLUDED BOTH SOUTH DAKOTA JURISDICTIONAL AND TOTAL 11 COMPANY AMOUNTS IN YOUR DIRECT TESTIMONY AND SCHEDULES? 12 A. Yes. The dollar values presented in my Direct Testimony are jurisdictionalized to South 13 Dakota values and labeled as (OTP SD). The South Dakota jurisdictional values are also 14 presented in combination with total company values, labeled as (OTP Total). 15 There are certain power plant and transmission projects where OTP is only a part 16 owner. In those circumstances, I included each of the following: the total project costs, 17 labeled as (Total Plant or Total Project), and the OTP ownership allocation of the project 18 amounts, labeled as (OTP Total). 19 Some categories of costs include costs that fall into numerous functions, each 20 with its own jurisdictional allocation, and therefore a straightforward calculation of a 21 jurisdictional amount based on a single allocator is not possible. Examples of these costs 22 include certain labor cost categories, which may include costs functionalized as 23 generation, transmission, distribution, administration and general, with each function 24 having its own unique jurisdictional allocation. For costs that are categorized across 25 functions like this, the South Dakota jurisdictional dollar values have been estimated by 26 multiplying the Total Company costs by a single blended allocator. When such an 27 estimate has been used, the dollar values are labeled as (SD EST). 28
2 Docket No. EL18-___ Tommerdahl Direct
1 Q. HOW IS YOUR DIRECT TESTIMONY ORGANIZED? 2 A. In Section III, I will discuss major capital projects OTP has completed since its last South 3 Dakota rate case. In Section IV, I discuss the determination of 2017 normalized retail 4 revenues. In Section V, I discuss jurisdictional and class allocation factors. In Section VI, 5 I discuss a proposed change to OTP’s Fuel Adjustment Clause Rider. Section VII 6 includes a discussion of corporate cost allocations. In Section VIII, I discuss economic 7 development rates. Section IX includes a discussion of the Lead Lag Study. In Section X, 8 I discuss the Merricourt project step increase rate proposal. Section XI includes a 9 discussion of miscellaneous issues, and Section XII includes my conclusions.
10 III. MAJOR CAPITAL PROJECTS SINCE LAST RATE CASE
11 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? 12 A. In this section of my Direct Testimony, I will discuss major capital projects that OTP has 13 completed since its last South Dakota rate case, including: (A) the Big Stone plant Air 14 Quality Control System project (AQCS Project); (B) the Hoot Lake plant Mercury and 15 Air Toxics Standards project (MATS Project); and (C) major transmission projects. I will 16 also discuss OTP’s new Customer Information System Project. 17 18 Q. WHEN WAS OTP’S LAST RATE CASE IN SOUTH DAKOTA? 19 A. OTP’s last South Dakota rate case was filed before the South Dakota Public Utilities 20 Commission (Commission) in 2010 and was based on a 2009 Test Year (Docket No. 21 EL10-011).
22 A. Big Stone AQCS Project 23 Q. WHAT WILL YOU DISCUSS IN THIS SUBSECTION? 24 A. In this subsection of my Direct Testimony, I will explain the $0.9 million (OTP SD) of 25 annual savings for South Dakota customers in the 2017 Test Year, which will continue 26 for 30 years, as a result of OTP’s completion of the Big Stone AQCS Project far under 27 budget. I will also discuss the reductions in earnings for shareholders resulting from the 28 under-budget completion of the AQCS Project.
3 Docket No. EL18-___ Tommerdahl Direct
1 Q. WHAT IS THE BIG STONE AQCS PROJECT? 2 A. The Big Stone AQCS Project is a major environmental upgrade project at the Big Stone 3 plant that went into service on December 29, 2015. To date, it is the largest capital 4 project ever undertaken by OTP. The AQCS Project was needed for the continued 5 operation of the Big Stone plant. The AQCS Project reduces nitrogen oxides and sulfur 6 dioxide emissions at our Big Stone plant by approximately 90 percent and reduces 7 mercury emissions by approximately 80 percent. In Docket No. EL12-027, a staff report 8 concluded that: “Based on the evaluation of Otter Tail’s IRP [Integrated Resource Plan] 9 and the analysis conducted in the ADP proceedings in North Dakota and Minnesota, the 10 AQCS project is found to be the least cost option compared to other alternatives.”1 OTP 11 completed the Big Stone AQCS Project substantially under budget and on time. The Big 12 Stone AQCS Project, including the associated capital costs and OTP’s completion of the 13 project far under budget, is discussed in detail in the Direct Testimony of OTP witness 14 Mr. Kirk A. Phinney. 15 16 Q. IS OTP PROPOSING TO CHANGE HOW BIG STONE AQCS PROJECT CAPITAL 17 COSTS ARE RECOVERED? 18 A. Yes. The South Dakota jurisdictional share of the Big Stone AQCS Project capital costs 19 currently are being recovered through OTP’s South Dakota Environmental Cost 20 Recovery Rider (ECRR), as approved in Docket No. EL14-082. OTP witness Mr. Bryce 21 C. Haugen describes, in his Direct Testimony, OTP’s proposal to move the Big Stone 22 AQCS Project capital costs from the ECRR into base rates effective at the time OTP is 23 proposing to implement interim rates in this case. 24 25 Q. DOES THIS PROPOSAL INCREASE COSTS TO CUSTOMERS? 26 A. No. Moving the Big Stone AQCS Project from the ECRR into base rates is merely a 27 change to how the costs of the project are recovered. 28
1 Report entitled “Evaluation of Otter Tail’s Air Quality Control System Project as the Least Cost Option Compared to Other Alternatives,” filed January 25, 2013.
4 Docket No. EL18-___ Tommerdahl Direct
1 Q. DID OTP COMPLETE THE BIG STONE AQCS PROJECT AT A COST 2 SUBSTANTIALLY BELOW BUDGET? 3 A. Yes. Mr. Phinney explains in his Direct Testimony that the final capital cost for the Big 4 Stone AQCS Project is $365.5 million (Total Plant), which is $125 million below the 5 total original project budget of $491 million (Total Plant). OTP’s total company share of 6 this savings in capital costs is $67.6 million (OTP Total), and the South Dakota 7 jurisdictional share is $6.3 million (OTP SD). 8 9 Q. HAVE YOU DETERMINED THE SAVINGS IN THE 2017 TEST YEAR FROM 10 COMPLETING THE BIG STONE AQCS PROJECT BELOW BUDGET? 11 A. Yes. I have determined that the under-budget completion of the Big Stone AQCS Project 12 reduced the 2017 Test Year revenue deficiency and will save South Dakota customers 13 approximately $0.9 million annually (OTP SD). This determination was based on a cost 14 of completion of $365.5 million (Total Project) (approximately $125 million (Total 15 Project) below budget) and reflects OTP’s 53.9 percent ownership share and the South 16 Dakota jurisdictional allocation of 9.342 percent. This savings for South Dakota 17 customers is the result of (1) the reduction in the South Dakota jurisdictional share of the 18 return of capital (depreciation) on approximately $125.5 million (Total Project) savings; 19 plus (2) the reduction in the annual return on capital (earnings for investors plus tax 20 effect) on $125.5 million (Total Project) savings. My calculation of the estimated annual 21 savings for South Dakota customers for the 2017 Test Year is set forth on 22 Exhibit__(SDT-1), Schedule 2. 23 24 Q. HAVE YOU ALSO DETERMINED THE CUMULATIVE SAVINGS FOR SOUTH 25 DAKOTA CUSTOMERS OVER THE INITIAL 10 YEARS OF USE AND THE FULL 26 30-YEAR LIFE OF THE BIG STONE AQCS PROJECT? 27 A. Yes. I estimate that OTP’s South Dakota customers will receive cumulative savings of 28 approximately $8.0 million (OTP SD) over the initial 10-years of use of the Big Stone 29 AQCS Project. I estimate that, over the 30-year life of the AQCS Project, OTP’s under- 30 budget completion of the Big Stone AQCS Project will reduce OTP’s South Dakota 31 customer costs by approximately $17.2 million (OTP SD) with a net present value of $7.8 5 Docket No. EL18-___ Tommerdahl Direct
1 million (OTP SD). These savings for OTP’s South Dakota customers are also the result 2 of the South Dakota jurisdictional share of the reduction in the return of approximately 3 $125.5 million (Total Project) of capital (reflected in depreciation) plus the reduction in 4 the return on approximately $125.5 million (Total Project) of capital. My calculations are 5 also set forth on Exhibit__(SDT-1), Schedule 2. 6
7 Q. IN ADDITION TO CUSTOMER SAVINGS, DOES THE UNDER-BUDGET 8 COMPLETION ALSO HAVE AN EFFECT ON SHAREHOLDERS? 9 A. Yes. While the lower investment from the under-budget completion of the Big Stone 10 AQCS Project provides substantial savings for South Dakota customers, there is a 11 corresponding effect on OTP shareholders in the form of reduced earnings resulting from 12 the reduced investment. 13 14 Q. HAVE YOU DETERMINED THE REDUCED EARNINGS FOR SHAREHOLDERS 15 IN THE 2017 TEST YEAR AND IN OTHER YEARS? 16 A. Yes. As a result of OTP’s under budget completion of the Big Stone AQCS Project, the 17 return to shareholders will be reduced (after OTP income taxes) by approximately: 18 A. $0.3 million (OTP SD) in the 2017 Test Year; 19 B. $2.9 million (OTP SD) during the first 10 years; and 20 C. $5.4 million (OTP SD) over the 30-year life of the Big Stone AQCS Project. 21 The net present value of reduced earnings is $2.0 million (OTP SD) over the first 22 10 years and $2.7 million (OTP SD) over the 30-year life of the Big Stone AQCS Project. 23 My calculations are set forth on Exhibit__(STD-1), Schedule 2. 24 25 Q. IS IT APPROPRIATE FOR THE COMMISSION TO CONSIDER THESE CUSTOMER 26 SAVINGS AND LOWER EARNINGS IN SETTING OTP’S RETURN ON EQUITY? 27 A. Yes. OTP witness Mr. Robert B. Hevert recommends that the Commission consider 28 OTP’s under-budget completion of the Big Stone AQCS Project when setting OTP’s 29 return on equity (ROE). Considering this accomplishment in setting the ROE for OTP 30 would help to reinforce that prudent execution of capital projects and the resulting cost
6 Docket No. EL18-___ Tommerdahl Direct
1 savings for customers is a priority of both utilities and regulators. While OTP has always 2 made the prudent execution of capital expenditures one of its most important business 3 priorities, OTP believes that reinforcement of that priority in the setting of OTP’s 4 authorized ROE is appropriate in this case from a regulatory perspective.
5 B. Hoot Lake MATS Project 6 Q. WHAT WILL YOU DISCUSS IN THIS SUBSECTION? 7 A. In this subsection, I will discuss the Hoot Lake MATS Project, which OTP also 8 completed under budget. 9 10 Q. WHAT IS THE HOOT LAKE MATS PROJECT? 11 A. The Hoot Lake MATS Project involved the upgrade of Electrostatic Precipitators and the 12 installation of an Activated Carbon Injection system at Hoot Lake. The Hoot Lake MATS 13 Project is designed to control mercury and particulate matter emissions at the plant. The 14 project is described in greater detail in Mr. Phinney’s Direct Testimony. 15 16 Q. DID OTP COMPLETE THE HOOT LAKE MATS PROJECT AT A COST 17 SUBSTANTIALLY BELOW BUDGET? 18 A. Yes. Mr. Phinney explains in his Direct Testimony that the final capital cost for the Hoot 19 Lake MATS Project is $7.145 million (OTP Total), which is $2.8 million (28 percent) 20 below the total original project budget of $10 million (OTP Total). 21 22 Q. IS OTP PROPOSING TO CHANGE TO HOW HOOT LAKE MATS PROJECT 23 CAPITAL COSTS ARE RECOVERED? 24 A. Yes. The South Dakota jurisdictional share of the Hoot Lake MATS Project capital costs 25 currently are being recovered through the ECRR. Mr. Haugen describes OTP’s proposal 26 to move the Hoot Lake MATS Project capital costs from the ECRR into base rates 27 effective at the time OTP is proposing to implement interim rates in this case. 28
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1 Q. DOES THIS PROPOSAL INCREASE COSTS TO CUSTOMERS? 2 A. No. Moving the Hoot Lake MATS Project from the ECRR into base rates is merely a 3 change to how the costs of the project are recovered.
4 C. Transmission Projects 5 Q. WHAT WILL YOU DISCUSS IN THIS SUBSECTION OF YOUR DIRECT 6 TESTIMONY? 7 A. In this subsection, I will provide background information and a description of OTP’s 8 major completed transmission projects, which are included in OTP’s proposal to roll 9 transmission projects now included in OTP’s Transmission Cost Recovery Rider (TCRR) 10 into base rates. Mr. Haugen will explain that proposal in his Direct Testimony. 11 12 Q. PLEASE BRIEFLY DESCRIBE THE MAJOR TRANSMISSION PROJECTS IN 13 WHICH OTP HAS INVESTED SINCE OTP’S LAST RATE CASE? 14 A. OTP has been involved with numerous transmission projects since OTP’s last rate case in 15 2010. The most significant completed projects include: (1) the Big Stone South to 16 Brookings multi-value project (MVP); (2) the CAPX2020 transmission projects, 17 including Fargo to Monticello, Bemidji to Grand Rapids, and Brookings to Hampton; (3) 18 the Casselton to Buffalo 115kV project, and (4) the Oakes Area transmission project. The 19 Commission has reviewed and approved each of these projects for cost recovery in prior 20 proceedings as noted in Mr. Haugen’s testimony. 21 22 Q. WHAT WAS THE PURPOSE OF THE BIG STONE SOUTH TO BROOKINGS 23 PROJECT? 24 A. The Big Stone South-Brookings County project is a 70-mile, 345kV transmission line 25 built between a new Big Stone South Substation near Big Stone City, S.D., and the 26 Brookings County Substation near Brookings, S.D. The project is one of 17 MVPSs 27 approved by the Midcontinent Independent System Operator (MISO) in December 2011. 28 The MVPs will help expand and enhance the region’s transmission system, reduce 29 congestion, provide access to affordable energy sources and meet public policy
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1 requirements, including renewable energy mandate. The project was placed in service in 2 September 2017. 3 4 Q. PLEASE BRIEFLY DESCRIBE THE CAPX2020 TRANSMISSION PROJECTS. 5 A. The three CAPX2020 transmission projects in which OTP has invested are part of the 6 CAPX2020 portfolio of five projects formed to upgrade and expand the electric 7 transmission grid to ensure continued reliable and affordable service. The total 8 CAPX2020 portfolio involves an 800 mile, nearly $2 billion investment initiative, 9 including four 345kV transmission lines and one 230kV line involving 11 transmission- 10 owning utilities in South Dakota, North Dakota, Minnesota and Wisconsin. The 11 CAPX2020 portfolio projects were approved by MISO as part of its Transmission 12 Expansion Planning process, which identifies issues and opportunities, develops 13 alternatives for consideration, and evaluates those alternatives to determine effective 14 transmission solutions. 15 16 Q. PLEASE DESCRIBE OTP’S CAPX2020 PROJECTS. 17 A. OTP has participated in three CAPX2020 projects: (1) CAPX2020 Fargo to Monticello; 18 (2) CAPX2020 Bemidji to Grand Rapids; and (3) CAPX2020 Brookings to Hampton. 19 The CAPX2020 Fargo to Monticello project includes 240 miles of 345kV line running 20 from Fargo, North Dakota to Monticello, Minnesota and associated upgrades. The project 21 was energized April 2, 2015. 22 The CAPX2020 Bemidji to Grand Rapids project, which is inclusive of the 23 Bemidji to Cass Lake segment, is a 70-mile 230kV line running from Bemidji, Minnesota 24 to Grand Rapids, Minnesota. The project was energized September 2012. 25 Finally, the CAPX2020 Brookings to Hampton includes 250 miles of 345kV line 26 running from Brookings, South Dakota to Hampton, Minnesota. The project, which 27 connects to new renewable generation resources in southern and western Minnesota and 28 North Dakota and South Dakota, was energized March 26, 2015. 29
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1 Q. PLEASE DESCRIBE THE CASSELTON TO BUFFALO AND OAKES PROJECTS. 2 A. The Casselton to Buffalo project includes 16 miles of 115kV line and related 3 modifications and replacements. The project was completed and placed in-service in 4 November 2017. The Oakes projects includes upgrades to the transmission system around 5 Oakes, North Dakota. This project was completed in late 2015. 6 7 Q. IS OTP NOW RECOVERING THE COST OF THESE PROJECTS IN OTP’S TCRR? 8 A. Yes. The South Dakota allocated portion of the costs of each of these transmission 9 projects is included in the eight completed projects that OTP is recovering through the 10 TCRR. 11 12 Q. WHAT IS OTP’S PROPOSAL REGARDING THOSE COMPLETED 13 TRANSMISSION PROJECTS CURRENTLY BEING RECOVERED IN OTP’S TCRR? 14 A. OTP is proposing to roll the recovery of these investments out of the TCRR and into base 15 rates at the time Otter Tail proposes interim rates to go into effect in this case. Mr. 16 Haugen discusses the roll-in of these projects into base rates in his Direct Testimony.
17 D. Customer Information System 18 Q. WHAT WILL YOU DISCUSS IN THIS SUBSECTION OF YOUR DIRECT 19 TESTIMONY? 20 A. In this subsection, I will provide background information and a description of OTP’s new 21 Customer Information System which OTP refers to internally as “CISone.” 22 23 Q. IS OTP NOW IMPLEMENTING CISONE? 24 A. Yes. As OTP witness Mr. Bruce Gerhardson briefly describes in his Direct Testimony, 25 OTP is implementing CISone to replace an existing legacy customer information system 26 that OTP built internally and has been using for almost 30 years. Among other things, 27 customer billing will be one of the key functional business operations that will transfer 28 from the legacy system to the new CISone system. Mr. Gerhardson outlines numerous 29 other functional improvements CISone will provide as OTP builds critical technical 30 infrastructure to address changing needs of both customers and OTP employees. OTP’s 10 Docket No. EL18-___ Tommerdahl Direct
1 current estimated cost of the system is $15.8 million (OTP Total) / $1.5 million (OTP 2 SD). 3 4 Q. PLEASE FURTHER DESCRIBE THE ADDITIONAL FUNCTIONALITY THAT 5 CISONE WILL PROVIDE OTP’S CUSTOMERS AND EMPLOYEES. 6 A. There are many benefits that OTP customers and employees will realize once CISone is 7 implemented. Much of this is due to the limitations of the current system due to its age. 8 One significant source of high-level benefit will be the system’s ability to “talk” to other 9 OTP systems through interfaces, allowing data to flow in real-time rather than through 10 overnight batches and file transfers as is currently done. This will allow information 11 exchange at a much more rapid pace. Other benefits include:
12 • Ease of new or updated rate implementation: The existing CIS is limited due 13 to field and capacity constraints and updating or changing rates or riders takes 14 significant database modification. CISone will allow OTP to more easily prepare 15 for rate/rider updates and changes, as well as provide a better process to test those 16 changes. 17 • Customer Self Service (CSS): CISone will better support self-service and online 18 business. 19 • Mobile work management (MWM): Mobile field workers will have access to 20 information much more quickly, and they will have access to information that was 21 not previously available to them in the field. “Apps” will be available through 22 smartphones and tablets. 23 • A new system will be able to support future initiatives: CISone will support 24 initiatives such as two-way Geographic Information System (GIS) integration, 25 Advanced Metering Infrastructure (AMI), and Outage Management System 26 (OMS) support. 27 • Less reliance on CIS programmers and technicians: More functions will be 28 shifted to system end-users. 29 • Improved automation: The current CIS system is not capable of meeting current 30 functional demands without significant manual intervention, which will not be 31 needed with CISone. 32 • Elimination of reusing of data fields: This will minimize the risk of data 33 corruption.
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1 • Easier detection and correction of billing issues: Detection and correction will 2 be facilitated. 3 • Advanced ad-hoc reporting: The new CIS system will come with many reports 4 and queries that previously would have taken significant programming to develop. 5 • More advanced “Checkout and Lock” features: These features will mitigate 6 the risk of data corruption and account errors. 7 • A more robust primary/secondary failover system: CISone is designed so that 8 an in the event of a failure it will result in less downtime to restore. 9 • Better ability to drive consistent business processes across all jurisdictions: 10 CISone will facilitate consistency across all jurisdictions. 11 12 Q. WHEN DOES OTP ANTICIPATE IMPLEMENTING CISONE? 13 A. CISone is currently scheduled to “go-live” in the 4th quarter, 2018. Implementation will 14 only occur after CISone has been fully tested to confirm that OTP’s customer billings 15 will be accurately and correctly computed and accounted for. OTP will keep the 16 Commission informed on the schedule during the course of this case. 17 18 Q. HOW DOES IMPLEMENTATION OF CISONE RELATE TO THE 19 IMPLEMENATION OF FINAL RATES IN THIS RATE CASE? 20 A Because the implementation of the CISone system closely aligns with the timeline of this 21 rate case and the potential implementation date of final rates, OTP is evaluating the 22 feasibility of simultaneously implementing final rates the same month as CISone is 23 implemented. If simultaneous implementation is not feasible, OTP is also considering 24 implementation of final rates in the current CIS system if this case has concluded prior to 25 CISone implementation and the Commission deems that to be the most appropriate 26 approach. 27 CISone also could potentially be ready for implementation ahead of 28 implementation of final rates. If OTP implements CISone ahead of final rates, OTP 29 believes it would be appropriate to have a two or three month “window” between 30 implementation of CISone and final rates for further confirmation of CISone system 31 operation. With interim rates in effect, OTP would be open to delaying implementation of 32 final rates as an option to best align the schedules of this case and CISone 12 Docket No. EL18-___ Tommerdahl Direct
1 implementation. Customers would be protected and compensated for any delay by 2 interest applied to any interim refund. 3 4 Q. IS OTP SEEKING RECOVERY OF CISONE COSTS IS THIS CASE? 5 A. Yes. OTP included the CISone project, including costs, in the 2017 Test Year as a known 6 and measurable change. CISone will only be included in final rates, not in Otter Tail’s 7 proposed interim rates. The CISone system will have a ten-year depreciable life. OTP 8 has included a Test Year adjustment to annualize the costs associated with CISone, based 9 on this ten-year life, into the 2017 Test Year. OTP witness Mr. Tyler A. Akerman 10 provides further detail of the normalizing adjustment in his Direct Testimony. 11 12 Q. WILL THE IMPLEMENTATION OF CISONE RESULT IN ANY CHANGES TO 13 OTP’S CUSTOMER BILL CALCULATIONS, RATE DESIGNS, TARIFF 14 LANGUAGE, OR OTP’S GENERAL RULES AND REGULATIONS? 15 A. Yes. Before filing this rate case, OTP met with Commission Staff to inform them that 16 OTP anticipates CISone will necessitate some changes to OTP’s tariffs and bills, as well 17 as changes to the language in OTP’s rate book. OTP will need Commission approval to 18 make those changes. OTP proposes to make a separate filing sometime in the second 19 quarter of 2018 to seek approval of the CISone tariff and bill changes. Because of the 20 potential scenarios related to timing of the final rates and CISone, OTP and Commission 21 Staff agreed handling these changes in a separate filing would provide greater flexibility 22 in terms of seeking Commission approvals for CISone related changes. This flexibility is 23 necessary should the schedule indicate CISone could be implemented ahead of the 24 completion of this case and implementation of final rates. 25 26 Q. ARE THERE ANY RATE PROPOSALS IN THIS CASE THAT OTP WILL NOT BE 27 ABLE TO IMPLEMENT IN OTP’S CURRENT CIS SYSTEM? 28 A. Yes. In this case, OTP is proposing to implement an E8760 allocation of fuel and 29 purchased power costs recovered through the Fuel Adjustment Clause rider (also known 30 as the Fuel Clause, FCA or Energy Adjustment). I will discuss this proposed change to 31 OTP’s Fuel Clause in greater detail later in my Direct Testimony but as a summary, 13 Docket No. EL18-___ Tommerdahl Direct
1 implementing this E8760 allocation results in a distinct and separate Fuel Clause rate for 2 each customer class. OTP’s current legacy billing system is not able to facilitate a 3 separate Fuel Clause rate for each class. This functionality is being designed into CISone. 4 OTP proposes that, if final rates go into effect before CISone is implemented, the 5 Commission allow OTP to delay the transition to a 10-class FCA rate until after CISone 6 is implemented. In the interim, OTP proposes to charge all classes the same FCA rate. In 7 OTP’s recent Minnesota general rate case, the Minnesota Public Utilities Commission 8 approved delaying a similar E8760 Fuel Clause rate implementation until OTP’s CISone 9 system is placed in service. A similar proposal is included in OTP’s current North Dakota 10 case. OTP is seeking consistency of the use of an E8760 allocator across all jurisdictions. 11 12 Q. HAS OTP PROVIDED SEPARATE RATE SCHEDULES TO REFLECT EACH OF 13 THESE SCENARIOS? 14 A. Yes. In Volume 3, a proposed version of Section 13.01 is provided that would be 15 applicable to the application of the E8760 allocation to the Fuel Clause once CISone is 16 placed into service. In this version, each customer class’s specific Energy Adjustment 17 Factor Ratio (EAF Ratio) is included. A second proposed version of Section 13.01 is 18 provided that would be applicable in the event final rates in this case are implemented 19 ahead of the implementation of CISone. In this version, each customer class’s specific 20 EAF Ratio is set to 1.000. In this instance, all customers would be charged the same FCA 21 rate as I noted above.
22 IV. 2017 NORMALIZED RETAIL REVENUES
23 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY? 24 A. This section describes how 2017 South Dakota normalized retail revenues were 25 determined. First, I will describe how 2017 South Dakota actual retail revenues were 26 established. I will then describe the adjustments made to determine total 2017 normalized 27 retail revenues for the 2017 Test Year. 28
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1 A. 2017 Actual Retail Revenues 2 Q. PLEASE DEFINE RETAIL REVENUES. 3 A. For the purposes of ratemaking, retail revenues are the total retail revenues (billed and 4 unbilled) on a calendar month basis, plus or minus the adjustments I discuss below. In 5 other words, the calendar month revenue includes revenue for the billed sales and 6 estimated revenue for electricity that has been delivered to customers, but not yet billed. 7 This includes revenues collected through base rates as well as revenues applicable to 8 OTP’s various cost recovery riders. 9 10 Q. WHAT DO YOU MEAN BY “REVENUES ON A CALENDAR MONTH BASIS”? 11 A. Calendar month revenues are determined by making an adjustment for unbilled revenues 12 to billing month retail revenues. Billing month revenues do not coincide with the calendar 13 month, as they are billed on cycles (20 cycles in a month for OTP). Total 2017 billed 14 revenues for the South Dakota retail jurisdiction were $33,113,281. 15 To have retail revenues match to the calendar year for which expenses are 16 incurred, the incremental amount of revenues that have not been billed at the end of the 17 year for each of the 20 billing cycles are estimated using a comprehensive model. This 18 model calculates the unbilled revenues for 2017 that were billed in January 2018, net of 19 the December 2016 unbilled revenues that were billed in January of 2017. For 2017, the 20 unbilled revenue calculation increased South Dakota retail revenues by $108,870. 21 In addition, total billed revenues are also adjusted by the amount of any over or 22 under collection balance attributable to OTP’s cost recovery riders to reflect the actual 23 calendar year revenue requirement within that rider. The total amount of these 24 adjustments was a decrease to South Dakota retail revenue of ($292,279). OTP’s total 25 South Dakota retail revenues for 2017 before any normalizing adjustments were 26 $32,929,872.
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1 B. Weather Normalization 2 Q. HAVE ACTUAL 2017 SOUTH DAKOTA RETAIL REVENUES BEEN WEATHER 3 ADJUSTED TO ARRIVE AT THE 2017 TEST YEAR REVENUES? 4 A. Yes, actual 2017 South Dakota retail revenues have been weather normalized as 5 described below. 6 7 Q. WHAT IS THE PURPOSE OF WEATHER NORMALIZING HISTORIC DATA? 8 A. If OTP were using a projected test year based on a budget, a weather normalization 9 adjustment would not be necessary, since budgets assume normal weather. However, in a 10 test year based on historic data, the historic sales data needs to be adjusted to produce 11 retail revenue and variable costs that are representative of the effects of “normal” 12 weather. 13 14 Q. PLEASE DESCRIBE THE WEATHER NORMALIZATION METHODOLOGY USED 15 BY OTP. 16 A. OTP’s weather normalization process utilizes a similar methodology to what was used in 17 OTP’s last South Dakota general rate case. For 2017, the weather normalization 18 adjustment results in an increase to South Dakota base revenues of $202,124. The 19 weather normalization adjustment also results in increased fuel expenses and associated 20 FCA revenues of approximately $133,229 for South Dakota. The combination of these 21 adjustments is shown as Test Year Adjustment TY-05 in Schedule 10 to Mr. Akerman’s 22 Direct Testimony. 23 OTP’s weather normalization process utilizes the current year plus the prior 20 24 years of OTP hourly weather data, monthly revenue, and monthly kWh data. A statistical 25 regression procedure is used to determine weather normalization models for each of 40 26 different rate groups within each of OTP’s three states. Variables used include: (i) 27 kWh/day; (ii) heating and cooling degree days; (iii) the number of months since January 28 1997; and (iv) up to 13 autoregressive terms. The results are checked for accuracy and 29 reasonableness using graphs and reports. Weather normalized kWh sales are then priced 30 on current rates using a calendar month basis. The resulting revenue amounts do not 31 include FCA revenues. 16 Docket No. EL18-___ Tommerdahl Direct
1 Consequently, to include the impact of weather normalization on the FCA, 2 weather normalized kWh sales are multiplied by the appropriate total cost of energy rate 3 for each of the twelve months to determine the fuel and purchased power costs. As noted 4 above, total FCA fuel and purchased power costs and associated FCA revenues for South 5 Dakota are $133,229. 6 7 Q. DOES WEATHER NORMALIZATION RESULT IN AN ADJUSTMENT TO 8 UNBILLED REVENUES FOR THE 2017 TEST YEAR? 9 A. Yes, but not separately. As stated in the previous question, weather normalization is 10 computed on a calendar month basis, which includes unbilled sales.
11 C. Billing Adjustments 12 Q. DO THE 2017 TEST YEAR SALES REFLECT ANY BILLING ADJUSTMENTS? 13 A. Yes. During 2017 OTP made minor bill adjustments attributable to time periods prior to 14 2017. There have also been billing adjustments made in early 2018 that were attributable 15 to 2017. 16 Test Year Adjustment TY-06 in Schedule 10 to Mr. Akerman’s Direct Testimony 17 moves the revenues and associated estimated fuel costs to the proper year. These 18 adjustments increase 2017 South Dakota revenues by $4,325, and associated fuel costs by 19 $2,179.
20 D. Total 2017 Normalized Retail Revenues 21 Q. WHAT ARE THE TOTAL NORMALIZED SOUTH DAKOTA RETAIL REVENUES 22 FOR 2017? 23 A. Table 1 below summarizes OTP’s total 2017 normalized South Dakota retail revenues. 24
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1 Table 1 2 Total 2017 SD Normalized Retail Revenue Summary Revenue Component SD Total Billed Revenues $33,113,281 Unbilled Revenue $108,870 Rider Revenue Adjustments $(292,279) Total 2017 Retail Revenue $32,929,872
Weather Normalization Adjustments (Base + Fuel) $335,353 Billing Adjustments $4,325 Total 2017 Normalized Retail Revenue $33,269,550 3 4 Mr. Haugen provides further detail in his Direct Testimony as to OTP’s proposed 5 class revenue responsibilities.
6 V. JURISDICTIONAL AND CLASS ALLOCATORS
7 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? 8 A. In this section of my Direct Testimony, I will discuss the use of jurisdictional and class 9 allocators. I will discuss Test Year allocators used by OTP, including the E8760 10 allocator. 11 12 Q. WHAT ARE THE ROLES OF JURISDICTIONAL AND CLASS ALLOCATORS IN 13 THE RATEMAKING PROCESS? 14 A. Jurisdictional allocators are used to allocate system costs among jurisdictions and class 15 allocators are used to allocate jurisdictional costs among customer classes. 16 17 Q. WHY ARE JURISDICTIONAL AND CLASS ALLOCATORS NECESSARY? 18 A. OTP operates an integrated electrical system that serves customers across multiple 19 jurisdictions. This integrated system design takes advantage of economies of scale to 20 provide least cost energy solutions for all our customers. Because OTP operates as one
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1 system, costs of investment in the system and the expenses necessary to operate the 2 system need to be allocated among the jurisdictions. Costs allocated to each jurisdiction 3 need to be further allocated to customer classes to design rates. 4 5 Q. HOW DO THESE ALLOCATIONS OCCUR? 6 A. System costs and revenues are allocated to jurisdictions in the Jurisdictional Cost of 7 Service Study (JCOSS) described in more detail by Mr. Akerman. Jurisdictional costs 8 and revenues are allocated to customer classes in the Class Cost of Service Study 9 (CCOSS) described by Mr. Haugen.
10 A. Test Year JCOSS and CCOSS Allocators 11 Q. WHAT ALLOCATORS DID OTP USE IN ITS TEST YEAR JCOSS AND CCOSS? 12 A. Table 2 below identifies the main allocators used in the 2017 Test Year JCOSS and 13 CCOSS. The OTP Cost Allocation Procedures Manual (CAPM), included as 14 Exhibit__(SDT-1), Schedule 3, provides additional detail regarding the development of 15 each allocator. 16 17 Table 2 18 JCOSS and CCOSS Allocators Cost Function Classification JCOSS Allocator2 CCOSS Allocator3 Base Demand E1 E1-E8760 Production Plant Peak Demand D1 D1 Base Energy (Wind) E2 E2-E8760 Transmission Plant Demand-Related D2 D2 Demand-Related (Primary) D3 D3 Demand-Related (Secondary) D4 D4 Customer-Related (Primary) C2 C2 Customer-Related (Secondary) C3 C3 Distribution Plant Street Lighting C4 C4 Area Lighting C5 C5 Meters C6 C6 Load Management C9 C9 19
2 See Volume 4A, Section C, Supporting Information, Schedule B-7. 3 See Volume 4A, Section C, Supporting Information, Schedule E-3.
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1 Q. HAS OTP CHANGED THE CAPM SINCE ITS LAST SOUTH DAKOTA RATE 2 CASE? 3 A. Yes. OTP has refined the language pertaining to the classification and allocation of wind 4 generation resources, as well as other minor clarifications and formatting updates since 5 OTP’s last South Dakota rate case in 2010. Exhibit (SDT-1), Schedule 3, provides the 6 content changes in red-line and clean versions. 7 8 Q. DID OTP USE THESE SAME ALLOCATORS IN ITS LAST SOUTH DAKOTA 9 RATE CASE? 10 A. Yes. We used the same energy, demand and customer allocation factors outlined in the 11 CAPM for cost allocations in this case as we did in our last South Dakota rate case except 12 for the addition of an E8760 allocator for the CCOSS and Fuel Clause Adjustment Rider. 13 14 Q. ARE THE ALLOCATORS USED IN THE CURRENT CASE BASED ON 15 HISTORICAL INFORMATION? 16 A. Yes. OTP is using a historic 2017 Test Year in this case and developed the allocation 17 factors based on 2017 actual information, adjusted for the known and measurable 18 changes I discussed earlier. This is consistent with the historical Test Year used in OTP’s 19 last South Dakota rate case. The process of developing the allocators is described in the 20 CAPM. 21 22 Q. DOES OTP USE THE SAME ALLOCATION METHODOLOGIES ACROSS ALL OF 23 ITS JURISDICTIONS? 24 A. Yes. Each of our jurisdictions has approved the same jurisdictional cost allocation 25 methodology. OTP’s proposal to implement the E8760 allocator for class cost of service 26 allocations is also consistent with what has been approved or proposed in OTP’s other 27 jurisdictions as well. 28
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1 B. E8760 Allocator 2 Q. WHAT IS AN E8760 ALLOCATOR? 3 A. An E8760 allocator applies a cost factor to each kWh of energy consumed for every one 4 of the 8,760 hours in the year to develop a weighted cost of energy factor. The E8760 5 allocator reflects changes in the cost of energy from hour to hour. 6 7 Q. HOW IS AN E8760 ALLOCATOR DIFFERENT FROM THE E1 AND E2 8 ALLOCATORS? 9 A. While the E8760 allocator reflects changes in the cost of energy from hour to hour, 10 OTP’s E1 and E2 allocation factors are computed based solely on energy consumed, 11 without any consideration for the associated date and time of consumption and 12 corresponding hourly cost of that energy. The difference between the E1 allocator and the 13 E2 allocator is that E1 excludes residential demand control, interruptible, irrigation, and a 14 portion of water heating and deferred sales. 15 16 Q. HOW DID OTP DEVELOP THE E1-E8760 AND E2-E8760 ALLOCATORS? 17 A. The class E8760 allocators were developed in five steps as follows: 18 Step 1: Develop Load Shapes. OTP developed class-based load shapes for each of the 19 8,760 hours based on load research data from 2016, the last full year of data available. 20 Step 2: Apply Load Shapes to Class Sales within South Dakota. The 2016 class-based 21 load shapes were applied to 2017 class sales for South Dakota. This resulted in a 22 distribution of all sales within each class, across all 8,760 hours of the year for South 23 Dakota. 24 Step 3: Apply Hourly Costs to Class-Based Load Shapes for South Dakota: OTP 25 multiplied the actual hourly class sales by hourly 2017 MISO Day Ahead Locational 26 Marginal Prices for the OTP load zone, which results in hourly costs by class. 27 Step 4: Sum Class Hourly Costs: This results in total energy costs over the 8,760 hours 28 for each class. 29 Step 5: Compare Class Energy Costs to Total Energy Costs: This results in the E8760 30 allocators, which are shown in Table 3 below. 31 21 Docket No. EL18-___ Tommerdahl Direct
1 Q. HAS OTP USED THE E1-E8760 AND E2-E8760 ALLOCATORS IN THE CCOSS? 2 A. Yes. OTP allocated energy-related production plant costs using the E1-E8760 and E2- 3 E8760 allocators in the CCOSS.
4 VI. FUEL ADJUSTMENT CLAUSE RIDER
5 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? 6 A. In this section of my Direct Testimony, I will discuss a proposed change to the name of 7 the Fuel Adjustment Clause Rider, Electric Rate Schedule 13.01, and the use of the 8 E8760 allocator I just discussed, in that rider. I will also discuss removal of any reference 9 to non-asset-based trading from that rate schedule. 10 11 Q. IS OTP PROPOSING A NEW NAME FOR THE FUEL ADJUSTMENT CLAUSE 12 RIDER? 13 A. Yes. OTP proposes to change the name of Electric Rate Schedule 13.01 from the Fuel 14 Adjustment Clause Rider to the Energy Adjustment Rider to be consistent with the 15 naming conventions of the comparable riders in OTP’s other jurisdictions. I will use that 16 proposed term throughout the rest of my testimony. 17 18 Q. DOES OTP PROPOSE TO USE AN E8760 ALLOCATOR TO ALLOCATE FUEL 19 COSTS IN ITS ENERGY ADJUSTMENT RIDER? 20 A. Yes. OTP proposes to use an E8760 allocator in its Energy Adjustment Rider. 21 22 Q. WHAT IS THE RATIONALE FOR COMPUTING AND USING AN E8760 23 ALLOCATOR FOR ENERGY ADJUSTMENT RIDER? 24 A. Energy usage can vary significantly between customer classes over the course of a day, 25 week, month or year. At the same time, costs to provide that energy also vary each day, 26 week, month or year. The E8760 allocator takes into account when energy is used and the 27 associated cost of that energy and creates an appropriate weighting of the overall cost 28 each class is accountable for. As a result, the E8760 allocator yields a distinct and
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1 separate Energy Adjustment Rider rate for each customer class that more accurately 2 reflects the cost causation responsibility of that class for energy costs. 3 4 Q. HOW DOES THE USE OF THE E8760 ALLOCATOR IMPACT CLASS 5 ALLOCATIONS OF FUEL COSTS? 6 A. For illustrative purposes, Table 3 below shows how the 10 customer classes are impacted 7 using the average fuel rate and applying the E2-E8760 allocator. The average fuel rate 8 shown is based on total system costs, which is consistent with how fuel is calculated and 9 as summarized in Volume 1, Statement P. 10 11 Table 3 Fuel Allocation A B C E2-E8760 E2-E8760 Avg Fuel Allocation Avg Fuel Customer Classes $/kWh Ratio $/kWh (A*B) Residential (RDC/RES) $ 0.026153 1.0240 $ 0.026779 Farms (FAR) $ 0.026153 1.017 $ 0.026587 General Service (TUS/GSO/GSU) $ 0.026153 1.031 $ 0.026975 Large General Service (PLG/SLG/TLG) $ 0.026153 0.981 $ 0.025661 Irrigation Services (IRR) $ 0.026153 0.912 $ 0.023838 Outdoor Lighting (ALT/SLT) $ 0.026153 0.808 $ 0.021140 OPA (OPA) $ 0.026153 1.007 $ 0.026327 Controlled Service Water Heating (WHR) $ 0.026153 1.038 $ 0.027154 Controlled Service Interruptible (LDF/SDF) $ 0.026153 1.013 $ 0.026484 12 Controlled Service Deferred (DFL/FTD) $ 0.026153 0.946 $ 0.024739 13 14 Q. HOW DOES OTP PROPOSE TO USE THE E2-E8760 ALLOCATOR IN THE 15 ENERGY ADJUSTMENT RIDER? 16 A. OTP proposes to allocate costs through the Energy Adjustment Rider using the E2-E8760 17 allocation method as a basis for cost allocation. OTP proposes to continue calculating a 18 monthly average fuel rate and then apply the E2-E8760 allocation ratio to derive an E2- 19 E8760 based fuel cost per kWh which is then applied to each of the 10 customer classes. 20 23 Docket No. EL18-___ Tommerdahl Direct
1 Q. WHEN DOES OTP PROPOSE TO IMPLEMENT USE OF THE E2-E8760 2 ALLOCATOR FOR THE ENERGY ADJUSTMENT RIDER? 3 A. OTP proposes to begin use of the E2-E8760 allocator for Energy Adjustment Rider 4 purposes at the time final rates go into effect, provided the CISone system is in service. 5 As described earlier in my testimony, CISone is scheduled to “go-live” in the 4th quarter 6 of 2018. OTP’s current legacy billing system is unable to calculate a separate Energy 7 Adjustment Rider rate for each of the ten customer classes, which is necessary to 8 implement use of the E8760 allocator. Therefore, implementation would need to be 9 delayed until CISone is in service. 10 11 Q. IS OTP PROPOSING A MODIFICATION TO THE ENERGY ADJUSTMENT RIDER 12 RELATED TO NON-ASSET BASED TRADING? 13 A. Yes. OTP is proposing to remove Paragraph 13 of Electric Rate Schedule 13.01, as OTP 14 is currently no longer involved in non-asset-based trading. I discuss this change to non- 15 asset-based trading later in my testimony.
16 VII. CORPORATE COST ALLOCATIONS
17 Q. WHAT WILL YOU DISCUSS IN THIS SECTION OF YOUR DIRECT TESTIMONY? 18 A. In this section of my Direct Testimony, I will explain how corporate costs that are 19 incurred by Otter Tail Corporation in connection with the services provided by Otter Tail 20 Corporation for the operation of OTP are handled in the 2017 Test Year. 21 22 Q. PLEASE DESCRIBE THE OWNERSHIP STRUCTURE OF OTP AND OTTER TAIL 23 CORPORATION. 24 A. OTP is a wholly owned subsidiary of Otter Tail Corporation. In 2008, Otter Tail 25 Corporation filed a petition with the Commission seeking approval to form a new holding 26 company through restructuring, with the purpose of establishing OTP as a separate, 27 subsidiary corporation. The Commission approved the request on October 30, 2008, and 28 as of July 1, 2009, OTP became a separate legal entity, instead of an operating division, 29 which OTP had been prior to the formation of Otter Tail Corporation. 24 Docket No. EL18-___ Tommerdahl Direct
1 Q. WHAT SERVICES DOES OTTER TAIL CORPORATION PROVIDE TO OTP? 2 A. Otter Tail Corporation provides the following services to OTP: financial reporting, tax 3 planning and reporting, treasury, financial planning, corporate communications, internal 4 audit, benefits plans, safety and risk management, shareholder services and investor 5 relations, aviation and executive management services. 6 7 Q. ARE THESE SERVICES GOVERNED BY ANY AGREEMENTS? 8 A. Yes. At the time of the restructuring, OTP entered into three agreements with Otter Tail 9 Corporation: (i) an Administrative Services Agreement that describes how services are 10 provided from Otter Tail Corporation to OTP and how costs for such services are 11 assigned and allocated to OTP; (ii) a Tax Sharing Agreement that describes how tax 12 obligations and benefits are to be allocated; and (iii) a Cash Management Agreement that 13 describes how cash management services can be provided by Otter Tail Corporation to 14 OTP. Currently, no cash management services are being provided by Otter Tail 15 Corporation to OTP. 16 17 Q. HOW ARE OTP TAXES COMPUTED UNDER THE TAX SHARING AGREEMENT? 18 A. OTP computes its taxes on a standalone basis, exclusive of Otter Tail Corporation. The 19 determination of taxes on a standalone basis means that OTP incurs the same taxes as if it 20 was a separate corporation and does not incur any taxes for Otter Tail Corporation or for 21 the business of other subsidiaries of Otter Tail Corporation. All tax decisions for OTP are 22 based on strategies beneficial to its ratepayers. All tax calculations included in the 2017 23 Test Year are based only on OTP financial performance. The tax calculations included in 24 this Test Year are detailed in Volume 4A, Supporting Information, Schedule C-7. 25 26 Q. HOW DO THE SERVICES PERFORMED BY OTTER TAIL CORPORATION 27 COMPARE WITH THE SERVICES PERFORMED BY SUBSIDIARY SERVICE 28 COMPANIES OF SOME OTHER UTILITY HOLDING COMPANIES? 29 A. The services performed for OTP by Otter Tail Corporation are less extensive than service 30 performed by other holding company service company subsidiaries, such as Xcel 31 Energy’s corporate services unit. Otter Tail Corporation does not process OTP’s invoices 25 Docket No. EL18-___ Tommerdahl Direct
1 or customers’ bills; it does not perform billing for OTP; it does not manage OTP’s human 2 resources (HR), information technologies (IT), or procurement. Rather, OTP directly 3 provides its own accounting, bill and invoice processing, IT, HR, supply chain, 4 engineering, rates and regulation, payroll, marketing and sales, fuel and energy 5 procurement, and customer service. 6 7 Q. HOW DID YOU ARRIVE AT THE APPROPRIATE LEVEL OF OTTER TAIL 8 CORPORATION EXPENSES TO INCLUDE IN THE TEST YEAR? 9 A. Under the Administrative Services Agreement, the costs of corporate functions are 10 allocated using the allocation methodology and specific allocation factors described in 11 the Corporate Cost Allocation Manual (CAM), included as Exhibit__(SDT-1), Schedule 12 4. Allocation factors were applied to actual 2017 corporate expenses, adjusted for certain 13 corporate expenses which have either been capped or disallowed in prior Commission 14 Orders. Both redline, and clean copies of the 2017 CAM are provided in Schedule 4. 15 16 Q. HOW WERE THE COST ALLOCATION METHODOLOGIES DEVELOPED? 17 A. The following goals were considered when the corporate cost allocation methodology 18 was developed: 19 1) The result should fully allocate costs; 20 2) Costs are directly assigned where possible; 21 3) If direct assignment is not possible, an indirect allocation will be made if there is a 22 cost causative link to another cost category for which direct assignment is used; 23 4) When neither direct nor indirect cost causation can be found, a representative 24 general allocator is used; 25 5) The result is equitable for customers and shareholders; 26 6) The methodology is easy to administer – no additional studies or data gathering is 27 needed; and 28 7) The allocators have components that are based on verifiable public information, to 29 the extent possible. 30
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1 Q. PLEASE EXPLAIN THE ALLOCATION PROCESS IN MORE DETAIL. 2 A. Otter Tail Corporation costs can be charged to OTP or to Otter Tail Corporation’s non- 3 utility operations. The allocation process uses three steps. First, all labor and other costs 4 that are appropriate for direct assignment to OTP or non-utility operations are identified 5 and directly assigned. Members of the Corporate Group use timesheets to directly assign 6 labor. Invoices and other costs are directly assigned as appropriate. In the 2017 Test 7 Year, approximately 42 percent of all Otter Tail Corporation costs were allocated to OTP 8 or non-utility operations using direct assignment. 9 Second, indirect allocators are used for certain functions. Indirect allocators are 10 used where an indirect-cost causative linkage to another cost category or group of cost 11 categories exists. About 17 percent of corporate costs were allocated to OTP or non- 12 utility operations using indirect allocators. 13 The remaining 41 percent of corporate costs are not appropriate for either direct 14 assignment or indirect allocation. These costs are allocated to OTP or non-utility 15 operations using the general allocator that is composed of revenues, assets and labor 16 dollars, equally weighted. 17 18 Q. HOW MUCH OF THE TOTAL OTTER TAIL CORPORATION COST IS 19 ALLOCATED TO OTP IN THE 2017 TEST YEAR? 20 A. Table 4, below, shows the allocation of Otter Tail Corporation costs for the 2017 Test 21 Year. 22 23 Table 4 24 Otter Tail Corporation Cost Allocation Otter Tail Corporation 2017 Costs SD Share Allocated to OTP $10,294,4614 51.5% $859,7515 Allocated to Non-Utility $9,694,759 47.9% Total Corporate Costs $19,989,220 100.0% 25
4 OTP Allocation before any adjustments $10,294,461 Net billings and accruals to Otter Tail Corporation ($17,769) Total Net Corporate Costs to OTP (Before Incentive Cap) $10,276,692 (Volume 1 Statement H-4 Line 37) 5 Volume 1 Statement H-4, Line 47 SD Share.
27 Docket No. EL18-___ Tommerdahl Direct
1 Q. DOES THE ALLOCATION IN TABLE 4 REFLECT THE COMMISSION’S 2 DECISIONS ON INCENTIVE COMPENSATION? 3 A. Yes. The Otter Tail Corporation costs allocated to OTP in the 2017 Test Year reflect the 4 Commission’s decisions regarding bonuses and incentive compensation in determining 5 the South Dakota share. Specifically, Otter Tail Corporation executives’ bonuses and 6 incentive compensation are capped at 25 percent of base salary, as reflected in Volume 7 4A, Section B, workpaper B-16. Statement H-4 shows the adjustment made to calculate 8 the South Dakota amount. 9 10 Q. ARE THE COSTS REFLECTED IN TABLE 4 REASONABLE AND APPROPRIATE 11 FOR INCLUSION IN THE 2017 TEST YEAR? 12 A. Yes. All costs have been allocated in a manner consistent with prior cases. The Otter Tail 13 Corporation costs reflected in Table 4 are reasonable and appropriate for inclusion in the 14 2017 Test Year. Approximately 70 percent of operating and net income for Otter Tail 15 Corporation is derived from OTP,6 yet as Table 4 above reflects, only 51.5 percent of 16 Corporate costs are allocated to OTP.
17 VIII. ECONOMIC DEVELOPMENT RATES
18 Q. WHAT TOPICS WILL YOU DISCUSS IN THIS SECTION OF YOUR DIRECT 19 TESTIMONY? 20 A. In this section of my Direct Testimony, I will discuss two new economic development 21 rates being proposed by OTP. 22 23 Q. DOES OTP’S CURRENT RATE STRUCTURE SUPPORT ECONOMIC 24 DEVELOPMENT? 25 A. Yes. As Mr. Gerhardson points out in his Direct Testimony, OTP has the 4th lowest 26 blended rate for all customers in the United States, and the second lowest of any investor-
6 Derived from page 5 of Otter Tail Corporation’s 2017 Annual Report to Shareholders. Operating Income for OTP was $90 million; Otter Tail Corporation operating income was $126 million. Similarly, OTP accounted for $49 million of Otter Tail Corporation’s total net income of $72 million.
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1 owned utility in South Dakota. High energy use entities that may be considering locating 2 or expanding in South Dakota will give careful consideration to low rates in evaluating 3 their options, including locating in areas in South Dakota that OTP serves. OTP’s high 4 customer satisfaction and reliable service are additional supporting factors that helps OTP 5 attract new load. 6 7 Q. IS OTP PROPOSING ANY NEW RATES IN THIS CASE THAT WOULD SUPPORT 8 FURTHER ECONOMIC DEVELOPMENT IN SOUTH DAKOTA? 9 A. Yes. In this case, OTP is proposing two new rate offerings: a new Economic 10 Development Rider-Large General Service (EDR) rate; and a new Super Large General 11 Service (Super LGS) rate offering. In order to expand OTP’s “tool-box” of rate offerings 12 to help attract new business, OTP has designed these two rate offerings to enhance OTP’s 13 potential to attract business to South Dakota. Both rate mechanisms would allow OTP to 14 compute customer-specific rate quotes in the form of a discount, using a formulaic 15 approach that insures that a proposed discount will still yield benefits to all other 16 customers should the customer take service from OTP. OTP witness Mr. David Prazak 17 provides the details associated with these new rate offerings in his Direct Testimony, 18 along with proposed rate schedules for each. 19 20 Q. PLEASE BRIEFLY DESCRIBE THE ECONOMIC DEVELOPMENT-LARGE 21 GENERAL SERVICE RIDER RATE. 22 A. The mechanism calculates a proposed rate discount off OTP’s Large General Service 23 Rider rate. OTP could potentially offer a discount for up to a five-year period with this 24 rider. OTP has developed a model to price the potential discount while ensuring that the 25 potential customer will at least pay the annual incremental (marginal) costs to serve them. 26 This helps ensure net benefits are realized by all other customers through the addition of 27 the load. 28 29 Q. PLEASE BRIEFLY DESCRIBE THE SUPER LGS RATE. 30 A. The Super LGS rate is intended for very large, high load factor customers such as a data 31 processing facility or a large agricultural processing facility that might have a connected 29 Docket No. EL18-___ Tommerdahl Direct
1 load of 25 MWs or more and run at a very high capacity level (at least 80 percent load 2 factor). Following a similar approach as the EDR rate, a rate would be computed based 3 on a customer’s specific operating profile and would be set at a level which still provides 4 benefits to other customers. Unlike the EDR rate, the Super LGS rate could continue 5 beyond a five-year period. 6 7 Q. PLEASE EXPLAIN FURTHER HOW THESE RATES BENEFIT OTHER 8 CUSTOMERS. 9 A. The computation of these rates takes into account the marginal costs OTP would incur to 10 serve these customers. Because these marginal costs are covered under both rate 11 offerings, the incremental margins over and above the marginal costs helps cover OTP’s 12 fixed costs of service. Other customers realize the benefit of these new customers in at 13 least two ways. First, in the near term (for example when a rider filing such as the TCRR 14 is made), the costs being recovered within the rider would be spread over a greater 15 number of KWs or kWhs, reducing the effective rate that all customers would pay. 16 Second, adding new load that contributes incremental margin to OTP could help delay 17 the need for future rate cases. When rates are reset in the next rate case, again, the costs 18 would be spread over a greater number of KWs and kWhs keeping rates lower than 19 without these customers. 20 21 Q. ARE THERE OTHER BENEFITS IF THESE RATES ARE SUCCESSFUL IN 22 ATTRACTING NEW BUSINESS TO OTP AREAS IN SOUTH DAKOTA? 23 A. Yes. For example, attracting a large agricultural processing facility or data processing 24 facility would certainly bring with it new employment opportunities; potentially attract 25 more people to the communities OTP serves; provide further economic activity to 26 existing or potentially new additional businesses providing products and services to the 27 area; increase the state’s tax base that would drive increased property, sales, and income 28 taxes for the state. 29
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1 Q. HOW WOULD YOU SUMMARIZE OTP’S NEED FOR ECONOMIC 2 DEVELOPMENT RATES? 3 A. The sustainability of the small towns OTP serves across rural South Dakota is critical for 4 OTP’s long-term success and its commitment to provide low cost, safe, reliable energy to 5 all customers. A declining customer base results in OTP costs being spread over fewer 6 customers, resulting in an increasing effect on future rates. OTP, its customers, and the 7 state of South Dakota all benefit when economic development efforts facilitate the 8 attraction and development of new business and the expansion or retention of existing 9 business. OTP’s design of the economic development rates discussed above assure 10 benefits are realized to all parties involved.
11 IX. LEAD LAG STUDY
12 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? 13 A. In this section of my Direct Testimony, I will explain OTP’s Lead Lag Study. 14 15 Q. WHAT IS THE PURPOSE OF THE LEAD LAG STUDY? 16 A. The Lead Lag Study is a widely used and accepted method for developing the Cash 17 Working Capital (CWC) component of rate base in connection with the determination of 18 revenue requirements. This study analyzes the lapse of time between the average day on 19 which a utility incurs expenses to serve its customers and the average day on which cash 20 is received from customers in payment of that service. Lead days refer to the days 21 between incurring an expense and paying for it. Lag days refer to the days between 22 rendering a service and receiving payment for that service. 23 24 Q. HAS OTP’S LEAD LAG STUDY BEEN UPDATED SINCE THE LAST RATE CASE? 25 A. Yes. OTP updated its Lead Lag Study in 2015 using data from 2014. 26
31 Docket No. EL18-___ Tommerdahl Direct
1 Q. IS THE CASH WORKING CAPITAL DETERMINATION METHODOLOGY 2 CONSISTENT WITH OTP’S LAST RATE CASE? 3 A. Yes. The study and procedures used to calculate the working capital requirement are 4 consistent with the approach and methodology filed by OTP and approved by the 5 Commission in OTP’s last South Dakota rate case. OTP reviewed the procedures used in 6 the Lead Lag Study filed in that case and concluded no significant changes in policies or 7 procedures had occurred and conducted the current study using those same procedures. 8 The updated study is included in Volume 4B. The results of the updated Lead Lag Study 9 are included in the CWC calculations provided in Volume 4A, Section C, Schedule B-4, 10 pages 1-3. OTP witness Mr. Akerman discusses the overall calculation of CWC and its 11 inclusion in rate base in his Direct Testimony. 12 13 Q. HOW DO THE RESULTS OF THE UPDATED LEAD LAG STUDY COMPARE TO 14 THE RESULTS OF THE STUDY USED IN OTP’S LAST RATE CASE? 15 A. The lag period has increased to 43.4 days from 38.9 days shown in OTP’s last rate case in 16 2010, with the majority of the increase coming from collections increasing from 20.07 17 days in 2010 to 24.7 days in this latest study. As reflected in Volume 4A, Section C, 18 Schedule B-4, page 1 of 3, OTP does not receive cash from computer-maintained billings 19 until 43.4 days after service has been rendered. As shown on Lines 58 through 60 of 20 Volume 4A, Section C, Schedule B-4, page 1 of 3, the 43.4 days is comprised of a 15.2- 21 day metering period lag, a 3.5-day bill processing lag, and a 24.7-day collection period 22 lag, which was based on the total annual billings to customers divided by the average 23 daily utility receivable balances.
24 X. MERRICOURT WIND PROJECT STEP INCREASE RATE 25 PROPOSAL
26 Q. WHAT IS THE PURPOSE OF THIS PORTION OF YOUR TESTIMONY? 27 A. In this section of my Direct Testimony, I will discuss OTP’s proposal to include the 150 28 MW Merricourt Wind (Merricourt) project into base rates through the use of a step 29 increase rate upon completion of the project. Mr. Akerman addresses the financial 30 adjustments associated with the Merricourt project to determine the increased 32 Docket No. EL18-___ Tommerdahl Direct
1 jurisdictional revenue requirement. Mr. Haugen addresses the associated class revenue 2 requirement impacts and Mr. Prazak addresses the updates to rates attributable to the 3 Merricourt project. 4 5 Q. WHEN IS THE MERRICOURT PROJECT SCHEDULED TO BE PLACED IN 6 SERVICE? 7 A. The Merricourt project is scheduled to be completed and in-service at the end of 2019. 8 9 Q. WHY IS OTP PROPOSING A STEP INCREASE RATE FOR THE MERRICOURT 10 PROJECT? 11 A. The Merricourt project is the largest single wind energy project in which OTP has 12 invested in to date, with an estimated total cost of approximately $271 million (OTP 13 Total), $25 million (OTP SD). Because of the size of the project and the absence of any 14 other recovery mechanism such as a rider to recover the cost project, OTP believes 15 developing a step increase rate in this case would be the most cost-effective and efficient 16 approach to request recovery. 17 18 Q. ARE THERE ANY OTHER RATE IMPACTS BEYOND COST RECOVERY THAT 19 WILL OCCUR DUE TO THE MERRICOURT PROJECT? 20 A. Yes. When Merricourt is placed in service, the energy output from Merricourt will be 21 generated at zero fuel cost and will displace other costs such as purchased power costs, 22 which flow through the Energy Adjustment Rider. An updated Statement P that reflects 23 the estimated reduction in purchased power costs is included in Volume 4A, Section 24 5. The estimated average base fuel rate, calculated on a system basis, drops from 25 $0.026153 to $0.022996 per kWh. 26 27 Q. IF A STEP INCREASE RATE WAS NOT APPROVED IN THIS CASE, HOW 28 WOULD OTP SEEK FUTURE RECOVERY OF THIS PROJECT? 29 A. OTP would need to file another rate case to request recovery of the Merricourt project 30 costs. OTP’s current assumption that final rates in this case will become effective 31 January 1, 2019, and the Merricourt project is scheduled to be completed and in-service 33 Docket No. EL18-___ Tommerdahl Direct
1 just one year later. As Mr. Gerhardson discusses, OTP believes it would be in the best 2 interest of all stakeholders to avoid the significant cost of another rate case, not long after 3 the conclusion of this case, to incorporate this project into base rates. 4 5 Q. ARE THERE OTHER MAJOR OTP INVESTMENTS THAT ARE GOING TO DRIVE 6 FUTURE RATE CASES? 7 A. Yes. OTP is also developing its Astoria Station (Astoria) project, an approximately $165 8 million simple cycle gas generating station to be located near Astoria, South Dakota, 9 which is currently scheduled to be completed in 2021. OTP anticipates that it will need to 10 file a rate case in the 2021 timeframe to request recovery of the Astoria project, as well as 11 incorporate then-completed transmission projects, such as the Big Stone South to 12 Ellendale project, currently under construction, into base rates. The step increase proposal 13 in this case will allow OTP to bridge the gap between this case and the potential 2021 14 case. 15 16 Q. WHEN DOES OTP PROPOSE THE STEP INCREASE RATES TO INCLUDE THE 17 MERRICOURT PROJECT WOULD TAKE EFFECT? 18 A. OTP proposes that the step increase rates would become effective January 1, 2020.
19 XI. MISCELLANEOUS ITEMS
20 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? 21 A. In this section of my Direct Testimony, I will discuss: 1) non-asset-based trading; 2) rate 22 case expenses; and 3) holding company formation expenses.
23 A. Non-Asset Based Trading 24 Q. DOES THE 2017 TEST YEAR INCLUDE ANY COSTS RELATED TO NON-ASSET 25 BASED TRADING ACTIVITIES? 26 A. No. OTP ceased all non-asset-based trading activities as of December 31, 2014. Thus, 27 there are no new non-asset-based trading costs or revenues in the 2017 Test Year. 28
34 Docket No. EL18-___ Tommerdahl Direct
1 Q. WHY DID OTP MAKE THE BUSINESS DECISION TO CEASE NON-ASSET 2 BASED TRADING ACTIVITIES? 3 A. OTP conducted a financial analysis on its non-asset-based trading business in the winter 4 and spring of 2014. The analysis showed historically declining margins and reduced 5 profits in the future. Based on this analysis, OTP ultimately concluded that it should exit 6 the non-asset-based trading business. 7 8 Q. DOES OTP HAVE ANY REMAINING NON-ASSET BASED TRADING 9 POSITIONS? 10 A. No. The last new non-asset-based trades occurred on December 31, 2014. A small 11 number of non-asset-based positions carried into the 2015 calendar year, but they were 12 completely liquidated by June 1, 2015. As of that date, OTP had no non-asset-based 13 trading positions.
14 B. Rate Case Expenses 15 Q. WHAT IS THE ESTIMATED RATE CASE EXPENSE FOR THIS CASE? 16 A. We estimate the rate case expenses associated with this case to be $550,000 (OTP SD). 17 This expense includes administrative costs, the charges to be expected from the 18 Commission and outside consulting and legal fees. 19 20 Q. HOW DID YOU DEVELOP THIS ESTIMATE? 21 A. Administrative costs and Commission charges are estimated based on fees assessed in 22 other South Dakota rate cases. Consulting fees and outside legal fees estimates were 23 based on information from service providers. The details are reflected in work paper TY-
24 09 in Volume 4A, Workpapers. 25 26 Q. WHAT IS THE AMOUNT OF RATE CASE EXPENSE INCLUDED IN THE 2017 27 TEST YEAR? 28 A. The 2017 Test Year annual rate case expense is $183,333 (OTP SD). 29
35 Docket No. EL18-___ Tommerdahl Direct
1 Q. WHAT AMORTIZATION PERIOD DID YOU USE? 2 A. We used a three-year amortization period. Because the rate case expense is a one-time 3 expense, it would be inappropriate to treat those expenses as recurring expenses. 4 Therefore, it is appropriate to amortize those expenses over the period of time expected 5 before OTP’s next rate case. Based on what we know today, we believe OTP will likely 6 file its next rate case in three years.
7 C. Holding Company Formation Expenses 8 Q. DOES THE 2017 TEST YEAR INCLUDE ANY ADJUSTMENT FOR 9 AMORTIZATION OF HOLDING COMPANY COSTS? 10 A. No. In Docket, EL08-025, the Commission approved OTP’s request to form a holding 11 company. OTP began amortizing holding company costs following its rate case in Docket 12 EL08-030 and updated the amortization to three years following OTP’s last general in 13 Docket EL-10-011. There are no holding company formation expenses included in the 14 2017 Test Year.
15 XII. CONCLUSION
16 Q. WHAT ARE YOUR CONCLUSIONS? 17 A. My Direct Testimony supports the conclusions that: 18 • OTP has effectively managed its major capital projects which has resulted in very 19 substantial customer savings; 20 • The 2017 Test Year South Dakota retail revenues are reasonable and appropriate 21 for ratemaking; 22 • OTP’s jurisdictional and class allocations are reasonable for establishing rates in 23 this case; 24 • OTP’s proposed revisions to its Fuel Clause Rider are reasonable; 25 • OTP’s corporate cost allocations meet Commission requirements and are 26 appropriate; 27 • OTP’s proposal rates for economic development are reasonable and appropriate;
36 Docket No. EL18-___ Tommerdahl Direct
1 • OTP’s proposal for step increase rates for the Merricourt project will help delay 2 the need for another rate case. 3 4 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 5 A. Yes, it does.
37 Docket No. EL18-___ Tommerdahl Direct Docket No. EL18-___ Exhibit__(SDT-1), Schedule 1 Page 1 of 1
Mr. Stuart D. Tommerdahl, CPA (Inactive) Manager, Regulatory Administration Otter Tail Power Company 215 South Cascade Street Fergus Falls, Minnesota 56537 218-739-8279
CURRENT RESPONSIBILITIES: (March 2012 to Present)
Provide leadership in revenue requirements analysis, pricing and rate design, tariff administration, load research, allocation methodologies for cost of service studies, long range revenue forecasting, wholesale energy accounting, cost of energy, and unbilled revenue.
PREVIOUS POSITIONS:
Otter Tail Power Company 2012 - Present Manager, Regulatory Administration 2004 – 2012 Manager, Risk Management 2003 - 2004 Business Analyst
Otter Tail Energy Services 1998-2003 Director, Financial Services 1997-1998 Manager, Financial Planning/Analysis
Otter Tail Power Company 1997 – 1997 Senior Regulatory/Economic Analyst 1993 – 1997 Regulatory/Economic Analyst
Great Plains Software, Fargo, ND 1986 - 1993 Budget & Financial Reporting Manager 1984 – 1986 Inventory Accountant / Purchasing
Twin Valley-Ulen Telephone Co., Twin Valley, MN 1983 – 1984 Accountant
EDUCATIONAL / CERTIFICATIONS Moorhead State University-Moorhead, B.S. Accounting, Minor in Economics. Certified Public Accountant (Inactive)
Docket No. EL18-___ Exhibit___(SDT-1) Schedule 2 Page 1 of 2
Otter Tail Power Company Estimated Project Savings Impacts on Revenue Requirements (Customer Savings) and Earnings (Reduced Shareholder Return) of the Big Stone Air Quality Control System (A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (O) Customer Impact Shareholder Impact
OTP SD Total Annual Avoided Return Revenue OTP SD OTP SD Requirement Total Annual Available for OTP SD (Column F x 9.42% Avoided Revenue Return (Column 30 Years OTP SD NPV OTP SD Rate OTP SD Total Rate Base Revenue Requirements OTP SD OTP SD NPV F x 5.47% Avoided Avoided Original cost Final Cost Project Savings OTP Total share OTP SD share Base Balance Annual Avoided Requirement (Column G + Avoided Revenue Avoided Revenue Equity Return Available for Available for Line No. Yr Total Project Total Project (1) @ 53.9% % (30 Year Life) Depreciation Factor) (4) Column H) Requirement Requirement (5) Factor) (6) Return Return (4) Notes 1 2015 $491,000,000 $365,513,806 $125,486,194 $67,637,059 9.341629% $6,318,403 $210,613 $595,194 $805,807 $345,568 2 2016 $6,107,790 $210,613 $687,737 $898,351 $334,049 3 2017 Test Year $5,897,176 $210,613 $664,022 $874,635 $322,530 Test Year 4 2018 $5,686,563 $210,613 $640,307 $850,920 $311,012 5 2019 $5,475,949 $210,613 $616,592 $827,205 $299,493 6 2020 $5,265,336 $210,613 $592,877 $803,490 $287,974 7 2021 $5,054,723 $210,613 $569,162 $779,775 $276,455 8 2022 $4,844,109 $210,613 $545,447 $756,060 $264,936 9 2023 $4,633,496 $210,613 $521,732 $732,345 $253,417 10 2024 $4,422,882 $210,613 $498,017 $708,630 $8,037,219 $5,473,181 $241,898 $2,937,331 $2,023,050 Initial 10 Years 11 2025 $4,212,269 $210,613 $474,301 $684,915 $230,379 12 2026 $4,001,655 $210,613 $450,586 $661,200 $218,860 13 2027 $3,791,042 $210,613 $426,871 $637,485 $207,341 14 2028 $3,580,428 $210,613 $403,156 $613,770 $195,822 15 2029 $3,369,815 $210,613 $379,441 $590,055 $184,303 16 2030 $3,159,202 $210,613 $355,726 $566,340 $172,784 17 2031 $2,948,588 $210,613 $332,011 $542,624 $161,265 18 2032 $2,737,975 $210,613 $308,296 $518,909 $149,746 19 2033 $2,527,361 $210,613 $284,581 $495,194 $138,227 20 2034 $2,316,748 $210,613 $260,866 $471,479 $126,708 21 2035 $2,106,134 $210,613 $237,151 $447,764 $115,189 22 2036 $1,895,521 $210,613 $213,436 $424,049 $103,671 23 2037 $1,684,908 $210,613 $189,721 $400,334 $92,152 24 2038 $1,474,294 $210,613 $166,006 $376,619 $80,633 25 2039 $1,263,681 $210,613 $142,290 $352,904 $69,114 26 2040 $1,053,067 $210,613 $118,575 $329,189 $57,595 27 2041 $842,454 $210,613 $94,860 $305,474 $46,076 28 2042 $631,840 $210,613 $71,145 $281,759 $34,557 29 2043 $421,227 $210,613 $47,430 $258,044 $23,038 30 2044 $210,613 $210,613 $23,715 $234,329 $11,519 31 Total $6,318,403 $10,911,250 $17,229,654 $7,843,928 $5,356,309 $2,706,167 Life of Project 32 33 Steam production plant jurisdicational allocator Base / Peak % 34 E1 9.364273% (2) 81.510000% (3) 35 D1 9.241806% (2) 18.490000% (3) 36 SD Jurisdictional Share % 9.341629% 37 38 (1) Phinney Direct Table 1, Page 10 39 (2) JCOSS Page 15-1 40 (3) Workpaper C-1 (Base/Peak Split) 41 (4) Rate Base Revenue Requirement Factor 9.42% Pg 2 of 2 42 (5) Net Present Value (NPV) computed using ROR Discount Rate 7.96% Pg 2 of 2 43 (6) Rate Base Equity Return Factor reflects the after-tax earnings 5.47% Pg 2 of 2 Docket No. EL18-___ Exhibit___(SDT-1) Schedule 2 Page 2 of 2
OTTER TAIL POWER COMPANY Revenue Requirement Factor Calculation To be used when estimating revenue requirement on rate baseamount changes Amounts rounded to 4 decimal places =
SD 1 Effective Tax Rate 21.0000% 2 SDPUC Special Hearing Fund Assessment 0.0015 3 Capital Structure Rate Ratio Cost Weighted Debt Cost 4LT Debt 5.3000% 46.90% 2.4900% 5.30% 5ST Debt 0.0000% 0.00% 0.0000% 6 Common Equity 10.3000% 53.10% 5.4692% 7 Required Rate of Return 7.9592% 8 Equity Return Tax RR (5.41% Equity X Tax Effect 1.61) ‐ 5.41% Equity) 1.4608% 9 Rate Base Revenue Requirement Factor 9.4200% 10 11 12 Tax Effect 1 / (1 ‐ Tax Rate) 1.267724 Gross Up of Equity % 6.93% 13 Equity % 5.47% 14 Difference 1.46% 15 16 PROOF ‐ EXAMPLE Total Debt Equity 17 Rate Base $ 10,000 $ 4,690 $ 5,310 18 19 Revenue Requirement 9.42% $ 942 20 Interest on Debt (Weighted Debt Cost X Debt Amt) $ 249 21 Taxable Income $ 693 22 Taxes 21.1500% $ 146.66 23 Return on Rate Base $ 795 7.95% ROR 24 Available for Return (Equity 5.41% X RB) $ 547 10.30% ROE 25 26 Equity Return 27 Revenue $ 942 28 Interest Expense $ 249 29 Taxes $ 147 30 Available for Return $ 547 31 Equity $ 5,310 32 ROE (Line 30/Line 31) 10.30% 33 34 Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 1 of 22
OTTER TAIL POWER COMPANY
Cost Allocations Procedures Manual
Revised October 2017 Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 2 of 22
INTRODUCTION The general methodology used in this procedure manual is one of functionalization and classification. Functionalization is the process by which costs are arranged according to the major utility function they serve, such as production, transmission, etc. Classification is the arrangement of costs within a function by the service characteristic to which they most closely apply or relate, to facilitate their allocation based on these service characteristics. The major functional areas used in this procedure manual are production, transmission, distribution, customer accounting and collecting, and customer service and information. The reason for using functions other than the three major ones (production, transmission and distribution) is to provide a better base for eventual allocation of cost and to provide the flexibility necessary to handle certain cost items. The principal service characteristics used in the classification process are: demand, energy, number of customers and number of meters. Sub-characteristics within each of these principal characteristics which allow a more precise division of cost, such as type of demand or energy, voltage level, or type of customer or meter were also used. These sub-characteristics provide added detail for a more accurate allocation of cost. The service characteristics or sub-characteristics provide the basis for determining allocation factors when allocation is necessary. Unless otherwise noted, all allocation factors described herein are used for both jurisdictional and class allocations. The philosophy used to arrive at the service characteristics was to determine what characteristic or characteristics best describe or approximate the decisions made or factors considered when an expense is incurred or a plant investment is made. The amount of dollars to be allocated and the cost of determining or obtaining values for a service characteristic were also factors considered when determining the service characteristics to use. There are 1516 service characteristics used in this study. They consist of four demand characteristics, twothree energy or kilowatt-hour characteristics, and nine meter or customer characteristics. These service characteristics, which are used to develop allocation factors are: 1. GENERATION DEMAND FACTOR (D1) - this factor is determined based on contribution to Otter Tail's average annual six-hour system peak kW demand. Any loads for which Otter Tail is responsible for providing generation are included in this factor. The hours ending 9:00, 10:00, and 11:00 a.m., and 6:00, 7:00, and 8:00 p.m. were averaged to arrive at the Generation Demand Factor. 2. TRANSMISSION DEMAND FACTOR (D2) - this factor is determined based on contribution to Otter Tail's Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 3 of 22
average annual six-hour transmission peak kW demand. Any loads for which Otter Tail is responsible for providing transmission service are included in this factor. The hours used are the same as those for the Generation Demand Factor. 3. DISTRIBUTION PRIMARY DEMAND FACTOR (D3) - this factor is determined based on contributions to Otter Tail's average annual six-hour primary distribution peak kW demand minus the 0.83 kW/customer already included in the minimum system portion of the primary customer component. (See Appendix A-1.) Any loads for which Otter Tail is responsible for providing primary distribution service are included in this factor. The hours used are the same as those for the Generation Demand Factor. 4. DISTRIBUTION SECONDARY DEMAND FACTOR (D4) - this factor is determined based on non-coincident kW demands at the secondary service level minus the 3.0 kW/customer already included in the minimum system portion of the secondary customer component. (See Appendix A-1.) Only loads served at voltages less than 2400 volts are included in this factor. 5. ENERGY FACTOR (E1) - this factor is based on kilowatt-hour (kWh) sales adjusted for line losses to the
14 generation level excluding interruptible, irrigation, and ⁄24 ths of water heating and deferred sales. 6. ENERGY FACTOR (E2) - this factor is based on total kWh sales adjusted for line losses to the generation level. It is only used for jurisdictional allocations. 7. ENERGY FACTOR (E8760) - this factor is based on hourly energy usage, to which are applied hourly marginal costs to develop an hourly cost relationship. It is only used to allocate jurisdictional amounts to the customer classes. 7.8. TOTAL RETAIL CUSTOMERS FACTOR (C1) - this factor is based on the total active retail customers served in each jurisdiction. 8.9. TOTAL DISTRIBUTION SERVICE LOCATIONS FACTOR (C2) – a distribution service location is any point on the distribution system at which service is or can be provided including inactive and seasonal locations. 9.10. TOTAL SECONDARY DISTRIBUTION SERVICE LOCATIONS FACTOR (C3) - this factor includes only those distribution service locations served or which can be served at secondary voltage (below 2400 volts). 10.11. STREETLIGHT FACTOR (C4) - this factor is based on the weighted installed cost of the streetlights in each jurisdiction. Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 4 of 22
11.12. AREA LIGHT FACTOR (C5) - this factor is based on the weighted installed cost of area lights in each jurisdiction. 12.13. METER FACTOR (C6) - this factor is based on the weighted installed cost of meters in service. 13.14. METER READING FACTOR (C7) - this factor is based on total weighted meter reading time. 14.15. TOTAL SYSTEM SERVICE LOCATIONS FACTOR (C8) - this factor is similar to the Total Distribution Service Locations Factor, except all locations on the system at which service can be or is provided are included. 15.16. LOAD MANAGEMENT FACTOR (C9) - this factor is based on the total number of locations that have radio load management receivers in each jurisdiction.
The methodology for applying the various procedures and allocators to system cost values to develop jurisdictional and class or group cost values is explained in detail on the following pages.
RATE BASE COMPONENTS PRODUCTION PLANT IN SERVICE The plant in service within this function was classified into preliminary demand and energy categories as follows: 1. DEMAND COST - this category includes all production plant except wind generation (accounts 310-347 346), except that related to the Big Stone Plant unit train. 2. BASE LOAD ENERGY COST - Big Stone unit train only.
The demand category was then reclassified into Base (Energy-Related) and Peak Demand categories based on the following formulas: Total Current Cost = (Existing Peaking Capacity [kW])(Current Peaking Unit Cost [$/kW]) + (Existing Steam & Hydro Capacity [kW])(Current Base Load Unit Cost [$/kW]) (Total Existing Plant Capacity)(Current Peaking Unit Cost) Peaking Demand Factor = Total Current Cost Base (Energy-Related) Demand Factor = 1 − Peaking Demand Factor $ of Peak Demand = (Demand Cost) × (Peaking Demand Factor) $ of Base (Energy-Related) Demand = (Demand Cost) × (Base Demand Factor)
Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 5 of 22
This determination of Base and Peak Demand amounts is based on the premise that all plants are or can be used to supply system peak demands. However, base load plants (steam and hydro) are also used to supply the bulk of the energy used on the system. Therefore, the base load plants have a dual function of supplying both energy and demand. The above classification of production plant into base and peak categories recognizes this fact and assigns a portion of the base load plants to each of these functions. The underlying assumption is that the cost to supply a peak kW of demand capacity to the system is the cost of a kW of capacity from a peaking plant. New unit costs in current year dollars were used to determine the peaking and base factors to provide an allocation method that separates costs based on present circumstances not on past circumstances. The use of current costs also eliminates any potential problems associated with the timing of plant additions, changes in load factors or changes in generation mix criteria which could lead to large short-term allocation factor variations. The dollars in each category were then allocated based on the following: BASE DEMAND - Energy Factor (E1) PEAK DEMAND - Generation Demand Factor (D1) BASE ENERGY - Energy Factor (E1) PEAK ENERGY - Generation Demand Factor (D1)
3. Wind generation is a non-dispatchable production resource with operating characteristics different from other base load or peaking generation. The typical capacity factor for wind generation is still being determined. While by the Midwest Midcontinent Independent Transmission System Operator (MISO) continues to evaluate the as they accredit capacity factorbased on each generation site’s production. While a majority of a wind, its current turbine’s output is energy, a portion of the investment is also needed to meet the system’s peak demand. The most recent MISO accreditations are used to create a weighted average for each wind capacity credit is 8 percent. Therefore, windfarm that results in a base/peak split. Wind generation investment is allocated as 92 percent BASE ENERGY (E2) and 8 percent PEAK DEMAND (D1). based on the following factors: BASE ENERGY - Energy Factor (E2) PEAK DEMAND – Generation Demand Factor (D1)
TRANSMISSION PLANT IN SERVICE Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 6 of 22
Allocated using the Transmission Demand Factor (D2).
DISTRIBUTION PLANT IN SERVICE The plant in service within this function was classified into the following categories: 1. Primary Demand (2400 volts and above) 2. Secondary Demand (below 2400 volts) 3. Primary Customer (2400 volts and above) 4. Secondary Customer (below 2400 volts) 5. Streetlighting 6. Area Lighting 7. Meters 8. Load Management based on the following account-by-account methodology: ACCOUNT 360 (LAND) - classified primary demand related (substation land). ACCOUNT 360.1 (LAND RIGHTS) - classified primary demand related. ACCOUNT 361 (STRUCTURES AND IMPROVEMENTS) - classified primary demand related. ACCOUNT 362 (STATION EQUIPMENT) - classified primary demand related. ACCOUNTS 364-369.1 - classified based on minimum size system (see Appendix A-1). ACCOUNT 370 (METERS) - direct assignment to meters characteristic. ACCOUNT 370.1 (LOAD MANAGEMENT SWITCHES) - direct assignment to load management characteristic. ACCOUNT 371 (INSTALLATION ON CUSTOMER'S PREMISES) - classified secondary customer related. ACCOUNT 371.1 (RENTAL EQUIPMENT) - classified primary customer related. ACCOUNT 371.2 (ALL OTHER PRIVATE LIGHTING) - direct assignment to area lighting. ACCOUNT 373 (STREETLIGHTING AND SIGNAL SYSTEMS) - direct assignment to streetlighting.
The categories were then allocated based on the following: PRIMARY DEMAND - Distribution Primary Demand Factor (D3) SECONDARY DEMAND - Distribution Secondary Demand Factor (D4) PRIMARY CUSTOMER - Total Distribution Service Locations Factor (C2) Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 7 of 22
SECONDARY CUSTOMER - Total Secondary Distribution Service Locations Factor (C3) STREETLIGHTING - Streetlight Factor (C4) AREA LIGHTING - Area Light Factor (C5) METERS - Metering Factor (C6) LOAD MANAGEMENT - Load Management Factor (C9)
GENERAL PLANT IN SERVICE General Plant in Service, except Account 397.3 (Radio Load Control Equipment), was functionalized into the following categories based on the labor ratios developed from data in FERC Form No. 1, Page 354, or similar data for a forecast year. 1. Production 2. Transmission 3. Distribution 4. Customer Accounting 5. Customer Service and Information The amounts in the production, transmission and distribution categories were then allocated using the gross plant in service ratios from the related plant in service functions. Customer Accounting and Customer Service and Information were allocated based on the expense ratios from the related expense functions. Account 397.3 directly assigned to Load Management category and allocated on the Load Management Factor (C9).
INTANGIBLE PLANT IN SERVICE Intangible Plant in Service was allocated using the gross general plant in service ratios.
ACCUMULATED PROVISION FOR DEPRECIATION PRODUCTION - Classification and allocation procedure is the same as that used for Production Plant in Service. TRANSMISSION - Allocated based on gross plant in service ratios developed from the Transmission Plant in Service function. DISTRIBUTION - Allocated based on gross plant in service ratios developed from the Distribution Plant in Service function. Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 8 of 22
GENERAL - Allocated based on gross plant in service ratios developed from the General Plant in Service function. INTANGIBLE - allocated using the gross plant in service ratios developed from the Intangible Plant in Service function.
NET CAPITALIZED ITEMS - BIG STONE PLANT Directly assigned to each jurisdiction. Allocated to classes or groups based on the gross Production Plant in Service ratio.
PLANT HELD FOR FUTURE USE PRODUCTION - allocated using gross plant in service ratios developed from the Production Plant in Service function. TRANSMISSION - allocated using the Transmission Demand Factor (D2). DISTRIBUTION - allocated using gross plant in service ratios developed from the Distribution Plant in Service function. GENERAL - allocated using gross plant in service ratios developed from the General Plant in Service function. INTANGIBLE - allocated using gross plant in service ratios developed from the Intangible Plant in Service function.
CONSTRUCTION WORK IN PROGRESS (CWIP) CWIP was separated into three parts or types: Major Projects, Short-Term, and Long-Term. The Major Projects section includes capital expenditures on which a current return is requested without an offset for Allowance For Funds Used During Construction (AFUDC). The Short-Term section are those projects with less than $10,000 cost or expected to be completed in less than 30 days. AFUDC is not accrued on short-term projects. The Long-Term section includes all other projects and AFUDC is accrued on this portion. The CWIP of each type was functionalized as production, transmission, distribution, general, or intangible plant. The allocations are then based on the gross plant in service ratios for each individual function.
WORKING CAPITAL Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 9 of 22
MATERIALS AND SUPPLIES: Materials and Supplies are separated into production, transmission, and distribution functions. The production portion includes materials and supplies at Big Stone and Coyote Plants as well as production repair parts. The remaining materials and supplies are split between transmission and distribution functions based on data from Page 227 of the latest FERC Form No. 1. The functional amounts are allocated on their respective gross plant in service ratios.
FUEL STOCKS: COAL STOCKS - allocated using Energy Factor (E1). FUEL OIL STOCKS - allocated using Generation Demand Factor (D1). PREPAYMENTS - allocated based on total net plant in service ratios. CUSTOMER ADVANCES - allocated based on total net plant in service ratios. CASH WORKING CAPITAL - calculated separately for each jurisdiction. Allocated to customer class on total operating expenses for each jurisdiction (OX).
ACCUMULATED DEFERRED INCOME TAXES Allocated using the total "net" plant in service ratios.
UNAMORTIZED BALANCE - SPIRITWOOD PLANT Directly assigned to each jurisdiction. Allocated to customer class using the gross Production Plant in Service ratio.
UNAMORTIZED RATE CASE EXPENSE Directly assigned to jurisdiction. Allocated to customer class on each jurisdiction's retail revenues (R10).
Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 10 of 22
OPERATING REVENUES RETAIL SALES Directly assigned to each jurisdiction and class as billed.
WHOLESALE SALES MUNICIPALITIES (SUPPLEMENTAL POWER ACCOUNTS 400.1-81, 400.2-81, and 400.3-81) - directly assigned to FERC jurisdiction and group as billed.
NONASSOCIATED UTILITIES, COOPERATIVES AND OTHER PUBLIC AUTHORITIES The revenues from asset-based sales are classified as base demand, peak demand, base energy, and peak energy as follows: 1. All revenues from these sales, except those considered Participation or Peaking Power, are classified as Base Energy. 2. Demand charges for Peaking sales are classified as Peak Demand. 3. Demand charges for Participation Power sales are classified as follows: $ of Peak Demand = Market price ($/MW/Mo.) × capacity of the sale (MW) $ of Base Demand = Total Demand charges − $ of Peak Demand. 4. Energy charges for Participation Power sales are classified Base Energy. 5. Energy charges for Peaking Power sales are classified Peak Energy.
The jurisdictional allocations were then made as follows: BASE DEMAND - Energy Factor (E1) PEAK DEMAND - Generation Demand Factor (D1) BASE ENERGY - Energy Factor (E2) PEAK ENERGY - Generation Demand Factor (D1)
OTHER ELECTRIC REVENUE ACCOUNT 450 (FORFEITED DISCOUNTS) - directly assigned to jurisdictions as collected. Allocated to classes (if required) based on Total Customers Factor (C1). Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 11 of 22
ACCOUNT 451 (CONNECTION FEES) - directly assigned to jurisdictions as collected. Allocated to classes (if required) based on Total Customers Factor (C1). ACCOUNT 456.5 (WHEELING) - directly assigned to FERC groups as collected. ACCOUNT 456.7 (RESIDENTIAL CONSERVATION SERVICE) - directly assigned to jurisdictions. Allocated to classes based on E8760 (Energy Factor). ALL OTHER ACCOUNTS - allocated using total net plant in service ratios.
EXPENSE COMPONENTS PRODUCTION EXPENSES The expenses within this function, except those in Account 555, were classified into PRELIMINARY demand and energy categories as follows: 1. STEAM AND HYDRO (SH) DEMAND - this category includes all expenses in Accounts 500, 502-511, 535- 543, and 556. 2. INTERNAL COMBUSTION (IC) DEMAND - this category includes all expenses in Accounts 546-554, except Account 547. 3. BASE ENERGY - includes Accounts 501, 512, 513, 514, 544, and 545. 4. PEAK ENERGY - includes Account 547.
The two demand categories (SH and IC) were then reclassified into BASE and PEAK Demand categories using the same methodology and formulas applied to those categories in Production Plant in Service. The expenses in Account 555 (Purchased Power) are classified into base and peak demand and energy based on the following: A. All expenses, except those for purchases labeled Participation or Peaking Power, were classified as Base Energy. B. Demand charges for Peaking Power were classified as Peak Demand. C. Demand Charges for Participation Power (including co-generators and shared customers) were classified as follows: $ of Peak Demand = MAPP Schedule H (peaking) rate ($/MW/Mo.) × capacity of the purchase (MW) × number of months purchased. Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 12 of 22
$ of Base Demand = Total Demand Charges − $ of Peak Demand. D. Energy charges for Participation Power were classified as Base Energy. E. Energy charges for Peaking Power were classified as Peak Energy. The jurisdictional allocations were then made as follows: BASE DEMAND - Energy Factor (E1) PEAK DEMAND - Generation Demand Factor (D1) BASE ENERGY - Energy Factor (E2) PEAK ENERGY - Generation Demand Factor (D1)
TRANSMISSION EXPENSES Allocated using the Transmission Demand Factor (D2).
DISTRIBUTION EXPENSES The expenses within this function were classified into the following categories: 1. Primary Demand (2400 volts and above) 2. Secondary Demand (below 2400 volts) 3. Primary Customer (2400 volts and above) 4. Secondary Customer (below 2400 volts) 5. Streetlights 6. Area Lights 7. Meters 8. Load Management Based on the following account-by-account methodology:
OPERATION ACCOUNT 580 (SUPERVISION AND ENGINEERING) - classified based on classification of Accounts 582-588. ACCOUNT 582 (STATION EXPENSE) - classified based on classification of related plant in service Account 362. ACCOUNT 583 (OVERHEAD LINE EXPENSE) - classified based on the classification of related plant in service Accounts 364, 365, 368 and 369. Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 13 of 22
ACCOUNT 584 (UNDERGROUND LINE EXPENSE) - classified based on the classification of related plant in service Accounts 366, 367, and 369.1. ACCOUNT 585 (STREETLIGHTING EXPENSE) - classified directly as streetlighting. ACCOUNTACCOUNTS 586.1-586.5 & 586.9 (METER EXPENSES) - classified directly as meters. ACCOUNTS 586.6-586.7 (METER EXPENSES) - classified directly as load management. ACCOUNT 587 (CUSTOMER INSTALLATION EXPENSE) - classified secondary customer. ACCOUNT 588 (MISCELLANEOUS EXPENSE) - classified based on classification of Accounts 582-587. ACCOUNT 589 (RENTS) - classified based on classification of related plant in service Account 364.
MAINTENANCE ACCOUNT 590 (SUPERVISION AND ENGINEERING) - classified based on classification of Accounts 592-596. ACCOUNT 592 (STATION EQUIPMENT) - classified based on classification of related plant in service Account 362. ACCOUNT 593 (OVERHEAD LINES) - classified based on classification of related plant in service Accounts 364, 365, and 369. ACCOUNT 594 (UNDERGROUND LINES) - classified based on classification of related plant in service Accounts 366, 367, and 369.1. ACCOUNT 595 (LINE TRANSFORMERS) - classified based on classification of related plant in service Account 368. ACCOUNT 596 (STREETLIGHTING) - classified directly to streetlighting. ACCOUNTACCOUNTS 597.1-597.2 (METERS) - classified directly to meters. ACCOUNT 597.3 (METERS) - classified directly to load management. ACCOUNT 598 (MISCELLANEOUS DISTRIBUTION PLANT) - classified based on classification of Accounts 592-597.
Each category was then allocated based on the following: PRIMARY DEMAND - Distribution Primary Demand Factor (D3). SECONDARY DEMAND - Distribution Secondary Demand Factor (D4). PRIMARY CUSTOMER - Total Distribution Service Locations Factor (C2). SECONDARY CUSTOMER - Total Secondary Distribution Service Locations Factor (C3). Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 14 of 22
STREETLIGHTING - Streetlight Factor (C4). AREA LIGHTING - Area Light Factor (C5). METERS - Meter Factor (C6). LOAD MANAGEMENT - Load Management Factor (C9).
CUSTOMER ACCOUNTING AND COLLECTING EXPENSES Expenses in this function were classified into two categories: 1. Meter Reading 2. Other Expenses as specified by the following: ACCOUNT 901 (SUPERVISION) - classified based on classification of Accounts 902-905. ACCOUNT 902 (METER READING EXPENSE) - classified meter reading. ACCOUNT 903 (CUSTOMER RECORDS AND COLLECTIONS) - classified other expense. ACCOUNT 904 (UNCOLLECTIBLE ACCOUNTS) - classified other expense. ACCOUNT 905 (MISCELLANEOUS CUSTOMER ACCOUNTING EXPENSES) - classified other expense.
The METER READING category was allocated using the Meter Reading Factor (C7) and the OTHER EXPENSES category using the Total System Service Locations Factor (C8).
CUSTOMER SERVICE AND INFORMATION EXPENSES Conservation related programs and promotional rebates are directly assigned to jurisdiction and then allocated to class based on E2E8760 (Energy Factor). All other Customer Service and Information Expenses are allocated based on Total Customer Factor (C1).
SALES EXPENSES Economic Development is directly assigned to jurisdiction and then allocated to class based on Total Customer Factor (C1). Account 913, Advertising, is assigned below the line. All other Sales Expenses are allocated based on Total Customer Factor (C1).
ADMINISTRATIVE AND GENERAL EXPENSES Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 15 of 22
ACCOUNTS 920 (SALARIES), 921 (SUPPLIES, ETC.), AND 926 (PENSIONS AND BENEFITS) - these accounts functionalized as: Production, Transmission, Distribution, Customer Accounting or Customer Service, based on FERC labor ratios (FERC Form No. 1, Page 354, or comparable data for a forecast year). Functional categories were then allocated using the expense ratios from the related expense functions, except that in the Production category the energy-related expenses and buy/sell transactions were not included in the ratios. (Energy-related expenses and buy/sell transactions are excluded because they are mainly purchased fuel which requires a minimum of company labor.) ACCOUNT 923 (OUTSIDE SERVICES) - allocated based on total net plant in service ratios. ACCOUNTS 924 (PROPERTY INSURANCE) and 925 (INJURIES & DAMAGES) - were allocated based on the total net plant in service ratios. ACCOUNTS 928 (REGULATORY COMMISSION EXPENSES) - directly assigned to each jurisdiction. Allocated to classes or groups based on total electric revenues from each class or group. ACCOUNT 930.1 (GENERAL ADVERTISING) -– The majority of this account is assigned below the line. Any remaining amount is allocated based on Total Customers Factor (C1). ACCOUNTS 930.2 (MISCELLANEOUS), 931 (RENTS), and 935.1-935.5 & 935.9 (MAINTENANCE) - allocated based on the gross general plant in service ratios. ACCOUNT 935.6 (MAINTENANCE) - directly assigned to load management and allocated on (C9).
DEPRECIATION EXPENSES PRODUCTION - Classification and allocation procedure is the same as that used for Production Plant in Service. TRANSMISSION - Allocated based on gross plant in service ratios developed from the Transmission Plant in Service function. DISTRIBUTION - Allocated based on gross plant in service ratios developed from the Distribution Plant in Service function. GENERAL - Allocated based on gross plant in service ratios developed from the General Plant in Service function. INTANGIBLE - Allocated using the gross plant in service ratios developed from the Intangible Plant in Service function.
Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 16 of 22
BIG STONE PLANT CAPITALIZED ITEMS EXPENSES Directly assigned to each jurisdiction. Allocated to classes or groups based on the gross Production Plant in Service ratio.
OTHER EXPENSE - SPIRITWOOD AMORTIZATION Directly assigned to each jurisdiction. Allocated to customer class using the gross Production Plant in Service ratio.
GENERAL TAXES Allocated using total net plant in service ratios.
DEFERRED INCOME TAXES Allocated using total net plant in service ratios.
INVESTMENT TAX CREDIT Allocated using total gross plant in service ratios.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) Allocated based on long-term construction work in progress ratios.
INCOME TAXES Income taxes are calculated for each jurisdiction separately. Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 17 of 22
APPENDIX A-1
DETERMINATION OF THE DEMAND & CUSTOMER COMPONENTS OF THE DISTRIBUTION SYSTEM The customer component of the distribution system, that portion which varies with the number of customers, was determined by applying the minimum size system method. This method involves determining the minimum size unit currently being installed and using the average installed book cost of that unit to determine the customer component. However, our accounting system is such that, except for Account 368 (transformers), the only average installed book cost available is for all the units in an account regardless of size. To circumvent this problem, the following procedures were used: 1. The Electric Distribution (ED) Department specified what the minimum size unit for each account is and then provided information as to the type and quantity of material included in this unit and the amount of labor necessary to install it. 2. For each account that a customer component is required, the average age of the account was determined by using results of the recently completed depreciation study. This age is then subtracted from the study year to determine in what year the average unit was installed. 3. The average installed cost of the minimum size unit for the year indicated above was then determined. This was done by developing material, labor, transportation, and payroll costs for the year this unit was installed and applying them to the information supplied in No. 1, above.
The following pages describe how the dollars in each account were assigned to the various categories of cost using the data developed above and other figures from the various accounts.
Symbol Legend: PSL = Poles for Streetlights DSL = Dollars allocated to Streetlighting DAL = Dollars allocated to Area Lighting DPCC = Dollars allocated to Primary Customer Category DPDC = Dollars allocated to Primary Demand Category DSCC = Dollars allocated to Secondary Customer Category DSDC = Dollars allocated to Secondary Demand Category UPD = Units of Primary Distribution Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 18 of 22
USD = Units of Secondary Distribution
Account 364 (Poles): (All poles considered primary) A. Average age of a pole. B. Minimum size pole. C. Installed cost of the minimum size pole of the age in "A." D. Number of streetlights on separate poles. (Based on sample survey by Engineering Services.) E. Number of area lights on separate poles. (Based on sample survey by Engineering Services.) F. Number of poles in Account 364. G. Total dollars in Account 364.
Dollar Allocations for Account 364 To Streetlighting = D × C∗ = DSL To Area Lighting = E × C∗ = DAL Customer Component = (F − D − E) × C = DPCC Demand Component = DSL − DAL − DPCC = DPDC *Cost of a minimum size pole was used because most streetlights are mounted on minimum size poles and those that are on larger poles are mounted on poles that do not have the usual framing (crossarms, etc.).
Account 365 (Overhead Conductor and Devices): I. Primary A. Average age of primary conductor. B. Minimum size primary unit. C. Average installed cost of a minimum size primary unit of the age in "A." D. Average number of poles in a minimum size unit of primary conductor. (Estimated by ED Department.) E. Total dollars in Account 365 considered primary (see note). F. Total number of poles used for primary distribution. (Number of poles in Account 364 - Number of poles allocated to streetlighting and area lighting.)
Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 19 of 22
F Number of units of primary distribution = UPD = D1
Dollar Allocations for Account 365 Primary Customer Component = C × UPD = DPCC Demand Component = E − DPCC = DPDC
NOTE: All bare copper, aluminum, ACSR and iron wire are primary. 30% of WP copper, 80% of WP aluminum and 50% of the steel wire are primary. (Estimated by ED Department - exact percentages very difficult to determine.) All miscellaneous conductor and other equipment are primary.
II. Secondary A. Average age of secondary conductor. B. Minimum size secondary unit. C. Average installed cost of a minimum size unit of the age in "A." D. Number of units of secondary conductor (see note). E. Total dollars in Account 365 considered secondary. (All conductor not primary - see primary section.) F. Dollar value of duplex conductor in Account 365. (Duplex assumed to be used entirely for street and area lights.) G. Percent of total number of lighting units (street and area lights) that are streetlights.
Dollar Allocations for Account 365 Secondary To Streetlighting = F × G = DSL To Area Lighting = F − DSL = DAL Customer Component = C × D = DSCC Demand Component = E − F − DSCC = DSDC NOTE: Estimated by ED Department based on 250' of secondary for each five urban residential cottages, and urban commercial customers, 3,360' of secondary per unit.
Account 366 (Underground Conduit): Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 20 of 22
The percentages developed from the allocation of Account 367 will be applied to this account.
Account 367 (Underground Conductor and Devices): I. Primary A. Average age of primary unit. B. Minimum size primary unit. C. Average installed cost of a minimum size primary unit of the age in "A." D. Number of feet of conductor in the minimum size primary unit. E. Total dollars in Account 367 considered primary. (All conductor rated 5 kV and above, and all nonconductor items are considered primary.) F. Total number of feet of primary conductor in Account 367.
F Number of units of primary distribution = UPD = D2
Dollar Allocations for Account 367 Primary Customer Component = C × UPD = DPCC Demand Component = E − DPCC = DPDC
II. Secondary A. Average age of secondary unit. B. Minimum size of secondary unit. C. Average installed cost of a minimum size secondary unit of the age in "A." D. Number of feet of conductor in the minimum size secondary unit. E. Total dollars in Account 367 considered secondary. (All conductor rated 600 volts or less is secondary.) F. Total number of feet of secondary conductor in Account 367 (see note). G. Dollar value of duplex conductor in Account 367 (duplex conductor is assumed to be used entirely for street and area lights). H. Percent of total number of lighting units (street and area lights) that is streetlights.
Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 21 of 22
F Number of units of secondary distribution = USD = D3
Dollar Allocations for Account 367 Secondary To Streetlighting = G × H = DSL To Area Lighting = G − DSL = DAL Customer Component = C × USD = DSCC Demand Component = E − G − DSCC = DSDC
NOTE: Includes all quadruplex and triplex cable and 1/3 of 600 volt single wire. (Duplex is for lighting only.)
Account 368 (Transformers): (All transformers classified secondary) A. Average installed cost of minimum size 2400 V. overhead unit.* B. Average installed cost of minimum size 7200 V. overhead unit.* C. Average installed cost of minimum size 14400 V. overhead unit.* D. Average installed cost of minimum size 2400 V. underground unit.* E. Average installed cost of minimum size 7200 V. underground unit.* F. Number of 2400 V. overhead units in the account. G. Number of 7200 V. overhead units in the account. H. Number of 14400 V. overhead units in the account. *Overhead unit cost includes cost of appropriate cutout and arrester. I. Number of 2400 V. underground units in the account. J. Number of 7200 V. underground units in the account. K. Total dollar value of Account 368.
Dollar Allocations for Account 368 Customer Component = (A × F) + (B × G) + (C × H) + (D × I) + (E × J) = DSCC Demand Component = K − DSCC = DSDC
Account 369 (Overhead Services): (All services classified secondary) A. Average age of a service. Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 22 of 22
B. Minimum size of a service. C. Average installed cost of a minimum size service of the age in "A." D. Total number of 3 and 4 services. E. Dollar value of two-wire services (two-wire services are considered all customer component). F. Total dollar value of Account 369.
Dollar Allocations for Account 369 Customer Component = (C × D) + E = DSCC Demand Component = F − DSCC = DSDC
Account 369.1 (Underground Services): (All services classified secondary) A. Average age of an underground service. B. Minimum size of an underground service. C. Average installed cost of a minimum size three-wire service of the age in "A." D. Total number of services in Account 369.1. E. Total dollar value of Account 369.1.
Dollar Allocations for Account 369.1 Customer Component = (C × D) = DSCC Demand Component = E − DSCC = DSDC Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Page 1 of 22
OTTER TAIL POWER COMPANY
Cost Allocations Procedures Manual
Revised October 2017 Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 2 of 22 Cost Allocation Procedure Manual
INTRODUCTION The general methodology used in this procedure manual is one of functionalization and classification. Functionalization is the process by which costs are arranged according to the major utility function they serve, such as production, transmission, etc. Classification is the arrangement of costs within a function by the service characteristic to which they most closely apply or relate, to facilitate their allocation based on these service characteristics. The major functional areas used in this procedure manual are production, transmission, distribution, customer accounting and collecting, and customer service and information. The reason for using functions other than the three major ones (production, transmission and distribution) is to provide a better base for eventual allocation of cost and to provide the flexibility necessary to handle certain cost items. The principal service characteristics used in the classification process are: demand, energy, number of customers and number of meters. Sub-characteristics within each of these principal characteristics which allow a more precise division of cost, such as type of demand or energy, voltage level, or type of customer or meter were also used. These sub-characteristics provide added detail for a more accurate allocation of cost. The service characteristics or sub-characteristics provide the basis for determining allocation factors when allocation is necessary. Unless otherwise noted, all allocation factors described herein are used for both jurisdictional and class allocations. The philosophy used to arrive at the service characteristics was to determine what characteristic or characteristics best describe or approximate the decisions made or factors considered when an expense is incurred or a plant investment is made. The amount of dollars to be allocated and the cost of determining or obtaining values for a service characteristic were also factors considered when determining the service characteristics to use. There are 16 service characteristics used in this study. They consist of four demand characteristics, three energy or kilowatt-hour characteristics, and nine meter or customer characteristics. These service characteristics, which are used to develop allocation factors are: 1. GENERATION DEMAND FACTOR (D1) - this factor is determined based on contribution to Otter Tail's average annual six-hour system peak kW demand. Any loads for which Otter Tail is responsible for providing generation are included in this factor. The hours ending 9:00, 10:00, and 11:00 a.m., and 6:00, 7:00, and 8:00 p.m. were averaged to arrive at the Generation Demand Factor. 2. TRANSMISSION DEMAND FACTOR (D2) - this factor is determined based on contribution to Otter Tail's average annual six-hour transmission peak kW demand. Any loads for which Otter Tail is responsible for providing transmission service are included in this factor. The hours used are the same as those for Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 3 of 22 Cost Allocation Procedure Manual
the Generation Demand Factor. 3. DISTRIBUTION PRIMARY DEMAND FACTOR (D3) - this factor is determined based on contributions to Otter Tail's average annual six-hour primary distribution peak kW demand minus the 0.83 kW/customer already included in the minimum system portion of the primary customer component. (See Appendix A-1.) Any loads for which Otter Tail is responsible for providing primary distribution service are included in this factor. The hours used are the same as those for the Generation Demand Factor. 4. DISTRIBUTION SECONDARY DEMAND FACTOR (D4) - this factor is determined based on non-coincident kW demands at the secondary service level minus the 3.0 kW/customer already included in the minimum system portion of the secondary customer component. (See Appendix A-1.) Only loads served at voltages less than 2400 volts are included in this factor. 5. ENERGY FACTOR (E1) - this factor is based on kilowatt-hour (kWh) sales adjusted for line losses to the
14 generation level excluding interruptible, irrigation, and ⁄24 ths of water heating and deferred sales. 6. ENERGY FACTOR (E2) - this factor is based on total kWh sales adjusted for line losses to the generation level. It is only used for jurisdictional allocations. 7. ENERGY FACTOR (E8760) - this factor is based on hourly energy usage, to which are applied hourly marginal costs to develop an hourly cost relationship. It is only used to allocate jurisdictional amounts to the customer classes. 8. TOTAL RETAIL CUSTOMERS FACTOR (C1) - this factor is based on the total active retail customers served in each jurisdiction. 9. TOTAL DISTRIBUTION SERVICE LOCATIONS FACTOR (C2) – a distribution service location is any point on the distribution system at which service is or can be provided including inactive and seasonal locations. 10. TOTAL SECONDARY DISTRIBUTION SERVICE LOCATIONS FACTOR (C3) - this factor includes only those distribution service locations served or which can be served at secondary voltage (below 2400 volts). 11. STREETLIGHT FACTOR (C4) - this factor is based on the weighted installed cost of the streetlights in each jurisdiction. 12. AREA LIGHT FACTOR (C5) - this factor is based on the weighted installed cost of area lights in each jurisdiction. 13. METER FACTOR (C6) - this factor is based on the weighted installed cost of meters in service. 14. METER READING FACTOR (C7) - this factor is based on total weighted meter reading time. Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 4 of 22 Cost Allocation Procedure Manual
15. TOTAL SYSTEM SERVICE LOCATIONS FACTOR (C8) - this factor is similar to the Total Distribution Service Locations Factor, except all locations on the system at which service can be or is provided are included. 16. LOAD MANAGEMENT FACTOR (C9) - this factor is based on the total number of locations that have radio load management receivers in each jurisdiction.
The methodology for applying the various procedures and allocators to system cost values to develop jurisdictional and class or group cost values is explained in detail on the following pages.
RATE BASE COMPONENTS PRODUCTION PLANT IN SERVICE The plant in service within this function was classified into preliminary demand and energy categories as follows: 1. DEMAND COST - this category includes all production plant (accounts 310- 346), except that related to the Big Stone Plant unit train. 2. BASE LOAD ENERGY COST - Big Stone unit train only.
The demand category was then reclassified into Base (Energy-Related) and Peak Demand categories based on the following formulas: Total Current Cost = (Existing Peaking Capacity [kW])(Current Peaking Unit Cost [$/kW]) + (Existing Steam & Hydro Capacity [kW])(Current Base Load Unit Cost [$/kW]) (Total Existing Plant Capacity)(Current Peaking Unit Cost) Peaking Demand Factor = Total Current Cost Base (Energy-Related) Demand Factor = 1 − Peaking Demand Factor $ of Peak Demand = (Demand Cost) × (Peaking Demand Factor) $ of Base (Energy-Related) Demand = (Demand Cost) × (Base Demand Factor)
This determination of Base and Peak Demand amounts is based on the premise that all plants are or can be used to supply system peak demands. However, base load plants (steam and hydro) are also used to supply the bulk of the energy used on the system. Therefore, the base load plants have a dual function of supplying both energy and demand. The above classification of production plant into base and peak categories recognizes this fact and assigns a portion of the base load plants to each of these functions. The underlying assumption is that the Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 5 of 22 Cost Allocation Procedure Manual
cost to supply a peak kW of demand capacity to the system is the cost of a kW of capacity from a peaking plant. New unit costs in current year dollars were used to determine the peaking and base factors to provide an allocation method that separates costs based on present circumstances not on past circumstances. The use of current costs also eliminates any potential problems associated with the timing of plant additions, changes in load factors or changes in generation mix criteria which could lead to large short-term allocation factor variations. The dollars in each category were then allocated based on the following: BASE DEMAND - Energy Factor (E1) PEAK DEMAND - Generation Demand Factor (D1) BASE ENERGY - Energy Factor (E1) PEAK ENERGY - Generation Demand Factor (D1)
3. Wind generation is a non-dispatchable production resource with operating characteristics different from other base load or peaking generation. The capacity factor for wind generation is determined by the Midcontinent Independent System Operator (MISO) as they accredit capacity based on each generation site’s production. While a majority of a wind turbine’s output is energy, a portion of the investment is also needed to meet the system’s peak demand. The most recent MISO accreditations are used to create a weighted average for each wind farm that results in a base/peak split. Wind generation investment is allocated based on the following factors: BASE ENERGY - Energy Factor (E2) PEAK DEMAND – Generation Demand Factor (D1)
TRANSMISSION PLANT IN SERVICE Allocated using the Transmission Demand Factor (D2).
DISTRIBUTION PLANT IN SERVICE The plant in service within this function was classified into the following categories: 1. Primary Demand (2400 volts and above) 2. Secondary Demand (below 2400 volts) 3. Primary Customer (2400 volts and above) 4. Secondary Customer (below 2400 volts) 5. Streetlighting Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 6 of 22 Cost Allocation Procedure Manual
6. Area Lighting 7. Meters 8. Load Management based on the following account-by-account methodology: ACCOUNT 360 (LAND) - classified primary demand related (substation land). ACCOUNT 360.1 (LAND RIGHTS) - classified primary demand related. ACCOUNT 361 (STRUCTURES AND IMPROVEMENTS) - classified primary demand related. ACCOUNT 362 (STATION EQUIPMENT) - classified primary demand related. ACCOUNTS 364-369.1 - classified based on minimum size system (see Appendix A-1). ACCOUNT 370 (METERS) - direct assignment to meters characteristic. ACCOUNT 370.1 (LOAD MANAGEMENT SWITCHES) - direct assignment to load management characteristic. ACCOUNT 371 (INSTALLATION ON CUSTOMER'S PREMISES) - classified secondary customer related. ACCOUNT 371.1 (RENTAL EQUIPMENT) - classified primary customer related. ACCOUNT 371.2 (ALL OTHER PRIVATE LIGHTING) - direct assignment to area lighting. ACCOUNT 373 (STREETLIGHTING AND SIGNAL SYSTEMS) - direct assignment to streetlighting.
The categories were then allocated based on the following: PRIMARY DEMAND - Distribution Primary Demand Factor (D3) SECONDARY DEMAND - Distribution Secondary Demand Factor (D4) PRIMARY CUSTOMER - Total Distribution Service Locations Factor (C2) SECONDARY CUSTOMER - Total Secondary Distribution Service Locations Factor (C3) STREETLIGHTING - Streetlight Factor (C4) AREA LIGHTING - Area Light Factor (C5) METERS - Metering Factor (C6) LOAD MANAGEMENT - Load Management Factor (C9)
GENERAL PLANT IN SERVICE General Plant in Service, except Account 397.3 (Radio Load Control Equipment), was functionalized into the following categories based on the labor ratios developed from data in FERC Form No. 1, Page 354, or similar data for a forecast year. 1. Production Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 7 of 22 Cost Allocation Procedure Manual
2. Transmission 3. Distribution 4. Customer Accounting 5. Customer Service and Information The amounts in the production, transmission and distribution categories were then allocated using the gross plant in service ratios from the related plant in service functions. Customer Accounting and Customer Service and Information were allocated based on the expense ratios from the related expense functions. Account 397.3 directly assigned to Load Management category and allocated on the Load Management Factor (C9).
INTANGIBLE PLANT IN SERVICE Intangible Plant in Service was allocated using the gross general plant in service ratios.
ACCUMULATED PROVISION FOR DEPRECIATION PRODUCTION - Classification and allocation procedure is the same as that used for Production Plant in Service. TRANSMISSION - Allocated based on gross plant in service ratios developed from the Transmission Plant in Service function. DISTRIBUTION - Allocated based on gross plant in service ratios developed from the Distribution Plant in Service function. GENERAL - Allocated based on gross plant in service ratios developed from the General Plant in Service function. INTANGIBLE - allocated using the gross plant in service ratios developed from the Intangible Plant in Service function.
NET CAPITALIZED ITEMS - BIG STONE PLANT Directly assigned to each jurisdiction. Allocated to classes or groups based on the gross Production Plant in Service ratio.
PLANT HELD FOR FUTURE USE PRODUCTION - allocated using gross plant in service ratios developed from the Production Plant in Service function. TRANSMISSION - allocated using the Transmission Demand Factor (D2). Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 8 of 22 Cost Allocation Procedure Manual
DISTRIBUTION - allocated using gross plant in service ratios developed from the Distribution Plant in Service function. GENERAL - allocated using gross plant in service ratios developed from the General Plant in Service function. INTANGIBLE - allocated using gross plant in service ratios developed from the Intangible Plant in Service function.
CONSTRUCTION WORK IN PROGRESS (CWIP) CWIP was separated into three parts or types: Major Projects, Short-Term, and Long-Term. The Major Projects section includes capital expenditures on which a current return is requested without an offset for Allowance For Funds Used During Construction (AFUDC). The Short-Term section are those projects with less than $10,000 cost or expected to be completed in less than 30 days. AFUDC is not accrued on short-term projects. The Long-Term section includes all other projects and AFUDC is accrued on this portion. The CWIP of each type was functionalized as production, transmission, distribution, general, or intangible plant. The allocations are then based on the gross plant in service ratios for each individual function.
WORKING CAPITAL MATERIALS AND SUPPLIES: Materials and Supplies are separated into production, transmission, and distribution functions. The production portion includes materials and supplies at Big Stone and Coyote Plants as well as production repair parts. The remaining materials and supplies are split between transmission and distribution functions based on data from Page 227 of the latest FERC Form No. 1. The functional amounts are allocated on their respective gross plant in service ratios.
FUEL STOCKS: COAL STOCKS - allocated using Energy Factor (E1). FUEL OIL STOCKS - allocated using Generation Demand Factor (D1). PREPAYMENTS - allocated based on total net plant in service ratios. CUSTOMER ADVANCES - allocated based on total net plant in service ratios. CASH WORKING CAPITAL - calculated separately for each jurisdiction. Allocated to customer class on total operating expenses for each jurisdiction (OX).
Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 9 of 22 Cost Allocation Procedure Manual
ACCUMULATED DEFERRED INCOME TAXES Allocated using the total "net" plant in service ratios.
UNAMORTIZED BALANCE - SPIRITWOOD PLANT Directly assigned to each jurisdiction. Allocated to customer class using the gross Production Plant in Service ratio.
UNAMORTIZED RATE CASE EXPENSE Directly assigned to jurisdiction. Allocated to customer class on each jurisdiction's retail revenues (R10).
Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 10 of 22 Cost Allocation Procedure Manual
OPERATING REVENUES RETAIL SALES Directly assigned to each jurisdiction and class as billed.
WHOLESALE SALES MUNICIPALITIES (SUPPLEMENTAL POWER ACCOUNTS 400.1-81, 400.2-81, and 400.3-81) - directly assigned to FERC jurisdiction and group as billed.
NONASSOCIATED UTILITIES, COOPERATIVES AND OTHER PUBLIC AUTHORITIES The revenues from asset-based sales are classified as base demand, peak demand, base energy, and peak energy as follows: 1. All revenues from these sales, except those considered Participation or Peaking Power, are classified as Base Energy. 2. Demand charges for Peaking sales are classified as Peak Demand. 3. Demand charges for Participation Power sales are classified as follows: $ of Peak Demand = Market price ($/MW/Mo.) × capacity of the sale (MW) $ of Base Demand = Total Demand charges − $ of Peak Demand. 4. Energy charges for Participation Power sales are classified Base Energy. 5. Energy charges for Peaking Power sales are classified Peak Energy.
The jurisdictional allocations were then made as follows: BASE DEMAND - Energy Factor (E1) PEAK DEMAND - Generation Demand Factor (D1) BASE ENERGY - Energy Factor (E2) PEAK ENERGY - Generation Demand Factor (D1)
OTHER ELECTRIC REVENUE ACCOUNT 450 (FORFEITED DISCOUNTS) - directly assigned to jurisdictions as collected. Allocated to classes (if required) based on Total Customers Factor (C1). ACCOUNT 451 (CONNECTION FEES) - directly assigned to jurisdictions as collected. Allocated to classes (if required) based on Total Customers Factor (C1). Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 11 of 22 Cost Allocation Procedure Manual
ACCOUNT 456.5 (WHEELING) - directly assigned to FERC groups as collected. ACCOUNT 456.7 (RESIDENTIAL CONSERVATION SERVICE) - directly assigned to jurisdictions. Allocated to classes based on E8760 (Energy Factor). ALL OTHER ACCOUNTS - allocated using total net plant in service ratios.
EXPENSE COMPONENTS PRODUCTION EXPENSES The expenses within this function, except those in Account 555, were classified into PRELIMINARY demand and energy categories as follows: 1. STEAM AND HYDRO (SH) DEMAND - this category includes all expenses in Accounts 500, 502-511, 535- 543, and 556. 2. INTERNAL COMBUSTION (IC) DEMAND - this category includes all expenses in Accounts 546-554, except Account 547. 3. BASE ENERGY - includes Accounts 501, 512, 513, 514, 544, and 545. 4. PEAK ENERGY - includes Account 547.
The two demand categories (SH and IC) were then reclassified into BASE and PEAK Demand categories using the same methodology and formulas applied to those categories in Production Plant in Service. The expenses in Account 555 (Purchased Power) are classified into base and peak demand and energy based on the following: A. All expenses, except those for purchases labeled Participation or Peaking Power, were classified as Base Energy. B. Demand charges for Peaking Power were classified as Peak Demand. C. Demand Charges for Participation Power (including co-generators and shared customers) were classified as follows: $ of Peak Demand = MAPP Schedule H (peaking) rate ($/MW/Mo.) × capacity of the purchase (MW) × number of months purchased. $ of Base Demand = Total Demand Charges − $ of Peak Demand. D. Energy charges for Participation Power were classified as Base Energy. E. Energy charges for Peaking Power were classified as Peak Energy. The jurisdictional allocations were then made as follows: Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 12 of 22 Cost Allocation Procedure Manual
BASE DEMAND - Energy Factor (E1) PEAK DEMAND - Generation Demand Factor (D1) BASE ENERGY - Energy Factor (E2) PEAK ENERGY - Generation Demand Factor (D1)
TRANSMISSION EXPENSES Allocated using the Transmission Demand Factor (D2).
DISTRIBUTION EXPENSES The expenses within this function were classified into the following categories: 1. Primary Demand (2400 volts and above) 2. Secondary Demand (below 2400 volts) 3. Primary Customer (2400 volts and above) 4. Secondary Customer (below 2400 volts) 5. Streetlights 6. Area Lights 7. Meters 8. Load Management Based on the following account-by-account methodology:
OPERATION ACCOUNT 580 (SUPERVISION AND ENGINEERING) - classified based on classification of Accounts 582-588. ACCOUNT 582 (STATION EXPENSE) - classified based on classification of related plant in service Account 362. ACCOUNT 583 (OVERHEAD LINE EXPENSE) - classified based on the classification of related plant in service Accounts 364, 365, 368 and 369. ACCOUNT 584 (UNDERGROUND LINE EXPENSE) - classified based on the classification of related plant in service Accounts 366, 367, and 369.1. ACCOUNT 585 (STREETLIGHTING EXPENSE) - classified directly as streetlighting. ACCOUNTS 586.1-586.5 & 586.9 (METER EXPENSES) - classified directly as meters. ACCOUNTS 586.6-586.7 (METER EXPENSES) - classified directly as load management. ACCOUNT 587 (CUSTOMER INSTALLATION EXPENSE) - classified secondary customer. Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 13 of 22 Cost Allocation Procedure Manual
ACCOUNT 588 (MISCELLANEOUS EXPENSE) - classified based on classification of Accounts 582-587. ACCOUNT 589 (RENTS) - classified based on classification of related plant in service Account 364.
MAINTENANCE ACCOUNT 590 (SUPERVISION AND ENGINEERING) - classified based on classification of Accounts 592-596. ACCOUNT 592 (STATION EQUIPMENT) - classified based on classification of related plant in service Account 362. ACCOUNT 593 (OVERHEAD LINES) - classified based on classification of related plant in service Accounts 364, 365, and 369. ACCOUNT 594 (UNDERGROUND LINES) - classified based on classification of related plant in service Accounts 366, 367, and 369.1. ACCOUNT 595 (LINE TRANSFORMERS) - classified based on classification of related plant in service Account 368. ACCOUNT 596 (STREETLIGHTING) - classified directly to streetlighting. ACCOUNTS 597.1-597.2 (METERS) - classified directly to meters. ACCOUNT 597.3 (METERS) - classified directly to load management. ACCOUNT 598 (MISCELLANEOUS DISTRIBUTION PLANT) - classified based on classification of Accounts 592-597.
Each category was then allocated based on the following: PRIMARY DEMAND - Distribution Primary Demand Factor (D3). SECONDARY DEMAND - Distribution Secondary Demand Factor (D4). PRIMARY CUSTOMER - Total Distribution Service Locations Factor (C2). SECONDARY CUSTOMER - Total Secondary Distribution Service Locations Factor (C3). STREETLIGHTING - Streetlight Factor (C4). AREA LIGHTING - Area Light Factor (C5). METERS - Meter Factor (C6). LOAD MANAGEMENT - Load Management Factor (C9).
CUSTOMER ACCOUNTING AND COLLECTING EXPENSES Expenses in this function were classified into two categories: 1. Meter Reading Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 14 of 22 Cost Allocation Procedure Manual
2. Other Expenses as specified by the following: ACCOUNT 901 (SUPERVISION) - classified based on classification of Accounts 902-905. ACCOUNT 902 (METER READING EXPENSE) - classified meter reading. ACCOUNT 903 (CUSTOMER RECORDS AND COLLECTIONS) - classified other expense. ACCOUNT 904 (UNCOLLECTIBLE ACCOUNTS) - classified other expense. ACCOUNT 905 (MISCELLANEOUS CUSTOMER ACCOUNTING EXPENSES) - classified other expense.
The METER READING category was allocated using the Meter Reading Factor (C7) and the OTHER EXPENSES category using the Total System Service Locations Factor (C8).
CUSTOMER SERVICE AND INFORMATION EXPENSES Conservation related programs and promotional rebates are directly assigned to jurisdiction and then allocated to class based on E8760 (Energy Factor). All other Customer Service and Information Expenses are allocated based on Total Customer Factor (C1).
SALES EXPENSES Economic Development is directly assigned to jurisdiction and then allocated to class based on Total Customer Factor (C1). Account 913, Advertising, is assigned below the line. All other Sales Expenses are allocated based on Total Customer Factor (C1).
ADMINISTRATIVE AND GENERAL EXPENSES ACCOUNTS 920 (SALARIES), 921 (SUPPLIES, ETC.), AND 926 (PENSIONS AND BENEFITS) - these accounts functionalized as: Production, Transmission, Distribution, Customer Accounting or Customer Service, based on FERC labor ratios (FERC Form No. 1, Page 354, or comparable data for a forecast year). Functional categories were then allocated using the expense ratios from the related expense functions, except that in the Production category the energy-related expenses and buy/sell transactions were not included in the ratios. (Energy-related expenses and buy/sell transactions are excluded because they are mainly purchased fuel which requires a minimum of company labor.) ACCOUNT 923 (OUTSIDE SERVICES) - allocated based on total net plant in service ratios. ACCOUNTS 924 (PROPERTY INSURANCE) and 925 (INJURIES & DAMAGES) - were allocated based on the total net plant in service ratios. Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 15 of 22 Cost Allocation Procedure Manual
ACCOUNTS 928 (REGULATORY COMMISSION EXPENSES) - directly assigned to each jurisdiction. Allocated to classes or groups based on total electric revenues from each class or group. ACCOUNT 930.1 (GENERAL ADVERTISING) -– The majority of this account is assigned below the line. Any remaining amount is allocated based on Total Customers Factor (C1). ACCOUNTS 930.2 (MISCELLANEOUS), 931 (RENTS), and 935.1-935.5 & 935.9 (MAINTENANCE) - allocated based on the gross general plant in service ratios. ACCOUNT 935.6 (MAINTENANCE) - directly assigned to load management and allocated on (C9).
DEPRECIATION EXPENSES PRODUCTION - Classification and allocation procedure is the same as that used for Production Plant in Service. TRANSMISSION - Allocated based on gross plant in service ratios developed from the Transmission Plant in Service function. DISTRIBUTION - Allocated based on gross plant in service ratios developed from the Distribution Plant in Service function. GENERAL - Allocated based on gross plant in service ratios developed from the General Plant in Service function. INTANGIBLE - Allocated using the gross plant in service ratios developed from the Intangible Plant in Service function.
BIG STONE PLANT CAPITALIZED ITEMS EXPENSES Directly assigned to each jurisdiction. Allocated to classes or groups based on the gross Production Plant in Service ratio.
OTHER EXPENSE - SPIRITWOOD AMORTIZATION Directly assigned to each jurisdiction. Allocated to customer class using the gross Production Plant in Service ratio.
GENERAL TAXES Allocated using total net plant in service ratios.
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DEFERRED INCOME TAXES Allocated using total net plant in service ratios.
INVESTMENT TAX CREDIT Allocated using total gross plant in service ratios.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) Allocated based on long-term construction work in progress ratios.
INCOME TAXES Income taxes are calculated for each jurisdiction separately. Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 17 of 22 Cost Allocation Procedure Manual
APPENDIX A-1
DETERMINATION OF THE DEMAND & CUSTOMER COMPONENTS OF THE DISTRIBUTION SYSTEM The customer component of the distribution system, that portion which varies with the number of customers, was determined by applying the minimum size system method. This method involves determining the minimum size unit currently being installed and using the average installed book cost of that unit to determine the customer component. However, our accounting system is such that, except for Account 368 (transformers), the only average installed book cost available is for all the units in an account regardless of size. To circumvent this problem, the following procedures were used: 1. The Electric Distribution (ED) Department specified what the minimum size unit for each account is and then provided information as to the type and quantity of material included in this unit and the amount of labor necessary to install it. 2. For each account that a customer component is required, the average age of the account was determined by using results of the recently completed depreciation study. This age is then subtracted from the study year to determine in what year the average unit was installed. 3. The average installed cost of the minimum size unit for the year indicated above was then determined. This was done by developing material, labor, transportation, and payroll costs for the year this unit was installed and applying them to the information supplied in No. 1, above.
The following pages describe how the dollars in each account were assigned to the various categories of cost using the data developed above and other figures from the various accounts.
Symbol Legend: PSL = Poles for Streetlights DSL = Dollars allocated to Streetlighting DAL = Dollars allocated to Area Lighting DPCC = Dollars allocated to Primary Customer Category DPDC = Dollars allocated to Primary Demand Category DSCC = Dollars allocated to Secondary Customer Category DSDC = Dollars allocated to Secondary Demand Category UPD = Units of Primary Distribution USD = Units of Secondary Distribution Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 18 of 22 Cost Allocation Procedure Manual
Account 364 (Poles): (All poles considered primary) A. Average age of a pole. B. Minimum size pole. C. Installed cost of the minimum size pole of the age in "A." D. Number of streetlights on separate poles. (Based on sample survey by Engineering Services.) E. Number of area lights on separate poles. (Based on sample survey by Engineering Services.) F. Number of poles in Account 364. G. Total dollars in Account 364.
Dollar Allocations for Account 364 To Streetlighting = D × C∗ = DSL To Area Lighting = E × C∗ = DAL Customer Component = (F − D − E) × C = DPCC Demand Component = DSL − DAL − DPCC = DPDC *Cost of a minimum size pole was used because most streetlights are mounted on minimum size poles and those that are on larger poles are mounted on poles that do not have the usual framing (crossarms, etc.).
Account 365 (Overhead Conductor and Devices): I. Primary A. Average age of primary conductor. B. Minimum size primary unit. C. Average installed cost of a minimum size primary unit of the age in "A." D. Average number of poles in a minimum size unit of primary conductor. (Estimated by ED Department.) E. Total dollars in Account 365 considered primary (see note). F. Total number of poles used for primary distribution. (Number of poles in Account 364 - Number of poles allocated to streetlighting and area lighting.)
F Number of units of primary distribution = UPD = D1
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Dollar Allocations for Account 365 Primary Customer Component = C × UPD = DPCC Demand Component = E − DPCC = DPDC
NOTE: All bare copper, aluminum, ACSR and iron wire are primary. 30% of WP copper, 80% of WP aluminum and 50% of the steel wire are primary. (Estimated by ED Department - exact percentages very difficult to determine.) All miscellaneous conductor and other equipment are primary.
II. Secondary A. Average age of secondary conductor. B. Minimum size secondary unit. C. Average installed cost of a minimum size unit of the age in "A." D. Number of units of secondary conductor (see note). E. Total dollars in Account 365 considered secondary. (All conductor not primary - see primary section.) F. Dollar value of duplex conductor in Account 365. (Duplex assumed to be used entirely for street and area lights.) G. Percent of total number of lighting units (street and area lights) that are streetlights.
Dollar Allocations for Account 365 Secondary To Streetlighting = F × G = DSL To Area Lighting = F − DSL = DAL Customer Component = C × D = DSCC Demand Component = E − F − DSCC = DSDC NOTE: Estimated by ED Department based on 250' of secondary for each five urban residential cottages, and urban commercial customers, 3,360' of secondary per unit.
Account 366 (Underground Conduit): The percentages developed from the allocation of Account 367 will be applied to this account.
Account 367 (Underground Conductor and Devices): I. Primary Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 20 of 22 Cost Allocation Procedure Manual
A. Average age of primary unit. B. Minimum size primary unit. C. Average installed cost of a minimum size primary unit of the age in "A." D. Number of feet of conductor in the minimum size primary unit. E. Total dollars in Account 367 considered primary. (All conductor rated 5 kV and above, and all nonconductor items are considered primary.) F. Total number of feet of primary conductor in Account 367.
F Number of units of primary distribution = UPD = D2
Dollar Allocations for Account 367 Primary Customer Component = C × UPD = DPCC Demand Component = E − DPCC = DPDC
II. Secondary A. Average age of secondary unit. B. Minimum size of secondary unit. C. Average installed cost of a minimum size secondary unit of the age in "A." D. Number of feet of conductor in the minimum size secondary unit. E. Total dollars in Account 367 considered secondary. (All conductor rated 600 volts or less is secondary.) F. Total number of feet of secondary conductor in Account 367 (see note). G. Dollar value of duplex conductor in Account 367 (duplex conductor is assumed to be used entirely for street and area lights). H. Percent of total number of lighting units (street and area lights) that is streetlights.
F Number of units of secondary distribution = USD = D3
Dollar Allocations for Account 367 Secondary To Streetlighting = G × H = DSL To Area Lighting = G − DSL = DAL Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 21 of 22 Cost Allocation Procedure Manual
Customer Component = C × USD = DSCC Demand Component = E − G − DSCC = DSDC
NOTE: Includes all quadruplex and triplex cable and 1/3 of 600 volt single wire. (Duplex is for lighting only.)
Account 368 (Transformers): (All transformers classified secondary) A. Average installed cost of minimum size 2400 V. overhead unit.* B. Average installed cost of minimum size 7200 V. overhead unit.* C. Average installed cost of minimum size 14400 V. overhead unit.* D. Average installed cost of minimum size 2400 V. underground unit.* E. Average installed cost of minimum size 7200 V. underground unit.* F. Number of 2400 V. overhead units in the account. G. Number of 7200 V. overhead units in the account. H. Number of 14400 V. overhead units in the account. *Overhead unit cost includes cost of appropriate cutout and arrester. I. Number of 2400 V. underground units in the account. J. Number of 7200 V. underground units in the account. K. Total dollar value of Account 368.
Dollar Allocations for Account 368 Customer Component = (A × F) + (B × G) + (C × H) + (D × I) + (E × J) = DSCC Demand Component = K − DSCC = DSDC
Account 369 (Overhead Services): (All services classified secondary) A. Average age of a service. B. Minimum size of a service. C. Average installed cost of a minimum size service of the age in "A." D. Total number of 3 and 4 services. E. Dollar value of two-wire services (two-wire services are considered all customer component). F. Total dollar value of Account 369.
Dollar Allocations for Account 369 Docket No. EL18-___ Exhibit__(SDT-1), Schedule 3 Otter Tail Power Company Page 22 of 22 Cost Allocation Procedure Manual
Customer Component = (C × D) + E = DSCC Demand Component = F − DSCC = DSDC
Account 369.1 (Underground Services): (All services classified secondary) A. Average age of an underground service. B. Minimum size of an underground service. C. Average installed cost of a minimum size three-wire service of the age in "A." D. Total number of services in Account 369.1. E. Total dollar value of Account 369.1.
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Last Update: February 20102017
I. INTRODUCTION
The corporate entity (“Corporate”) of Otter Tail Corporation provides services to the operating companies that comprise the Corporation. One of three things can occur with costs from Corporate services: 1) allocated to Otter Tail Power Company; 2) allocated to Varistar Inc., or 3) not allocated and remain at Corporate. The purpose of this manual is to detail how costs are being allocated to Otter Tail Power Company.
Otter Tail Power Company (the largest operating company of Otter Tail Corporation) serves retail electric customers in three jurisdictions including Minnesota, North and South Dakota and is governed by the rules and regulations in each jurisdiction. As a regulated utility, Otter Tail Power is allowed to recover prudent and reasonable costs for services it receives from Corporate, and reflects the cost of these services in its revenue requirements for setting rates. Costs allocated from Corporate are based on allocation factors that are calculated annually. In Minnesota, a different allocation method for the general allocator has been ordered for regulated reporting; however, this change in percentage is adjusted by Otter Tail Power Company so all costs billed from Corporate are at the same rate, regardless of jurisdiction.
The services provided by Corporate include financial reporting, tax planning and reporting, treasury and cash management, financial planning, internal audit, human resource and labor expertise, benefit plans, corporate communications, safety and risk management, shareholder services and investor relations, sourcing, aviation and executive management services (CEO, COO, CFO and General Counsel). These services are distinct from and do not duplicate similar services in Otter Tail Power Company. See Section V below for additional information of Corporate services. To support these services, there are specific corporate costs associated with administration and information technology (“IT”) that also need to be allocated.
The remainder of this document is devoted to explaining the services being provided and the methodology and allocation factors used to allocate Corporate service costs to Otter Tail Power Company.
II. METHODOLOGY
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Corporate identifies costs in three categories: 1) directly assignable costs, 2) indirect costs that are allocated on a department or functional allocation factor, and 3) general costs that are allocated using a general allocation factor.
Directly assignable costs are those costs where the purpose behind the costs can be attributed to a specific operating company. For example, consulting fees to help with a project related to an individual operating company would be directly assigned to that operating company.
Indirect costs have an identifiable cost causation related to another activity or factor. For example, costs for an employee in the Risk Management department of Corporate to attend a seminar on safety would be allocated using a functional allocation factor such as number of employees.
General costs are those costs that cannot be directly assigned or where cost-causation cannot be identified. Examples would include postage, local telephone and communication service costs, time spent preparing the annual report and other SEC filings, preparing to meet with rating agencies, working with and tracking shareholder matters. These types of costs will be allocated on a general allocation factor discussed below.
Allocation factors are updated annually in February with the most recent calendar year's data. The updated allocation factors are then implemented and utilized for all Corporate Costs in February and remain unchanged for 12 months. Current year factors are applied to corporate billings to the utility in first month following availability of final, audited financial information required for some factors.
III. ALLOCATION FACTORS
Indirect Allocation Factors:
A. IT Factor: This factor is based on the previous year ending December 31 ratio of corporate labor assigned to Otter Tail Power where the numerator is the total Corporate labor (not including bonuses) assigned to Otter Tail Power and the denominator is the total of all Corporate labor (not including bonuses). See Appendix A.
B. HR Factor: This factor is based on the average of the previous year ending December 31 ratio of employees, and the previous year ending December 31 ratio of benefit expenses. For the employee ratio the numerator is both full and part-time employees in electric operations and the denominator is the total number of full and part-time employees for all of Otter Tail Corporation. For the benefit ratio, the numerator is total benefit costs (including benefit costs cleared through the payroll loading rate) from electric operations, and the denominator is consolidated benefit costs for all of Otter Tail Corporation (including benefit costs cleared through the payroll loading rate) excluding benefit costs for Corporate employees.). The specific consolidated corporate accounts that will be
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used to calculate this ratio (including Otter Tail Power benefit costs cleared through payroll loading) are accounts C5030, C5230, C6030, C6530, C7030. See Appendix A.
C. RM Factor: This risk-management factor is the average of the previous year ending December 31 ratio of employees, and the previouscurrent year ratio of insurance premiums paid. For the employee ratio the numerator is both full and part-time employees in electric operations and the denominator is the total number of full and part- time employees for all of Otter Tail Corporation. For the insurance premium ratio, the numerator is the total premiums paid by Otter Tail Power and the denominator is the sum of insurance premiums paid by all operating companies. See Appendix A.
D. Internal Audit Factor: This factor is based on the previous year ending December 31 ratio where the numerator is the total hours spent auditing electric operations and the denominator is the sum of hours auditing electric and non-electric operations. Non- electric operations do not include hours spent auditing Corporate-related matters. See Appendix A.
General Allocation Factor:
This factor is based on a three-factor formula that is comprised of the average ratio of Total Assets, Total Revenues and Total Labor Dollars for the most recent calendar year. The specific consolidated corporate accounts that will be used to calculate the Total Labor Dollars ratio are C5010, C5020, C5030, C5210, C5220, C5230, C6010, C6015, C6020, C6030, C6510, C6520, C6530, C7010, C7020 and C7030. Appendix A shows the computation of this factor based on prior-year audited numbers and shows the source for the information to calculate each ratio.1
IV. CLARIFICATION ON CERTAIN COSTS
There are certain costs that need to be discussed in further detail to gain an understanding of exactly how they are being allocated, or in some instances, not being allocated. This section will list each of these costs individually and provide background and instruction on how each is handled for allocation purposes.
A. Labor: Employees at Corporate track their time on a daily basis. Percentages are used to track time between Corporate, Otter Tail Power Company, and Varistar activities. The time designated Otter Tail Power is directly assigned to the power company. The percentage of time being recorded in the Corporate column is allocated based on the
1 The Minnesota Public Utilities Commission (PUC) has ordered in Otter Tail Power Company's last rate case (Docket No. E017/GR-07-1178), that the General Allocator calculation method must comply with the PUC's orders in Docket E,G999/CI-90-1008. That docket established a general allocator based on the ratio of regulated to unregulated expenses, excluding fuel, purchased power, and purchased cost of goods sold.
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employee’s position and will use one of the allocation factors discussed above in Section III.
B. Bonuses and Benefits: Cash bonuses are allocated based on each employee’s labor ratio from the previous year. An employee's labor ratio reflects both directly assigned and allocated labor. Bonuses are accrued and allocated during the current year, and a true-up is made in the following year after the exact bonus amount is determined and the employee’s actual labor ratio from the previous year is available. Benefit costs are allocated on each employee’s labor ratio from the most recent 30-day pay period.
C. Contributions, Employee Stock Purchase Plan and Deferred Compensation Expense: The costs associated with these three items: The contributions made by Otter Tail Corporation are not allocated to Otter Tail Power. Each operating company makes its own contributions and those contributions made from a corporation perspective are typically not allocated. Costs for the stock purchase plan and deferred compensation plan are kept at Corporate and not allocated.
D. Employee Stock Purchase Plan and Deferred Compensation Expense: The costs associated with the Employee Stock Purchase Plan are allocated based on the ratio of Otter Tail Power employee stock purchases to the total of the most recent stock purchase and Deferred Compensation expense is allocated to Otter Tail Power based on the general allocator.
D.E. Stock Option Expense: Under FAS 123(R)Accounting Standard Codification (ASC) Topic 718 companies are required to record the value of stock options over the period in which the options vest. These expenses are allocated to Otter Tail Power based on the number of options granted to employees in this company. No stock options were granted in 2016 and none are expected to be granted to employees in 2017.
E.F. Restricted Stock and Restricted Stock Units: Under FAS 123(R)ASC Topic 718 companies are required to record the value of restricted stock and restricted stock units over the period in which the shares vest. Restricted stock and restricted stock unit expense on shares granted to Otter Tail Power employees are directly assigned to Otter Tail Power. NoThe portion of restricted stock or restricted stock units granted to Corporate employees and the Board of Directors is allocated to Otter Tail Power Company based on the general allocator.
F.G. Executive Stock IncentivePerformance Award Plan: Under FAS 123(R)ASC Topic 718 companies are required to record the value of incentive stock, awarded based on the performance of the company’s stock price, over the time period used to evaluate performance. Otter Tail Corporation provides incentive stock to the corporate officers as part of their overall compensation package. The costs associated with this plan are not allocated. allocated based on the prior year time allocations for each executive. In
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addition when performance shares are awarded to Otter Tail Power’s president the cost related to his award is directly assigned to Otter Tail Power.
G.H. Bank Charges: Corporate serves as the “Bank” for operating companies and therefore incurs the various fees associated with the accounts maintained by the operating companies. Each operating companyOtter Tail Power is directly charged for theirits respective fees and the fees associated with Corporate’s accounts are allocated using the General Allocation Factor.
H.I. External Audit Fees: Otter Tail Corporation currently retains an independent registered public accounting firm to audit its financial reports and records. Each year this firm provides to Otter Tail Corporation a Client Service Plan that outlines the number of hours it has assigned to audit electric and non-electric operations. Fees from the firm are allocated based on the ratio of assigned hours for electric versus total audit hours on consolidated operations. The hours assigned to corporate are allocated using the general allocator.
I.J. Meetings: Costs associated with periodic meetings that involve personnel from across the operating companies such as quarterly leadership meetings, quarterly accounting and HR meetings are not allocated.
K. Training and Development: Costs associated with training and development are direct charged where possible but otherwise allocated using the appropriate indirect allocator or the general allocator.
J.L.Travel and meals: With the exception of travel-related expense related to operations of Otter Tail Power’s jointly owned generation plants, or if corporate employees are working specifically forOtter Tail Power, corporate travel expense is not allocated.
K.M. Aviation Services: Corporate provides air service for the operating companies of Otter Tail Corporation. There are two aircraftsis one aircraft available for use. One is which is the King Air. The King Air is owned by Otter Tail Power Company (the King Air), the other is owned by Varistar Corporation (the Encore).. To help recover the variable costs associated with flying these twothis aircraft, corporate charges hourly rates which are reviewed periodically.2 (See Appendix B for hourly rates)
Because the King Air is owned by Otter Tail Power, at the end of each quarter the costs associated with the King Air that have not been recovered through the hourly rate are charged to Otter Tail Power. For example, the costs not cleared for the quarter total $9,000. Otter Tail Power has recorded depreciation expense for the quarter of $1,000 which is added to the $9,000 of un-cleared costs for a total of $10,000. The $10,000 is
2 The aviation charge rates may be changed during the year to reflect changes in variable costs (i.e., aviation fuel).
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multiplied by the non-utility usage factor (the percentage of hours flown for operating companies other than Otter Tail Power) and for our example we’ll say it’s 52%. Otter Tail Power will then be charged $3,800 ($9,000 less $5,200 ($10,000 x 52%)) to reflect the utility-portion of costs not cleared on the King Air.
V. DESCRIPTION AND ALLOCATION OF SERVICES PROVIDED
Further detail is discussed below on the services provided by Corporate. Each service shown below is directly related to an individual cost center at Corporate. For each service a description is provided along with the primary allocation factor that is used to allocate associated costs. Again, costs that can be directly assigned to the various operating companies are directly assigned. Indirect costs are allocated using one of the factors discussed in Section III.
A. Corporate Overheads
Description: Represents charges for succession planning and developing leadership at the operating companies, bank charges, building lease and depreciation expense.
Allocation Factor: Costs associated with succession planning and developing leaders at the various operating companies are not allocated but kept at Corporate. All otherAllocation Factor: All costs not directly assigned are allocated on the General Allocation Factor.
B. Executive Management Services
Description: Represents charges for Otter Tail Corporation’s executive management team comprised of the four Officers, and Contributions.
Allocation Factor: Contributions are not allocated and all other costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
C. Board of Directors
Description: Represents charges for board of director fees, restricted stock, travel and other expenses associated with attending Board meetings or related to being a board member.
Allocation Factor: Fees and restricted stock expense are allocated on the General Allocation Factor. Otter Tail Power is not allocated any costs associated with restricted stock granted to directors or travel related expenses.
D. Corporate Development
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Description: Represents charges for the Corporate Development staff that are responsible for identifying and researching acquisition candidates, due diligence on acquisition targets, and integrating recently acquired companies into Otter Tail Corporation.
Allocation Factor: All costs are currently being directly assigned to Varistar Corporation but if Otter Tail Power uses these services for an acquisition, the associated costs would be directly billed to Otter Tail Power.
E. Platform Leadership
Description: Represents charges for the Platform Leaders and their staff that have oversight responsibilities with the non-electric operating companies.
Allocation Factor: All costs are currently being directly assigned to Varistar Corporation.
F. Administrative Services
Description: Represents charges for providing administrative support to all the other services, office supplies, cell phones and office equipment leases.
Allocation Factor: All costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
G. Information Technology
Description: Represents charges for supporting corporate computers, networks, land- based phones and T1 lines, internet, software and other various pieces of hardware. In addition, consulting services are provided as requested to the various operating companies.
Allocation Factor: License and maintenance fees comprise a large portion of the non- labor costs. As much as possible, these costs are directly assigned based on the number of user licenses utilizing the software by each operating company. All costs not directly assigned are allocated on the IT Factor including labor classified as Corporate. The corporate VP of Information Technology is a shared position with Otter Tail Power Company. The specific costs for this position are directly assigned to Otter Tail Power as appropriate.
H. Corporate Accounting
Description: Represents charges for maintaining financial records, statements and systems, SEC filings, tax accounting and filings, cash management and consulting with various operating companies on an as-needed basis.
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Allocation Factor: External audit fees are allocated as discussed in Section IV. Costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
I. Internal Audit
Description: Represents charges for reviewing internal controls and conducting operation audits at the various companies within Otter Tail Corporation.
Allocation Factor: Costs not directly assigned are allocated on the Internal Audit Factor including labor classified as Corporate.
J. Financial Planning
Description: Represents charges for supporting financial analysis and budgeting at the operating company and corporate level.
Allocation Factor: Costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
K. Treasury
Description: Represents charges for communicating with both debt and equity analysts, maintaining Otter Tail Corporation’s capital structure, monitoring and accessing capital markets and other services as identified by the Chief Financial Officer.
Allocation Factor: Costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
L. Corporate Communications
Description: Represents charges for corporate communications including press releases, advertising and branding and annual report preparation. Another service provided is coordinating and tracking contributions made on behalf of Corporate.
Allocation Factor: Costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
M. Shareholder Services
Description: Represents charges for maintaining shareholder records, communicating with investors at various fairs, coordinating transfer agents and planning the annual shareholder meeting.
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Allocation Factor: Costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
N. Human Resources/Leadership Development
Description: Represents charges for establishing and maintaining policies related to employment and benefits of corporate employees and executive compensation, searches for candidates for upper-level management positions on behalf of operating companies, organizing and facilitating leadership training, organizing and aiding in the administration of company benefit programs.
Allocation Factor: Costs not directly assigned are allocated on the HR Factor including labor classified as Corporate. In case of leadership and employee development training, costs are allocated based on employees in attendance at training sessions, if possible and otherwise allocated using the HR allocator.
O. Legal Affairs
Description: Represents charges for legal services related to employment law, litigation, contracts, rates and regulation, environmental matters, real estate and other various legal matters.
Allocation Factor: AllMost costs associated with legal services are directly assigned. All but if costs cannot be directly charged, the general allocator is used. Typically, labor costs for all corporate lawyers other than the General Counsel are directlygenerally assigned to one operating company, or a group of operatingthe Varistar companies. Three as Otter Tail Power employs their own attorneys, however, there are times when corporate lawyers are currentlyperform work for Otter Tail Power which would be assigned to Otter Tail Power and two lawyers are assigned to non-electric companies. as such.
P. Risk Management
Description: Represents charges for assisting operating companies with assessment and management of risks, identifying and implementing loss control strategies to minimize the frequency and financial consequences of accidental losses, assisting operating companies in post loss claim management, overseeing Otter Tail Corporation’s consolidated insurance program, and identifying and documenting the environmental conditions during the process of acquiring a new company.
Allocation Factor: Costs not directly assigned are allocated on the RM Factor including labor classified as Corporate.
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Q. Sourcing
Description: Charges represent services related to sourcing, procurement, vendor relationships, and developing strategies to leverage the consolidated buying power of Otter Tail Corporation as a whole.
Allocation Factor: Sourcing-related costs are directly assigned in most instances. Costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
VI. CONCLUSION
As circumstances arise, such as adding a new service that will be provided by Corporate, appropriate changes will be made to the manual. Appendix A will be updated annually in February when the prior-year audited records are available and Appendix B will be updated as Aviation Rates are changed.
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Last Update: February 2017
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I. INTRODUCTION
The corporate entity (“Corporate”) of Otter Tail Corporation provides services to the operating companies that comprise the Corporation. One of three things can occur with costs from Corporate services: 1) allocated to Otter Tail Power Company; 2) allocated to Varistar Inc., or 3) not allocated and remain at Corporate. The purpose of this manual is to detail how costs are being allocated to Otter Tail Power Company.
Otter Tail Power Company (the largest operating company of Otter Tail Corporation) serves retail electric customers in three jurisdictions including Minnesota, North and South Dakota and is governed by the rules and regulations in each jurisdiction. As a regulated utility, Otter Tail Power is allowed to recover prudent and reasonable costs for services it receives from Corporate, and reflects the cost of these services in its revenue requirements for setting rates. Costs allocated from Corporate are based on allocation factors that are calculated annually. In Minnesota, a different allocation method for the general allocator has been ordered for regulated reporting; however, this change in percentage is adjusted by Otter Tail Power Company so all costs billed from Corporate are at the same rate, regardless of jurisdiction.
The services provided by Corporate include financial reporting, tax planning and reporting, treasury and cash management, financial planning, internal audit, human resource and labor expertise, benefit plans, corporate communications, safety and risk management, shareholder services and investor relations, aviation and executive management services (CEO, COO, CFO and General Counsel). These services are distinct from and do not duplicate similar services in Otter Tail Power Company. See Section V below for additional information of Corporate services. To support these services, there are specific corporate costs associated with administration and information technology (“IT”) that also need to be allocated.
The remainder of this document is devoted to explaining the services being provided and the methodology and allocation factors used to allocate Corporate service costs to Otter Tail Power Company.
II. METHODOLOGY
Corporate identifies costs in three categories: 1) directly assignable costs, 2) indirect costs that are allocated on a department or functional allocation factor, and 3) general costs that are allocated using a general allocation factor.
Directly assignable costs are those costs where the purpose behind the costs can be attributed to a specific operating company. For example, consulting fees to help with a project related to an individual operating company would be directly assigned to that operating company.
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Indirect costs have an identifiable cost causation related to another activity or factor. For example, costs for an employee in the Risk Management department of Corporate to attend a seminar on safety would be allocated using a functional allocation factor such as number of employees.
General costs are those costs that cannot be directly assigned or where cost-causation cannot be identified. Examples would include postage, local telephone and communication service costs, time spent preparing the annual report and other SEC filings, preparing to meet with rating agencies, working with and tracking shareholder matters. These types of costs will be allocated on a general allocation factor discussed below.
Allocation factors are updated annually in February with the most recent calendar year's data. The updated allocation factors are then implemented and utilized for all Corporate Costs in February and remain unchanged for 12 months.
III. ALLOCATION FACTORS
Indirect Allocation Factors:
A. IT Factor: This factor is based on the previous year ending December 31 ratio of corporate labor assigned to Otter Tail Power where the numerator is the total Corporate labor (not including bonuses) assigned to Otter Tail Power and the denominator is the total of all Corporate labor (not including bonuses). See Appendix A.
B. HR Factor: This factor is based on the average of the previous year ending December 31 ratio of employees, and the previous year ending December 31 ratio of benefit expenses. For the employee ratio the numerator is full -time employees in electric operations and the denominator is the total number of full -time employees for all of Otter Tail Corporation. For the benefit ratio, the numerator is total benefit costs (including benefit costs cleared through the payroll loading rate) from electric operations, and the denominator is consolidated benefit costs for all of Otter Tail Corporation (including benefit costs cleared through the payroll loading rate). The specific consolidated corporate accounts that will be used to calculate this ratio (including Otter Tail Power benefit costs cleared through payroll loading) are accounts C5030, C5230, C6030, C6530, C7030. See Appendix A.
C. RM Factor: This risk-management factor is the average of the previous year ending December 31 ratio of employees, and the current year ratio of insurance premiums paid. For the employee ratio the numerator is full -time employees in electric operations and the denominator is the total number of full -time employees for all of Otter Tail Corporation. For the insurance premium ratio, the numerator is the total premiums paid by Otter Tail Power and the denominator is the sum of insurance premiums paid by all operating companies. See Appendix A.
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D. Internal Audit Factor: This factor is based on the previous year ending December 31 ratio where the numerator is the total hours spent auditing electric operations and the denominator is the sum of hours auditing electric and non-electric operations. Non- electric operations do not include hours spent auditing Corporate-related matters. See Appendix A.
General Allocation Factor:
This factor is based on a three-factor formula that is comprised of the average ratio of Total Assets, Total Revenues and Total Labor Dollars for the most recent calendar year. The specific consolidated corporate accounts that will be used to calculate the Total Labor Dollars ratio are C5010, C5020, C5030, C5210, C5220, C5230, C6010, C6015, C6020, C6030, C6510, C6520, C6530, C7010, C7020 and C7030. Appendix A shows the computation of this factor based on prior-year audited numbers and shows the source for the information to calculate each ratio.1
IV. CLARIFICATION ON CERTAIN COSTS
There are certain costs that need to be discussed in further detail to gain an understanding of exactly how they are being allocated, or in some instances, not being allocated. This section will list each of these costs individually and provide background and instruction on how each is handled for allocation purposes.
A. Labor: Employees at Corporate track their time on a daily basis. Percentages are used to track time between Corporate, Otter Tail Power Company, and Varistar activities. The time designated Otter Tail Power is directly assigned to the power company. The percentage of time being recorded in the Corporate column is allocated based on the employee’s position and will use one of the allocation factors discussed above in Section III.
B. Bonuses and Benefits: Cash bonuses are allocated based on each employee’s labor ratio from the previous year. An employee's labor ratio reflects both directly assigned and allocated labor. Bonuses are accrued and allocated during the current year, and a true-up is made in the following year after the exact bonus amount is determined and the employee’s actual labor ratio from the previous year is available. Benefit costs are allocated on each employee’s labor ratio from the most recent 30-day pay period.
1 The Minnesota Public Utilities Commission (PUC) has ordered in Otter Tail Power Company's last rate case (Docket No. E017/GR-07-1178), that the General Allocator calculation method must comply with the PUC's orders in Docket E,G999/CI-90-1008. That docket established a general allocator based on the ratio of regulated to unregulated expenses, excluding fuel, purchased power, and purchased cost of goods sold.
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C. Contributions: The contributions made by Otter Tail Corporation are not allocated to Otter Tail Power. Each operating company makes its own contributions and those contributions made from a corporation perspective are typically not allocated.
D. Employee Stock Purchase Plan and Deferred Compensation Expense: The costs associated with the Employee Stock Purchase Plan are allocated based on the ratio of Otter Tail Power employee stock purchases to the total of the most recent stock purchase and Deferred Compensation expense is allocated to Otter Tail Power based on the general allocator.
E. Stock Option Expense: Under Accounting Standard Codification (ASC) Topic 718 companies are required to record the value of stock options over the period in which the options vest. These expenses are allocated to Otter Tail Power based on the number of options granted to employees in this company. No stock options were granted in 2016 and none are expected to be granted to employees in 2017.
F. Restricted Stock and Restricted Stock Units: Under ASC Topic 718 companies are required to record the value of restricted stock and restricted stock units over the period in which the shares vest. Restricted stock and restricted stock unit expense on shares granted to Otter Tail Power employees are directly assigned to Otter Tail Power. The portion of restricted stock or restricted stock units granted to Corporate employees and the Board of Directors is allocated to Otter Tail Power Company based on the general allocator.
G. Executive Stock Performance Award Plan: Under ASC Topic 718 companies are required to record the value of incentive stock, awarded based on the performance of the company’s stock price, over the time period used to evaluate performance. Otter Tail Corporation provides incentive stock to the corporate officers as part of their overall compensation package. The costs associated with this plan are allocated based on the prior year time allocations for each executive. In addition when performance shares are awarded to Otter Tail Power’s president the cost related to his award is directly assigned to Otter Tail Power.
H. Bank Charges: Corporate serves as the “Bank” for operating companies and therefore incurs the various fees associated with the accounts maintained by the operating companies. Otter Tail Power is directly charged for its respective fees and the fees associated with Corporate’s accounts are allocated using the General Allocation Factor.
I. External Audit Fees: Otter Tail Corporation currently retains an independent registered public accounting firm to audit its financial reports and records. Each year this firm provides to Otter Tail Corporation a Client Service Plan that outlines the number of hours it has assigned to audit electric and non-electric operations. Fees from the firm are allocated based on the ratio of assigned hours for electric versus total audit hours on
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consolidated operations. The hours assigned to corporate are allocated using the general allocator.
J. Meetings: Costs associated with periodic meetings that involve personnel from across the operating companies such as leadership meetings, quarterly accounting and HR meetings are not allocated.
K. Training and Development: Costs associated with training and development are direct charged where possible but otherwise allocated using the appropriate indirect allocator or the general allocator.
L. Travel and meals: With the exception of travel-related expense related to operations of Otter Tail Power’s jointly owned generation plants or if corporate employees are working specifically forOtter Tail Power, corporate travel expense is not allocated.
M. Aviation Services: Corporate provides air service for the operating companies of Otter Tail Corporation. There is one aircraft available for use which is the King Air. The King Air is owned by Otter Tail Power Company. To help recover the variable costs associated with flying this aircraft, corporate charges hourly rates which are reviewed periodically.2 (See Appendix B for hourly rates)
Because the King Air is owned by Otter Tail Power, at the end of each quarter the costs associated with the King Air that have not been recovered through the hourly rate are charged to Otter Tail Power. For example, the costs not cleared for the quarter total $9,000. Otter Tail Power has recorded depreciation expense for the quarter of $1,000 which is added to the $9,000 of un-cleared costs for a total of $10,000. The $10,000 is multiplied by the non-utility usage factor (the percentage of hours flown for operating companies other than Otter Tail Power) and for our example we’ll say it’s 52%. Otter Tail Power will then be charged $3,800 ($9,000 less $5,200 ($10,000 x 52%)) to reflect the utility-portion of costs not cleared on the King Air.
V. DESCRIPTION AND ALLOCATION OF SERVICES PROVIDED
Further detail is discussed below on the services provided by Corporate. Each service shown below is directly related to an individual cost center at Corporate. For each service a description is provided along with the primary allocation factor that is used to allocate associated costs. Again, costs that can be directly assigned to the various operating companies are directly assigned. Indirect costs are allocated using one of the factors discussed in Section III.
A. Corporate Overheads
2 The aviation charge rates may be changed during the year to reflect changes in variable costs (i.e., aviation fuel).
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Description: Represents charges for bank charges, building lease and depreciation expense.
Allocation Factor: All costs not directly assigned are allocated on the General Allocation Factor.
B. Executive Management Services
Description: Represents charges for Otter Tail Corporation’s executive management team and Contributions.
Allocation Factor: Contributions are not allocated and all other costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
C. Board of Directors
Description: Represents charges for board of director fees, restricted stock, travel and other expenses associated with attending Board meetings or related to being a board member.
Allocation Factor: Fees and restricted stock expense are allocated on the General Allocation Factor. Otter Tail Power is not allocated any costs associated with travel related expenses.
D. Corporate Development
Description: Represents charges for the Corporate Development staff that are responsible for identifying and researching acquisition candidates, due diligence on acquisition targets, and integrating recently acquired companies into Otter Tail Corporation.
Allocation Factor: All costs are currently being directly assigned to Varistar Corporation but if Otter Tail Power uses these services for an acquisition, the associated costs would be directly billed to Otter Tail Power.
E. Platform Leadership
Description: Represents charges for the Platform Leaders and their staff that have oversight responsibilities with the non-electric operating companies.
Allocation Factor: All costs are currently being directly assigned to Varistar Corporation.
F. Administrative Services
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Description: Represents charges for providing administrative support to all the other services, office supplies and office equipment leases.
Allocation Factor: All costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
G. Information Technology
Description: Represents charges for supporting corporate computers, networks, land- based phones and T1 lines, internet, software and other various pieces of hardware. In addition, consulting services are provided as requested to the various operating companies.
Allocation Factor: License and maintenance fees comprise a large portion of the non- labor costs. As much as possible, these costs are directly assigned based on the number of user licenses utilizing the software by each operating company. All costs not directly assigned are allocated on the IT Factor including labor classified as Corporate. The corporate VP of Information Technology is a shared position with Otter Tail Power Company. The specific costs for this position are directly assigned to Otter Tail Power as appropriate.
H. Corporate Accounting
Description: Represents charges for maintaining financial records, statements and systems, SEC filings, tax accounting and filings, cash management and consulting with various operating companies on an as-needed basis.
Allocation Factor: External audit fees are allocated as discussed in Section IV. Costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
I. Internal Audit
Description: Represents charges for reviewing internal controls and conducting operation audits at the various companies within Otter Tail Corporation.
Allocation Factor: Costs not directly assigned are allocated on the Internal Audit Factor including labor classified as Corporate.
J. Financial Planning
Description: Represents charges for supporting financial analysis and budgeting at the operating company and corporate level.
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Allocation Factor: Costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
K. Treasury
Description: Represents charges for communicating with both debt and equity analysts, maintaining Otter Tail Corporation’s capital structure, monitoring and accessing capital markets and other services as identified by the Chief Financial Officer.
Allocation Factor: Costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
L. Corporate Communications
Description: Represents charges for corporate communications including press releases, advertising and branding and annual report preparation. Another service provided is coordinating and tracking contributions made on behalf of Corporate.
Allocation Factor: Costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
M. Shareholder Services
Description: Represents charges for maintaining shareholder records, communicating with investors at various fairs, coordinating transfer agents and planning the annual shareholder meeting.
Allocation Factor: Costs not directly assigned are allocated on the General Allocation Factor including labor classified as Corporate.
N. Human Resources/Leadership Development
Description: Represents charges for establishing and maintaining policies related to employment and benefits of corporate employees and executive compensation, searches for candidates for upper-level management positions on behalf of operating companies, organizing and facilitating leadership training, organizing and aiding in the administration of company benefit programs.
Allocation Factor: Costs not directly assigned are allocated on the HR Factor including labor classified as Corporate. In case of leadership and employee development training, costs are allocated based on employees in attendance at training sessions, if possible and otherwise allocated using the HR allocator.
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O. Legal Affairs
Description: Represents charges for legal services related to employment law, litigation, contracts, rates and regulation, environmental matters, real estate and other various legal matters.
Allocation Factor: Most costs associated with legal services are directly assigned but if costs cannot be directly charged, the general allocator is used. Typically, labor costs for all corporate lawyers other than the General Counsel are generally assigned to the Varistar companies as Otter Tail Power employs their own attorneys, however, there are times when corporate lawyers perform work for Otter Tail Power which would be assigned as such.
P. Risk Management
Description: Represents charges for assisting operating companies with assessment and management of risks, identifying and implementing loss control strategies to minimize the frequency and financial consequences of accidental losses, assisting operating companies in post loss claim management, overseeing Otter Tail Corporation’s consolidated insurance program, and identifying and documenting the environmental conditions during the process of acquiring a new company.
Allocation Factor: Costs not directly assigned are allocated on the RM Factor including labor classified as Corporate.
VI. CONCLUSION
As circumstances arise, such as adding a new service that will be provided by Corporate, appropriate changes will be made to the manual. Appendix A will be updated annually in February when the prior-year audited records are available and Appendix B will be updated as Aviation Rates are changed.
Updated February 2017 10
Volume 2A
Direct Testimony and Supporting Schedules
Bryce C. Haugen
Before the South Dakota Public Utilities Commission State of South Dakota
In the Matter of the Application of Otter Tail Power Company For Authority to Increase Rates for Electric Utility Service in South Dakota
Docket No. EL18-___
Exhibit___
TRANSITION OF CAPITAL PROJECTS FROM RIDERS TO BASE RATES, PRODUCTION TAX CREDITS, MISCELLANEOUS TEST YEAR ITEMS, CLASS COST OF SERVICE STUDY AND CLASS REVENUE RESPONSIBILITIES
Direct Testimony and Schedules of
BRYCE C. HAUGEN
April 20, 2018 TABLE OF CONTENTS
I. INTRODUCTION AND QUALIFICATIONS ...... 1 II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY ...... 1 III. MOVING CAPITAL PROJECTS FROM RIDERS INTO RATE BASE ...... 2 A. ECRR ...... 2 1. Base Rates ...... 3 2. ECRR Adjustment ...... 6 B. TCRR ...... 7 1. Base Rates ...... 8 2. TCRR Adjustment ...... 10 IV. PRODUCTION TAX CREDITS ...... 13 V. ADVERTISING EXPENSE ...... 15 VI. CHARITABLE CONTRIBUTIONS ...... 16 VII. CCOSS AND CLASS REVENUE RESPONSIBILITIES ...... 16 A. 2017 TEST YEAR ...... 16 1. CCOSS ...... 16 2. Class Revenue Responsibilities ...... 18 B. STEP-IN RATE PROPOSAL ...... 20 VIII. CONCLUSION ...... 22
ATTACHED SCHEDULES
Schedule 1 – Haugen Resume
Schedule 2 – Rider Roll-In Plant in Service
Schedule 3 – ECRR 2017 Test Year Tracker Schedule
Schedule 4 – ECRR Charge Update
Schedule 5 – TCRR 2017 Test Year Tracker Schedule
Schedule 6 – TCRR Charge Update
1 I. INTRODUCTION AND QUALIFICATIONS
2 Q. PLEASE STATE YOUR NAME AND OCCUPATION. 3 A. My name is Bryce C. Haugen. I am employed by Otter Tail Power Company (OTP) as 4 Senior Rates Analyst, Regulatory Administration. 5 6 Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE. 7 A. I graduated from Minnesota State Community and Technical College, Fergus Falls, 8 Minnesota in 2003 with an A.A. degree. I graduated from Moorhead State University, 9 now Minnesota State University, Moorhead, Minnesota, in 2005 with a B.S. degree in 10 Finance. I graduated from National University, La Jolla, California, in 2014 with a 11 Master of Science in Organizational Leadership. I started my career as the Operations 12 Manager for the Theodore Roosevelt Medora Foundation in 2005 in Medora, North 13 Dakota. In 2009, I joined Baker Boy Bake Shop in Dickinson, North Dakota as a cost 14 accountant and became a production supervisor in 2010. In 2012, I joined OTP as 15 Business Coordinator in the Project Management department. I subsequently worked as 16 Credit Risk Analyst in the Risk Management department and joined the Regulatory 17 Administration department in 2013 as Rates Analyst. I accepted my current position as 18 Senior Rates Analyst in November 2015. My primary responsibilities in this position are 19 to lead the work team responsible for the preparation and financial analysis used to 20 determine revenue requirements associated with various state and federal cost recovery 21 mechanisms and to lead development of regulatory filings associated with these cost 22 recovery mechanisms. A copy of my resume is included as Exhibit___(BCH-1), Schedule 23 1.
24 II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY
25 Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? 26 A. My Direct Testimony describes: moving investments currently being recovered in the 27 Environmental Cost Recovery Rider (ECRR) and Transmission Cost Recovery Rider 28 (TCRR) into base rates (Section III); treatment of wind investment-related production tax 29 credits (PTCs) (Section IV); advertising expenses (Section V); charitable contributions
1 Docket No. EL18-___ Haugen Direct
1 (Section VI); and Class Cost of Service Study (CCOSS) and class revenue 2 responsibilities (Section VII). 3 4 Q. DID YOU USE ANY LABELING CONVENTIONS IN YOUR DIRECT 5 TESTIMONY? 6 A. Yes. There are certain power plant and transmission projects where OTP is only a part 7 owner. I distinguish among total project costs, OTP’s share of the total and the South 8 Dakota Jurisdictional share as follows: total project costs, labeled as (Total Plant or Total 9 Project), the OTP ownership allocation of the project amounts, labeled as (OTP Total), 10 and the South Dakota Jurisdictional share, labeled as (OTP SD).
11 III. MOVING CAPITAL PROJECTS FROM RIDERS INTO RATE BASE
12 Q. PLEASE DESCRIBE THE PURPOSE OF THIS SECTION OF YOUR DIRECT 13 TESTIMONY. 14 A. OTP proposes to transfer recovery of certain costs presently recovered in the ECRR and 15 the TCRR to base rates at the time Interim Rates go into effect. This section of my Direct 16 Testimony explains the mechanics of this proposal. OTP witness Mr. Tyler A. Akerman 17 quantifies the impact of this proposal on the 2017 Test Year revenue requirement.
18 A. ECRR 19 Q. WHAT IS THE ECRR? 20 A. SDCL §§ 49-34A-97 through 49-34A-100 authorize the Commission to approve a tariff 21 mechanism for the automatic annual adjustment of charges to recover the costs incurred 22 for environmental improvements to existing generation facilities. Eligible environmental 23 improvements include any environmental improvements required under the Clean Air 24 Act, the Clean Water Act, or any other federal law or rule, or any state law or rule 25 implementing a federal law or rule, or voluntary environmental measures designed to 26 protect the environment. 27 OTP’s ECRR was established in Docket No. EL14-082, with initial rates going 28 into effect December 1, 2014. 29
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1 Q. PLEASE IDENTIFY OTP’S RELEVANT ECRR FILINGS. 2 A. OTP’s prior ECRR filings are shown in Table 1 below: 3 4 Table 1 5 ECRR – History ECRR History Docket Number Commission Approved Effective Date Original ECRR Charge EL14-082 December 10, 2014 December 1, 2014 and Mechanism First Update EL15-029 October 15, 2015 November 1, 2015 Second Update EL16-030 October 31, 2016 November 1, 2016 Third Update EL17-035 October 13, 2017 November 1, 2017 6 7 Q. WHAT IS OTP’S PROPOSAL WITH REGARD TO THE ECRR IN THIS CASE? 8 A. OTP requests that the projects included in the ECRR as of December 31, 2017, be rolled 9 into base rates. OTP proposes that this occur at the time Interim Rates go into effect. 10 11 Q. WHAT TYPES OF INVESTMENTS ARE CURRENTLY INCLUDED IN THE ECRR? 12 A. Two projects are recovered in the ECRR (ECRR Projects): The Big Stone Plant Air 13 Quality Control System (AQCS) project and the Hoot Lake Plant Mercury and Air 14 Toxics Standards (HLP MATS) project. OTP witness Mr. Kirk A. Phinney discusses 15 these projects in detail in his Direct Testimony. 16 17 Q. WHEN WERE THE PROJECTS PLACED INTO SERVICE? 18 A. The HLP MATS project was placed in service in August 2014. The AQCS project was 19 placed in service in December 2015.
20 1. Base Rates 21 Q. HOW HAVE COSTS CURRENTLY BEING RECOVERED IN THE ECRR BEEN 22 HANDLED IN THE 2017 TEST YEAR FOR THIS RATE CASE? 23 A. The ECRR Projects’ costs currently being recovered in the ECRR are part of the rate base 24 used to determine the 2017 Test Year revenue requirement. This includes all gross plant 25 in service, accumulated depreciation, and associated deferred income tax balances. 26
3 Docket No. EL18-___ Haugen Direct
1 Q. WHAT IS THE IMPACT TO CUSTOMERS? 2 A. Moving these projects from the ECRR into base rates is merely a change to how the costs 3 of the projects are recovered. If approved, OTP’s South Dakota customers will no longer 4 pay for the ECRR Projects through the ECRR. Instead, customers will pay for the ECRR 5 Projects through base rates. 6 7 Q. WHAT ARE THE PRIMARY TEST YEAR COST COMPONENTS THAT ARE 8 AFFECTED BY INCLUDING THESE PROJECTS IN BASE RATES? 9 A. The primary rate base components are: (i) gross plant in service; (ii) accumulated 10 depreciation; and (iii) accumulated deferred income taxes. The primary operating 11 expense components that are impacted include: (i) depreciation and (ii) general tax 12 expenses. 13 14 Q. WHAT ARE THE 2017 TEST YEAR PLANT IN SERVICE BALANCES FOR THE 15 ECRR PROJECTS? 16 A. The 2017 Test Year reflects the December 31, 2017, 13-month average gross plant in 17 service balance of approximately $204.2 million (OTP Total) and $19.1 million (OTP 18 SD) for the AQCS project and approximately $6.5 million (Total Plant and OTP Total) 19 and $0.6 million (OTP SD) for the HLP MATS project. A summary of the 13-month 20 average gross plant in-service amounts rolling in to base rates is included as 21 Exhibit___(BCH-1), Schedule 2. 22 23 Q. ARE THESE THE FINAL COSTS OF THESE INVESTMENTS? 24 A. Yes. In his Direct Testimony, OTP witness Mr. Phinney explains that the final cost of the 25 AQCS project was $365.5 million (Total Plant) and that the final cost of the HLP MATS 26 project was $7.145 million (Total Plant and OTP Total).1 It is these final project costs 27 that drive the 13-month average plant balances included in the 2017 Test Year.
1 During the course of the AQCS and HLP MATS projects, there were costs of removal for facilities removed from the plants due to the scope of the projects. While the final, total costs of the projects include removal costs (which are collected in depreciation rates), the project investments reflected in the ECRR do not contain the costs of
4 Docket No. EL18-___ Haugen Direct
1 Q. WHEN WILL OTP TRANSFER THESE PROJECT COSTS OUT OF THE ECRR AND 2 INTO RATE BASE? 3 A. OTP proposes to transfer these project costs out of the ECRR and into rate base at the 4 time OTP’s proposed Interim Rates go into effect. A corresponding adjustment to the 5 ECRR charge is included with this filing to reflect the transfer of the net plant in-service 6 value of the ECRR Projects out of the ECRR. From that point forward, recovery of the 7 ECRR Projects will be in base rates. I provide additional discussion below of the 8 adjustment to the ECRR charge being made as part of this case. 9 10 Q. WHAT WILL HAPPEN TO THE ECRR CHARGE AT THE CONCLUSION OF THIS 11 CASE? 12 A. At the conclusion of the case, OTP proposes that the ECRR charge be adjusted to zero as 13 of the implementation of final rates. OTP proposes that any over or under collection 14 balance in the ECRR at the time final rates go into effect be included as part of the 15 Interim Rate refund. 16 17 Q. WHY DOES OTP PROPOSE TO RECOVER OR RETURN THE TRACKER 18 BALANCE TO CUSTOMERS THROUGH THE INTERIM RATE REFUND? 19 A. The ECRR tracker account balance is expected to be at or near zero at the end of the 20 Interim Rate period. The approach proposed by OTP allows for timely and accurate 21 collection for the ECRR tracker and for zeroing out the ECRR tracker with no over or 22 under recovery of the tracker balance. 23 24 Q. ARE THERE ANY TEST YEAR ADJUSTMENTS ASSOCIATED WITH OTP’S 25 PROPOSAL TO MOVE THE ECRR PROJECTS INTO BASE RATES? 26 A. Yes. The TY-14 adjustment removes $2,374,465 of 2017 actual revenues (as collected 27 through the ECRR) associated with the ECRR Projects from the 2017 Actual Year in 28 arriving at the 2017 Test Year, resulting in a corresponding decrease to the 2017 Test
removal, resulting in lower investment amounts reflected in the ECRR. The plant balance amounts in the ECRR include AFUDC.
5 Docket No. EL18-___ Haugen Direct
1 Year net operating income. This results in a decrease to the total available for return and 2 an increase to the deficiency in the 2017 Test Year. The calculation of the 2017 actual 3 ECRR revenues is shown in Exhibit___(BCH-1), Schedule 3. 4 5 Q. WHY IS THIS ADJUSTMENT NECESSARY? 6 A. This adjustment is necessary to calculate the total available for return from base rates in 7 the 2017 Test Year. While the TY-14 adjustment increases the 2017 Test Year base rate 8 deficiency, as explained above, the adjustment (and OTP’s proposal to roll the ECRR 9 Projects into base rates) does not result in a significant change to customers’ overall bills.
10 2. ECRR Adjustment 11 Q. PLEASE DESCRIBE OTP’S PROPOSED ADJUSTMENT TO THE ECRR CHARGE. 12 A. OTP’s current ECRR charge was approved in Docket No. EL17-035.2 The current ECRR 13 charge is based on the rate of return and South Dakota allocation factors approved in 14 OTP’s last general rate case3 and in the absence of an update, would remain in place 15 through October 2018. 16 OTP proposes to adjust the ECRR charge by: (1) removing the ECRR Projects 17 from the ECRR; and (2) returning the ECRR tracker balance to customers over the 18 Interim Rate period, which is anticipated to begin May 21, 2018 and continue through the 19 implementation of final rates. OTP forecasts the ECRR tracker balance to be a credit to 20 customers of $189,296 as of May 20, 2018. The adjusted ECRR charge passes the tracker 21 balance back to customers over the Interim Rate period through an ECRR credit of 22 $0.00075 per kWh. Exhibit___(BCH-1), Schedule 4 provides the adjusted ECRR charge 23 calculation. OTP provides Tariff Schedule 13.08 in Volume 3, Section 1, of this filing 24 detailing the ECRR charge to be implemented on May 21, 2018. 25
2 In the Matter of the Petition of Otter Tail Power Company For Approval of the Environmental Cost Recovery Charge, Docket No. EL17-035, Order Approving Environmental Cost Recovery Rider Charge, October 13, 2017. 3 In the Matter of the Application by Otter Tail Power Company for Authority to Increase Rates for Electric Service in South Dakota, Docket No. EL10-011, Order Approving the Joint Motion for Approval of the Settlement Stipulation, March 14, 2011.
6 Docket No. EL18-___ Haugen Direct
1 Q. HOW LONG WILL THE UPDATED ECRR CHARGE REMAIN IN EFFECT? 2 A. OTP proposes the updated ECRR charge remain in place until the implementation of 3 final rates in this case. OTP anticipates final rates will be implemented on 4 January 1, 2019.
5 B. TCRR 6 Q. WHAT IS THE TCRR? 7 A. SDCL §§ 49-34A-25.1 through 49-34A-25.4 authorize the Commission to approve a 8 rider to recover capital costs related to certain transmission investments and for the 9 recovery of regional transmission organization (RTO) projects that are subject to cost 10 sharing. OTP’s TCRR is such a rider. OTP’s TCRR was established in Docket No. EL10- 11 015. 12 13 Q. PLEASE IDENTIFY OTP’S PAST TCRR FILINGS. 14 A. OTP’s prior TCRR filings are shown in Table 2 below: 15 16 Table 2 17 TCRR – History TCRR History Docket Number Commission Approved Effective Date Initial TCRR Charge EL10-015 November 30, 2011 December 1, 2011 and Mechanism First Revision* EL12-017 April 24, 2013 March 27, 2012 Second Revision EL12-054 April 24, 2013 May 1, 2013 Third Revision EL13-029 February 21, 2014 March 1, 2014 Fourth Revision EL14-090 February 24, 2015 March 1, 2015 Fifth Revision EL15-045 February 22, 2016 March 1, 2016 Sixth Revision EL16-035 February 17, 2017 March 1, 2017 Seventh Revision EL17-048 February 28, 2018 March 1, 2018 18 *Administrative change for consistency in header and footers with other tariff sheets. 19 20 Q. WHAT IS OTP’S PROPOSAL REGARDING THE TCRR IN THIS CASE? 21 A. OTP proposes to move all projects included in the TCRR as of December 31, 2017 into 22 base rates. OTP proposes this occur at the time Interim Rates go into effect. OTP 23 proposes the South Dakota retail portion of MISO and SPP revenues and expenses 24 remain in the TCRR during the interim period and at the conclusion of the case. 25
7 Docket No. EL18-___ Haugen Direct
1 Q. WHAT PROJECTS ARE CURRENTLY BEING RECOVERED IN THE TCRR? 2 A. Costs associated with the projects listed in Table 3 below (collectively, the TCRR 3 Projects) are currently being recovered in OTP’s TCRR: 4 5 Table 3 6 TCRR Projects Approved for Project Rider Recovery In Service Date Proposed Recovery Fargo to Monticello CAPX EL10-015 April 2015 Base Rates 2020 Bemidji to Grand Rapids EL10-015 August 2012 Base Rates CAPX 2020 Bemidji to Cass Lake EL10-015 August 2012 Base Rates CAPX 2020 Rugby Wind EL10-015 August 2011 Base Rates Interconnection Casselton – Buffalo 115 EL12-054 November 2017 Base Rates kV Brookings to Hampton EL14-090 March 2015 Base Rates CAPX2020 Big Stone Area EL16-035 September 2017 Base Rates Transmission to Brookings Oakes Area Transmission EL13-029 October 2015 Base Rates Improvements 7
8 1. Base Rates 9 Q. HOW HAVE THE TCRR PROJECTS BEEN HANDLED IN THE 2017 TEST YEAR 10 FOR THIS RATE CASE? 11 A. The TCRR Projects’ costs currently being recovered in the TCRR are part of the rate base 12 used to determine the 2017 Test Year revenue requirement. This includes all gross plant 13 in service, accumulated depreciation, and associated deferred income tax balances. 14 15 Q. DOES THIS PROPOSAL INCREASE COSTS TO CUSTOMERS? 16 A. No. Moving these projects from the TCRR into base rates is merely a change to how the 17 costs of the projects are recovered. If approved, OTP’s South Dakota customers will no 18 longer pay for the TCRR Projects through the TCRR. Instead, customers will pay for the 19 TCRR Projects through base rates.
8 Docket No. EL18-___ Haugen Direct
1 Q. WHAT ARE THE PRIMARY TEST YEAR COST COMPONENTS THAT ARE 2 AFFECTED BY INCLUDING THE TCRR PROJECTS IN BASE RATES? 3 A. The primary rate base components are: (i) gross plant in service; (ii) accumulated 4 depreciation; and (iii) accumulated deferred income taxes. The primary operating 5 expense components that are impacted include: (i) depreciation and (ii) general tax 6 expenses. 7 8 Q. WHAT IS THE 2017 TEST YEAR PLANT IN SERVICE BALANCE FOR THE TCRR 9 PROJECTS? 10 A. The 2017 Test Year reflects the December 31, 2017, 13-month average gross plant in 11 service for the TCRR Projects being moved into rate base of $169.3 million (OTP Total) 12 and $2.3 million (OTP SD). A detail of all the 13-month average gross plant in service 13 amounts moving into base rates is included as Exhibit___(BCH-1), Schedule 2. 4 14 15 Q. WHEN WILL OTP TRANSFER THE TCRR PROJECTS OUT OF THE TCRR AND 16 INTO RATE BASE? 17 A. OTP proposes to transfer the TCRR Projects into rate base at the time Interim Rates go 18 into effect. A corresponding adjustment to the TCRR charge is included with this filing to 19 reflect the transfer of the net plant in-service value of these projects out of the TCRR. 20 From that point forward, recovery of the TCRR Projects will be in base rates. I provide 21 additional discussion below of the adjustments to the TCRR charge being made as part of 22 this case. 23 24 Q. WILL THE TCRR BE ADJUSTED AT THE CONCLUSION OF THIS CASE? 25 A. No. As discussed in more detail below, the adjusted TCRR charge being proposed by 26 OTP as part of this case would remain in effect until February 28, 2019. OTP files its 27 annual TCRR updates on or before November 1 of each year, with rates going into effect
4 The 13-month average gross plant in-service amounts provided in Exhibit __ (BCH-1) Schedule 2 differ from those provided in Volume 4A, Section 2, Part 4, Workpaper SD-12. Schedule 2 to this testimony includes the correct 13-month average gross plant in-service amounts. OTP will update Workpaper SD-12 to reflect Schedule 2 at the earliest opportunity. OTP estimates this impact to be less than 0.07 percent of the total revenue requirement requested in this case.
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1 the following March 1. OTP will make a TCRR update filing on or before 2 November 1, 2018 detailing a new TCRR charge to be effective March 1, 2019. 3 4 Q. ARE THERE ANY TEST YEAR ADJUSTMENTS RELATED TO OTP’S PROPOSAL 5 TO MOVE THE TCRR PROJECTS INTO BASE RATES? 6 A. Yes. The TY-13 adjustment removes $245,070 of 2017 actual revenues (as collected 7 through the TCRR) associated with the TCRR Projects from the 2017 Actual Year in 8 arriving at the 2017 Test Year, resulting in a corresponding decrease to the 2017 Test 9 Year net operating income. This results in a decrease to the total available for return and 10 an increase to the deficiency in the 2017 Test Year. The calculation of the 2017 actual 11 TCRR revenues is shown in Exhibit___(BCH-1), Schedule 5. 12 13 Q. WHY IS THIS ADJUSTMENT NECESSARY? 14 A. This adjustment is necessary to calculate the total available for return from base rates in 15 the 2017 Test Year. While the TY-13 increases the 2017 Test Year base rate deficiency, 16 as explained above, the adjustment (and OTP’s proposal to roll the TCRR Projects into 17 base rates) does not result in a significant change to customers’ overall bills.
18 2. TCRR Adjustment 19 Q. PLEASE DESCRIBE OTP’S PROPOSED ADJUSTMENT TO THE TCRR CHARGES. 20 A. OTP’s current TCRR charges were approved in Docket No. EL17-048. 5 The TCRR 21 charge updates in that case took effect March 1, 2018. These charges are based on the 22 rate of return and South Dakota allocation factors approved in OTP’s last general rate 23 case and in the absence of an update, would remain in effect through February 2019. 24 OTP proposes to adjust the TCRR charges by: (1) removing the TCRR Project 25 investments from the TCRR; (2) recalculating the TCRR charges based on the true-up 26 amount forecasted in the rider at the time Interim Rates go in to effect and the projected 27 RTO revenues and expenses for May 2018 through February 2019. OTP forecasts the
5 In the Matter of the Petition of Otter Tail Power Company for Approval of the Transmission Cost Recovery Rider Rate, Docket No. EL 17-048, Order Approving 2018 Transmission Cost Recovery Rate Adjustment, February 28, 2018.
10 Docket No. EL18-___ Haugen Direct
1 TCRR balance to be $1,170,601 for the May 21, 2018 through February 28, 2019 2 recovery period. The adjusted TCRR residential charge is equal to $0.421 per kWh. 3 Exhibit___(BCH-1), Schedule 6 provides the adjusted TCRR charge calculation. OTP 4 provides Tariff Schedule 13.05 in Volume 3, Section 1, of this filing detailing the TCRR 5 charges to be implemented on May 21, 2018. 6 7 Q. WHY IS IT APPROPRIATE TO ADJUST THE TCRR CHARGES AS OF MAY 21, 8 2018? 9 A. OTP’s proposed Interim Rates include the TCRR Projects investments. Allowing the 10 current TCRR to remain in effect without adjustment would result in OTP collecting 11 more revenues than required. 12 13 Q. WHY DID OTP SELECT A MAY 2018 THROUGH FEBRUARY 2019 RECOVERY 14 PERIOD FOR TCRR CHARGES? 15 A. OTP’s annual TCRR updates are filed on or by November 1 each year. Updating the 16 TCRR charges within this proceeding to be in effect through a typical TCRR recovery 17 period allows for OTP’s 2018 annual update filing to be made November 1, 2018 with 18 proposed charge updates to be effective March 1, 2019. 19 OTP proposes to continue annual update filings to the TCRR in compliance with 20 prior TCRR dockets, most notably Docket No. EL12-054.6 The initial filing for future 21 annual updates will continue to be made on or before November 1 each year with 22 proposed updates expected to be implemented March 1 of the following year. 23 24 Q. WILL THE SOUTH DAKOTA RETAIL PORTION OF MISO AND SPP REVENUES 25 AND EXPENSES REMAIN IN THE TCRR? 26 A. Yes. OTP proposes these revenues and expenses stay in the TCRR. 27
6As agreed upon in the Parties’ April 17, 2013 Settlement Stipulation, In the Matter of the Petition of Otter Tail Power Company for Approval of its 2013 Transmission Cost Recovery Eligibility and Rate Adjustment, Docket. No. EL12-054.
11 Docket No. EL18-___ Haugen Direct
1 Q. WHAT IS THE PRIMARY REASON FOR LEAVING THE SOUTH DAKOTA 2 RETAIL PORTION OF THESE RTO REVENUES AND EXPENSES IN THE TCRR? 3 A. OTP expects the amounts of RTO revenues and RTO expenses will continue to fluctuate 4 from year to year due in part to the continued growth and investment in regional cost 5 shared projects. RTO revenues and RTO expenses also continue to fluctuate as a result of 6 proceedings before the Federal Energy Regulatory Commission (FERC).7 OTP proposes 7 that any impacts of FERC’s rulings on past and future RTO revenues and expenses be 8 trued-up within the TCRR. Finally, there will be adjustments to RTO revenues and RTO 9 expenses associated with the 2017 Tax Reform and Jobs Act. Given the likelihood of 10 ongoing adjustments to RTO revenues and RTO expenses, the TCRR is an appropriate 11 recovery mechanism. 12 13 Q. PLEASE PROVIDE A SUMMARY OF THE RECENT FERC PROCEEDINGS 14 REGARDING MISO REVENUES AND EXPENSES. 15 A. On November 12, 2013 and February 12, 2015, two groups of industrial customers and 16 other stakeholders filed complaints at FERC seeking to reduce the ROE component of the 17 transmission rates that MISO Transmission Owners, including OTP, may collect under 18 the MISO Tariff. FERC issued its Final Decision on the first complaint on 19 September 28, 2016 reducing the base ROE applicable to investments under FERC’s 20 jurisdiction. The second complaint is still pending before FERC. 21 22 Q. WHAT WAS THE RESULT OF THE FERC DECISION IN THE FIRST 23 COMPLAINT? 24 A. The MISO Transmission Owners, including OTP, were required to refund to customers 25 the difference between: (i) actual revenues collected for the period November 12, 2013 to 26 February 12, 2016 and (ii) revenues over that same period calculated using the ROE 27 ordered in the September 28, 2016 Final Decision. OTP uses a forward-looking rate
7 FERC Docket No. EL 14-12-002. A final decision in this docket was issued on September 28, 2016. FERC Docket No. EL 14-12-002, 153 FERC ¶ 63,027, Final Decision (Sept. 28, 2016); FERC Docket No. EL 15-45-000. A preliminary decision in this docket was issued on June 30, 2016. FERC Docket No. EL 15-45-000, 155 FERC ¶ 63,030, Initial Decision (June 30, 2016).
12 Docket No. EL18-___ Haugen Direct
1 formula in MISO and makes an annual true-up filing with MISO. OTP’s refund 2 obligation was processed by MISO in two parts: the refund obligation associated with the 3 forecasted rate was processed in February 2017 and the refund associated with the true- 4 up was processed in June 2017. OTP included the impacts of the refund within its 2017 5 Annual Update filing to its TCRR, in Docket No. EL17-048, resulting in an $137,000 6 credit for South Dakota customers. 7 8 Q. WILL OTP APPLY THE RESULTS OF THE SECOND COMPLAINT IN A SIMILAR 9 FASHION TO THE FIRST? 10 A. Yes. OTP expects MISO to process the second complaint related settlements in the same 11 fashion as the first complaint related settlements. OTP proposes to include any second 12 complaint related settlements in the TCRR as it did with the first complaint related 13 settlements. OTP will include any such settlements in the first Annual Update to its 14 TCRR following the FERC decision and MISO settlements.
15 IV. PRODUCTION TAX CREDITS
16 Q. WHAT ARE PRODUCTION TAX CREDITS? 17 A. Production Tax Credits (PTCs) are tax credits authorized by the Internal Revenue Code 18 26 USC § 45. Owners of PTC-eligible wind turbines can claim a credit against taxable 19 income based on the amount of energy produced from those turbines. PTCs are available 20 for ten years after production commences. 21 22 Q. DOES OTP CURRENTLY RECEIVE PTCS EARNED FOR THE ENERGY 23 PRODUCTION FROM ITS WIND PROJECTS? 24 A. Yes. OTP has three major wind projects: the Langdon wind project, the Ashtabula wind 25 project and the Luverne wind project. OTP currently receives PTCs for its Ashtabula 26 wind project. OTP received PTCs for its Langdon wind project until November 2017 – 27 the date PTCs ended due to the 10-year sunset provisions – though customers have 28 continued to receive credits associated with the now expired Langdon PTCs and will 29 continue to do so until interim rates go into effect.
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1 OTP’s Luverne wind project does not receive PTCs, as OTP elected to take a one- 2 time Federal Grant payment which reduced the overall plant in service balance of the 3 project in lieu of PTCs. 4 5 Q. WHEN WILL OTP STOP RECEIVING PTCS FOR THE ASHTABULA WIND 6 PROJECT? 7 A. Due to the 10-year sunset on PTCs based on original in-service dates, OTP will stop 8 receiving PTCs for Ashtabula in October 2018. 9 10 Q. HOW DID OTP TREAT PTCS IN ITS 2017 TEST YEAR? 11 A. OTP made an adjustment to remove the Langdon and Ashtabula wind project PTCs from 12 the 2017 Test Year so that these PTCs are not included in the final rate determination.8 13 14 Q. WILL CUSTOMERS RECEIVE CREDIT FOR ALL PTCS RELATED TO THESE 15 WIND PROJECTS? 16 A. Yes. PTCs are currently credited to customers in base rates. This will continue during 17 Interim Rates for Ashtabula PTCs, which expire in October 2018. OTP made an 18 adjustment to Interim Rates to remove the PTCs related to the Langdon wind project 19 because OTP stopped receiving those PTCs in November 2017. Final rates are expected 20 to go into effect after the expiration of the Ashtabula PTCs (in October 2018), and final 21 rates in this case do not include PTCs for these wind projects. 22 23 Q. WHAT IS THE TOTAL EFFECT OF INCLUDING ASHTABULA PTCS IN INTERIM 24 RATES? 25 A. As shown in Volume 4a 2017 SD YT-11, the 2017 Actual Year includes a $3,935,633 26 (OTP Total) or $330,682 (OTP SD) credit to customers for Ashtabula PTCs, or $27,557 27 (OTP SD) on a monthly basis. While these amounts have been removed from the 2017 28 Test Year, they remain in Interim Rates.9
8 Exhibit___(TAA-1), Schedule 10 and Volume 4a 2017 SD TY-11. 9 Volume 4A_D.02.b NOI Interim Input Summary.
14 Docket No. EL18-___ Haugen Direct
1 Q. WHAT IS OTP’S PROPOSAL TO ADDRESS THE LOSS OF THE PRODUCTION 2 TAX CREDITS WHEN THEY EXPIRE FOR THE ASHTABULA WIND PROJECT? 3 A. The PTCs for OTP’s Ashtabula wind farm expire in October 2018. If Interim Rates 4 remain in effect beyond October 2018, OTP proposes that the Interim Rate refund be 5 reduced by the amount of PTCs credited to customers after October 2018. 6 7 Q. PLEASE PROVIDE EXAMPLES OF OTP’S PROPOSAL. 8 A. Interim Rates are calculated with a credit of $27,557 per month related to Ashtabula 9 PTCs. OTP will stop receiving these PTCs in October 2018. If final rates for this case go 10 in to effect November 1, 2018, no adjustment for PTCs will be necessary. If, however, 11 final rates are implemented on January 1, 2019, OTP proposes that the Interim Rate 12 refund be reduced by $55,114, which is the PTCs credited to customers in November and 13 December, during Interim Rates, but that OTP did not actually realize. 14 15 Q. EXPLAIN WHY THIS APPROACH IS APPROPRIATE. 16 A. This method for handling the Ashtabula PTCs ensures that customers receive the 17 appropriate amount of credits while also ensuring that OTP is not passing back PTCs that 18 it does not earn. The reduction to the Interim Rate refund would be $27,557 per month 19 for each month after October 2018 that final rates go into effect.
20 V. ADVERTISING EXPENSE
21 Q. PLEASE DESCRIBE OTP’S TREATMENT OF ADVERTISING EXPENSE IN THE 22 2017 TEST YEAR. 23 A. Advertising expenditures that are reasonable in amount and purpose are included as 24 operating expenses in the cost of service determination for ratemaking purposes. The 25 types of advertising included are those designed to encourage energy conservation, 26 promote safety, inform and educate consumers on the utility’s financial services, 27 disseminate information on a utility’s corporate affairs to its owners.
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1 OTP excluded $370,933 (OTP Total) / $32,420 (OTP SD) from the 2017 Test 2 Year. 10 The 2017 Test Year includes $52,595 (OTP Total) / $4,597 (OTP SD) of 3 allowable advertising expenses.
4 VI. CHARITABLE CONTRIBUTIONS
5 Q. PLEASE DESCRIBE OTP’S TREATMENT OF CHARITABLE CONTRIBUTIONS IN 6 THE 2017 TEST YEAR. 7 A. OTP does not include any charitable contributions in the 2017 Test Year expenses as 8 shown on in Volume 4A Workpaper B-6, page 1.
9 VII. CCOSS AND CLASS REVENUE RESPONSIBILITIES
10 Q. PLEASE DESCRIBE THE PURPOSE OF THIS SECTION OF YOUR DIRECT 11 TESTIMONY. 12 A. In this section of Direct Testimony, I explain OTP’s 2017 Test Year embedded CCOSS 13 and proposed class revenue responsibilities. I also discuss the embedded CCOSS and 14 proposed class revenue responsibilities for the step-in rate proposal described by OTP 15 witness Mr. Stuart D. Tommerdahl.
16 A. 2017 Test Year
17 1. CCOSS 18 Q. HAS OTP PREPARED A CCOSS FOR THE 2017 TEST YEAR? 19 A. Yes. OTP prepared an embedded CCOSS that is included in Volume 4a, Section 1, 20 Part 2. 21 22 Q. DID OTP ALSO PREPARE A MARGINAL COST STUDY? 23 A. Yes. OTP witness Mr. David G. Prazak discusses the elements and use of the marginal 24 cost study in his Direct Testimony. 25
10 OTP Initial Filing, Volume 4a, Workpaper B-14, page 1 of 1.
16 Docket No. EL18-___ Haugen Direct
1 Q. ARE THE CCOSS AND THE MARGINAL COST STUDY USED FOR DIFFERENT 2 PURPOSES? 3 A. Yes. An embedded cost study, modified to consider disproportionate rate impacts, is used 4 to assign class revenue responsibility. The marginal cost study is then used to develop 5 rates within each class. Marginal costs do not impact class revenue responsibility. Mr. 6 Prazak explains in more detail the use of marginal costs for rate design in his Direct 7 Testimony. 8 9 Q. WHAT COSTS DOES THE CCOSS MEASURE? 10 A. OTP’s CCOSS is an embedded cost study, meaning it measures the 2017 Test Year cost 11 of the OTP system and all costs are fully distributed to classes. 12 13 Q. IS OTP USING THE SAME GENERAL CCOSS METHODOLOGY AS IT USED IN 14 ITS LAST SOUTH DAKOTA RATE CASE? 15 A. Generally, yes. We added a separate Base Energy (Wind) classification of production 16 plant, as wind production plant has different operating characteristics from other base 17 load or peaking generation. We also incorporated the E8760 allocator. Mr. Tommerdahl 18 discusses the development of the CCOSS allocation factors used in his Direct Testimony. 19 20 Q. WHAT DOES OTP’S 2017 TEST YEAR CCOSS SHOW REGARDING CLASS COST 21 RESPONSIBILITIES? 22 A. Table 4 below compares the present revenue responsibilities and cost responsibilities of 23 OTP’s customer classes as a percent of overall revenues. OTP’s 2017 Test Year CCOSS 24 shows that the revenue responsibility of the Residential class is currently below its cost 25 responsibility (as measured in the CCOSS). Conversely, the present revenue 26 responsibility of the General Service class is greater than its cost responsibility. 27
17 Docket No. EL18-___ Haugen Direct
1 Table 4 2 Comparison of Present Revenue Responsibility and Cost Responsibility (A) (B) (C) (D) Present Revenue Difference between Class Responsibility Cost Responsibility Present and CCOSS (B) - (C) Residential 29.94% 30.37% -0.43% Farms 2.18% 2.13% 0.06% General Service 20.81% 19.15% 1.66% Large General Service 39.05% 39.55% -0.51% Irrigation 0.07% 0.11% -0.05% Lighting 1.93% 1.95% -0.02% OPA 0.86% 0.92% -0.06% Controlled Service Water Heating 1.12% 1.44% -0.33% Controlled Service Interruptible 2.93% 3.26% -0.33% 3 Controlled Service Deferred 1.11% 1.11% 0.00% 4
5 2. Class Revenue Responsibilities 6 Q. PLEASE SUMMARIZE HOW OTP USED THE CCOSS TO DISTRIBUTE TOTAL 7 REVENUES AMONG THE CLASSES OF SERVICE. 8 A. The CCOSS is the primary guide for setting the class revenue responsibilities. However, 9 determining the appropriate class revenue responsibilities is not as simple as setting them 10 to equal the results of the CCOSS. It is necessary to consider other objectives, 11 particularly the objective of maintaining reasonable rate continuity, and mitigating 12 disproportionate or abrupt rate impacts. A more complete discussion of the rate design 13 considerations applied by OTP is contained in OTP witness Mr. Prazak’s Direct 14 Testimony. 15 16 Q. HOW DOES OTP PROPOSE TOTAL REVENUES BE ALLOCATED TO 17 CUSTOMER CLASSES? 18 A. Absent a rate case, OTP estimates 2017 normalized class revenues (including riders) are 19 $33,269,550, as shown in Column D of Table 5 below. OTP’s proposed 2017 Test Year 20 revenues are $36,628,125, as shown in Column E of Table 5. The total net dollar increase 21 for OTP’s South Dakota customers is $3,358,575 (Column F), or 10.10 percent (Column 22 G). 18 Docket No. EL18-___ Haugen Direct
1 Based on a consideration of all of OTP’s rate design objectives, OTP proposes the 2 distribution of revenue responsibilities contained in Table 5. This distribution of revenue 3 responsibilities results in a reasonable movement of each class’s revenue responsibility 4 towards class cost responsibility without producing unreasonable bill impacts. 5 6 Table 5 7 Recommended Revenue Allocation Proposed Net Revenue Impact
(A) (B) (C) (D) (E) (F) (G) Class Responsibility 2017 Normalized 2017 Normalized 2017 Normalized Proposed Net Dollar Class Base Revenues Rider Revenues Revenues 2017 Test Year Net Impact Increase without a rate case without a rate case (Base + Riders) Revenues Residential $6,164,530 $3,626,296 $9,790,826 $11,001,905 $1,211,079 12.37% Farms 430,815 287,784 718,599 796,731 78,132 10.87% General Service 4,139,061 2,700,056 6,839,117 7,516,542 677,425 9.91% Large General Service 6,484,885 6,743,201 13,228,086 14,349,607 1,121,521 8.48% Irrigation 14,107 7,432 21,540 25,337 3,798 17.63% Lighting 470,527 148,514 619,042 711,639 92,597 14.96% OPA 140,786 147,985 288,771 329,388 40,617 14.07% Controlled Service Water Heating 209,783 160,611 370,394 410,196 39,802 10.75% Controlled Service Interruptible 353,269 659,600 1,012,869 1,077,920 65,051 6.42% Controlled Service Deferred 148,874 231,433 380,307 408,860 28,553 7.51% 8 $18,556,637 $14,712,913 $33,269,550 $36,628,125 $3,358,575 10.10% 9 10 Q. PLEASE EXPLAIN HOW YOU ARRIVED AT THE TOTAL NET DOLLAR 11 INCREASE IDENTIFIED IN TABLE 5. 12 A. OTP currently receives a certain amount of base rate and rider revenue from its South 13 Dakota customers that it would continue to receive without a rate case. These amounts 14 are identified in Column B and Column C of Table 5. As discussed above, OTP proposes 15 to move certain projects currently being recovered in riders into base rates. This is a shift 16 in the recovery mechanism and does not result in a change to a customer’s overall bill. 17 Therefore, Column D, which is the sum of the base and rider revenues, provides the 18 appropriate base from which to measure the rate increase being proposed in this case. 19 Column E identifies the 2017 Test Year proposed revenues, which includes the rider 20 projects rolling into base rates. The overall bill impact that a customer will experience 21 under OTP’s proposal is shown by comparing Column E to Column D. 22
19 Docket No. EL18-___ Haugen Direct
1 Q. IF OTP’S RECOMMENDED REVENUE DISTRIBUTION IS ACCEPTED, WILL 2 THERE STILL BE DIFFERENCES BETWEEN CLASS REVENUE 3 RESPONSIBILITY AND COST RESPONSIBILITY? 4 A. Yes. OTP does not propose an unmoderated adherence to the results of the CCOSS. For 5 this reason, differences remain between OTP’s proposed class revenue responsibility and 6 cost responsibilities identified by the CCOSS. 7 8 Q. PLEASE COMPARE THE PRESENT, PROPOSED, AND CCOSS REVENUE 9 RESPONSIBILITIES. 10 A. Table 6 below provides the revenue responsibilities under present rates (Column B), 11 CCOSS (Column C), and proposed revenues (Column D). The difference between 12 proposed revenues and CCOSS (Column F) is less for all classes than the difference 13 between present rates and CCOSS (Column E), which shows that OTP’s revenue 14 apportionment proposal moves all classes closer to cost. 15 16 Table 6 17 Comparison of Proposed Revenue Responsibility to CCOSS (A) (B) (C) (D) (E) (F)
Revenue Difference between Difference Present Revenue Responsibility from Proposed Revenue Present and between Proposed Class Responsibility CCOSS Responsibility CCOSS and CCOSS (B) - (C) (D) - (C) Residential 29.94% 30.37% 30.04% -0.43% -0.33% Farms 2.18% 2.13% 2.18% 0.06% 0.05% General Service 20.81% 19.15% 20.52% 1.66% 1.37% Large General Service 39.05% 39.55% 39.18% -0.51% -0.38% Irrigation 0.07% 0.11% 0.07% -0.05% -0.04% Lighting 1.93% 1.95% 1.94% -0.02% -0.01% OPA 0.86% 0.92% 0.90% -0.06% -0.03% Controlled Service Water Heating 1.12% 1.44% 1.12% -0.33% -0.32% Controlled Service Interruptible 2.93% 3.26% 2.94% -0.33% -0.32% 18 Controlled Service Deferred 1.11% 1.11% 1.12% 0.00% 0.0% 19
20 B. Step Increase Rate Proposal 21 Q. HAS OTP PREPARED A CCOSS FOR THE STEP INCREASE RATE PROPOSAL? 22 A. Yes. OTP prepared an embedded CCOSS that is included in Volume 4a, Section 5, 23 Part 2. 20 Docket No. EL18-___ Haugen Direct
1 Q. IS OTP PROPOSING TO CHANGE ITS RECOMMENDED CLASS REVENUE 2 RESPONSIBILITIES WHEN THE STEP INCREASE GOES INTO EFFECT? 3 A. No. We recommend that each class maintain the same revenue responsibility (as a 4 percentage of total revenues) between the 2017 Test Year and the step increase. As 5 explained by OTP witnesses Mr. Bruce G. Gerhardson and Mr. Tommerdahl, the step 6 increase proposal is a targeted approach to avoid the cost and expense of a full rate case. 7 Mr. Gerhardson and Mr. Tommerdahl also explain that OTP anticipates filing a rate case 8 in the 2021 timeframe to coincide with the Astoria Station project coming online. We 9 therefore believe it is not administratively efficient to develop and implement a new 10 revenue allocation addressing the step increase. 11 Table 7 below identifies the allocation of overall revenues reflecting the step 12 increase rate proposal to customer classes. 13 14 Table 7 15 Step Increase Rate Proposal Class Revenue Responsibilities (A) (B) (C) (D) (E) 2017 Test Year 2017 Test Year 2017 Test Year Proposed Revenue Proposed 2017 Test Year Step Step Proposed a Class Responsibility Revenues Revenues Revenues (B)*Total Step-In Revenue (C) + (D) Residential 30.04% $11,001,905 $188,964 $11,190,869 Farms 2.18% 796,731 13,684 810,416 General Service 20.52% 7,516,542 129,101 7,645,643 Large General Service 39.18% 14,349,607 246,462 14,596,069 Irrigation 0.0692% 25,337 435 25,772 Lighting 1.9429% 711,639 12,223 723,862 OPA 0.90% 329,388 5,657 335,045 Controlled Service Water Heating 1.12% 410,196 7,045 417,241 Controlled Service Interruptible 2.94% 1,077,920 18,514 1,096,434 Controlled Service Deferred 1.12% 408,860 7,022 415,882 16 Total 100.00% $36,628,125 $629,108 $37,257,233 17 a OTP Initial Filing, 2017 Step COSS, Volume 4a, Section 5, Part 1 18
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1 VIII. CONCLUSION
2 Q. WHAT ARE YOUR CONCLUSIONS? 3 A. OTP’s proposal to move capital projects from riders to base rates is reasonable and 4 appropriate. OTP has correctly adjusted the 2017 Test Year for PTCs and advertising 5 expenses. The 2017 Test Year does not include any charitable contributions. OTP’s 6 CCOSS is a reasonable basis for designing rates, and OTP’s recommended class revenue 7 allocation is reasonable and should be adopted. 8 9 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 10 A. Yes, it does.
22 Docket No. EL18-___ Haugen Direct Docket No. EL18-___ Exhibit__(BCH-1), Schedule 1 Page 1 of 1
Mr. Bryce C. Haugen Senior Rates Analyst, Regulatory Administration Otter Tail Power Company 215 South Cascade Street Fergus Falls, Minnesota 56537 218-739-8385
CURRENT RESPONSIBILITIES: (November 2015 to Present)
Provide leadership for rates analysts for the preparation and financial analysis used to determine revenue requirements associated with various state and federal cost recovery mechanisms and to lead development of regulatory filings associated with these cost recovery mechanisms. Primary state responsibilities are related to the environmental, renewable, and transmission cost recovery riders.
PREVIOUS POSITIONS:
Otter Tail Power Company 2015 - Present Senior Rates Analyst, Regulatory Administration 2013 - 2015 Rates Analyst, Regulatory Administration 2012 - 2013 Credit Risk Analyst, Risk Management 2012 – 2012 Business Assistant, Project Management
Baker Boy Bake Shop Inc., Dickinson, ND 2010 - 2012 Supervisor, Production 2009 - 2010 Cost Accountant, Accounting
Theodore Roosevelt Medora Foundation, Medora, ND 2006 - 2009 Operations Manager 2005 - 2006 Assistant Operations Manager
EDUCATION / CERTIFICATIONS Minnesota State Community & Technical College – Fergus Falls, MN – Associate of Arts Minnesota State University Moorhead – Moorhead, MN - B.S. in Finance National University – La Jolla, CA – Masters of Science in Organizational Leadership
OTTER TAIL POWER COMPANY Docket No. EL18-___ Exhibit __(BCH-1), Schedule 2 Electric Utility - State of South Dakota Page 1 of 1 RIDER ROLL-IN SUMMARY SCHEDULE
2017 Test Year Line 13 MA 13 MA No. OTP Total OTP SD 1 ECRR Projects 2 Gross Plant In Service: 3 Big Stone Plant AQCS $204,237,395 $19,079,099 4 HLP MATS 6,528,410 $609,860 5 Total Gross Plant In Service $210,765,805 $19,688,959 6 7 TCRR Projects 8 Gross Plant In Service: 9 CAPX 2020: Fargo $81,454,933 $730,850 10 CAPX 2020: Bemidji 16,331,201 194,019 11 Cass Lake-Nary-Helga-Bemidji 7,039,948 209,094 12 Rugby Wind Interconnection 394,399 6,174 13 Casselton – Buffalo 115 kV Project 8,906,720 419,599 14 CAPX 2020: Brookings - Hampton 26,326,560 16,133 15 Big Stone Area Transmission to Brookings* 21,819,111 32,775 16 Oakes Area Transmission Improvements 7,010,020 644,041 17 Total Gross Plant In Service $169,282,892 $2,252,686
*Because OTP is using a 13 month average balance, we are understating the plant in service amount for the Big Stone Area Transmission to Brookings project shown in this Schedule, as the project went into service in September 2017. Otter Tail Power Company Docket No. EL18-___ Environmental Cost Recovery Rider Exhibit__(BCH-1), Schedule 3 South Dakota Page 1 of 1
Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 2017 Line TRACKER SUMMARY January February March April May June July August September October November December YE No. Requirements Compared to Billed: Actual Actual Acual Actual Actual Actual Actual Actual Actual Projected Actual Actual Projected Revenue Requirements 1 Air Quality Control System 185,464 185,010 185,325 187,179 185,572 185,688 185,456 186,547 186,197 184,658 184,540 185,612 2,227,248 2 Hoot Lake Plant MATS Project 12,553 12,553 12,553 12,173 12,173 12,173 12,173 12,173 12,173 12,173 12,173 12,173 147,217 3 Total Revenue Reguirements 198,017 197,564 197,879 199,352 197,745 197,861 197,629 198,720 198,370 196,831 196,713 197,785 2,374,465 4 Docket No. EL18-___ Otter Tail Power Company Exhibit__ (BCH-1), Schedule 4 Environmental Cost Recovery Rider Page 1 of 2 South Dakota
Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 2017 Line TRACKER SUMMARY January February March April May June July August September October November December YE No. Requirements Compared to Billed: Actual Actual Acual Actual Actual Actual Actual Actual Actual Projected Actual Actual Projected Revenue Requirements 1 Air Quality Control System 185,464 185,010 185,325 187,179 185,572 185,688 185,456 186,547 186,197 184,658 184,540 185,612 2,227,248 2 Hoot Lake Plant MATS Project 12,553 12,553 12,553 12,173 12,173 12,173 12,173 12,173 12,173 12,173 12,173 12,173 147,217 3 Total Revenue Reguirements 198,017 197,564 197,879 199,352 197,745 197,861 197,629 198,720 198,370 196,831 196,713 197,785 2,374,465 4 5 South Dakota Filing Fee 241 241 241 241 241 241 241 241 241 241 255 255 2,920 6 7 Net Revenue Requirement 198,258 197,804 198,120 199,593 197,986 198,102 197,870 198,961 198,611 197,072 196,968 198,040 2,377,385 8 9 Billed (forecast kWh x adj factor) 237,959 229,793 198,276 192,381 161,606 168,563 172,926 182,428 178,171 159,882 178,175 186,698 2,246,858 10 11 Difference (39,701) (31,988) (156) 7,212 36,380 29,539 24,943 16,533 20,440 37,190 18,793 11,342 130,527 12 Carrying Charge (1,885) (2,145) (2,358) (2,374) (2,344) (2,131) (1,960) (1,816) (1,724) (1,607) (1,385) (1,276) (23,007) 13 Cummulative Difference (343,219) (377,352) (379,867) (375,029) (340,993) (313,585) (290,602) (275,885) (257,170) (221,587) (204,179) (194,113) 14 15 Carrying Charge Calculation (2,145) (2,358) (2,374) (2,344) (2,131) (1,960) (1,816) (1,724) (1,607) (1,385) (1,276) (1,213) 16 Cumulative Carrying Charge (4,030) (6,389) (8,763) (11,107) (13,238) (15,198) (17,014) (18,739) (20,346) (21,731) (23,007) (24,220) 17 Carrying cost 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 18 19 20 Forecasted Sales (MWh) 34,372 33,052 30,383 34,714 37,836
Approved SD Docket EL 16-030; October 31, 2016 Nov 2016 - Oct SUMMARY 2017
Revenue Requirements $2,537,097 Carrying Charge (14,767) 2015 - 2016 True Up (284,465) Total Revenue Requirements $2,237,865
Oct 2016 - Sept 2017 projected sales in mWh 417,441
Average Charge $0.00536 Docket No. EL18-___ Otter Tail Power Company Exhibit__ (BCH-1), Schedule 4 Environmental Cost Recovery Rider Page 2 of 2 South Dakota
2018 Line TRACKER SUMMARY January February March April May 1 - 20 May 21 - 31 June July August September October November December YE May - Dec No. Requirements Compared to Billed: Actual Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Recovery Revenue Requirements 1 Air Quality Control System 182,793 182,793 182,793 182,793 117,931 0 0 0 0 0 0 0 0 849,103 0 2 Hoot Lake Plant MATS Project 11,364 11,364 11,364 11,364 7,332 0 0 0 0 0 0 0 0 52,790 0 3 Total Revenue Reguirements 194,157 194,157 194,157 194,157 125,263 0 0 0 0 0 0 0 0 901,893 0 4 5 South Dakota Filing Fee 255 255 255 255 165 90 255 255 255 255 255 0 0 2,550 1,365 6 7 Net Revenue Requirement 194,412 194,412 194,412 194,412 125,427 90 255 255 255 255 255 0 0 904,443 1,365 8 9 Billed (forecast kWh x adj factor) 226,547 218,697 185,735 162,416 93,314 (7,916) (22,498) (24,756) (26,766) (24,039) (24,115) (27,674) (31,531) 697,414 (189,296) 10 11 Difference (32,135) (24,285) 8,678 31,997 32,113 8,006 22,753 25,011 27,021 24,294 24,370 27,674 31,531 151,689 190,661 12 Carrying Charge (1,213) (1,422) (1,582) (1,538) (1,348) (1,155) (1,112) (977) (827) (663) (516) (367) (196) (12,916) (5,813) 13 Cummulative Difference (227,461) (253,167) (246,072) (215,613) (184,848) (177,997) (156,356) (132,322) (106,129) (82,497) (58,643) (31,335) (0) (0) (0) 14 15 Carrying Charge Calculation (1,422) (1,582) (1,538) (1,348) (1,155) (1,112) (977) (827) (663) (516) (367) (196) (0) 16 Cumulative Carrying Charge (25,642) (27,224) (28,762) (30,110) (31,265) (32,377) (33,355) (34,182) (34,845) (35,360) (35,727) (35,923) (35,923) 17 Carrying cost 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 7.50% 18 19 20 Forecasted Sales (MWh) 44,162 45,234 38,416 33,593 19,300 10,615 30,171 33,199 35,894 32,238 32,340 37,112 42,285 434,559 253,854
Approved SD Docket EL 17-035; Oct 13, 2017 Nov 2017 - Proposed Charge May 21, 2018 - SUMMARY Oct 2018 SUMMARY Dec 2018
Revenue Requirements $2,310,096 Revenue Requirements $1,365
Carrying Charge (11,997) Carrying Charge (5,813) True Up (216,397) True Up (184,848) Total Revenue Requirements $2,081,702 Total Revenue Requirements ($189,296)
May 21, 2018 - Dec 2018 Nov 2017 - Oct 2018 projected sales in mWh 430,563 projected sales in mWh 253,854 Average Charge $0.00483 Average Charge ($0.00075) Otter Tail Power Company Docket No. EL18-___ Transmission Cost Recovery Rider Exhibit__(BCH-1) Schedule 5 South Dakota Page 1 of 1
Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 Line TRACKER SUMMARY January February Collection March April May June July August September October November December YE No. Requirements Compared to Billed: Actual Actual Period Actual Actual Actual Actual Actual Actual Actual Actual Actual Actual Actual Revenue Requirements ck 1 CAPX 2020 Fargo 7,294 7,599 89,286 7,292 7,291 7,341 7,292 7,292 7,305 7,293 7,293 7,293 7,292 87,877 2 CAPX 2020 Bemidji 1,889 1,905 23,721 1,889 1,872 1,894 1,889 1,915 1,922 1,889 1,889 1,901 1,889 22,740 3 Cass Lake-Nary-Helga-Bemidji 2,020 2,020 24,135 2,020 2,020 2,020 2,020 2,020 2,020 2,020 2,020 2,020 2,020 24,240 4 Rugby Wind Interconnection 48 48 574 48 48 48 48 48 48 48 48 48 48 575 5 Casselton – Buffalo 115 kV 3,366 3,366 40,300 3,366 3,366 3,366 3,366 3,366 3,366 3,366 3,366 3,366 3,366 40,397 6 Oakes Area Transmission 5,618 5,618 68,430 5,618 5,618 5,475 5,618 5,618 5,618 5,618 5,618 5,618 5,618 67,276 7 CAPX 2020 - Brookings 163 165 2,004 163 163 166 163 163 164 163 163 165 164 1,965 8 BSAT - Brookings 9 10 Total Revenue Requirements 20,399 20,722 248,450 20,397 20,378 20,310 20,396 20,422 20,444 20,397 20,397 20,411 20,398 245,070 11 Otter Tail Power Company Docket No. EL18-___ Transmission Cost Recovery Rider Exhibit__(BCH-1), Schedule 6 South Dakota Page 1 of 3
Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2018 2018 2018 Line TRACKER SUMMARY March April May June July August September October November December YE January February Collection No. Requirements Compared to Billed: Actual Actual Actual Actual Actual Actual Actual Actual Actual Actual Actual Actual Projected Period Revenue Requirements ck 1 CAPX 2020 Fargo 7,292 7,291 7,341 7,292 7,292 7,305 7,293 7,293 7,293 7,292 87,877 6,614 6,578 86,175 2 CAPX 2020 Bemidji 1,889 1,872 1,894 1,889 1,915 1,922 1,889 1,889 1,901 1,889 22,740 1,725 1,719 22,390 3 Cass Lake-Nary-Helga-Bemidji 2,020 2,020 2,020 2,020 2,020 2,020 2,020 2,020 2,020 2,020 24,240 1,838 1,838 23,876 4 Rugby Wind Interconnection 48 48 48 48 48 48 48 48 48 48 575 43 43 566 5 Casselton – Buffalo 115 kV 3,366 3,366 3,366 3,366 3,366 3,366 3,366 3,366 3,366 3,366 40,397 5,815 5,815 45,294 6 Oakes Area Transmission 5,618 5,618 5,475 5,618 5,618 5,618 5,618 5,618 5,618 5,618 67,276 5,014 5,014 66,068 7 CAPX 2020 - Brookings 163 163 166 163 163 164 163 163 165 164 1,965 147 147 1,930 8 BSAT - Brookings 899 898 1,797 9 10 Total Revenue Requirements 20,397 20,378 20,310 20,396 20,422 20,444 20,397 20,397 20,411 20,398 245,070 22,094 22,052 248,095 11 12 SD Filing Fee 802 802 802 802 802 802 802 802 802 802 8,863 802 802 9,628 13 14 Preservation of ADIT Proration 159 159 1,913 15 16 MISO & SPP Expenses 17 MISO Schedule 26 Expense 141,851 95,016 67,701 86,837 98,951 101,011 97,108 85,838 140,449 131,372 1,180,059 121,178 110,540 1,277,853 18 MISO Schedule 26A Expense 50,573 41,711 38,631 41,199 42,937 47,965 42,084 41,858 53,907 47,430 583,439 69,823 64,150 582,268 19 SPP Schedule 7,8, or 9 Expense 53,178 31,536 29,205 25,181 39,022 26,044 28,527 27,611 26,943 27,567 377,825 7,668 19,112 341,596 20 SPP Schedule 11 Expense 1,882 1,487 1,184 954 1,474 918 1,281 824 945 952 14,291 317 1,611 13,830 21 Total MISO & SPP Expenses 247,484 169,750 136,721 154,172 182,384 175,938 169,000 156,132 222,244 207,322 2,155,614 198,986 195,414 2,215,546 22 23 MISO Revenues 24 MISO Schedule 9 Revenue (134,002) (29,035) (8,811) (9,783) (13,274) (12,525) (10,253) (13,524) (22,872) (25,047) (326,919) (23,276) (3,287) (305,690) 25 MISO Schedule 26 Revenue (25,074) (19,018) (21,159) (26,505) (28,797) (26,696) (26,863) (21,352) (22,001) (22,999) (259,226) (24,188) (24,006) (288,659) 26 MISO Schedule 37 Revenue (165) (166) (187) (163) (163) (163) (163) (163) (163) (163) (1,852) (157) (0) (1,815) 27 MISO Schedule 38 Revenue (202) (202) (225) (199) (198) (198) (198) (198) (198) (198) (2,227) (197) (0) (2,214) 28 MISO Schedule 26A Revenue (506) (476) (499) (581) (638) (649) (551) (514) (497) (470) (6,536) (1,500) (1,423) (8,304) 29 MISO MVP ARR Revenue (373) (168) (153) (138) (304) (185) (67) (53) (61) (75) (2,364) (543) (340) (2,457) 30 Total MISO Revenues (160,322) (49,064) (31,033) (37,370) (43,373) (40,417) (38,095) (35,804) (45,792) (48,952) (599,123) (49,860) (29,056) (609,138) 31 32 Net Revenue Requirement 108,360 141,866 126,800 138,000 160,235 156,768 152,104 141,527 197,665 179,570 1,810,424 172,181 189,372 1,866,044 33 34 Billed (forecast kWh x adj factor) 176,902 171,123 143,162 150,870 156,565 164,263 159,244 141,277 177,931 186,929 2,008,935 226,428 222,240 2,076,935 35 36 Difference (68,541) (29,257) (16,362) (12,870) 3,670 (7,495) (7,140) 250 19,735 (7,359) (198,511) (54,247) (32,868) (212,485) 37 Carrying Charge (107) (542) (730) (838) (925) (907) (961) (1,012) (1,017) (898) (7,117) (951) (1,332) (10,220) 38 Life-to-Date Revenue Requirement (Cumulative Difference)(85,623) (115,421) (132,513) (146,221) (143,476) (151,879) (159,980) (160,741) (142,023) (150,281) (150,281) (205,478) (239,678) 39 40 Carrying Charge Calculation (542) (730) (838) (924.85) (907.49) (961) (1,012) (1,017) (898) (951) (1,332) (1,554) (11,666) 41 Cumulative Carrying Charge 3,995 3,265 2,427 1,502 595 (366) (1,378) (2,394) (3,293) (4,243) (5,575) (7,129) (12,593) 42 Carrying cost 7.59% 7.59% 7.59% 7.59% 7.59% 7.59% 7.59% 7.59% 7.59% 7.59% 7.78% 7.78% 43 44 45 Forecasted Sales (MWh) 45,234 45,234
Rates effective March 1, 2017 - February 28, 2018; Commission Approved February 17, 2017; Mar 2017 - SUMMARY Feb 2018
Revenue requirements $2,146,128 Carrying Charge (4,049) 2016 True-Up (88,873) Total requirements $2,053,206
Mar 2017-Feb 2018 projected sales in MWh 417,898 Average Charge $0.00491 Otter Tail Power Company Docket No. EL18-___ Transmission Cost Recovery Rider Exhibit__(BCH-1), Schedule 6 South Dakota Page 2 of 3
Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 2018 2018 2018 2018 2018 2018 2018 2018 2018 2018 2018 2019 2019 2019 Line TRACKER SUMMARY March April May June July August September October November December YE January February Collection No. Requirements Compared to Billed: Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Period Revenue Requirements ck 1 CAPX 2020 Fargo 6,638 6,578 4,244 30,652 4,244 2 CAPX 2020 Bemidji 1,846 1,719 1,109 8,117 1,109 3 Cass Lake-Nary-Helga-Bemidji 1,838 1,838 1,186 8,537 1,186 4 Rugby Wind Interconnection 43 43 28 202 28 5 Casselton – Buffalo 115 kV 5,815 5,818 3,754 27,017 3,754 6 Oakes Area Transmission 5,014 5,014 3,235 23,290 3,235 7 CAPX 2020 - Brookings 148 147 95 683 95 8 BSAT - Brookings 898 899 581 4,175 581 9 0 10 Total Revenue Requirements 22,241 22,056 14,230 0 0 0 0 0 0 0 102,673 0 0 14,230 11 12 SD Filing Fee 417 417 417 417 417 417 417 417 417 417 5,771 417 417 4,167 13 14 Preservation of ADIT Proration 15 16 MISO & SPP Expenses 17 MISO Schedule 26 Expense 105,572 90,668 76,470 80,214 93,002 93,002 80,214 90,677 93,002 116,253 1,150,793 111,032 101,875 935,741 18 MISO Schedule 26A Expense 62,441 54,826 49,968 47,189 51,147 51,136 48,917 51,431 57,316 63,978 672,324 76,449 68,525 566,058 19 SPP Schedule 7,8, or 9 Expense 19,112 19,112 18,678 17,889 17,889 17,889 17,889 17,889 17,889 17,889 208,907 18,068 18,068 180,037 20 SPP Schedule 11 Expense 1,611 1,611 1,575 1,508 1,508 1,508 1,508 1,508 1,508 1,508 17,283 1,523 1,523 15,179 21 Total MISO & SPP Expenses 188,737 166,217 146,691 146,801 163,547 163,535 148,529 161,506 169,716 199,628 2,049,307 207,072 189,991 2,051,969 22 23 MISO Revenues 24 MISO Schedule 9 Revenue (14,970) (10,014) (6,468) (5,214) (7,972) (5,719) (4,643) (8,834) (10,923) (15,215) (116,539) (10,463) ($5,286) (80,739) 25 MISO Schedule 26 Revenue (24,006) (24,006) (23,461) (22,469) (22,469) (22,469) (22,469) (22,469) (22,469) (22,469) (276,953) (21,543) (21,543) (223,832) 26 MISO Schedule 37 Revenue (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (157) (0) (0) (0) 27 MISO Schedule 38 Revenue (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (197) (0) (0) (0) 28 MISO Schedule 26A Revenue (1,411) (1,399) (1,382) (1,349) (1,370) (1,375) (1,337) (1,323) (1,317) (1,307) (16,492) (1,528) (1,499) (13,787) 29 MISO MVP ARR Revenue (340) (340) (332) (318) (318) (318) (318) (318) (318) (318) (4,118) (318) (318) (3,192) 30 Total MISO Revenues (40,726) (35,758) (31,643) (29,351) (32,129) (29,881) (28,768) (32,945) (35,027) (39,309) (414,455) (33,851) (28,645) (321,550) 31 32 Net Revenue Requirement 170,668 152,931 129,695 117,867 131,834 134,071 120,177 128,977 135,105 160,736 1,743,296 173,638 161,762 1,393,862 33 34 Billed (forecast kWh x adj factor) 158,213 138,349 96,855 97,682 107,484 116,211 104,373 104,703 120,154 136,901 1,629,595 144,710 141,527 1,170,601 35 36 Difference 12,455 14,582 32,840 20,185 24,349 17,859 15,804 24,275 14,951 23,834 113,701 28,928 20,235 223,261 37 Carrying Charge (1,554) (1,483) (1,398) (1,194) (1,071) (920) (811) (713) (561) (467) (12,456) (316) (130) (7,583) 38 Life-to-Date Revenue Requirement (Cumulative Difference)(228,777) (215,678) (184,236) (165,246) (141,968) (125,029) (110,036) (86,474) (72,084) (48,717) (20,105) 0 (953,896) 39 40 Carrying Charge Calculation (1,483) (1,398) (1,194) (1,071) (920) (811) (713) (561) (467) (316) (130) 0 (6,184) 41 Cumulative Carrying Charge (8,613) (10,011) (11,205) (12,277) (13,197) (14,008) (14,721) (15,282) (15,749) (16,065) (16,195) (16,195) (144,894) 42 Carrying cost 7.78% 7.78% 7.78% 7.78% 7.78% 7.78% 7.78% 7.78% 7.78% 7.78% 7.78% 7.78% 43 44 45 Forecasted Sales (MWh) 38,416 33,593 29,916 30,171 33,199 35,894 32,238 32,340 37,112 42,285 390,397 44,697 43,714 361,565
Rates effective March 1, 2018 - February 28, 2019; Commission Approved February 28, 2018; Proposed May 21, 2018 - February 28, 2019 Mar 2018 - May 2018 - SUMMARY Feb 2019 SUMMARY Feb 2019
Revenue requirements $1,997,460 Revenue requirements $1,393,862 Carrying Charge (10,148) Carrying Charge (7,583) True-Up (208,321) True-Up (215,678) Total requirements $1,778,991 Total requirements $1,170,601
Mar 2018-Feb 2019 projected sales in MWh 431,959 May 2018-Feb 2019 projected sales in MWh 361,565 Average Charge $0.00412 Average Charge $0.00324 Otter Tail Power Company Docket No. EL18-___ Transmission Cost Recovery Rider Exhibit__(BCH-1), Schedule 6 South Dakota Page 3 of 3
Class Allocation and Rate Design
Line May '18 - No. Recovery Period Feb '19
1 Total South Dakota Revenue Requirements $1,170,601
2 Large General Service Class 42.5% $497,999 3 Controlled Service 1.5% $17,908 4 Lighting 0.7% $7,899 5 All Other Service 55.25% $646,794
6 Total $1,170,601
7 Large General Service Class kW** 323,942 8 Large General Service Class kWh** 178,299,749
9 Controlled Service kWh 25,985,110 10 Lighting kWh 3,615,463 11 All Other Service kWh 153,664,730
12 Large General Service Class $ / kW 0.538 13 Large General Service Class cents / kWh 0.182
14 Controlled Service cents / kWh 0.069 15 Lighting cents / kWh 0.218 16 All Other Service cents / kWh 0.421
* Jurisdictional transmission allocation factor (D2 = 9.187%) is proposed in Otter Tail's general rate case in South Dakota Docket No. EL18-__. ** LGS revenue is 35% demand and 65% energy
Volume 2A
Direct Testimony and Supporting Schedules
Kevin G. Moug
Before the South Dakota Public Utilities Commission State of South Dakota
In the Matter of the Application of Otter Tail Power Company For Authority to Increase Rates for Electric Utility Service in South Dakota
Docket No. EL18-___
Exhibit___
FINANCIAL SOUNDNESS, CAPITAL STRUCTURE AND COST OF CAPITAL
Direct Testimony and Schedules of
Kevin G. Moug
April 20, 2018
TABLE OF CONTENTS
I. INTRODUCTION AND QUALIFICATIONS...... 1 II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY ...... 1 III. DESCRIPTION OF OTP AND OTTER TAIL CORPORATION ...... 4 IV. OTP CAPITAL STRUCTURE AND EQUITY RATIO ...... 6 V. OTP RECENT CAPITAL EXPENDITURES AND ONGOING CAPITAL EXPENDITURES PLANS ...... 8 VI. OTP’S CREDIT RATINGS AND COST OF BORROWING ...... 12 VII. EFFECTS OF OTP’S BUSINESS AND FINANCIAL RISKS ON ITS CREDIT RATINGS ...... 15 VIII. COMPONENTS OF OTP’S PROPOSED CAPITAL STRUCTURE ...... 18 A. LONG-TERM DEBT ...... 18 B. COMMON EQUITY ...... 19 XI. CONCLUSION ...... 21
ATTACHED SCHEDULES Schedule 1 – Qualifications, Duties and Responsibilities of Kevin G. Moug Schedule 2 – Proposed Cost of Capital for 2017 Test Year Schedule 3 – Effect of One-Notch Change in Credit Rating Schedule 4 – Moody’s Rating Factors for OTP from October 7, 2017 Credit Opinion for OTP Schedule 5 – Levels and Cost of Long-Term Debt for 2018 Forecast Year Schedule 6 – Common Equity for 2018 Forecast Year Schedule 7 – Public and Non-Public Issuances of Common Equity by Otter Tail Corporation
1 I. INTRODUCTION AND QUALIFICATIONS
2 Q. PLEASE STATE YOUR NAME AND OCCUPATION. 3 A. My name is Kevin G. Moug. I am the Chief Financial Officer and Senior Vice 4 President of Otter Tail Corporation and the Treasurer for Otter Tail Power Company 5 (OTP). OTP is a wholly owned subsidiary of Otter Tail Corporation. 6 7 Q. PLEASE SUMMARIZE YOU QUALIFICATIONS AND EXPERIENCE. 8 A. I have been Senior Vice President and Chief Financial Officer of Otter Tail 9 Corporation since 2001. A copy of my resume is included as Exhibit___(KGM-1), 10 Schedule 1.
11 II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY
12 Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? 13 A. The purpose of my Direct Testimony is to demonstrate the reasonableness of the 14 capital structure, cost of Long-Term Debt (LTD), and the overall Rate of Return 15 (ROR) to be used for OTP’s 2017 Test Year. As I will explain, that capital structure is 16 based on the OTP’s 2018 projected capital structure. I will discuss the financial 17 impacts and scope of OTP’s recent capital expenditures and OTP’s estimated future 18 capital expenditures. I will also discuss the importance of the decisions of the South 19 Dakota Public Utilities Commission (Commission) in this proceeding, including 20 granting a reasonable Return on Equity (ROE), to: (1) maintaining OTP strong credit 21 ratings; (2) the long-term cost of completing OTP’s capital expenditures plans; and (3) 22 OTP’s ability to attract capital and provide service at a fair and reasonable cost. 23 24 Q. PLEASE PROVIDE A BRIEF OVERVIEW OF YOUR DIRECT TESTIMONY. 25 A. OTP’s proposed capital structure, cost of LTD, and ROR are reasonable for the 2017 26 Test Year and should be adopted for determining OTP’s rates. OTP’s proposed 27 capital structure, cost of LTD, and ROR for the 2017 Test Year are based on the 1 Docket No. EL18-___ Moug Direct
1 forecast of OTP’s 2018 capital structure, cost of LTD, and ROR. That forecast 2 reflects the issuance of $100 million of LTD in February 2018, which has the effects 3 of reducing OTP’s equity ratio, cost of LTD, and ROR below the levels that would 4 have resulted from using OTP’s actual equity ratio, cost of LTD, and ROR for 2017. 5 As a result, OTP’s approach provides a significant benefit to South Dakota customers. 6 OTP has been engaged in an extensive capital expenditure program, involving 7 capital expenditures of approximately $806 million from 2013 through 2017.1 OTP 8 required external sources of debt and equity capital to fund those investments, in 9 addition to substantial amounts of internally generated equity. OTP’s extensive 10 capital expenditures plan is expected to continue from 2018 through 2022 with an 11 additional approximately $901 million of further capital expenditures by OTP in that 12 5-year period.2 Completion of OTP’s capital expenditures plan will also require 13 external sources of equity and debt capital in addition to internally generated cash flow 14 from operations. 15 The Commission’s decisions in this proceeding, including the Commission’s 16 decisions with respect to OTP’s capital structure and ROE, may significantly affect 17 investors’ perceptions of OTP’s regulatory environment, which has important 18 implications for OTP’s financial outlook and OTP’s senior unsecured credit ratings. 19 The credit ratings in effect when OTP places LTD to help finance the rest of its capital 20 expenditures plan will affect OTP’s cost of service for 10 to 30 years. As a result, the 21 Commission’s decisions in this proceeding may affect OTP’s cost of service for a 10 22 to 30-year period. 23 24 Q. PLEASE SUMMARIZE OTP’S RECOMMENDED ROR, INCLUDING CAPITAL 25 STRUCTURE, COST OF LTD, AND ROE. 26 A. OTP recommends an overall ROR of 7.96 percent. This ROR is based on the capital 27 components and related costs summarized in Table 1 and shown on attached Exhibit
1 Otter Tail Corporation Form 10-K for year ended December 31, 2015, p 50 and Otter Tail Corporation Form 10-K for year ended December 31, 2017, p 49. 2 Otter Tail Corporation Form 10-K for year ended December 31, 2017, p 49.
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1 ___(KMG-1), Schedule 2. 2 3 Table 1 4 Recommended Capital Structure and ROR 5 for the 2017 Test Year Component Percentage Cost Weighted Cost Long-Term Debt 46.90% 5.30% 2.49% Common Equity 53.1% 10.30% 5.47% Total 100.0% 7.96% 6 7 OTP’s recommended 7.96 percent ROR is 54 basis points lower than the 8.50 percent 8 ROE approved by the Commission for OTP’s 2009 Test Year in OTP’s last South 9 Dakota general rate case. 10 11 Q. HOW IS THE BALANCE OF YOUR DIRECT TESTIMONY ORGANIZED? 12 A. Section III provides a brief description of the financial characteristics of OTP and 13 Otter Tail Corporation. Section IV compares the equity ratio in OTP’s proposed 14 capital structure to the equity ratios of other utilities. Section V describes our historic 15 and planned financing and capital expenditures and credit ratings and explains the 16 importance of OTP’s regulatory environment and investor perceptions to our long- 17 term capital costs, and the impacts on our capital expenditures plans and costs. 18 Section VI explains OTP’s credit ratings and their effect on the costs of borrowing. 19 Section VII explains the effects of business and financial risks on OTP’s credit ratings. 20 Section VIII provides a detailed description of the components of OTP’s capital 21 structure and costs of LTD to be used for the 2017 Test Year. Section IX includes my 22 conclusions and recommendations. 23 24 Q. HAS OTP ALSO PROVIDED SUPPLEMENTAL COST OF CAPITAL 25 INFORMATION? 26 A. Yes. Information is included in Volume 4A, Section 3, Rate of Return/Cost of Capital 27 Schedules D-1 through D-4.
3 Docket No. EL18-___ Moug Direct
1 III. DESCRIPTION OF OTP AND OTTER TAIL CORPORATION
2 Q. PLEASE PROVIDE A SUMMARY DESCRIPTION OF OTP AND OTTER TAIL 3 CORPORATION. 4 A. OTP is a wholly owned subsidiary of Otter Tail Corporation and is a separate legal 5 entity from Otter Tail Corporation. OTP issues its own LTD and has its own credit 6 facility with banks that provide OTP’s short-term borrowings. Otter Tail Corporation 7 owns all of OTP’s outstanding common stock. There are no loans outstanding 8 between OTP and Otter Tail Corporation. Otter Tail Corporation is publicly held and 9 traded on the NASDAQ. OTP is Otter Tail Corporation’s only utility operating 10 company. 11 12 Q. HOW DOES OTTER TAIL CORPORATION COMPARE IN SIZE TO OTHER 13 ELECTRIC UTILITIES? 14 A. Otter Tail Corporation is the second smallest publicly traded investor owned utility in 15 the United States,3 and it is much smaller than the average of publicly traded investor 16 owned utilities. Otter Tail Corporation’s total market capitalization is $1.67 billion4 17 while the average total market capitalization of publicly traded investor owned utilities 18 is $16.7 billion.5 Otter Tail Corporation is also the smallest publicly traded investor 19 owned utilities doing business in South Dakota, including Northwestern Energy 20 NWE) with market capitalization of $2.54 billion6, Black Hills (BKH) with market 21 capitalization of $2.79 billion7, Montana-Dakota Utilities (MDU) with market
3http://www.eei.org/resourcesandmedia/industrydataanalysis/industryfinancialanalysis/QtrlyFinancialUpdates/D ocuments/QFU_Stock/2017_Q4_Stock_Performance.pdf. 4 http://www.nasdaq.com/symbol/ottr 3-12-18. 5 EEI 2017 Stock Performance, Q4 2017 Financial Update, total industry $720,427 million divided by 43 utilities http://www.eei.org/resourcesandmedia/industrydataanalysis/industryfinancialanalysis/QtrlyFinancialUpdates/Do cuments/QFU_Stock/2017_Q4_Stock_Performance.pdf. 6 http://www.nasdaq.com/symbol/NWE 3-12-18. 7 http://www.nasdaq.com/symbol/BKH 3-12-18.
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1 capitalization of $5.3 billion8 and Xcel Energy (XE) with market capitalization of 2 $21.95 billion.9 3 4 Q. HOW DOES OTTER TAIL CORPORATION’S COMMON STOCK OWNERSHIP 5 PROFILE COMPARE TO OTHER ELECTRIC UTILITIES? 6 A. Otter Tail Corporation also has a level of institutional ownership of its common stock 7 which is substantially lower than the average institutional ownership of the electric 8 utilities in the comparable group of OTP witness Mr. Robert B. Hevert, and lower than 9 all other investor owned utilities providing electric service in South Dakota. 10 11 Q. DOES OTTER TAIL CORPORATION’S LOWER LEVEL OF INSTITUTIONAL 12 OWNERSHIP HAVE AN EFFECT ON OTP’s COST OF EQUITY? 13 A. Yes. As Mr. Hevert explains in his Direct Testimony, institutional investors are an 14 important and efficient source of equity capital. Otter Tail Corporation’s significantly 15 lower level of institutional common stock ownership indicates there is a lower level of 16 equity capital available (from institutional demand) to Otter Tail Corporation and 17 OTP, with lower demand leading to a higher cost of equity for OTP. 18 19 Q. HOW DOES OTTER TAIL CORPORATION’S AVERAGE DAILY TRADING 20 VOLUME COMPARE TO OTHER ELECTRIC UTILITIES? 21 A. Otter Tail Corporation daily trading volume of approximately 100,000 shares per day 22 is far below the average daily trading volume of Mr. Hevert’s comparable group and 23 the levels of NWE, BKH, MDU and XE, as described in Mr. Hevert’s Direct 24 Testimony. 25 26 Q. IS THIS LOWER TRADING VOLUME RELATED TO LIQUIDITY RISK AND 27 LOWER INSTITUTIONAL OWNERSHIP?
8 http://www.nasdaq.com/symbol/mdu 3-12-18. 9 http://www.nasdaq.com/symbol/xel 3-12-18.
5 Docket No. EL18-___ Moug Direct
1 A. Yes. The lower trading volume creates a challenge for an institutional investor’s 2 ability to acquire or sell the large blocks of stock that are typically held by an 3 institutional investor. This has an adverse effect on liquidity for owners of Otter Tail 4 Corporation common stock and implications for OTP’s cost of equity, as Mr. Hevert 5 also explains.
6 IV. OTP CAPITAL STRUCTURE AND EQUITY RATIO
7 Q. HOW DID OTP DETERMINE ITS PROPOSED CAPITAL STRUCTURE? 8 A. OTP’s proposed capital structure for its 2017 Test Year is based on the 13 month 9 average of OTP’s 2018 forecast capital structure. 10 11 Q. WHY IS OTP PROPOSING THE USE OF A 2018 FORECAST CAPITAL 12 STRUCTURE FOR A 2017 HISTORICAL TEST YEAR? 13 A. OTP is proposing the use of its 13-month average 2018 forecast capital structure 14 because of a significant change that occurred in February 2018. In February, OTP 15 issued $100 million of LTD at a rate of 4.07 percent. This LTD was issued to provide 16 long term financing for major capital expenditures that have been and are being placed 17 in service. 18 19 Q. HOW DOES THE USE OF THE 2018 FORECAST CAPITAL STRUCTURE 20 AFFECT RATES? 21 A. The use of the 2018 forecast capital structure added $100 million to OTP’s long term 22 debt, which reduced its equity ratio by approximately 3.4 percent from the 2017 23 historic 13-month average (on a test year basis), and reduced the average cost of LTD 24 by approximately 28 basis points from the 2017 historic 13-month average. Thus, the 25 use of the 2018 forecast capital structure and cost of LTD provides substantial benefits 26 to South Dakota customers, reducing the 2017 Test Year revenue requirement by 27 approximately $317,000. 28
6 Docket No. EL18-___ Moug Direct
1 Q. HOW DOES OTP’S PROPOSED 53.1 PERCENT EQUITY RATIO COMPARE TO
2 EQUITY RATIOS OF MR. HEVERT’S COMPARABLE GROUP COMPANIES? 3 A. As Mr. Hevert explains, OTP’s equity ratio is well within the range of the equity ratios 4 of companies in his comparable group. Mr. Hevert notes the mean equity ratio from 5 the operating utilities in his comparable group is 51.61 percent, the median equity ratio 6 is 52.80 percent, and the range is from 44.86 percent to 57.42 percent. OTP’s 7 proposed 53.1 percent equity ratio is well within that range. 8
9 Q. DO OTP’S CAPITAL STRUCTURE AND EQUITY RATIO PROVIDE OTHER 10 CUSTOMER BENEFITS? 11 A. Yes. OTP’s capital structure and equity ratio have also contributed to OTP’s ability to 12 simultaneously finance its significant capital expenditures at reasonable costs, 10 and 13 reduce its cost of LTD. We also expect that OTP’s capital structure and equity ratio 14 will facilitate OTP’s completion of its capital expenditures over the next 5 years. All 15 of these result in benefits to OTP customers. 16 17 Q. IS A REDUCTION IN OTP’S EXPENSES AND RATES (RESULTING FROM 18 FEDERAL INCOME TAX REFORM) A FACTOR THAT AFFECTS THE 19 REASONABLENESS OF OTP’S CAPITAL STRUCTURE AND EQUITY RATIO? 20 A. As explained in Mr. Hevert’s Direct Testimony, a reduction in OTP’s expenses and 21 rates to reflect OTP’s reduced federal income tax is the type of result that the rating 22 agencies have characterized as a credit negative event which has an effect on both the 23 cost of equity and reasonableness of the capital structure. 24 25 Q. IS OTP PROPOSING AN INCREASE IN ITS EQUITY RATIO AS A RESULT OF 26 FEDERAL INCOME TAX REFORM? 27 A. No. OTP does believe, however, that federal income tax reform provides further 28 substantial support for the reasonableness of OTP’s proposed 53.1 percent equity ratio
10 Otter Tail Corporation 2016 Form 10(K), p. 50.
7 Docket No. EL18-___ Moug Direct
1 V. OTP RECENT CAPITAL EXPENDITURES AND ONGOING 2 CAPITAL EXPENDITURES PLANS
3 Q. PLEASE SUMMARIZE OTP’S RECENT CAPITAL EXPENDITURES. 4 A. OTP’s capital expenditures increased significantly in 2012 and have remained very 5 substantial since then as shown on Table 2 below: 6 7 Table 2 8 OTP Capital Expenditures 2012 – 2017 11 Year Capital Expenditure ($ millions) 2012 $102 2013 $150 2014 $149 2015 $136 2016 $150 2017 $119 Total $806 Average $134 9 10 OTP witness Mr. Bruce Gerhardson provides further information regarding the various 11 projects that were included in these capital expenditures. 12 13 Q. HOW DO THESE PRIOR EXPENDITURES COMPARE TO OTP’S NET PLANT 14 IN SERVICE WHEN THEY BEGAN? 15 A. OTP’s net electric plant in service as of December 31, 2011 was approximately $922 16 million.12 OTP’s $806 million investment during 2012-2017 represented 17 approximately 99 percent of its net electric plant as of December 31, 2011. 18 19 Q. HOW HAS OTP PROVIDED LONG-TERM FUNDING FOR ITS 2012-2017 20 CAPITAL EXPENDITURES?
11 Otter Tail Corporation Form 10-K for year ended December 31, 2014, p 50 and Otter Tail Corporation Form 10-K for year ended December 31, 2016, p 49. 12 Otter Tail Corporation, 2011 Form 10-K, p. 115.
8 Docket No. EL18-___ Moug Direct
1 A. OTP provided long-term funding for its $806 million of capital expenditures in 2012- 2 2017 with a combination of approximately $250 million of LTD issued by OTP 3 (including the February 2018 issuance), earnings retained by OTP, and equity 4 infusions from Otter Tail Corporation. Earnings retained by OTP and equity infusions 5 from Otter Tail Corporation increased OTP’s equity balance from $330 million at year 6 end 2011 to $558 million at year end 2017. From 2012-2017, almost 80 percent of 7 OTP’s net income has been reinvested, either as retained earnings or added infusions 8 of equity from Otter Tail Corporation. These equity reinvestments provided needed 9 funding for OTP’s capital expenditures and were also needed essential to maintain a 10 balance of debt and equity and a balanced capital structure for OTP. 11 12 Q. HAVE OTP’S CAPITAL EXPENDITURES AND RELATED FUNDING BEEN A 13 SIGNIFICANT PART OF OTTER TAIL CORPORATION’S STRATEGY? 14 A. Yes. OTP is Otter Tail Corporation’s largest business, and Otter Tail Corporation has 15 focused on OTP within Otter Tail Corporation’s two platforms, electric and 16 manufacturing. That focus on OTP has been successful, but $901 million of planned 17 capital expenditures for OTP remains for the four-year period of 2018-2022, as shown 18 in Table 3 below:13 19 Table 3 20 Projected OTP Capital Expenditures 2018 – 202114 Year Capital Expenditure ($ millions) 2018 $95 2019 $382 2020 $185 2021 $145 2022 $94 Total $901 Average $180 21
13 Otter Tail Corporation Form 10-K for year ended December 31, 2016, p 49. 14 Otter Tail Corporation Form 10-K for year ended December 31, 2014, p 50 and Otter Tail Corporation Form 10-K for year ended December 31, 2016, p 49.
9 Docket No. EL18-___ Moug Direct
1 Q. HOW DO THESE CAPITAL EXPENDITURES COMPARE TO OTHER 2 UTILITIES? 3 A. As Mr. Hevert notes in his Direct Testimony, OTP’s planned capital expenditure level 4 is far higher than any other company in his proxy group, as shown in Chart 1: 5 6 Chart 1: 7 Comparison of OTP and Hevert Comparable Group 8 Planned Capital Expenditures 9 (As a percentage of net plant)
80% 69% 70% 59% 59% 60% 48% 50% 41% 39% 39% 40% 36% 33% 31% 30% 25% 21% 20%
10%
0%
EE
HE
IDA
ALE LNT
BKH OTP
PNM
OGE
MDU NWE
10 NSP-MN
11 As Mr. Hevert also notes, OTP’s projected 69 percent capital expenditures level as a 12 percentage of its net plant is also significantly higher than all publicly traded investor 13 owned utilities in South Dakota, including XEL (at 59 percent), MDU (at 59 percent), 14 NWE (at 31 percent), and BKH (at 36 percent).15 15 16 Q. WILL THE ROE AND CAPITAL STRUCTURE AUTHORIZED IN THIS 17 PROCEEDING HAVE AN EFFECT ON FINANCING OF OTP’S CAPITAL 18 EXPENDITURE PLANS?
15 Hevert Direct Testimony, Section VI, Capital Expenditures.
10 Docket No. EL18-___ Moug Direct
1 A. Yes. The ROE and capital structure authorized in this proceeding will have a 2 substantial impact on OTP’s financing of its capital expenditures plan in two 3 important ways. First, the ROE and capital structure will have a direct impact on the 4 level of OTP’s authorized earnings. The level of authorized earnings will, in turn, 5 directly impact OTP’s ability to fund capital expenditures with internally generated 6 retained earnings. 7 As I explained, OTP has reinvested almost 80 percent of its earnings in the 8 2012-2017 period of its previous substantial capital expenditures. Previously 9 authorized ROEs have had a significant effect on the availability of these internally 10 generated retained earnings, which have been a significant source of funding for 11 OTP’s capital expenditures and are expected to remain a significant source of funding 12 for the remainder of OTP’s capital expenditures plan. 13 The authorized ROE and capital structure will have a significant effect on the 14 perceptions of rating agencies and investors, which is likely to be heightened by the 15 scale of the OTP capital expenditures plan and the general recognition that federal 16 income tax reform will have negative effects on utilities and the resulting uncertainty 17 for utilities. These perceptions could have a substantial impact on credit ratings and 18 the availability and external debt and equity capital that will be needed to complete 19 OTP’s capital expenditures plans. Later in my Direct Testimony, I will also discuss 20 plans for issuance of new LTD and external sources of equity in the 2018-2022 time 21 period during which OTP will be completing its capital expenditures plan. 22 23 Q. DO RATE CASE AND ROE DECISIONS AFFECT CREDIT RATING AGENCY 24 EVALUATION OF UTILITIES? 25 A. Yes. The effect of rate case and ROE decisions is demonstrated in the February 20, 26 2018 action by Moody’s Investor Services (Moody’s) which changed its ratings 27 outlook on ALLETE from Stable to Negative. Moody’s noted the combined effects of 28 the recent Minnesota Power rate case decision of the Minnesota Public Utilities 29 Commission (MPUC) and the reduced cash flow anticipated from the recent federal 30 tax reform. Moody’s noted the rate case decision was likely to negatively affect
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1 financial metrics and also was seen as an indication of a deterioration of Minnesota 2 Power’s regulatory environment, noting that the “rate case outcome also points to a 3 less constructive regulatory relationship between MP and the MPUC.” 4 In a February 8, 2018 Issuer Comment, Moody’s also discussed the negative 5 effects of the MPUC rate case decision, noting that; “The MPUC reduced MP's 6 allowed ROE to 9.25% from the requested 10.25%, below the national average of 7 about 9.6%.”
8 VI. OTP’S CREDIT RATINGS AND COST OF BORROWING
9 Q. ARE CREDIT RATINGS IMPORTANT TO OTP? 10 A. Credit ratings are particularly important to OTP now while OTP is completing its 11 capital expenditures program. As I will explain, completion of that plan will require 12 OTP to issue additional LTD in order to complete the plan, and the interest rates at 13 which OTP issues its LTD will continue to affect costs for many years into the future. 14 OTP’s credit ratings have a direct effect on the interest rates for OTP’s LTD. 15 16 Q. HOW DOES OTP ARRANGE ITS LTD FINANCING? 17 A. OTP raises the LTD needed for financing its operations, including its capital 18 expenditures, through private placements with institutional investors rather than 19 through public issuances of LTD. OTP uses private placements because the size of its 20 debt offerings attracts better interest in the private placement market from fixed 21 income investors as well as not incurring the added costs of issuing public debt and 22 having to incur an additional borrowing cost for a small size premium that would exist 23 in the public debt market. OTP’s private placements of LTD are for terms of 10 to 30 24 years. 25 26 Q. DOES OTP’S USE OF PRIVATE PLACEMENTS FOR LTD MAKE CREDIT 27 RATINGS UNIMPORTANT TO OTP AND OTP’S CUSTOMERS? 28 A. No. Credit ratings remain very important to OTP and OTP customers because 29 institutional investors use these ratings, along with their own analysis, in making 12 Docket No. EL18-___ Moug Direct
1 decisions regarding whether to invest in OTP’s LTD debt and the interest rate to 2 require in order to make an investment in OTP’s LTD. 3 4 Q. WHAT ARE OTP’S CURRENT CREDIT RATINGS? 5 A. OTP’s current credit ratings are set out in Table 4 below: 6 7 Table 4 8 OTP Credit Ratings16 Moody’s Fitch S&P Corporate Credit/Long term A3 BBB BBB issuer Default Rating Senior Unsecured Rating N.A. BBB+ BBB
Outlook Stable Stable Positive 9 10 The “Positive” outlook from S&P reflects a change in outlook from Stable on August 11 21, 2017.17 12 13 Q. HAVE YOU ESTIMATED THE EFFECTS ON LTD INTEREST RATES OF A 14 ONE-NOTCH CHANGE IN OTP’S CREDIT RATING? 15 A. Yes. Based on recent history, a one-notch change by Moody’s (from OTP’s current 16 A3 rating to Baa1) would lead to a 25 to 40 basis point change in interest rates, with 17 an increase in the Credit Rating reducing interest rates and a decrease in the Credit 18 Rating increasing interest rates. This change in interest rates would not apply to LTD 19 that is now outstanding but would apply to LTD that would be placed when the change 20 in the Credit Rating became effective. 21 22 Q. WOULD A CREDIT RATING CHANGE ALSO HAVE AN EFFECT ON THE 23 COSTS OF OTP’S SHORT TERM DEBT?
16 Moody’s August 9, 2017 Credit Opinion for OTP (Moody’s 2017); Fitch, August 17, 2017 (Fitch 2017); S&P August 21, 2017 Ratings for OTP and Otter Tail Corporation (S&P 2017). 17 S&P 2017, p. 1.
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1 A. Yes. OTP’s STD credit agreement contains a defined pricing grid. A one notch 2 downgrade in OTP’s credit ratings would result in higher short-term borrowing costs 3 of 25 basis points under the current credit agreement. 4 5 Q. DOES OTP PLAN TO ISSUE LTD DURING THE 2018-2022 TIME PERIOD IN 6 ORDER TO COMPLETE ITS CAPITAL EXPENDITURE PLAN? 7 A. Yes. OTP plans to finance its estimated $901 million of capital expenditures in the 8 2018-2022 timeframe with a balanced mix of equity and debt, including OTP retained 9 earnings and equity infusions from Otter Tail Corporation, including the results of 10 common stock issuances. 11 12 Q. HAVE YOU ESTIMATED THE POTENTIAL EFFECTS ON OTP’S INTEREST 13 EXPENSES IF THERE IS A RATING CHANGE? 14 A. Yes. Table 5 below summarizes the effects on OTP total interest expenses per $200 15 million of LTD that may be issued if there is a one-notch downgrade and interest rates 16 increase by 25 and 40 basis points, with that LTD outstanding from 10 years to 30 17 years. Those calculations are shown on Exhibit___(KGM-2), Schedule 3. 18 19 Table 5 20 Effect of 25 basis point interest rate increase on 21 $200 million issuance of LTD OTP Total OTP Total @ 25 basis points @ 40 basis points Annual increase $500,000 $800,000 Cumulative increase over 10 years $5,000,000 $8,000,000 Cumulative increase over 20 years $10,000,000 $16,000,000 Cumulative increase over 30 years $15,000,000 $24,000,000 22 23 Q. WILL THE CHANGE IN THE COST OF THIS ADDITIONAL LTD AFFECT 24 LONG TERM COSTS OF SERVICE? 25 A. Yes. The terms of newly issued debt are expected to range from 10 to 30 years. As a 26 result, these costs will remain part of the costs of service for a substantial period of 27 time.
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1 VII. EFFECTS OF OTP’S BUSINESS AND FINANCIAL RISKS ON ITS 2 CREDIT RATINGS
3 Q. DO RATING AGENCIES CONSIDER BOTH BUSINESS RISKS AND 4 FINANCIAL METRICS IN ESTABLISHING A UTILITY’S CREDIT RATINGS? 5 A. Yes. Credit rating agencies assess, and assign ratings to, both a utility’s: (1) Business 6 Risk; and (2) Financial Risk when making rating determinations. A utility’s Financial 7 Risk is based on credit metrics. Business Risk and Financial Risk are considered 8 together when a credit rating agency determines a utility’s credit rating and each 9 category of risk affects the level of risk that the rating agency requires of the other 10 category in order to maintain a given rating. For example, the required Financial Risk 11 becomes more stringent (i.e. the credit metrics must be better) to maintain a given 12 credit rating as the utility’s Business Risk rating decreases (indicating higher level 13 business risk). 14 15 Q. WHAT ARE THE COMPONENTS THAT ARE CONSIDERED IN DETERMINING 16 A UTILITY’S BUSINESS RISK? 17 A. A utility’s business risk considers a number of factors, including: (1) the regulatory 18 environment in which the utility provides service, including the timing and ability to 19 recover investment; (2) the risk of environmental and other changes that may affect 20 the utility’s costs and ability to provide service; (3) the size and diversity of a utility’s 21 customer base; and (4) the economic strength of the utility’s service area. Because a 22 utility’s ability to set rates and recover its costs is so dependent on cost of service 23 regulation, a utility’s regulatory environment is a key element of its business risk 24 rating. The scope of a utility’s investments is also a very significant factor in 25 assessing a utility’s risk. 26
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1 Q. HAVE THE RATING AGENCIES ADDRESSED THE LARGE SCOPE OF OTP’S 2 CAPITAL EXPENDITURES? 3 A. Yes. Moody’s, Fitch, and S&P have each explicitly recognized the large scope of 4 OTP’s capital expenditure program. Based on information for 2017-2021, Moody’s 5 has noted “OTP’s current five-year capital investment program is approximately $862 6 million.”18 Fitch similarly noted the “Large capex program at OTP totaling $862 7 million through 2021.”19 S&P stated it could revise the outlook downward from 8 positive to stable “if rising capital spending continues without adequate and timely 9 recovery of costs.”20 Rating agencies (and the capital markets) are particularly aware 10 of the need for regulatory decisions that support the recovery of capital expenditures 11 during periods of substantial expenditures 12 13 Q. HAVE THE RATING AGENCIES ADDRESSED THE RELATIONSHIP OF 14 REGULATORY DECISIONS TO OTP’S CAPEX PROGRAM? 15 A. Yes. The importance and connection of supportive regulatory decisions to OTP’s 16 capital expenditures plan has been explicitly discussed. Moody’s recently said: 17 OTP’s rating outlook reflects Moody’s expectation that the regulatory 18 environments for OTP remain credit supportive and that OTP will 19 continue to produce predictable and stable cash flows. 20 *** 21 For OTP, a rating downgrade is possible if its regulatory support wanes 22 and becomes less credit supportive such that regulatory lag increases or 23 cost recovery is negatively affected.21 24 25 Fitch has similarly said: 26 Otter Tail Power’s (OTP) Stable Outlook reflects that regulated nature 27 of its electric utility operations and a balanced regulatory environment 28 across its three state jurisdictions …..22 29
18 Moody’s 2017, p. 4. 19 Fitch 2017, p. 4. 20 S&P 2017, p. 2. 21 Moody’s 2017, pp 1, 2. 22 Fitch 2017, p 2.
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1 S&P has noted the Positive outlook may not lead to an upgrade of the credit 2 rating: 3 [I]f rising capital spending continues without adequate and timely 4 recovery of costs.”23 5 6 Q. HOW IMPORTANT ARE REGULATORY AND COST RECOVERY IN 7 RELATION TO FINANCIAL METRICS IN DETERMINING OTP’S RATINGS? 8 A. Regulatory and cost recovery appear to be as important as financial metrics in 9 determining OTP’s credit ratings. Exhibit___(KGM-1), Schedule 4 is a copy of 10 Moody’s Rating Factors for OTP from the August 9, 2017 Credit Opinion for OTP. 11 The August 9, 2017 Credit Opinion shows the four factors Moody’s considered in its 12 rating decisions for OTP along with the weightings given to each. Regulatory 13 Framework was weighted 25 percent. Ability to Recover Costs and Earn Returns 14 (which reflect regulation) was weighted 25 percent. Diversification was weighted 10 15 percent. Financial Strength was weighted 40 percent.24 The impact of regulation and 16 resulting ability to recover costs and earn returns accounted for 50 percent of the 17 ratings. 18 19 Q. WILL THE ROE AUTHORIZED IN THIS PROCEEDING BE IMPORTANT TO 20 OTP’S CREDIT RATINGS, INVESTORS, AND COST OF CAPITAL? 21 A. Yes. While ROE is certainly not the only factor considered in the evaluation of a rate 22 case or a potential investment in a utility doing business in a particular state, it is easy 23 for rating agencies and investors to identify and compare ROEs to expectations and to 24 ROEs from other jurisdictions. The ROEs are also regarded as an indicator of 25 regulatory support or the lack of support, as the Moody’s action and Issuer Comment 26 pertaining to Minnesota Power demonstrate. Moody’s also recently noted “A rating 27 upgrade could be considered if OTP’s regulatory environments improved materially, 28 further shortening regulatory lag and improving rates and returns.”25
23 S&P 2017, p. 2. 24 Moody’s 2017, p. 5. 25 Moody’s 2017, p. 2.
17 Docket No. EL18-___ Moug Direct
1 Q. IS OTP’S CAPITAL STRUCTURE IMPORTANT TO OTP’S RATING AGENCIES, 2 INVESTORS, AND COST OF CAPITAL? 3 A. Yes. A utility’s capital structure provides the long-term structural foundation for the 4 financing required to support its operations and capital investment plans. It is 5 particularly important when a utility is making significant capital expenditures, as 6 reflected in Fitch’s recent Rating Report noting that: 7 Fitch expects … that future funding needs will be met by a balanced mix 8 of debt and equity and that [Otter Tail Corporation] will downstream 9 additional equity as needed to support the balanced capital structure.26 10 11 Q. WHAT IS YOUR CONCLUSION? 12 A. When a utility is engaged in an extensive capital expenditure program, a decision in a 13 single rate case can have adverse effects that last long beyond the term of the rates set 14 in that case. This is true in the case of OTP at this time, which continues to be 15 engaged in an extensive capital expenditure program that will involve capital 16 expenditures of approximately $901 million in the 2018-2022 timeframe. As a result, 17 OTP requests the Commission take these facts into consideration when determining 18 where to set the ROE for OTP within the range of reasonable ROEs.
19 VIII. COMPONENTS OF OTP’s PROPOSED CAPITAL STRUCTURE
20 Q. WHAT ARE THE COMPONENTS OF OTP’S CAPITAL STRUCTURE? 21 A. OTP’s capital structure consists of LTD, STD and common equity.
22 A. LONG-TERM DEBT 23 Q. WHAT IS THE AMOUNT AND COST OF OTP’S LTD IN THE PROPOSED 24 CAPITAL STRUCTURE FOR THE 2017 TEST YEAR? 25 A. The 13-month average of OTP’s LTD for the 2018 forecast year that is proposed for 26 use in the 2017 Test Year is $492.7 million and the cost of LTD is 5.30 percent, as 27 shown on Exhibit___(KGM-1), Schedule 5.
26 Fitch 2017, p.3.
18 Docket No. EL18-___ Moug Direct
1 Q. HOW DO THE AMOUNT AND THE COST OF OTP’S LTD IN THE CURRENT 2 RATE CASE COMPARE TO OTP’S LAST RATE CASE? 3 A. Since OTP’s last rate case, LTD has increased by approximately $196.5 million and 4 the cost has decreased by approximately 151 basis points as shown in Table 6 below: 5 6 Table 6 7 OTP LTD 2008 Rate Case and Current Case 8 ($ millions) 2008 Rate Case Current Rate Case Difference Amount $296.2 $492.7 $196.5 Cost 6.81% 5.30% (1.51)% 9
10 B. COMMON EQUITY 11 Q. WHAT IS THE AMOUNT OF OTP’S 2018 FORECAST COMMON EQUITY AND 12 HOW WAS IT DETERMINED? 13 A. OTP’s common equity of $562.3 million reflects the average of 13 month-end 14 expected equity balances from December 2017 through December 2018 as shown on 15 Exhibit___ (KGM-1), Schedule 6. Since that schedule was prepared, Otter Tail 16 Corporation has made a $10 million equity infusion into OTP. OTP does not 17 anticipate increasing the proposed 53.1 percent equity ratio as a result of that equity 18 infusion or other possible equity infusions by Otter Tail Corporation. 19 20 Q. HAS OTTER TAIL CORPORATION RECENTLY ISSUED COMMON STOCK? 21 A. Yes. Otter Tail Corporation has had follow on offerings of its common stock since 22 2004 and 2008. Otter Tail Corporation also issued common stock during the 2014- 23 2017 timeframe using its “At the Market Program,” its Dividend Reinvestment Plan 24 (DRIP), and its Employee Stock Purchase Plan (ESPP). All of these common stock 25 issuances are included on Exhibit___KGM-1), Schedule 7. 26
19 Docket No. EL18-___ Moug Direct
1 Q. ARE THERE COSTS OF ISSUING COMMON STOCK? 2 A. Yes. When common stock is issued, the corporation issuing the stock incurs costs in 3 the process of issuance, including underwriter discounts, audit, legal, printing and 4 listing fees, and other expenses of issuance. When these issuance costs (also known as 5 “flotation costs”) are incurred, they reduce the net proceeds received by the 6 corporation issuing the stock (under generally accepted accounting principles). 7 Flotation costs are comparable to the issuance costs for LTD. The flotation costs 8 associated with Otter Tail Corporation’s common stock issuances are identified in 9 Exhibit___KGM-1), Schedule 7, which Mr. Hevert used to determine the flotation 10 cost adjustment. All of these flotation costs were treated as a reduction in proceeds 11 and reflected on the balance sheet and not expensed, which is the standard practice 12 with all flotation costs. 13 14 Q. WERE THESE 2014-2017 COMMON STOCK ISSUANCES BY OTTER TAIL 15 CORPORATION RELATED TO OTP’S CAPITAL EXPENDITURES? 16 A. Yes. These Otter Tail Corporation common stock issuances were directly related to 17 OTP’s prior capital expenditures, its current capital expenditures and its planned 18 future capital expenditures. 19 20 Q. PLEASE SUMMARIZE OTTER TAIL CORPORATION’S PLANNED COMMON 21 STOCK ISSUANCES. 22 A. As I noted earlier, OTP plans to finance its estimated $901 million of capital 23 expenditures in the 2018-2022 timeframe with a balanced mix of equity and debt, 24 including OTP retained earnings and equity infusions from Otter Tail Corporation, 25 including the results of common stock issuances. These common stock issuances by 26 Otter Tail Corporation are expected to include issuances under its At-the-Market 27 (ATM) program, its Dividend Reinvestment Plan (DRIP) and its Employee Stock 28 Purchase Plan (ESPP) during the 2018 - 2022 timeframe. 29
20 Docket No. EL18-___ Moug Direct
1 Q. ARE THE 2014-2017 AND PLANNED COMMON STOCK ISSUANCES 2 DIRECTLY RELATED TO OTP’S INVESTMENT PLANS? 3 A. Yes. The 2014-2017 common stock issuances and planned issuances of common 4 stock by Otter Tail Corporation during the 2018 – 2022 timeframe are directly related 5 to the current and planned capital expenditures for OTP.
6 XI. CONCLUSION
7 Q. CAN YOU PLEASE SUMMARIZE YOUR CONCLUSIONS? 8 A. Yes. I recommend the Commission approve a capital structure for the 2017 Test Year 9 including 53.10 percent equity, a 10.30 percent ROE, and an ROR of 7.96 percent. 10 11 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 12 A. Yes, it does.
21 Docket No. EL18-___ Moug Direct
Docket No. EL18-___ Exhibit ___(KGM-1), Schedule 1 Page 1 of 1
KEVIN G. MOUG
EMPLOYMENT______
2001-PRESENT Otter Tail Corporation Fargo, ND Sr. Vice President & Chief Financial Officer
1996-PRESENT Varistar Corporation Fargo, ND Chief Financial Officer & Treasurer
1993-1996 Advance Dental Management Mondovi, WI Chief Financial Officer
1981-1993 Deloitte & Touche Minneapolis, MN Senior Manager – Middle Market Practice
EDUCATION______
• Bachelor of Science in Business Administration University of North Dakota
INDUSTRY CERTIFICATIONS______
• Certified Public Accountant (Inactive)
PROFESSIONAL AFFILIATIONS______
• American Institute of Certified Public Accountants Member • Financial Executive International Member • US Bank Advisory Board Board Member • Essentia Health West Region Board of Directors • Essentia Health System Board of Directors Audit Committee Chair
OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit ___(KGM-1), Schedule 2 Page 1 of 1
PROPOSED COST OF CAPITAL FOR 2017 TEST YEAR
(A) (B) (C) (D) (E) Weighted Line Percent Cost of Cost of No. Capitalization Amount of Total Capital Capital
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% OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit ___(KGM-1), Schedule 3 Page 1 of 1
Impact of 25 Basis Point Debt Cost Increase on $200 Million
Line No. Description Amount 1 Hypothetical amout of debt issuance $200,000,000 2 25 basis points increase in Interest Rate 0.0025 3 Total Interest Cost $500,000
Impact of 40 Basis Point Debt Cost Increase on $200 Million
Line No. Description Amount 4 Hypothetical amout of debt issuance $200,000,000 5 40 basis points increase in Interest Rate 0.0040 6 Total Interest Cost $800,000 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit ___(KGM-1), Schedule 4 Page 1 of 1
Moody's Rating Factors Otter Tail Power Company Line No. 1 Regulated Electric and Gas Utilities Industry Current LTM [3]Moody's 12-18 Month Forward View As of March 2 Grid [1][2] 3/31/2017 2017 3 Factor 1 : Regulatory Framework (25%) Measure Score Measure Score 4 a) Legislative and Judicial Underpinnings of A A A A 5 the Regulatory Framework 6 b) Consistency and Predictability of A A A A 7 Regulation 8 Factor 2 : Ability to Recover Costs and Earn 9 Returns (25%) 10 a) Timeliness of Recovery of Operating and A A Aa Aa 11 Capital Costs 12 b) Sufficiency of Rates and Returns Baa Baa Baa Baa 13 Factor 3 : Diversification (10%) 14 a) Market Position Baa Baa Baa Baa 15 b) Generation and Fuel Diversity Ba Ba Baa Baa 16 Factor 4 : Financial Strength (40%) 17 a) CFO pre-WC + Interest / Interest (3 Year 5.5x A 6x-6.4x Aa 18 Avg) 19 b) CFO pre-WC / Debt (3 Year Avg) 22.5% A 23%-27% A 20 c) CFO pre-WC - Dividends / Debt (3 Year 15.7% Baa 16%-20% A 21 Avg) 22 d) Debt / Capitalization (3 Year Avg) 42.7% A 36%-40% A 23 Rating: 24 Grid-Indicated Rating Before Notching A3 A2 25 Adjustment 26 HoldCo Structural Subordination Notching 0 0 0 0 27 a) Indicated Rating from Grid A3 A2 28 b) Actual Rating Assigned A3 A3
29 [1] All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non- Financial Corporations. [2] As of 3/31/2017(L) [3] This represents Moody's forward view; not the view of the issuer; and unless noted in the text, does not incorporate significant acquisitions and divestitures. Source: Moody's Financial MetricsTM OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit ___(KGM-1), Schedule 5 Page 1 of 1 COMPOSITE COST OF PROPOSED LONG-TERM DEBT FOR 2017 TEST YEAR
Line DESCRIPTION Interest PRINCIPAL AMOUNTS OUTSTANDING (1) No. Debentures Rate Dec-17 Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Total Interest Cost 1 4.630% Series for 2021 4.630% $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $6,482,000 2 6.150% Unsecured Series B 2022 Senior Notes 6.150% 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 1,845,000 3 6.370% Unsecured Series C 2027 Senior Notes 6.370% 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 2,675,400 4 6.470% Unsecured Series D 2037 Senior Notes 6.470% 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 3,235,000 5 4.070% Unsecured Series A 2048 Senior Notes 4.070% 0 0 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 84,615,385 3,443,846 6 Total Debentures 0 $262,000,000 $262,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $346,615,385 $17,681,246
7 Series Bonds 8 4.680% 2029 Series 4.680% $60,000,000 $60,000,000 $60,000,000 $60,000,000 $60,000,000 $60,000,000 60,000,000 $60,000,000 60000000 60,000,000 60,000,000 60,000,000 60,000,000 60,000,000 2,808,000 9 5.470% 2044 Series 5.470% 90,000,000 90,000,000 90,000,000 90,000,000 90,000,000 90,000,000 90,000,000 90,000,000 90000000 90,000,000 90,000,000 90,000,000 90,000,000 90,000,000 4,923,000 10 Total Series Bonds $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $7,731,000 11 12 Subtotal Bond Balances $412,000,000 $412,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $496,615,385 $25,412,246 5.12% 13 14 Loss/Gain on Reacquired Debt (3,434,337) (3,380,088) (4,325,839) (4,268,817) (4,211,795) (4,154,773) (4,097,751) (4,040,729) (3,983,707) (3,926,685) (3,869,663) (3,812,641) (3,755,619) (3,943,265) 678,719
15 Total Long-Term Debt Capital $408,565,663 $408,619,912 $507,674,161 $507,731,183 $507,788,205 $507,845,227 $507,902,249 $507,959,271 $508,016,293 $508,073,315 $508,130,337 $508,187,359 $508,244,381 $492,672,120 $26,090,965
WEIGHTED COST OF LONG-TERM DEBT 5.30% (1) Actual balances are used for December 2017 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit ___(KGM-1), Schedule 6 Page 1 of 1
COMMON EQUITY FOR 2017 TEST YEAR
Month-end Balances
TOTAL Line CONTRIBUTED RETAINED COMMON No. CAPITAL EARNINGS EQUITY
1 December 2017 376,989,466 181,478,804 558,468,270 2 January 376,989,466 187,131,648 564,121,114 3 February 376,989,466 190,877,392 567,866,858 4 March 376,989,466 184,304,662 561,294,128 5 April 376,989,466 186,499,101 563,488,566 6 May 376,989,466 188,178,472 565,167,937 7 June 376,989,466 180,477,234 557,466,700 8 July 376,989,466 185,197,716 562,187,182 9 August 376,989,466 189,674,530 566,663,996 10 September 376,989,466 182,377,990 559,367,456 11 October 376,989,466 183,091,677 560,081,143 12 November 376,989,466 187,384,550 564,374,015 13 December 376,989,466 181,737,136 558,726,602
14 Average Common Equity $562,251,845 OTTER TAIL POWER COMPANY Docket No. EL18-___ Electric Utility - State of South Dakota Exhibit ___(KGM-1), Schedule 7 Page 1 of 1
Floation Costs Line Underwriting Offering Total Flotation Flotation No. Issuing Entity Mechanism Date Shares issued Offering Price Discount Expense Gross Proceeds Costs Net Proceeds cost % 1 Otter Tail Corp. ESSP 2004 66,958 NA $ - $ - $ 1,292,959 $ - $ 1,292,959 0.00% 2 Otter Tail Corp. ESSP 2009 62,450 NA $ - $ - $ 1,197,791 $ - $ 1,197,791 0.00% 3 Otter Tail Corp. ESPP 2014 39,222 NA $ - $ - $ 1,049,188 $ - $ 1,049,188 0.00% 4 Otter Tail Corp. ESPP 2015 42,253 NA $ - $ - $ 1,095,620 $ - $ 1,095,620 0.00% 5 Otter Tail Corp. ESPP 2016 53,875 NA $ - $ - $ 1,491,266 $ 1,159 $ 1,490,107 0.08% 6 Otter Tail Corp. ESPP 2017 5,284 NA $ - $ - $ 210,585 $ 367 $ 210,218 0.17%
7 Otter Tail Corp. DRIP 2004 223,165 NA $ - $ - $ 4,308,033 $ - $ 4,308,033 0.00% 8 Otter Tail Corp. DRIP 2009 233,943 NA $ - $ - $ 4,493,385 $ 5,877 $ 4,487,508 0.13% 9 Otter Tail Corp. DRIP 2014 288,045 NA $ - $ - $ 7,707,964 $ - $ 7,707,964 0.00% 10 Otter Tail Corp. DRIP 2015 330,379 NA $ - $ 56,545 $ 8,566,009 $ 56,545 $ 8,509,464 0.66% 11 Otter Tail Corp. DRIP 2016 302,524 NA $ - $ - $ 9,708,531 $ 32,973 $ 9,675,558 0.34% 12 Otter Tail Corp. DRIP 2017 107,285 NA $ - $ - $ 4,139,552 $ 17,554 $ 4,121,998 0.42%
13 Otter Tail Corp. ATM 2014 519,636 $ 30 $ 306,727 $ 780,616 $ 15,336,352 $ 1,087,343 $ 14,249,009 7.09% 14 Otter Tail Corp. ATM 2015 133,197 $ 28 $ 56,485 $ 339,160 $ 3,785,244 $ 395,645 $ 3,389,599 10.45% 15 Otter Tail Corp. ATM 2016 1,014,115 $ 33 $ 561,548 $ 33,235,729 $ 561,548 $ 32,674,181 1.69%
16 Otter Tail Corp. Secondary 2004-05 3,075,000 $ 25 $ 2,921,250 $ 391,452 $ 78,258,750 $ 3,312,702 $ 74,946,048 4.23% 17 Otter Tail Corp. Secondary 2008 5,175,000 $ 30 $ 5,627,812 $ 807,185 $ 155,250,000 $ 6,434,997 $ 148,815,003 4.14%
18 Weighted Average 3.60%