Direct Testimony and Schedules Jamie L. Jago Before the Minnesota Public Utilities Commission State of Minnesota In the Matter of the Application of Minnesota Power for Authority to Increase Rates for Electric Utility Service in Minnesota Exhibit TAX MATTERS November 2, 2016
Table of Contents Page I. INTRODUCTION AND QUALIFICATIONS... 1 II. ISSUES RELATING TO DEFERRED TAXES... 2 A. Bonus Depreciation... 3 B. Net Operating Losses... 4 C. Normalization... 7 III. FEDERAL TAX CREDITS... 13 A. Production Tax Credits... 13 B. Trend in ADITA Balances for Federal NOLs and PTCs... 16 C. Federal Investment Tax Credits... 18 IV. MEDICARE PART D... 20 V. PROPERTY TAX EXPENSE... 26 VI. CONCLUSION... 34 i Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 I. INTRODUCTION AND QUALIFICATIONS Q. Please state your name and business address. A. My name is Jamie L. Jago and my business address is 30 West Superior Street, Duluth, Minnesota 55802. Q. By whom are you employed and in what position? A. I am employed by ALLETE, Inc. ( ALLETE ), doing business as Minnesota Power ( Minnesota Power or the Company ). My current position is Director Taxes. Q. Please summarize your qualifications and experience. A. I have 31 years of experience at ALLETE and three years of experience in public accounting prior to ALLETE. I started at ALLETE in the tax department and was promoted to Manager in 2005. From 2008-2011, I was Manager of Financial Reporting & Budgeting, moving back to the Manager Taxes position in March of 2011. In 2016, I was promoted to my current position as Director Taxes. I earned a Bachelor of Accounting degree from the University of Minnesota Duluth. I am a Certified Public Accountant, licensed in Minnesota (inactive). I have taken several courses regarding public utility taxation and utility ratemaking sponsored by organizations such as PriceWaterhouseCoopers, Deloitte & Touche, and the Edison Electric Institute ( EEI ). I am a member of the EEI Taxation Committee and the Minnesota Society of Certified Public Accountants. Q. What are your present duties at ALLETE? A. In my current position, I am responsible for compliance, accounting, and planning for the income, property, and sales tax areas for ALLETE and its subsidiaries. Q. For whom are you testifying in this proceeding? A. I am testifying on behalf of Minnesota Power, an operating division of ALLETE. 1 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 Q. What is the purpose of your testimony? A. The purpose of my testimony is to discuss several tax issues relevant to this rate proceeding. These tax issues include bonus depreciation, tax net operating losses, and the calculation of accumulated deferred income tax assets and liabilities as required by the Internal Revenue Service ( IRS ). I will also discuss federal Production Tax Credits ( PTCs ) and federal Investment Tax Credits ( ITCs ). Finally, I will discuss Medicare Part D and the Company s property tax expense. Q. Are you sponsoring any exhibits in this proceeding? A. Yes. I am sponsoring the following exhibits: Exhibit (JLJ), Schedule 1 Pro Rata Calculation Worksheet. Exhibit (JLJ), Schedule 2 FERC Attachment O Order. Exhibit (JLJ), Schedule 3 Minnesota Power s Medicare Part D Petition in Docket No. E015/M-10-1083. Exhibit (JLJ), Schedule 4 Minnesota Power s Medicare Part D Reply Comments in Docket No. E015/M-10-1083. In addition, my testimony refers to and supports Volume II, Schedule H and Volume IV, Schedule H of this rate case filing. II. ISSUES RELATING TO DEFERRED TAXES Q. Is the treatment of deferred taxes an important issue for ratemaking purposes? A. Yes. Over the past several years, various tax laws have allowed companies such as Minnesota Power to defer the payment of taxes; this is helpful for spurring investment, but requires somewhat complex accounting treatment. The amount of Minnesota Power s deferred taxes has increased considerably since its previous rate case (Docket No. E015/GR-09-1151), such that the treatment of these issues will have a material effect on the revenue requirement analysis for Minnesota Power. I will discuss three interrelated topics relating to deferred taxes: bonus depreciation, tax net operating losses ( NOLs ), and normalization. The bonus depreciation feeds into the calculation 2 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 of the Company NOL, which then feeds into our application of normalization accounting methods. A. Bonus Depreciation Q. Please describe bonus depreciation. A. Bonus depreciation is an additional amount of tax-deductible depreciation that is taken in the first year that an asset is placed in service. The bonus tax deduction in the first year is typically 50 percent of the qualified cost of the asset. Bonus depreciation was created by Congress to assist with economic recovery by providing an incentive for businesses to make capital investments. Q. Does it benefit customers when a utility such as Minnesota Power utilizes bonus depreciation? A. Yes. Bonus depreciation is, in essence, an accelerated tax deduction. Utilizing bonus depreciation increases the Company s amount of accumulated deferred income taxes ( ADIT ), which is normally a liability on the Company s books. The increased balance of ADIT benefits customers by reducing rate base and correspondingly reducing revenue requirements. Q. Has Minnesota Power taken full advantage of bonus depreciation? A. Minnesota Power has taken full advantage of the bonus depreciation provisions of the most recent extension of bonus depreciation in the Protecting Americans from Tax Hikes ( PATH ) Act of 2015, as well as the bonus depreciation provisions of various tax acts of prior years. Q. Does this rate case filing reflect Minnesota Power s use of bonus depreciation for capital projects anticipated during the test year? A. Yes. Under the PATH Act of 2015, bonus depreciation has been extended for years 2015 to 2019, and, therefore, the 2017 test year reflects bonus depreciation for capital additions. 3 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Q. What is the result of Minnesota Power having taken advantage of bonus depreciation? A. Without bonus depreciation, Minnesota Power would have had taxable income in prior years. By taking bonus depreciation, Minnesota Power has fully offset its taxable income in those prior years, resulting in it experiencing a tax NOL carryforward to the test year. An NOL simply means that the company has more tax deductions than can be used in the current period. The NOL can be carried forward to another period where it can be applied to reduce then-current taxes. B. Net Operating Losses Q. How did Minnesota Power s NOL carryforward develop? A. Minnesota Power experienced an NOL for 2009 due to bonus depreciation. A portion of the NOL for that year was carried back to previous tax years to the full extent available; the remainder of the 2009 NOL was carried forward, beginning the NOL carryforward. As it undertook significant capital projects in 2010 and subsequent years, particularly the Bison Wind projects in 2010 through 2014, Minnesota Power utilized bonus depreciation, resulting in additional NOLs and thus increasing the NOL carryforward. Minnesota Power currently projects that it will have taxable income for 2016 and later years to which the NOL carryforward can be applied, such that (under current federal tax law) the NOL carryforward will be fully utilized in approximately 2020. Q. How is the NOL carryforward arising from bonus depreciation reflected in Minnesota Power s books? A. Because the cash benefit of the accelerated tax depreciation has not been realized, but has instead been deferred for future realization, that deferral is recorded on Minnesota Power s books as an Accumulated Deferred Income Tax Asset ( ADITA ). Q. How was the ADITA for the NOL treated in Minnesota Power s prior rate case? A. Minnesota Power s last rate case, Docket No. E015/GR-09-1151, was filed on November 2, 2009, for test year 2010. At that time Minnesota Power had not yet filed 4 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 its 2009 tax return and had anticipated it could carry back the NOL to prior years. Minnesota Power anticipated a tax loss for the 2010 test year, but did not include an ADITA for the NOL carryforward in the ADIT balance used in that rate case. The tax benefit of the NOL was considered a current receivable, which did not impact rate base. Q. How was the ADITA for the NOL treated thereafter? A. In Renewable Resource Rider ( RRR ) and Transmission Cost Recovery Rider ( TCR ) filings, Minnesota Power requested inclusion of an ADITA for the NOL carryforward. In Minnesota Power s 2011 TCR docket (the 2011 Transmission Factor proceeding ), Docket No. E-015/M-11-695, Minnesota Power and the Department of Commerce (the Department ) filed detailed Comments concerning how NOLs ought to be calculated in riders and the effect of that treatment on revenue requirements. Ultimately, Minnesota Power and the Department agreed, and the Commission ordered, that a hybrid approach should be used for Current Cost Recovery Riders. Q. What was the hybrid approach for including NOLs in the RRR and TCR filings? A. In the hybrid approach, each project included within a rider filing was separately analyzed to determine if it created a tax loss by virtue of its own tax depreciation and expenses. If the project created an NOL on its own, an ADITA for the NOL for that project was included. If the project did not create an NOL on its own, no ADITA for an NOL was included in the revenue requirements calculation for that project. Q. Has Minnesota Power adhered to the approach ordered in the 2011 Transmission Factor proceeding? A. Yes. However, determining the ADITA for the NOLs, and corresponding revenue requirements, on a project-by-project basis under this methodology has been very complex and time-consuming. 5 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 Q. How is the ADITA for the NOL treated in this rate case? A. In this rate case, Minnesota Power has incorporated the ADITA for the NOL in the ADIT balance for computing rate base. Consistent with this approach, Minnesota Power proposes to remove the ADITA for the NOL from rider revenue requirements calculations beginning with the implementation of interim rates, and will not include it in subsequent Current Cost Recovery Rider filings. The inclusion of the ADITA for the NOL in the ADIT balance reflects the fact that Minnesota Power was not able to fully utilize all of its tax deductions in prior years. Q. Why is Minnesota Power changing from the approach of including the ADITA in riders to incorporating it in the ADIT balance for computing rate base? A. The ADITA for the NOL was included in the riders because Minnesota Power had just completed its most recent rate proceeding, and was then experiencing additional NOLs due to the further extension of bonus depreciation. Riders were the only vehicle available at that time for addressing the ADITA for the NOLs; otherwise, it would not have been possible to determine the correct net ADIT for purposes of calculating revenue requirements for projects added after the rate case. In other words, the use of the riders was a temporary solution for the unusual situation resulting from how the timing of the previous rate case interacted with the timing of changes in the tax laws and the timing of the Company s projects. Inclusion of the ADITA for the NOL in the ADIT balance for computing rate base is the more standard, and straightforward, way to account for the NOLs. Inclusion of the NOLs in base rates is consistent with how other utilities have been accounting for NOLs. In addition, removing the ADITA for the NOL from being addressed in several separate riders will prevent potential duplication of the deferred tax asset between the Current Cost Recovery Riders and base rates, and will provide transparency regarding the total amount of ADITA for the NOL in the ADIT balance. 6 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 Q. What effect does this treatment have in this rate case? A. Including the ADITA for the NOL will decrease the ADIT balance, thereby increasing rate base by $158 million Total Company 1 ($134 million MN 2 ). If it was not transferred out of the riders into this rate case, approximately this same amount of ADITA for the NOL would have been included in the Current Cost Recovery Riders. C. Normalization Q. What does normalization mean in the context of public utility ratemaking? A. Normalization refers to the method of accounting in which the tax benefits associated with accelerated depreciation and ITCs from utility assets are spread over the same time period that the cost of investments are recovered from customers. The objective of normalization is to ensure that current and future utility customers are treated equitably by allowing all customers to enjoy the tax benefits associated with utility assets. Normalization has the effect of evening out, or levelizing, customer rates over time. Q. Is normalization required by law? A. Yes. In Internal Revenue Code Sections 168(i)(9) and (10), Congress mandated that public utilities must use normalization for depreciation. Normalization is also specifically required for ITCs. This requirement was first imposed in Internal Revenue Code Section 46(f)(2); even though that section has since been repealed, under Internal Revenue Code Section 50(d)(2) it still applies with respect to property on which a regulated utility claims ITCs. Q. Does the ADITA for the NOLs described above have to be normalized? A. Yes. Minnesota Power was not able to fully utilize all of its tax deductions in prior years. Therefore, under IRS Regulation 1.167(l)-1(h)(1)(iii), the ADITA for the NOL must be offset against the ADIT balance for the calculation of rate base to reflect that no cash was received for some of the accelerated tax deductions. 1 Total Company refers to total Minnesota Power regulated, without Minnesota Power s non-regulated entities. 2 MN refers to total Minnesota jurisdictional. 7 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Q. What happens if a utility fails to adhere to the normalization requirements? A. Intentional disregard of the normalization requirements is considered a normalization violation. Normalization can be violated by the use of inconsistent estimates and projections, per Internal Revenue Code Section 168(i)(9)(B)(i)-(iii). This could include the computation of federal tax expense for depreciation over a period shorter than the book service life; the amortization of ITCs over a period shorter than the book service life; or the failure to net the ADITA for an NOL against the corresponding ADIT liability if it was created by accelerated tax depreciation. Internal Revenue Code Section 168(f)(2) states that if a public utility fails to use normalization, the utility is prohibited, going forward, from taking accelerated depreciation, which would dramatically increase the utility s rate base. Similarly, a normalization violation related to ITCs will result in the loss of all unamortized ITCs, which would increase income tax expense. Either would have the effect of increasing future revenue requirements. Q. Do the IRS normalization rules have special detailed provisions relating to the use of a pro rata deferred tax calculation? A. Yes. Similar to the normalization requirements for calculating regulatory tax expense, by spreading the tax benefits of accelerated tax depreciation to all customers over the book service life of the assets, a separate normalization requirement exists for the calculation of the ADIT balance used to reduce rate base when using a future, or forecast, test year. Q. Please describe the IRS normalization regulation requiring a pro rata calculation when the utility uses a forecast test year. A. IRS Regulation 1.167(l)-1(h)(6)(ii) states, If solely a future period is used for such determination [determining the maximum amount of the ADITA to exclude from rate base], the amount of the reserve account for the period is the amount of the reserve at the beginning of the period and a pro rata portion of the amount of any projected increase to be credited or decrease to be charged to the account during such period. 8 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 Section (h)(6)(ii) goes on to explain the calculation methodology in detail: The pro rata portion of any increase to be credited or decrease to be charged during a future period (or the future portion of a part-historical and part-future period) shall be determined by multiplying any such increase or decrease by a fraction, the numerator of which is the number of days remaining in the period at the time such increase or decrease is to be accrued, and the denominator of which is the total number of days in the period (or future portion). Section (h)(6)(iv) also includes examples showing the calculation methodology, including one example involving a future, or forecast, test year. Q. Why does the IRS require that the deferred tax calculation be computed in a special manner when the utility is using a future test year? A. The purpose of this requirement is to ensure that the estimated deferred tax balance utilized as a reduction to rate base does not deny a utility a current return for accelerated depreciation benefits the utility is only projected to have. If new rates become effective before the end of a test period, an indirect flow-through of the benefits of accelerated depreciation occurs because the rates are based on a reserve amount in excess of the actual balance. The purpose of the proration requirement is to prevent this flow-through. Q. Did the IRS recently interpret its Regulation 1.167(l)-1(h)(6)? A. Yes. Although this regulation has been in existence since the 1970s, taxpayers recently began seeking guidance from the IRS on the proper way to apply it. In 2015, the IRS issued several Private Letter Rulings ( PLRs ) concerning Regulation 1.167(l)-1(h)(6), specifically the use of the proration formula in the context of setting formula/wholesale rates with a true-up. 3 The IRS determined that this proration requirement applies to all future test period rate filings that implement rates before the end of the test period, including stand-alone rate adjustments and formula rates with a true-up. This IRS interpretation came as a surprise; it caused many utilities to become concerned that they had committed a normalization violation by submitting various 3 PLRs 201531010, 201531011, 201531012, 201532018, and 201541010. 9 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 types of rate filings that did not comply with the proration formula requirement. In the 2015 PLRs, the IRS determined that as long as the utility applied the proration formula in future filings, the IRS would not declare a normalization violation. The IRS did this because it assumed that no taxpayer had intentionally violated the normalization rules. Q. How did Minnesota Power analyze Regulation 1.167(l)-1(h)(6) in previous rate cases? A. For Minnesota Power s previous two rate cases, Minnesota Power reviewed Regulation 1.167(l)-1(h)(6) and ultimately concluded the proration requirement did not apply because final rates were estimated to be going into effect after the end of the test year. The focus was on the implementation of final rates, not interim rates. Q. Has Minnesota Power analyzed Regulation 1.167(l)-1(h)(6) again for this case? A. Yes. In light of the recent focus on the proration issue, Minnesota Power took a fresh look at the IRS rule. Based upon our review of the IRS regulation, along with an analysis of the Minnesota interim rate statute, we determined the pro rata calculation is applicable to this rate proceeding. This is also consistent with the approach that other Minnesota electric utilities are taking. Q. What effect does Minnesota Power s compliance with the pro rata calculation rule have in this rate case? A. Minnesota Power has concluded that the rates that it requests in this rate case will take effect before the end of the future test period (i.e., before the end of 2017). Therefore, Minnesota Power has concluded that for purposes of rates (including interim rates), it must use the proration calculation set forth in Regulation 1.167(l)-1(h)(6)(ii). Utilizing the proration methodology to calculate ADIT results in a reduction to the ADIT balance, thereby increasing rate base. The increase in rate base for the test year for this adjustment is $9.3 million Total Company ($7.9 million MN). A worksheet showing how this was determined is attached as Exhibit (JLJ), Schedule 1 to my Direct Testimony. 10 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 Q. What else has Minnesota Power done in light of its conclusion that the pro rata calculation rule applies? A. A group of MISO participants, including Minnesota Power, applied to the Federal Energy Regulatory Commission ( FERC ) for permission to change their calculation of Attachment O of the MISO Tariff to use the pro rata method. In an Order dated December 30, 2015, FERC approved the application. A copy of this FERC Order is attached as Exhibit (JLJ), Schedule 2 to my Direct Testimony. Minnesota Power and some of the other transmission owners subsequently agreed upon a standard spreadsheet format for calculating deferred taxes for purposes of Attachment O under the pro rata methodology. This standard MISO spreadsheet format has been utilized for this filing and is attached as Exhibit (JLJ) Schedule 1 to my Direct Testimony. In addition, Minnesota Power is consistently following this methodology for all other rate filings that it believes meet the IRS definition of a future test year: Current Cost Recovery Riders, Attachment O, and formula-based rates. Q. As it reanalyzed this issue, did Minnesota Power consider the impact of potential non-compliance with the IRS normalization rules? A. Yes. The penalty for failure to comply with the normalization rules disqualification from taking any accelerated depreciation is extremely severe, and would be very detrimental to ratepayers. Minnesota Power is committed to acting prudently with regard to IRS regulations in order to minimize the risk of potential negative consequences to ratepayers. Minnesota Power understands that as long as it uses the proration formula in future applicable filings, the IRS would not declare a normalization violation. Q. Was Minnesota Power s decision made in reliance on the IRS PLRs? A. No. The issuance of the PLRs refocused our attention on Regulation 1.167(l)-1(h)(6). 11 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Q. Have you reviewed other recent Commission dockets that involve the pro rata calculation requirement? A. Yes. The use of the pro rata calculation was discussed in pending matters involving Northern States Power Company, doing business as Xcel Energy, (Docket Nos. E002/GR-15-826 and E002/M-15-805) and Otter Tail Power Company (Docket No. E017/GR-15-1033). Q. In light of the submissions in those dockets, please explain how the pro rata calculation relates to tax expense. A. Generally, the deferred tax expense that is utilized in the calculation of the cost of service is the same expense increment used to adjust the deferred tax reserve. IRS Regulation 1.167(l)-1(h)(6) requires a proration adjustment to be made to the calculation of the deferred tax reserve, but that does not mean that it requires the same adjustment to be made to the deferred tax expense; in fact, the IRS regulation does not even suggest an adjustment be made to deferred tax expense. Accumulated deferred taxes are a reduction to rate base, as they are cost-free capital provided by the IRS as a result of accelerated tax deductions. This additional capital reduces the return needed on the investment made by the shareholders for the rate base. IRS Regulation 1.167(l)-1(h)(6), regarding future test periods and the use of the proration method, addresses the cost-free capital provided by the IRS. That rule does not address, much less change, the level of current and deferred tax expense to be included in the cost of service calculation. Rather, tax expense is calculated under other normalization rules that require the use of both current and deferred tax expense to reflect the book service life of the assets. Q. Are there any other topics from the testimony in the above-referenced rate cases that you want to discuss? A. Yes. I would like to discuss the applicability of the recent PLRs that were issued related to projected formula rate filings with a subsequent rate filing that included a true-up mechanism, resulting in discussions about whether the proration formula for 12 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 ADIT should also be used in subsequent true-ups. Minnesota Power s rate case, which is for retail rates, does not have an automatic true-up mechanism after the test period for actual amounts, whether for income tax items or for items other than income taxes. Minnesota Power s rate case is a single-year rate case with a future test period. Therefore, the discussions in those other dockets concerning true-ups (and the PLRs statements about true-ups) are not directly relevant in this case. In addition, the Department s assumption that there ought to be a true-up is inconsistent with the IRS examples in Regulation 1.167(l)-1(h)(6). Those examples use a situation in which the future test year is 1975, with rates contemplated to be in effect for 1975, 1976, and 1977. The regulation specifies how to calculate the deferred tax reserve for the test year, and does not provide for any subsequent true-up for the later years of 1976 and 1977 that will be utilizing the same rate calculation. Therefore, Minnesota Power does not believe any true-up should be utilized after the test period is complete. Minnesota Power is adhering to the IRS normalization rules. III. FEDERAL TAX CREDITS A. Production Tax Credits Q. What are PTCs? A. PTCs are tax credits that result from the generation of electricity using renewable resources. They are intended to act as a financial incentive to support the development of renewable energy facilities and are provided for the first ten years of a renewable energy facility s operation. Q. Describe Minnesota Power s history with PTCs. A. Minnesota Power first began generating PTCs with its construction of the Taconite Ridge Wind Energy Center in 2008. Minnesota Power was able to use the resulting PTCs in 2008 to reduce federal tax expense because it did not have an NOL at that time. Beginning with the tax return for 2009, filed in 2010, Minnesota Power had an NOL and was not able to utilize the PTCs generated. 13 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 The construction of Minnesota Power s four Bison Wind projects, which were placed in service in years 2010 through 2014, generated significant PTCs, but those PTCs were not utilized and were instead deferred for future utilization and recorded as an ADITA. Within subsequent RRRs, the Bison Wind PTCs were used to reduce revenue requirements in the year they were generated. As a result of crediting revenue requirements for the PTCs in the year generated, the ADITA for the Bison Wind PTCs was included as an offset to the corresponding deferred tax liabilities within those RRRs. Q. How is the ADITA for the PTCs incorporated in this rate case? A. With this rate case, Minnesota Power has removed the ADITA for the PTCs from the most recently filed RRR (Docket No. E015/M-16-776 (the 2017 RRR ), filed on November 2, 2016), and has instead incorporated the existing PTC deferred tax asset into the ADIT, beginning with interim rates. Consistent with the treatment in prior RRRs, Minnesota Power will continue to use the PTCs from estimated 2017 wind generation to reduce federal tax expense and revenue requirements. Q. What effect will this have on rates? A. For the Bison Wind projects, the inclusion of the PTCs, and the ADITA for PTCs, will be neutral to overall rates, because it will result in moving these items from the RRR to base rates. For the Taconite Ridge project, the inclusion of the ADITA for PTCs will result in an increase in rate base. The Taconite Ridge project was placed in service in 2008, and has been included in base rates. Therefore, the cumulative average ADITA for PTCs from Taconite Ridge ($10.9 Total Company, $9.2 MN) has not been included in the RRR, or as a component of ADIT, previously. 14 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 Q. Please describe why incorporating all of the ADITA for PTCs in base rates is reasonable. A. All four Bison Wind projects were placed in service after the previous rate case (Docket No. E015/GR-09-1151), and for this rate case, they are moved to rate base from the RRR. Therefore, the corresponding ADITA for PTCs should be reflected in the same computation of rate base. As to Taconite Ridge, the Company s most recent rate case (Docket No. E015/GR-09-1151) included the tax benefit of the test year amount of PTCs for Taconite Ridge ($1,868,118 Total Company, $1,487,227 MN) in tax expense. No ADITA for PTCs for Taconite Ridge was included in ADIT, as it was assumed the PTCs would be utilized. As a result, every year since 2010, customers have been receiving the tax benefit from PTCs for the Taconite Ridge project, even though Minnesota Power has not yet received that tax benefit. Therefore, inclusion of the corresponding ADITA for PTCs for Taconite Ridge is appropriate. Q. What PTC deferred tax asset are you requesting to include in base rates? A. Minnesota Power is requesting Commission approval to include $154,738,748 Total Company ($131,032,771 MN) of PTCs in rate base. Q. How was this amount calculated? A. Minnesota Power has not yet utilized any of its accumulated PTCs as of the date of this filing. Therefore, the amount includes all PTCs accumulated through year-end of 2015, plus the PTCs budgeted for 2016 and 2017. This calculation is shown in Table 1. 15 Jago Direct and Schedules
1 Table 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 Q. Will any PTCs remain in the RRR? A. Because it is difficult to predict the expected generation from wind production for the test year, and therefore it is difficult to predict the tax benefit from the PTCs from the Bison Wind and Taconite Ridge projects, Minnesota Power proposes to utilize the RRR to annually true-up the PTCs for any difference between the PTCs projected in the test year and the actual PTCs generated in future years. A true-up is advisable because the potential annual variability in wind, and the magnitude of the annual estimated tax benefit from PTCs, make it quite difficult to confidently estimate future wind production and the resulting PTCs. In addition, Minnesota Power expects these PTCs to increase in the future, as the IRS applies an inflation factor to the current rate of $23 per megawatt hour ( MWh ). Use of an annual true-up would provide a mechanism to capture this expected future benefit. Further, use of an annual true-up would provide a method to automatically adjust for the loss of PTCs at the end of the respective ten-year credit period. For these reasons, this proposed true-up methodology will provide transparency and fairness to both the utility and the ratepayers for a material item that is particularly difficult to predict. B. Trend in ADITA Balances for Federal NOLs and PTCs Q. Has Minnesota Power projected the trends in its ADITA balances after the test year? A. Yes. We have projected the anticipated deferred tax balances for some items that could impact rate base in years after the test year. I would like to specifically call attention to the ADITA for the federal NOLs and for the PTCs. As described previously, Minnesota Power anticipates that the NOL carryforward, under current tax 16 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 law, will be fully utilized in approximately 2020. This will cause the ADITA for the NOL to decrease to zero over the next several years. Since Minnesota Power is in the tax position of using NOL carryforwards to totally eliminate all current federal tax expense, the PTCs being generated are not being utilized, causing the carryforward balance for the PTCs to increase. At the same time, due to the size of the PTCs expected to be generated by Minnesota Power, the decrease in the ADITA for the NOL is being offset by the increase in the carryforward for the PTCs. The relationship and timing of these ADITA projected changes is shown in Figure 1. Figure 1 11 12 13 14 15 16 17 Based upon these projected changes in the ADITA for the NOL and the PTCs, Minnesota Power believes the rate base impact over time does not change materially and no special provisions for these expected changes would need to be considered for adjusting rates after the test year period. 17 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 C. Federal Investment Tax Credits Q. What are federal ITCs? A. Federal ITCs are currently available for qualified renewable energy projects, providing a credit in the amount of 30 percent of qualified expenditures for solar, wind, hydro, and geothermal projects. An ITC is generated at the time the qualifying facility is placed in service. Federal ITCs are intended to act as a financial incentive to support the development of renewable energy facilities. Q. Please describe Minnesota Power s history with federal ITCs. A. Minnesota Power has used federal ITCs for decades; the types of expenditures that qualify have changed over the years. Previously, investments in public utility property such as steam generation, transmission, distribution, and hydro facilities qualified for ITCs. Q. How are federal ITCs incorporated in this rate case? A. Minnesota Power amortizes federal ITCs under former Internal Revenue Code Section 46(f)(2) (as described above, this provision is still applicable even though it was repealed). ITC amortization is a reduction to tax expense, and this method has been utilized by Minnesota Power since the 1970s. No change in the treatment of ITCs is being proposed in this rate case. Q. Please describe the federal ITCs earned on the Thomson Hydro Dam. A. In 2015, Minnesota Power placed in service the substantial rebuild of the Thomson Hydro Dam, which was destroyed by a flood in 2012. The rebuild of the dam qualifies for $24 million of federal ITCs under Internal Revenue Notice 2008-60, Electricity Produced From Certain Renewable Resources. Notice 2008-60 provides guidance for determining when a rebuilt renewable asset will qualify as a new asset for purposes of earning a tax credit. In late 2015, once the costs for the Thomson Hydro Dam rebuild incurred through 2015 were known, Minnesota Power was able to determine that the project qualified under the ITC criteria. 18 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 Q. Will the ITCs earned on the Thomson Hydro Dam be amortized in this rate case? A. No. As noted above, because Minnesota Power s current NOL carryforwards will be used for the next several years to offset all current federal income tax liability, Minnesota Power will not realize a reduction in federal tax payable for several years. Under IRS normalization rules, Minnesota Power cannot begin to amortize this new federal ITC until it is utilized in a subsequent tax year. Minnesota Power currently anticipates fully utilizing the NOL carryforward in approximately 2020, and at that time will begin using Minnesota Power s tax credit carryforwards. Minnesota Power will begin amortizing these federal ITCs in the year utilized on a federal tax return, which will be a few years after 2020, as credits are utilized in the order generated. Q. Please describe how Minnesota Power treated the ITCs for the Thomson Hydro Dam. A. The federal ITCs generated in 2015 from the Thomson Hydro Dam were recorded as a debit to a deferred tax asset included in the total ADIT balance, and a credit to the Accumulated Federal Investment Tax Credit liability account. However, because the credits are not being amortized in this test year, the deferred tax asset has been removed from the ADIT balance. The removal of the deferred tax asset for the unused ITC defers the impacts of the ITC until the year that the credits will be utilized and regulatory tax expense will be reduced for the amortization of the ITC from the Thomson Hydro Dam rebuild. Q. What effect does this have in this rate case? A. There will be no effect on rates in this rate case from the ITCs earned on the Thomson Hydro Dam project. Under the IRS normalization rules, the ITCs cannot be amortized until later, and the deferred tax asset that reflects the carryforward of the credit to a future tax year has been removed. The Commission approved the request to include the Thomson Hydro Dam project as part of Minnesota Power s Renewable Resources Rider in Docket No. E015/M-14-577. The inclusion of this topic in my testimony is simply to ensure full transparency of this issue, so that stakeholders are aware of 19 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 Minnesota Power s efforts to qualify all possible projects for tax credits to reduce tax expense for the benefit of customers. IV. MEDICARE PART D Q. What is the Medicare Part D subsidy? A. The Medicare Prescription Drug, Improvement, and Modernization Act ( MMA ) was signed into law in 2003. The MMA introduced a prescription drug benefit under Medicare Part D, as well as a federal subsidy to sponsors of retiree health benefit plans that provide a benefit that is at least actuarially equivalent to the benefits under Medicare Part D. The subsidy reduces the health plan s benefit obligation, and was estimated to be approximately 26 percent of the cost of qualified prescription costs. Employers could request reimbursement for this subsidy as the qualified prescription costs were incurred by plan participants over the life of the retiree health benefit plan. Q. Did the Medicare Part D subsidy create a tax benefit? A. Yes. Employers were permitted under the MMA to deduct all retiree health care payments for prescription benefits, even though part of the prescription benefits were offset by the subsidy. The subsidy had the effect of reducing the expense of the health plan s benefit obligation. The tax benefit resulted from the ability of the Company to fully deduct the amounts actually paid for prescription drug benefits in future years without recognizing the subsidy as a reduction of those amounts paid. Q. How did the Medicare Part D subsidy impact the retiree health benefit expense? A. Retiree health benefit costs are determined on an actuarial basis, with the amount of annual benefit expense determined using actuarial assumptions. The annual tax benefit for the expected tax savings relating to the anticipated Medicare Part D subsidy was a component of Minnesota Power s annual actuarially-determined expense for Other Post-Employment Benefits ( OPEB ). The tax benefit resulted in a reduction of the annual OPEB expense. The expected subsidy itself was also a component, reducing the annual OPEB expense. Company witness Ms. Nicole Johnson provides 20 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 additional information on Minnesota Power s OPEB expenses in her Direct Testimony. Q. How did Minnesota Power account for the Medicare Part D subsidy tax benefit? A. For Generally Accepted Accounting Principles ( GAAP ) purposes, Minnesota Power was required annually to recognize the tax benefit for the subsidies included in the annual OPEB expense by reducing tax expense and recording a deferred tax asset for the future tax deduction. This treatment reflects the difference in timing between when the tax benefit was recognized for GAAP purposes and when the tax deduction was allowed on the return. Minnesota Power recorded the annual reduction in tax expense and the deferred tax asset in all years the MMA was in effect, 2004 through 2010. Q. What was the impact of this accounting treatment in Minnesota Power s prior rate cases? A. The deferred tax asset increased rate base, increasing the needed revenue requirement, while the tax benefit included as a component of the tax expense reduced the needed revenue requirement. In Minnesota Power s most recent rate case (Docket No. E015/GR-09-1151), and the previous rate case (Docket No. E015/GR-08-415), the net benefit was a positive impact to ratepayers and was passed on as a reduced revenue requirement. In the 2008 rate case, the net jurisdictional benefit provided to ratepayers in reduced revenue requirements was $855,974. In the 2009 rate case, the net jurisdictional benefit provided to ratepayers was $627,900. Q. Did the law change? A. Yes. On March 23, 2010, the Patient Protection and Affordable Care Act ( PPACA ) was signed into law, with an amendment signed on March 30, 2010. The PPACA included many provisions, including the elimination of the tax deduction for the portion of the prescription drug costs for which an employer receives a Medicare Part D subsidy, for taxable years beginning after December 31, 2012. 21 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 Q. What effect did this have on Minnesota Power? A. Although the elimination of the tax deduction for the Medicare Part D subsidy did not take effect until 2013, GAAP required the resulting income tax expense to be recorded in the period of enactment of the tax law change. Accordingly, the Company recorded the effect of the PPACA in 2010. A reduction in the deferred tax asset was recognized in March 2010 through a charge to the earnings of ALLETE. Q. What was the amount of that write-off? A. The total ALLETE 4 amount written-off and charged to continuing operations was $3,984,456, and a Securities and Exchange Commission ( SEC ) 8-K disclosure of this event was required due to the nature and materiality of the amount. Minnesota Power was charged $3,456,031, of which the Minnesota jurisdictional amount was $2,926,567. Q. Did the Company request Commission consideration of this law change in 2010? A. Yes. The PPACA enactment in March 2010 occurred after Direct Testimony had been filed in the Company s then most-recent rate case (Docket No. E015/GR-09-1151). The timing of the law change did not allow sufficient time to address the issue within that rate case. Therefore, Minnesota Power proposed addressing the issue in a separate proceeding. Minnesota Power subsequently filed a Petition for Approval to Defer the Tax Impact of the PPACA on Medicare Part D Subsidies ( 2010 Medicare Part D Petition ), which was assigned Docket No. E015/M-10-1083 ( 2010 Medicare Part D Docket ). A copy of the 2010 Medicare Part D Petition is attached as Exhibit (JLJ), Schedule 3 to my Direct Testimony. 4 Total ALLETE includes all of ALLETE, Inc. s subsidiaries, including its regulated and non-utility, energy focused businesses. 22 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 Q. What did Minnesota Power propose in the 2010 Medicare Part D Petition? A. In that Petition, the Company explained the impact of the Medicare Part D tax benefit on rates. Minnesota Power proposed to record the deferred tax asset of $2,926,567 as a non-earning regulatory asset in order to allow a more thorough analysis of the total impact of the PPACA. Minnesota Power explained why this proposal met the Commission s previously-articulated criteria for requests for deferred accounting. Minnesota Power proposed that once the full impact of the PPACA was fully analyzed in a future rate case, the deferred tax asset would be amortized over a period of 30 years. Q. What occurred in the 2010 Medicare Part D Docket? A. The Department filed Comments recommending denial of the 2010 Medicare Part D Petition. Minnesota Power submitted Reply Comments disagreeing with the Department s Comments. A copy of Minnesota Power s March 18, 2011, Reply Comments is attached as Exhibit (JLJ), Schedule 4 to my Direct Testimony. In response, the Department recommended that the Commission allow Minnesota Power to defer the $2,926,567 Minnesota jurisdictional amount, with amortization over a 30- year period, conditioned on Minnesota Power providing information in its next rate case about the impact of the PPACA. In an Order dated May 24, 2011, the Commission deferred action on the potential cost recovery of the tax impact of the Medicare Part D subsidies until the Company s next rate case, and required Minnesota Power, in the next rate case, to provide a detailed accounting of the effects of the PPACA, including information on five specific topics. Q. Is Minnesota Power requesting cost recovery for the tax impact of the Medicare Part D subsidies now? A. Yes. This is the first rate case after the Commission s May 24, 2011, Order in Docket No. E015/M-10-1083. 23 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Q. Has the Company provided the additional information specified in the Commission s May 24, 2011, Order? A. Yes. In addition to incorporating the documents that constitute our initial cost recovery proposal in Docket No. E015/M-10-1083, Minnesota Power is providing information on the effects of the PPACA specified in that Order in the Direct Testimony of Company witness Ms. Johnson. This information is intended to allow a detailed analysis of the total effects of the PPACA legislation and the identification of any offsetting benefits that could relate to cost recovery. It is presented in Ms. Johnson s Direct Testimony because much of it relates to employee benefits and Ms. Johnson is Vice President Human Resources for Minnesota Power. As outlined in Ms. Johnson s Direct Testimony, the PPACA has resulted in some additional costs and some additional requirements with which the Company must comply. She also explains how the PPACA was a catalyst in changing some benefit plans. However, the PPACA did not result in material savings to Minnesota Power that would reduce or change the request for Medicare Part D cost recovery. Q. Did the PPACA result in any additional tax impacts to the Company? A. No. Other than eliminating the tax deduction for the Medicare Part D subsidy, the PPACA does not result in any other direct tax impacts for the Company. Q. What is the amount of cost recovery Minnesota Power is requesting at this time? A. Minnesota Power is making an updated version of the same request that it made in the 2010 Medicare Part D Petition: it proposes to record the deferred tax asset as a nonearning regulatory asset. The total tax impact for Minnesota Power is $3,456,031. In Exhibit 1 of the 2010 Medicare Part D Petition (Exhibit (JLJ), Schedule 3), the Company calculated that the Minnesota jurisdictional amount of the cost recovery of the tax impact was $2,926,567. That calculation was based on the then-current jurisdictional percentage. Using the current jurisdictional percentage used throughout the rest of this rate case, the Minnesota jurisdictional amount of the cost recovery of the tax impact figure is only slightly different: $2,990,431. 24 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Q. Why is recovery of this amount of tax impact reasonable? A. Minnesota Power has reflected a tax benefit for the Medicare Part D subsidy as a reduction in tax expense in both the Company s most recent rate case (Docket No. E015/GR-09-1151), and the prior rate case (Docket No. E015/GR-08-415). In both cases, the Company passed along the benefit as a reduction in revenue requirements. The net benefit of $627,900 from the 2009 rate case has been continuing to benefit customers each year, and will continue to benefit customers until rates are effective for this current proceeding. The cumulative net benefit to customers for the period since November 1, 2009, when final rates became effective for the 2008 rate case, amounts to well over $4 million. Although Ms. Johnson s Direct Testimony identifies some impacts, benefits, and costs of the PPACA separate and apart from the tax benefit for the Medicare Part D subsidy, none of them were included in the 2009 rate case as a benefit or expense. Only the net tax benefit for the Medicare Part D subsidy was included. Therefore, Minnesota Power believes that the Medicare Part D tax impact, which has been benefitting customers for several years without any inclusion of other changes from the PPACA, warrants separate consideration for cost recovery. Q. How does Minnesota Power propose to recover this Medicare Part D tax benefit? A. Minnesota Power proposes to include the additional revenue requirement needed to recover the tax impact of this item over 30 years, consistent with the original Medicare Part D Petition, minus six years for the time that has lapsed since the original deferral. An amortization period of 30 years was agreeable to the Department in its Comments in response to Minnesota Power s Medicare Part D Petition. Minnesota Power believes that recovery of this tax benefit over the remaining 24 years is reasonable because the amortization period was originally designed to mirror the time period the subsidy would benefit Minnesota Power, which was the typical remaining life expectancy of a retiree generating the subsidy that Minnesota Power would receive. This amortization period was agreeable to the Department in its April 21, 2011, Comments in the 2010 Medicare Part D Docket. 25 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 As this item is a tax item, the revenue requirement needed to collect the tax benefit is computed using the gross-up factor of 1.7056, as computed on Schedule G-7, Development of Gross Revenue Conversion Factor, and on Schedule H-2, Computation of Federal and State Income Taxes. Therefore, the revenue requirement calculation is as follows: $2,990,431 x 1.7056 = $5,100,480. Minnesota Power proposes to include the jurisdictional revenue requirement of $5,100,480 amortized over 24 years, or $212,520 per year, approximately. V. PROPERTY TAX EXPENSE Q. What is the purpose of your testimony related to property tax expense? A. In this rate case, Minnesota Power is requesting recovery of property tax expense, based on forecasted property tax expense for 2017 (payable in 2018). I explain how Minnesota Power s property taxes are assessed, and why Minnesota Power s methodology for forecasting property expense is reasonable. Q. Who assesses Minnesota Power s property for purposes of property taxes? A. Minnesota uses a system in which most of the property of electric utilities is assessed on a state-wide unitary basis by the Minnesota Department of Revenue ( DOR ). Approximately ninety percent of Minnesota Power s property tax expense results from the DOR s assessment, referred to as centrally-assessed taxes. Because centrallyassessed taxes account for so much of Minnesota Power s property tax expense, my property tax testimony focuses on those taxes. Approximately five percent of Minnesota Power s property tax expense is for taxes based on assessments conducted at a local level by County Assessors. And the remaining approximately five percent of Minnesota Power s property tax expense is assessed by the state of North Dakota under its laws and rules relating to wind and transmission property tax. 26 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 Q. Please describe the process the DOR uses for centrally-assessed taxes. A. The DOR estimates the System Unit Value for all of Minnesota Power s operating property. That System Unit Value is then allocated to the states in which Minnesota Power does business; for the 2016 valuation, approximately 80 percent of Minnesota Power s unit value is allocated to Minnesota. From that allocated value, the DOR subtracts the value of property that is locally assessed and of property that is exempt from property tax. The remainder is known as the Apportionable Market Value. The DOR provides the System Unit Value and Apportionable Market Value to utilities in a report typically issued in June each year. The Apportionable Market Value is apportioned to each parcel in each of the local taxing jurisdictions in which Minnesota Power s property is located. Each local jurisdiction adds the value of our locally-assessed property in that jurisdiction to the apportioned value for that jurisdiction to reach an overall market value for that jurisdiction. They multiply the market value by the class rate to determine tax capacity, which is then multiplied by the local tax rate (which varies from year to year) to arrive at the property tax liability for each jurisdiction. Q. How does the DOR determine the System Unit Value? A. Because entire operating utilities are not often bought and sold, and not often built from scratch all at one time, the conventional approaches for valuing property are difficult to apply to utilities. The State of Minnesota has adopted administrative rules that set forth a methodology that the DOR uses to value utilities. 5 Very briefly summarized, the DOR uses two primary approaches, and considers other approaches, and then assigns weightings to the results of those approaches. The first approach is known as the cost approach. 6 The premise of this approach is that the original cost of the utility s system plant, minus depreciation, plus certain 5 See Minn. R. 8100.0100 et seq. 6 See Minn. R. 8100.0300, subp. 3. 27 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 construction work in progress, property held for future use, and contributions in the aid of construction, indicates the utility s overall market value. The second approach is known as the income approach. 7 The premise of this approach is that the net operating income generated by the utility, divided by a capitalization rate ( Cap Rate ) that is intended to reflect the present value of anticipated future income, indicates the utility s overall market value. By rule, the net operating income figure used in this approach is derived from a weighted average of the utility s net operating income over the previous three years. The DOR does a Cap Rate Study each year in which it analyzes economic data and determines the Cap Rate for use in this approach. Like most companies subject to centrally-assessed taxes, ALLETE submits information to the DOR each year advocating for a different Cap Rate. The DOR considers this information, but generally does not adjust its Cap Rate once determined for the year. The DOR may also consider other approaches, principally the market approach, sometimes known as the stock and debt approach. 8 This approach assumes that the utility s market capitalization (i.e., the price of the utility s stock multiplied by the number of shares outstanding), minus the company s debt, with various other adjustments, is indicative of the utility s overall market value. After determining an estimated value under the above approaches, the DOR assigns a weight to each. The default weightings are 50 percent cost approach, 50 percent income approach, and 0 percent market approach. 9 The result of these calculations is the DOR s System Unit Value. Q. Are the value estimates derived from the various approaches usually similar? A. For at least the previous five years, the estimated value for Minnesota Power derived from the cost approach has been significantly more than the estimated value derived 7 See Minn. R. 8100.0300, subp. 4 8 See Minn. R. 8100.0300, subp. 4a. 9 See Minn. R. 8100.0300, subp. 5. 28 Jago Direct and Schedules
1 2 3 4 5 6 7 from the income approach. As a result, the weighting assigned to each approach is tremendously important in determining the System Unit Value, and in turn in determining the amount of property tax expense. For example, if Minnesota Power s System Unit Value under the cost approach is $3 billion, but is only $2 billion under the income approach, a swing in weighting from 55 percent income/45 percent cost to 45 percent income/55 percent cost can result in a change of over $1 million in tax expense. 8 9 10 11 12 13 14 15 16 17 Q. Is it difficult to predict the amount of centrally-assessed taxes Minnesota Power will have to pay each year? A. Yes. Valuation of utility property is a complex and subjective exercise, and the DOR has the ability to exercise discretion at each stage of the process. The DOR s exercise of discretion is particularly pronounced in the overall weighting it gives to the approaches, which can vary widely from year to year. Over the past five years, the DOR s weightings have varied significantly from year to year, and also have varied significantly between the weighting in their initial assessment report and their final weighting, as summarized in Table 2. 18 19 20 21 22 23 24 25 Table 2 DOR Weighting Year DOR Initial Weighting DOR Final Weighting 2012 47.5% Cost, 47.5% Income, 5% Market 45% Cost, 55% Income 2013 45% Cost, 50% Income, 5% Market 30% Cost, 65% Income, 5% Market 2014 45% Cost, 50% Income, 5% Market 35% Cost, 60% Income, 5% Market 2015 50% Cost, 45% Income, 5% Market 40% Cost, 55% Income, 5% Market 2016 50% Cost, 45% Income, 5% Market 39% Cost, 59% Income, 2% Market Q. What does Minnesota Power do to mitigate the unpredictability of centrallyassessed taxes? A. As noted above, the DOR determines an initial System Unit Value for Minnesota Power each year. Minnesota Power then takes advantage of a process, set forth in Minnesota Statutes, providing for informal meetings with the DOR as well as a formal administrative appeal of the DOR s initial valuation. Through this process, Minnesota 29 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Power advocates for predictable and favorable weightings, a favorable Cap Rate, and other adjustments to lower Minnesota Power s System Unit Value and to make the DOR s valuation determination more consistent and predictable. The DOR considers the information provided by Minnesota Power and then issues a final System Unit Value. In each of the last five years (2012 to 2016), the result of this process has been that the weightings were adjusted and the final System Unit Value was lower than the initial determination; the amounts of the reduction have varied from year to year. Q. How does Minnesota Power forecast the amount of centrally-assessed taxes for each year? A. Minnesota Power uses a model that reflects the relevant financial data inputs for each of the three approaches (some of which are actual data for past years and some of which are budgeted future data) and that assumes that the weightings between the valuation approaches will be the same as what they were in the previous year. This results in an estimated System Unit Value. Minnesota Power then estimates the allocation to Minnesota based on the most current data available, and assumes that the subtraction for locally-assessed and exempt property will be the same as the previous year, with modifications for any known changes. This results in an estimated Apportionable Market Value. Minnesota Power then calculates the previous year s overall effective tax rate (i.e., the Apportionable Market Value plus the value of locally-assessed property, divided by the total amount of tax paid), assumes that the effective tax rate for the current year will be in the same range, and uses that effective tax rate to estimate the amount of tax expense. Q. What is Minnesota Power s forecast for centrally-assessed taxes for 2017 (payable in 2018)? A. Minnesota Power forecasts that its property tax expense from centrally-assessed taxes will be approximately $37.5 million. These calculations incorporate the DOR s final 2016 weighting of 39 percent cost approach, 59 percent income approach, and 2 30 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 percent market approach. In the income approach portion of these calculations, Minnesota Power estimated that the DOR would use a Cap Rate of 7.1 percent. Q. Why was a Cap Rate of 7.1 percent used in Minnesota Power s forecast? A. Our forecast of the DOR s Cap Rate is based on the downward trend of the DOR s Cap Rate over the last five years (7.9 percent in 2012; 7.5 percent in 2013; 7.6 percent in 2014; 7.4 percent in 2015; and 7.2 percent in 2016), considered in conjunction with other economic conditions and indicators. An important component of the Cap Rate calculation is the risk-free rate (i.e., the yield of U.S. Treasury bonds), which has been at a historically low level for several years and has remained very low this year. Each year when the DOR determines a Cap Rate to use in its assessment of Minnesota Power, Minnesota Power presents information to the DOR which the Company believes supports a considerably higher Cap Rate. But the DOR has the authority and discretion to dictate to the Company the Cap Rate that the DOR will use for all Minnesota electric utilities each year. Although Minnesota Power believes that its forecast that the DOR will use a 7.1 percent Cap Rate for 2017 is reasonable, it is important to make clear that Minnesota Power does not agree that use of a 7.1 percent Cap Rate would result in an accurate market value for Minnesota Power s property. Q. Why is Minnesota Power s forecast for centrally-assessed taxes for 2017 reasonable? A. The Company s forecast is based on the most recent information available, and it is based on reasonable assumptions. For example, the use of the previous year s weighting is the most recent data available. Minnesota Power s circumstances have not changed drastically since the previous year, so it is reasonable that the DOR s weightings should be the same as the previous year. And, the Company is not aware of a more reasonable way to predict the weighting the DOR will use. It is important to recognize that the budget process necessitates the estimation of property tax expense approximately 18 months before the final property tax bills. 31 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Specifically, the 2017 budget was prepared in mid-2016, before final 2016 figures for capital additions and other inputs to the formula are known. The local assessment rates and actual tax bills will not be created until early 2018. The Company s approach has proven to be reasonably accurate in forecasting property tax expense, as shown in Table 3. Table 3 Minnesota Power s Total Minnesota Property Expense Forecast and Actual Year Minnesota Power s Forecasted Minnesota Taxes ($ Million) 32 Minnesota Power s Actual Minnesota Taxes ($ Million) Variance 2011 $18.7 $21.2 13.3% 2012 $21.8 $23.6 8.3% 2013 $24.4 $26.4 8.2% 2014 $29.3 $29.3 0.0% 2015 $34.1 $33.5 (1.8%) 2016 $37.5 Payable in 2017 tbd Q. How does the 2017 forecast for centrally-assessed taxes for Minnesota Power compare to 2016? A. The 2017 forecast for centrally-assessed taxes, $37.5 million Total Company ($32.3 million MN), represents a 6.2 percent increase over the budgeted 2016 figure of $35.3 million Total Company ($30.4 million MN). Q. What is driving the increase? A. Much of the increase results from Minnesota Power s expectation that the DOR s Cap Rate will go down slightly. As explained above, this expectation is based on the expected continued downward trend in the DOR s Cap Rate and on the projection that interest rates will stay at relatively low levels into the future. Even a very small change in the Cap Rate results in a large change in the valuation under the income approach. Also, some of the increase results from the fact that other inputs into the valuation approaches, identified in the DOR rule, have increased since the previous year. Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Q. How does the increase compare to recent trends? A. Minnesota Power s property tax expense has been increasing significantly each year. Table 4 summarizes the Company s total property tax expense for Minnesota, not just centrally-assessed taxes, but it is illustrative of the trend because centrally-assessed taxes constitute such a large percentage of the Company s total property tax expense. Table 4 Increases in Minnesota Power s Total Minnesota Property Tax Expense Year Minnesota Power s Increase Compared Total Property Tax Expense to Previous Year ($ Million) 2011 $21.2 2012 $23.6 11.32% 2013 $26.4 11.86% 2014 $29.3 10.98% 2015 $33.5 14.33% Minnesota Power s expectation that its centrally-assessed taxes will increase by 6.2 percent from 2016 to 2017 is consistent with the trend that such taxes have steadily been increasing. Q. How does Minnesota Power forecast the portion of the property tax expense that results from local assessment in Minnesota? A. Minnesota Power assumed all Minnesota locally-assessed taxable values remained the same for 2017, with a 2 percent increase in local tax rates (i.e., if the local rate in a jurisdiction for 2016 was 3.2 percent, Minnesota Power multiplied that rate by 1.02 to reach a 2017 estimated rate of 3.264 percent). Q. How does Minnesota Power forecast the portion of the property tax expense that results from North Dakota wind and transmission tax? A. The wind portion of the North Dakota property tax is a generation and capacity tax. Because Minnesota Power estimates no material changes for North Dakota wind generation and no capacity changes, Minnesota Power forecasts the wind portion of 33 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 the property tax at approximately the same amount as paid in 2016. The transmission portion of the property tax is based on a specific dollar value per transmission mile per kilovolt ( kv ) size of the line. Because the amount of line in North Dakota will not materially change between 2016 and 2017, Minnesota Power forecasts the transmission portion of the property tax at the same amount as paid in 2016. Q. Please summarize Minnesota Power s budgeted property tax expense for 2017. A. Table 5 provides a summary of Minnesota Power s budgeted property tax expense. Table 5 2017 Tax Budget Component Budgeted 2017 Expense ($ Million) Total Company Jurisdictional Centrally-assessed MN $37.5 $32.3 Locally-assessed MN $2.2 $1.9 North Dakota $2.2 $1.9 Total $41.9 $36.1 Q. Is Minnesota Power requesting a method to true-up property tax expense? A. Yes. Although Minnesota Power believes it has done the best it reasonably can do to forecast property tax expense, the actual amount can vary for the reasons I discuss above. Minnesota Power proposes that if the 2017 Apportionable Market Value determined by the DOR is materially different from our projection, Minnesota Power will use the actual amount for final rates. Once the final 2017 Apportionable Market Value is determined, Minnesota Power will supplement my testimony so that the record in this rate case reflects whether the final property tax expense is significantly different from forecast. VI. CONCLUSION Q. Please summarize your Direct Testimony. A. Minnesota Power has properly used bonus depreciation, resulting in an NOL that will be carried forward to approximately 2020. Starting with this rate case, Minnesota 34 Jago Direct and Schedules
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Power is incorporating the NOL deferred tax asset in the ADIT balance for computing rate base. As to PTCs, Minnesota Power has moved the ADITA from the RRRs to base rates. Minnesota Power will continue to amortize federal ITCs as it has been doing, and will amortize the federal ITCs from the Thomson Hydro rebuild once utilized on a federal tax return. Minnesota Power believes no special provisions for the expected changes in ADITA balances would need to be considered for adjusting rates in future years after the test year. As to the Medicare Part D subsidy, Minnesota Power has provided the requested information, and seeks cost recovery for the Minnesota jurisdictional amount of $2,990,431, or $212,520 annually, as amortized over 24 years. Finally, Minnesota Power has reasonably forecasted its 2017 property tax expense, subject to a true-up when the 2017 Apportionable Market Value is known. Q. Does this complete your Direct Testimony? A. Yes. 35 Jago Direct and Schedules
Minnesota Power Month Calculation of IRC Required Deferred Income Tax Prorata Adjustment (Plant Deferred) 2017 Monthly Change Days to Prorate IRS Prorate Factor Monthly Change Prorated Test Year (a) (b) (c) = (b) / 365 (d) = (a) * (c) Annual Amount 34,659,329 MP Exhibit (JLJ) Direct Schedule 1 Page 1 of 1 January 2,888,277 335 91.78% 2,650,885 February 2,888,277 307 84.11% 2,429,318 March 2,888,277 276 75.62% 2,184,013 April 2,888,277 246 67.40% 1,946,620 May 2,888,277 215 58.90% 1,701,314 June 2,888,277 185 50.68% 1,463,921 July 2,888,277 154 42.19% 1,218,616 August 2,888,277 123 33.70% 973,310 September 2,888,277 93 25.48% 735,917 October 2,888,277 62 16.99% 490,612 November 2,888,277 32 8.77% 253,219 December 2,888,277 1 0.27% 7,913 Total 34,659,329 46.32% 16,055,657 Beg/End Average 17,329,665 8,027,829 Rate Base Increase 9,301,836
20151230-3075 FERC PDF (Unofficial) 12/30/2015 153 FERC 61,371 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION MP Exhibit (JLJ) Direct Schedule 2 Page 1 of 12 Before Commissioners: Norman C. Bay, Chairman; Cheryl A. LaFleur, Tony Clark, and Colette D. Honorable. Midcontinent Independent System Operator, Inc. Docket No. ER16-197-000 ORDER ACCEPTING REVISIONS TO FORMULA RATES, SUBJECT TO CONDITION (Issued December 30, 2015) 1. On October 30, 2015, Midcontinent Independent System Operator, Inc. (MISO), in its role as administrator of the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (Tariff), submitted proposed revisions to the formula rates for certain MISO Transmission Owners (the Certain TOs, and together with MISO, Filing Parties) 1 included in Attachment O of the Tariff. These revisions are proposed in order to comply with section 1.167(l)-1(h)(6)(ii) of the United States Internal Revenue Service (IRS) regulations. 2 2. As discussed below, we accept the proposed revisions to the company-specific Attachment O of the Certain TOs, subject to condition. These revisions will be effective on January 1, 2016, as requested. 1 The Certain TOs for this filing consist of: Ameren Services Company (Ameren), as agent for Ameren Illinois Company d/b/a Ameren Illinois (Ameren Illinois) and Ameren Transmission Company of Illinois (Ameren Transmission); Minnesota Power (and its subsidiary Superior Water, L&P) (collectively, Minnesota Power); Montana- Dakota Utilities Co. (Montana-Dakota); Northern Indiana Public Service Company (NIPSCo); Northern States Power Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc. (collectively, NSP Companies); Otter Tail Power Company (Otter Tail); and Southern Indiana Gas & Electric Company (d/b/a Vectren Energy Delivery of Indiana) (Vectren). 2 Treas. Reg. 1.167(l)-1(h)(6)(ii).
20151230-3075 FERC PDF (Unofficial) 12/30/2015 Docket No. ER16-197-000-2 - I. Background MP Exhibit (JLJ) Direct Schedule 2 Page 2 of 12 3. The Certain TOs use the formula rates set forth in their company-specific Attachments O to calculate their transmission revenue requirements for Commissionjurisdictional services. Each of the Certain TOs employs a forward-looking Attachment O, whereby it inputs a projection for its revenue requirement under its formula rate each year. The projection is then subject to a true-up each year based on actual costs when actual data becomes available. 4. In order to comply with IRS regulations, the Filing Parties propose Tariff revisions to modify the calculation of average Accumulated Deferred Income Tax (ADIT) balances. The IRS procedure for determining the amount of the reserve for deferred taxes to be excluded from rate base is set forth in section 1.167(l)-1(h)(6)(ii) of the IRS regulations. 3 The IRS requires, for a utility that solely utilizes a future period (projected test year) to determine depreciation, that the amount of the reserve account for the period is the amount of the reserve at the beginning of the period and a pro rata portion of the amount of any projected increase to be credited or decrease to be charged to the account during such period. 4 The pro rata amount of any increase or decrease during the future portion of the period is determined by multiplying the increase or decrease by a fraction, the numerator of which is the number of days remaining in the period at the time the increase is to accrue, and the denominator of which is the total number of days in the future portion of the period. 5 According to the Filing Parties, if the IRS were to rule that the Certain TOs were out of compliance with section 1.167(l)-1(h)(6)(ii), they would be ineligible to claim accelerated depreciation, which could result, initially, in a rate increase for customers. 5. The IRS has issued a series of Private Letter Rulings addressing how these provisions apply to utilities that use a projected test year. In the Private Letter Rulings, the IRS has found that utilities utilizing a projected test year, in order to claim accelerated depreciation for utility plant in their income tax filings, must use the formula provided in 3 Id. 4 Id. 5 Id.
20151230-3075 FERC PDF (Unofficial) 12/30/2015 MP Exhibit (JLJ) Direct Schedule 2 Page 3 of 12 Docket No. ER16-197-000-3 - section 1.167(l)-1(h)(6)(ii) of the IRS s regulations to calculate the amount of deferred taxes subject to exclusion from the rate base. 6 6. To comply with the IRS regulation, Filing Parties propose for each of the Certain TOs to revise Note F of its company-specific Attachment O to provide that the calculation of ADIT in the annual projection will be performed in accordance with section 1.167(l)-1(h)(6)(ii) of the IRS s regulations. In addition, the proposed revised Note F also requires the posting of work papers supporting the ADIT calculations with each Annual True-Up and/or projected revenue requirement and the inclusion of the work papers in their annual Informational Filing submitted to the Commission. 7. For three of the Certain TOs, Ameren Illinois, Ameren Transmission, and NSP Companies, Filing Parties also propose that they comply with the IRS regulation by not only providing the calculation of ADIT in accordance with section 1.167(l)-1(h)(6)(ii) of the IRS s regulations in the annual projection, but also in the true-up calculation performed at the end of the year. II. Notice of Filing and Responsive Pleadings 8. Notice of the filing was published in the Federal Register, 80 Fed. Reg. 68,528 (2015), with interventions and protests due on or before November 20, 2015. 9. Timely motions to intervene were filed by American Municipal Power Inc., NRG Power Marketing LLC and GenOn Energy Management, LLC. Southwestern Electric Cooperative, Inc. (Southwestern) filed a timely motion to intervene and protest. Answers to the protests were filed by Ameren and the Certain TOs. Southwestern filed an answer to the answer of Ameren. A. Southwestern Protest 10. Southwestern s protest focuses on two areas: (1) the proposed revisions to Attachment O submitted, and (2) general issues related to the Attachment O rate formula. 11. With regard to the proposed Attachment O revisions, Southwestern states that the use of the two referenced Private Letter Rulings for the basis of the proposed revisions is improper. According to Southwestern, a Private Letter Ruling is not an IRS regulation, nor is it precedent applicable to all entities. Rather, a Private Letter Ruling is entity 6 See I.R.S. P.L.R. 14324114 (Jul. 6, 2015), https://www.irs.gov/pub/irswd/201541010.pdf; I.R.S. P.L.R. 14012014 (Apr. 14, 2015), https://www.irs.gov/pub/irswd/201531010.pdf.
20151230-3075 FERC PDF (Unofficial) 12/30/2015 MP Exhibit (JLJ) Direct Schedule 2 Page 4 of 12 Docket No. ER16-197-000-4 - specific. Southwestern questions whether the Private Letter Rulings apply to the Certain TOs. 12. Southwestern objects to the proposed provision in Note F to Attachment O directing the Certain TOs to perform calculations outside their Attachment O rate formula through ADIT worksheets. 7 Southwestern argues that the calculations described in Note F should be incorporated into the Attachment O rate formula itself, as then Attachment O would contain all of the necessary detail to explain how the inputs were determined. 13. In addition to addressing Note F, Southwestern addresses various other components of the formula rate using Ameren Illinois s formula rate for an example. Southwestern argues that revisions to a single component of a previously-approved formula rate should result in the opening of the entire rate for scrutiny not only those components revised by the utility but any other inter-related components affected by the proposed change. 8 14. Southwestern states that the inclusion of ADIT Account No. 190 is inappropriate in the rate base. Southwestern argues that ADIT Account No. 190 amounts are purely book entries that involve no investment, and they allow a utility to earn a return and associated income taxes on amounts that do not represent an actual investment on the part of the utility. 9 15. In addition, Southwestern believes that Attachment O fails to exclude customerfunded accounts from the rate base. 10 These accounts would include: (1) Injury & Damages Reserves, (2) Account 242 Balance, (3) Accumulated Provision for Pensions and Benefits, (4) Customer Advance for Construction, and (5) Customer Deposits. Southwest argues that all such accounts should be excluded from rate base as the accounts are funded by current rates and transmission customers. 16. Southwestern contends that the calculation of the rate base in Attachment O fails to properly account for plant retirements. Southwestern claims that a defect in the 7 Motion to Intervene and Protest of the Southwestern Electric Cooperative, Inc. (Southwestern Protest) at 6-8. 8 Id. at 8-9. 9 Id. at 10-13. 10 Id. at 13-15.
20151230-3075 FERC PDF (Unofficial) 12/30/2015 Docket No. ER16-197-000-5 - Attachment O rate formula results in a zero net effect on rate base when a plant retires. 11 According to Southwestern, when plant in service is reduced due to a retirement, then Commission guidelines require that Accumulated Depreciation be reduced by the same amount, resulting in no effect on rate base. Southwestern contends that the Commission should require utilities using formula rates to justify further cost recovery of large facilities after they are retired prematurely. 17. Southwestern additionally claims that other portions of MISO s Attachment O formula rate need to be reconsidered, 12 and the formula rate itself, relating to costs and expenses recovered (i.e. General & Intangible Plant and Administration & General Expenses), should be investigated to assure that the resulting rates are just and reasonable. Additionally, Southwestern argues that Attachment O fails to exclude Corporate Income Taxes and Debt Expenses; and uses an improper Wage and Salaries Allocation Factor and Capital Structure. 18. Southwestern requests that the Commission: (1) direct MISO to revise the Attachment O to include the revised calculation of ADIT, and (2) set the remaining issues for hearing and settlement judge procedures. B. The Certain TOs Answer MP Exhibit (JLJ) Direct Schedule 2 Page 5 of 12 19. The Certain TOs assert that many of the issues raised by Southwestern are not relevant to the filing and are therefore beyond the scope of this proceeding. In particular, the Certain TOs object to Southwestern raising numerous issues with respect to the company-specific Attachment O for Ameren Illinois. The Certain TOs view these arguments by Southwestern as not relevant to the filing, which proposed only discrete revisions to the formula rate for the Certain TOs to ensure compliance with IRS regulations. 20. Further, the Certain TOs claim that this is not the proceeding for Southwestern to bring a Federal Power Act (FPA) section 206 complaint against Ameren Illinois to challenge various components of its formula rate. According to the Certain TOs, the Commission will not consider a protest filed pursuant to FPA section 205 as a complaint filed pursuant to FPA section 206. 13 These two sections of the FPA are different, they 11 Id. at 16. 12 Id. at 17-22. 13 Answer of the Certain MISO Transmission Owners (Certain TOs Answer) at 4-5.
20151230-3075 FERC PDF (Unofficial) 12/30/2015 Docket No. ER16-197-000-6 - allege, so mixing these two sorts of proceedings would be needlessly complex. Further, Southwestern s pleading fails to meet the regulatory requirements for filing complaints. 14 21. Regarding ADIT, the Certain TOs believe Southwestern is incorrect that the Private Letter Rulings cited in the filing are irrelevant because they do not apply to the Certain TOs. The Certain TOs explain that the IRS regulations themselves at section 1.167(l)-1(h)(6)(i) dictate that a taxpayer does not use a normalization method of regulated accounting if, for ratemaking purposes, the amount of the reserve for deferred taxes that the utility excludes from rate base exceeds the amount of such reserve for deferred taxes for the period used in determining the taxpayer s expense in computing cost of service in such ratemaking. 15 The IRS regulation further provides that if a utility uses a projected test year to determine depreciation, the amount of the reserve account for the period is the amount of the reserve at the beginning of the period and a pro rata portion of the amount of any projected increase to be credited or decrease to be charged to the account during such period. 16 22. The Certain TOs also contend that contrary to Southwestern, the applicable IRS regulation relates to ADIT Account No. 190, and not merely Account Nos. 282, 281, and 283. According to the Certain TOs, the IRS regulations do not reference any account numbers whatsoever. The regulations simply refer to the reserve for deferred taxes under section 167(l). 17 Thus, if all or any portion of the balance in any of the four accounts constitutes a portion of the reserve for deferred taxes under section 167(l), then the amount must be included in calculating the limitation imposed by the regulation section. The Certain TOs state that the proper accounting for deferred taxes related to accelerated tax depreciation includes Account No. 190 when the company is in a net operating loss as a result of taking accelerated depreciation deductions. 23. Further, the Certain TOs claim that the supporting documentation required by the revisions fully satisfy Commission policy. The Certain TOs have already offered to post the work papers supporting the ADIT calculations with each annual true-up and/or projected revenue requirement and include the work papers in their annual Informational Filing submitted to the Commission. 18 They argue that other parts of the Attachment O 14 Id. at 5. 15 Id. at 6. 16 Id. 17 Id. at 7. 18 Id. at 8. MP Exhibit (JLJ) Direct Schedule 2 Page 6 of 12
20151230-3075 FERC PDF (Unofficial) 12/30/2015 Docket No. ER16-197-000-7 - formula rate likewise use numbers that are not pulled directly from the FERC Form No. 1. For example, the formula rate protocols for the general Attachment O state that [t]he Annual Update for the Rate Year shall... [p]rovide the formula rate calculations and all inputs thereto, as well as supporting documentation and workpapers for data that are used in the formula rate that are not otherwise available in the Applicable Form. 19 Nearly identical language is found in the company-specific Attachment O for NSP Companies, Otter Tail, Ameren Transmission, and Ameren Illinois, among others. 20 Moreover, they state, other examples of numbers used in Attachment O that are based upon calculations in a work paper, as opposed to being reflected in the FERC Form No. 1, include: (a) Material and Supplies; (b) Prepayments (split between gas and electric); (c) Land Held For Future Use; and (d) Transmission related Regulatory Commission expense. 21 Nevertheless, the Certain TOs offer to include, in a compliance filing, work papers in Attachment O, if the Commission requests. 22 C. Ameren Answer MP Exhibit (JLJ) Direct Schedule 2 Page 7 of 12 24. Ameren contends that Southwestern s protest raises issues that are almost entirely unrelated to the proposed revisions, and are beyond the scope of this proceeding. Additionally, Ameren argues, Southwestern s complaints should be brought pursuant to FPA section 206, so that Southwestern is subject to the appropriate burden of proof. 23 25. According to Ameren, the IRS regulations concern more than normalization of ADIT. The heading of the IRS regulations at issue is entitled, Exclusion of normalization reserve from rate base, which clearly implicates ratemaking in its reference to rate base. The text of the regulation also establishes a limitation on the ADIT balance that a taxpayer can use to reduce rate base, and the text contains the 19 Id. 20 Id. 21 Id. at 8-9. 22 Id. 23 Motion for Leave to Answer and Answer of Ameren Services Company on behalf of Ameren Illinois Company and Ameren Transmission Company of Illinois (Ameren Answer) at 5.
20151230-3075 FERC PDF (Unofficial) 12/30/2015 MP Exhibit (JLJ) Direct Schedule 2 Page 8 of 12 Docket No. ER16-197-000-8 - phrases for ratemaking purposes and in such ratemaking. 24 Ameren thus argues that the limit on the ADIT balances described is patently a ratemaking limitation. 26. Ameren also observes that the series of Private Letter Rulings on this topic have similar legal analysis and conclusions, and apply to utilities using the same ratemaking that Certain TOs use, which highlights the need for the Certain TOs to revise their company-specific Attachment O to explicitly comply with that IRS regulation. 27. According to Ameren, Account No. 190 contains two types of future tax benefits. The first is the tax benefit that has been provided to ratepayers, but has not yet been recovered from the government. With respect to this type of tax benefit, the utility is, in fact, out of pocket because it has fronted the tax benefit to the ratepayer and thus deserves to earn a return on that amount until the utility recovers the amount from the government. The second type of future tax benefit is that of a net operating loss carryforward. This amount is inextricably linked to the deferred tax credit accounts, Nos. 281, 282, and 283. Where a favorable timing difference exists, the tax benefit is recorded in those accounts. Ameren states that this recordation presumes that the relevant tax deductions reduced the utility s tax liability, thereby producing cost-free capital. However, where there is a net operating loss carryforward, not all of the deductions actually reduced the utility s tax liability. They will in the future, but have not yet done so due to a shortage of taxable income to offset. The tax benefits of the deductions that failed to reduce taxes are reflected in Account No. 190. Where this is the case, Account Nos. 281, 282, and 283 overstate the quantity of cost-free capital possessed by the utility. It is only by also considering Account No. 190 that the proper level of cost-free capital can be derived. 25 28. In response to Southwestern s concerns, Ameren attaches an illustrative work paper showing the actual proration calculation for the projected 2016 amounts for Account No. 282, as Exhibit No. 1. Also attached, as Exhibit No. 2 to Ameren s Answer, is the true-up proration example, showing how Ameren expects the true-up proration calculation to work, once Ameren has 2016 actual amounts for that calculation. Ameren states that these work papers are specific to Ameren Illinois and Ameren Transmission s Attachment O and are not intended to represent how any other MISO Transmission Owner would perform the proration calculations or true-up proration calculations. If the Commission so directs, Ameren would file such work papers with the Commission in a future compliance filing. 24 Id. at 6. 25 Id. at 8-9.
20151230-3075 FERC PDF (Unofficial) 12/30/2015 MP Exhibit (JLJ) Direct Schedule 2 Page 9 of 12 Docket No. ER16-197-000-9 - 29. Ameren asserts that Southwestern s alternative proposal, that the Commission should require Ameren Illinois to exclude amounts from Account No. 190 that are unrelated to transmission service, should be rejected as a collateral attack on Attachment O. Ameren states that Ameren Illinois Attachment O, like the Attachment Os of the other MISO transmission owners, employs a transmission plant allocator to functionalize particular costs to transmission. Ameren Illinois utilizes the transmission plant allocator to determine the amount of the total account that is attributable to transmission. As such, Southwestern s argument that Ameren Illinois should conduct a line-by-line review of specific entries to determine if they pertain to transmission service, as opposed to employing the transmission plant allocator, is contrary to the accepted methodology set forth in Attachment O. 30. Ameren asserts that the bulk of the Southwestern Protest is outside the scope of this narrow proceeding, which concerns the Certain TOs limited revisions to Attachment O to modify the manner by which they calculate average ADIT balances. Ameren claims that arguments pertaining to Injury and Damages Reserves, the Account No. 242 Balance, Accumulated Provision for Pensions and Benefits, Customer Advances for Construction, and Customer Deposits have no bearing on Attachment O because these reserves and accounts are not used or referenced in Attachment O. Ameren states that Southwestern s attempt to insert these issues into this proceeding should be rejected. 31. Ameren further contends that many of Southwestern s issues should not be raised here, but in a proceeding to challenge the annual update to the formula rate, such as the ongoing proceedings in Docket No. ER15-1300. Specifically, Ameren contends that the projected transmission revenue requirement of Ameren Illinois for calendar year 2015 is unrelated to this proceeding, but is before the Commission in Docket No. ER15-1300- 000. According to Ameren, the correct venue for Southwestern to challenge projected cost data for calendar year 2015 would have been in a challenge before the Commission in the relevant time period. Having failed to raise the issue in an appropriate proceeding, Southwestern should not be permitted to create for itself a second chance in this proceeding. 32. Finally, because Ameren is concerned about the nature of the claims made in the Southwestern Protest, Ameren asks that the Commission award it attorneys fees for abuse of process. 26 26 Id. at 16.
20151230-3075 FERC PDF (Unofficial) 12/30/2015 Docket No. ER16-197-000-10 - D. Southwestern Answer MP Exhibit (JLJ) Direct Schedule 2 Page 10 of 12 33. Southwestern observes that it is not opposed to the conceptual revisions proposed by the Certain TOs. Southwestern claims that, since the Commission approved the Certain TOs Attachment O formula rates in 2003, the rate formulas on file with the Commission have grown considerably, with many more calculations made outside the four corners of the formula. While agreeing with Ameren that several other inputs into the Attachment O formula rate are not specifically tied to values reported in the FERC Form No. 1, Southwestern is nevertheless displeased that few inputs are specifically tied to FERC Form No. 1 values. 27 III. Discussion A. Procedural Maters 34. Pursuant to Rule 214 of the Commission s Rules of Practice and Procedure, 18 C.F.R. 385.214 (2015), the timely, unopposed motions to intervene serve to make the entities that filed them parties to this proceeding. 35. Rule 213(a)(2) of the Commission's Rules of Practice and Procedure, 18 C.F.R. 385.213(a)(2) (2015), prohibits an answer to a protest or answer unless otherwise ordered by the decisional authority. We will accept the answers filed by the Certain TOs, Ameren, and Southwestern because they have provided information that assisted us in our decision-making process. B. Substantive Matters 36. We accept the proposed revisions to the company-specific Attachments O of the Certain TOs, subject to condition, as discussed below. 28 We find that these proposed revisions are reasonable to comply with IRS regulations. 37. Specifically, we accept the proposed revisions to Note F to apply the IRS regulations to the annual projected ADIT amounts for Minnesota Power, Montana- 27 Motion for Leave to Answer and Answer of Southwestern Electric Cooperative, Inc. (Southwestern Answer) at 7-8. 28 The Commission can revise a proposal filed under section 205 of the FPA as long as the filing utility accepts the change. See City of Winnfield v. FERC, 744 F.2d 871, 875-77 (D.C. Cir. 1984). A utility is free to indicate that it is unwilling to accede to the Commission s conditions in this order by withdrawing its filing.
20151230-3075 FERC PDF (Unofficial) 12/30/2015 MP Exhibit (JLJ) Direct Schedule 2 Page 11 of 12 Docket No. ER16-197-000-11 - Dakota, NIPSCo, Otter Tail, and Vectren. However, we direct Filing Parties to revise the proposed Note F for Ameren Illinois, Ameren Transmission and NSP Companies to remove the application of the IRS regulations to the annual true-up ADIT amounts, so that the Note F will only apply to the annual projected ADIT amounts. 38. With respect to the proposed true-up procedures of Ameren Illinois, Ameren Transmission, and NSP Companies, the Filing Parties have not justified these proposed revisions as just and reasonable. In particular, the guidance in the Private Letter Rulings does not require any changes in calculating the true-up amounts, and the filing does not contain any rationale as to why those proposed revisions are needed for the annual true up. Therefore, we direct Filing Parties, in a compliance filing due within 30 days of the date of this order, to revise the proposed Tariff changes to remove reference to the use of an IRS calculation for the annual true-up, and to provide that annual true-up calculations will continue to use the average of the beginning-of-year and end-of-year balances for all ADIT accounts. 39. To ensure appropriate transparency in calculating formula rates, we direct Filing Parties, in a compliance filing due within 30 days of the date of this order, to include the ADIT worksheets within the company-specific Attachments O of each of the Certain TOs. 40. We disagree with Southwestern s objection that Private Letter Rulings issued by the IRS cannot be a basis for the proposed rate revisions. While Southwestern contends that a Private Letter Ruling is case-specific, applying only to the taxpayer who sought the ruling, and even though the Certain TOs have not received company-specific Private Letter Rulings from the IRS, we believe that the legal and policy rationale behind the Private Letter Rulings which have already been issued to other similarly situated utilities shows how the IRS interprets its regulations. 41. We find no merit to Southwestern s general and specific objections to other, unrelated, parts of the Attachment O formula rate. Southwestern s arguments are beyond the scope of the issues raised in this proceeding. We find nothing in the interaction between Note F and the other rate components that creates an unjust and unreasonable rate, and Southwestern has provided us with no basis for including these unchanged rate components in our review under section 205 of the FPA. 29 For some of its objections related to the inputs into the formula rate, Southwestern may have options pursuant to the annual update of the formula rate. In fact, Southwestern has already 29 Southwestern Pub. Serv. Co, 152 FERC 61,126, at PP 11-14 (2015); 16 U.S.C. 824d (2012).
20151230-3075 FERC PDF (Unofficial) 12/30/2015 Docket No. ER16-197-000-12 - requested data pursuant to that process to which Ameren has responded. 30 For those arguments that seek changes to the formula itself, or more broadly to Commission policy on formula rates, Southwestern can consider whether to file a complaint under section 206 of the FPA. 31 42. Finally, Ameren s request for attorneys fees is denied. The Commission orders: (A) The proposed revisions in each Attachment O specific to the Certain TOs are hereby accepted, to be effective as requested, on January 1, 2016, subject to condition, as discussed in the body of this order. (B) Filing Parties are directed to submit a compliance filing within 30 days of the issuance of this order, as discussed in the body of this order. By the Commission. ( S E A L ) MP Exhibit (JLJ) Direct Schedule 2 Page 12 of 12 Nathaniel J. Davis, Sr., Deputy Secretary. 30 See Southwestern Protest at 11-14, 19-21. 31 16 U.S.C. 824e (2012).
MP Exhibit (JLJ) Direct Schedule 3 Page 1 of 24 30 west superior street / duluth, minnesota 55802-2093 / 218-723-3961 /www.allete.com Christopher D. Anderson Associate General Counsel Fax 218-723-3955 e-mail canderson@allete.com October 8, 2010 VIA ELECTRONIC FILING Dr. Burl W. Haar Executive Secretary Minnesota Public Utilities Commission 121 7 th Place East, Suite 350 St. Paul, MN 55101-2147 Re: In the Matter of Minnesota Power s Petition for Approval to Defer the Tax Impact of the PPACA on Medicare Part D subsidies Docket No. E015/M-10- Dear Dr. Haar: Minnesota Power hereby submits via electronic filing its Petition for Approval to Defer the Tax Impact of the PPACA on Medicare Part D subsidies. An affidavit of service is included. Please contact me at the number listed above should you have any questions regarding this filing. Yours truly, Christopher D. Anderson kl c: Service List