________________________________________________________________________ BEFORE THE MINNESOTA OFFICE OF ADMINISTRATIVE HEARINGS 600 North Robert Street St. Paul, Minnesota 55101 FOR THE MINNESOTA PUBLIC UTILITIES COMMISSION 121 7th Place East Suite 350 St. Paul, Minnesota 55101-2147 MPUC Docket No. E015/GR-16-664 OAH Docket No. 5-2500-34078 __________________________ In the Matter of the Application of Minnesota Power for Authority to Increase Rates for Electric Utility Service in Minnesota __________________________ DIRECT TESTIMONY AND SCHEDULES OF MINNESOTA OFFICE OF THE ATTORNEY GENERAL – RESIDENTIAL UTILITIES AND ANTITRUST DIVISION WITNESS: SHOUA LEE May 31, 2017 ________________________________________________________________________ TABLE OF CONTENTS Page I. BACKGROUND AND QUALIFICATIONS .....................................................................1 II. PURPOSE ............................................................................................................................1 III. TRANSMISSION CAPITAL ADDITIONS .......................................................................2 IV. GENERATION CAPITAL ADDITIONS ...........................................................................4 V. DEPRECIATION FOR THE BOSWELL ENERGY CENTER .........................................6 A. BEC 3 AND 4. .........................................................................................................12 1. Stranded Costs. ..........................................................................................13 2. Removal Costs. ..........................................................................................18 3. Estimated O&M And Replacement Costs. ................................................20 4. Long-Run Increased Returns For Shareholders. ........................................24 5. Delay Of Coal Retirements. .......................................................................27 6. Recommendation Regarding BEC 3 And 4. ..............................................29 B. BEC 1 AND 2. .........................................................................................................31 C. SUMMARY OF BEC RECOMMENDATIONS. ..............................................................34 i VI. COSTS RELATED TO EARLY RETIREMENT OF BEC 1 AND 2 ..............................36 VII. STORM DAMAGE AMORTIZATION EXPENSE .........................................................37 VIII. SAPPI/CLOQUET GENERATOR AMORTIZATION EXPENSE .................................38 IX. CREDIT CARD PROCESSING FEES .............................................................................40 X. CHARITABLE CONTRIBUTIONS .................................................................................42 XI. MEMBERSHIP DUES ......................................................................................................47 XII. EMPLOYEE GIFTS ..........................................................................................................60 XIII. TRAVEL, ENTERTAINMENT, AND EMPLOYEE EXPENSES ..................................64 XIV. SUMMARY AND CONCLUSION ..................................................................................79 ii 1 I. BACKGROUND AND QUALIFICATIONS 2 3 Q. Please state your name and business address. 4 A. My name is Shoua Lee. My business address is 445 Minnesota Street, Suite 1400, Saint 5 Paul, MN 55101. 6 Q. By whom are you employed? 7 A. I am a Financial Analyst with the Residential Utilities and Antitrust Division in the 8 Office of the Minnesota Attorney General (“OAG”). 9 Q. What is your educational and professional background? 10 A. I have a Master of Business Administration and a Bachelor of Science in Finance. I have 11 provided testimony on behalf of the OAG in the following general rate cases; Otter Tail 12 Power’s electric rate case in Docket No. E-017/GR-15-1033, Xcel Energy’s electric rate 13 case in Docket No. E-002/GR-15-826, CenterPoint Energy’s gas rate case in Docket No. 14 G-008/GR-15-424, and Dakota Electric Association’s electric rate case in Docket No. E- 15 111/GR-14-482. I have also provided analysis in other utility rate cases, depreciation 16 filings, rider filings, as well as other financial dockets. 17 II. PURPOSE 18 19 Q. What is the purpose and scope of your testimony? 20 A. The purpose of my testimony is to review Minnesota Power’s (“the Company” or “MP”) 21 request for a rate increase, and evaluate whether specific portions of that request are 22 reasonable. 23 including its claimed costs and revenues. Following my evaluation, I recommend several 24 specific changes. In general, I focus on evaluating the Company’s revenue deficiency, I do not, however, provide an opinion on the overall revenue 1 1 requirement or revenue deficiency. Instead, I recommend specific changes that should be 2 made, and do not have a recommendation on those issues on which I did not provide 3 testimony. 4 III. TRANSMISSION CAPITAL ADDITIONS 5 6 Q. Does the Company summarize its transmission capital additions for the 2017 Test 7 8 Year? A. 9 Yes. The Company provided its actual 2010 to 2015 transmission capital additions, as well as its forecasted 2016 transmission capital additions, and budgeted 2017 capital 10 additions in MP Exhibit_(CEF) Direct Schedule 1. 11 Q. How are these forecasts related to the 2017 Test Year? 12 A. A Test Year has a beginning-of-year rate base and an end-of-year rate base because 13 capital additions occur during the year. To ensure that these additions are reflected, but 14 not double-counted, rates are set on an average basis. In other words, the rate base 15 number that is used to construct the revenue requirement is the beginning-of-year rate 16 base plus the end-of-year rate base divided by two. The 2017 beginning-of-year rate 17 base is based on 2016 numbers, and the 2017 end-of-year rate base reflects the capital 18 additions included in the Test Year. At the time the Company filed this case using a 2017 19 Test Year, however, it did not have final 2016 numbers. For that reason, the Company 20 used forecasted 2016 numbers to construct the 2017 beginning-of-year rate base in the 21 Test Year. 2 1 Q. Does the Company have the actual 2016 amount of transmission capital additions? 2 A. Yes. The Company responded to the Department of Commerce’s (“Decpartment”) 3 Information Request to update MP Exhibit_(CEF) Direct Schedule 1 with actual 2016 4 amounts. 1 5 Q. Is the actual 2016 amount different than the Company’s forecast? 6 A. Yes. The actual 2016 amount of transmission capital additions is less than the 7 Company’s 2016 forecast by $16.4 million. This decreases the Company’s in-service 8 plant balance by $16.4 million for 2016 and has a carry forward impact to the 2017 Test 9 Year beginning balance for in-service plant that is used to calculate the rate base and 10 revenue requirement. The impact of this decrease lowers the 2017 Test Year revenue 11 requirement by $1,604,396. 2 12 Q. What is your recommendation? 13 A. I recommend that the Company update its 2016 in-service plant ending balance and 14 subsequent 2017 in-service plant beginning balance, in order to reflect the decreased 15 levels of in-service plant in the 2017 Test Year, and to decrease the revenue requirement 16 by $1,604,396. 17 Q. Do you have other concerns about this issue? 18 A. Yes. The Company stated in its response to the Department’s Information Request that 19 in calculating the impact of the $16.4 million decrease in in-service plant on the 2017 20 Test Year revenue requirement, it “assumed that all delayed 2016 projects are completed 21 in 2017.” 3 I interpret this statement as meaning that the Company has assumed that all of 1 See Department Information Request 2105, Schedule SL-1. Id. 3 Id. 2 3 1 the 2016 projects that were not completed will be completed in 2017. I am concerned 2 that this one-line statement in an Information Request is the only evidence the Company 3 has provided to substantiate its assumption that it will complete all 2016 delayed projects 4 by the end of the 2017 Test Year. I am also concerned because it appears that the 5 Company is also assuming that completing the 2016 delayed projects will have no impact 6 on the budget available for 2017 projects, or that adding the 2016 projects will have no 7 impact on the budget available for 2017 projects. I do not think this makes sense. It is 8 reasonable to assume that the Company’s 2017 budgeted capital projects will change if it 9 is now choosing to focus its resources and project timelines to completing delayed 2016 10 projects rather than on focusing on its budgeted 2017 projects. 11 Q. How will you address this issue? 12 A. I do not have a recommendation at this time, but ask that the Company provide more 13 information on the impact that delayed 2016 capital projects has on planned projects for 14 2017. 15 IV. GENERATION CAPITAL ADDITIONS 16 17 Q. Does the Company summarize its generation capital additions for the 2017 Test 18 19 Year? A. Yes. The Company’s budgeted generation capital additions of $27.7 million in the Test 20 Year as shown in MP Exhibit _(JJS) Direct Schedule 1. These additions represent the 21 difference between the beginning-of-year generation capital rate base, and the end-of- 22 year generation capital rate base. At the time it filed its rate case, MP projected that it 23 would add $27.7 million of generation capital investments during the Test Year. 4 1 Q. Did the Company update its 2017 generation capital additions? 2 A. Yes. I issued a discovery request that asked the Company to update MP Exhibit_(JJS) 3 Direct Schedule 1. The Company’s response indicated that the in-service dates have 4 changed for seven of the generation capital projects, such that these seven projects will 5 either no longer be in service in 2017, or have been postponed or cancelled. 4 The 6 Company also stated that five other projects now have different in-service dates within 7 the 2017 Test Year, where four of these five projects had in-service dates that were 8 delayed between one to two months. 9 Q. 10 11 date outside of the 2017 Test Year? A. 12 13 The seven generation capital projects that will not be in service in the 2017 Test Year total $2.3 million. Q. 14 15 What were the 2017 budgeted amounts for those projects that have a new in-service Did the Company request to substitute these seven projects with other capital projects? A. Yes. The Company stated there are six new generation capital projects that have 16 “emerged after the creation of the Test Year project.” The Company states these six new 17 projects will have in-service dates in the middle and end of 2017. 18 Q. Do you have concerns about this substitution? 19 A. Yes. My primary concern is that the Company has provided no information about this 20 substitution other than this very brief statement. 21 include new projects in the Test Year. 4 See OAG Information Request 124, Schedule SL-2. 5 I do not view this as sufficient to 1 Q. What is your recommendation? 2 A. I recommend the Company remove $2,303,091 which is the 2017 budget for the 3 generation capital projects that will not be in-service in the 2017 Test Year, which will 4 impact the 2017 Test Year revenue requirement. I have asked the Company to provide 5 the impact on the revenue requirement of taking these projects out of the Test Year in 6 OAG Information Request 155 and will provide this amount in my rebuttal testimony. 7 V. DEPRECIATION FOR THE BOSWELL ENERGY CENTER 8 9 Q. What is the Boswell Energy Center? 10 A. The Boswell Energy Center (“BEC”) is a group of coal-fired electrical generating units 11 owned by MP and located in Cohasset. The BEC is made up of four generating units— 12 BEC 1, 2, 3, and 4. BEC 1 and 2 are older units with a net generating capability of 67 13 MW each. 5 BEC 3 is a newer and larger facility that provides a capacity of 364 MW. 6 14 BEC 4 is the newest and largest generator, with a nameplate capacity of 585 MW. 7 15 Together, the four generators provide more than 1,000 MW of generating capacity. The 16 BEC also includes the Common Facilities, made up of equipment and other investments 17 that are shared by the various generating units. 18 Q. Does MP have a proposal related to the BEC in this case? 19 A. Yes. MP proposes to make significant changes to the depreciation rates for the BEC 20 investments. The Company’s proposal is, essentially, made up of two parts. First, MP 21 proposes to combine the five separate investments of the BEC into a single investment 5 Skelton Direct at 19. Id. at 18. 7 Id. at 13. 6 6 1 for purposes of depreciation. And, second, MP proposes to significantly extend the 2 depreciation schedule of the BEC investments to 2050. 3 Q. What is depreciation? 4 A. Depreciation represents the reduction in value of an investment over time. Once an 5 investment, such as a coal-fired generating plant, is made, it immediately begins to 6 reduce in plant value. 7 Company’s books, is reduced to zero. Normally, an investment is depreciated evenly 8 over the useful life of the investment which results in a depreciation schedule that is 9 intended to reach a plant balance of $0 at the time the investment is expected to be retired Over time its value, which is recorded as rate base on the 10 or removed. Utilities make annual filings with the Minnesota Public Utilities 11 Commission (“Commission” or “MPUC”) to determine depreciation rates for their rate 12 base investments. 13 Mechanically, depreciation affects rates in two ways. First, the plant values of in- 14 service investments are reduced. This has the impact of the reducing the rate base value 15 on which a utility earns a rate of return. Second, the amount of depreciation expense in 16 the Test Year is recorded as an operating expense to the utility and, like other types of 17 operating expenses, increases the revenue requirement. 18 In addition to the reduction of value in investments, depreciation expense includes 19 removal expenses. In general, utilities are expected to incur additional expenses to 20 remove or shut down investments like power plants at the time they are retired. To 21 ensure that sufficient funds are available at the time of retirement, utilities estimate the 22 removal funds that will be needed in the future and recover them over the same schedule 23 that is used for depreciation expense. 7 1 Q. What is the current depreciation schedule for the BEC investments? 2 A. The Commission’s most recent order regarding the depreciation schedule for the BEC 3 came in the Company’s 2016 Remaining Life Depreciation Petition. In that Petition, MP 4 contemplated one change for the BEC investments from the Commission’s decision in its 5 2015 Integrated Resource Planning (“IRP”) filing, 8 which was to adjust the remaining 6 life for BEC 1 and 2 from 2022 to reflect a possible shut down of these two units on 7 December 31, 2018. 9 The Department comments in the depreciation filing supported the 8 shutdown of BEC 1 and 2 by the end of December 2018. The Company agreed with the 9 Department’s recommendation and the Commission approved this proposal. 10 Based on 10 this decision, the useful lives of BEC 1 and 2 will end in 2018; BEC 3 in 2034; BEC 4 in 11 2035; and the Common Facilities on 2030. The remaining life of BEC Common is based 12 on an average of the other units. 13 Q. What is the basis for the current depreciation schedule for BEC? 14 A. The current schedule for BEC depreciation is based on the Company’s estimate for when 15 the physical life of the units will end. In other words, it is based on the Company’s 16 estimate of when the units will be retired or decommissioned. 17 Q. Does MP propose to change the expected operational lives of the BEC investments? 18 A. No. After several rounds of discovery I still felt that MP’s request was somewhat 19 unclear, so I issued OAG Information Request No. 127, which asked the Company to 20 “confirm that MP’s proposal is to separate the ‘cost recovery’ period for depreciation 8 In the Matter of Minnesota Power’s 2016-2030 Integrated Resource Plan, Docket No. E-015/RP-15-690, ORDER APPROVING RESOURCE PLAN WITH MODIFICATIONS, at 15 (July 18, 2016). 9 In the Matter of Minnesota Power’s 2016 Remaining Life Depreciation Petition, Docket No. E-015/D-16-797, 2016 REMAINING LIFE DEPRECIATION PETITION, at 12 (Sept. 30, 2016). 10 In the Matter of Minnesota Power’s 2016 Remaining Life Depreciation Petition, Docket No. E-015/D-16-797, ORDER (Apr. 21, 2017). 8 1 expense for the BEC Units . . . from the operational or physical life period,” or, in the 2 alternative to confirm if the Company was “proposing that the operational or probable 3 service life of any of the BEC Units be extended to 2050.” 11 4 MP responded: 5 6 7 8 9 10 11 12 13 14 15 Yes, Minnesota Power’s proposal is to separate the cost recovery period for depreciation expense for the BEC units from the operational life of these units. . . . While the Direct Testimony of Company witness Mr. Herbert G. Minke, III asserts that BEC units may physically be operated until 2050, the Company is not proposing any changes to the operational or probable service lives of BEC units as part of this rate review proceeding. We expect discussions about the future operations of BEC units to be made in other regulatory proceedings, such as future Integrated Resource Planning dockets.” 12 This response confirms my understanding that MP’s proposal is to separate the cost 16 recovery schedule for depreciation expense from the operational life of the BEC units. In 17 other words, the depreciation schedule would no longer be based on the remaining life of 18 the BEC units. 19 Q. Is MP’s proposal consistent with standard accounting rules? 20 A. No. As MP’s witness Mr. Minke explained, utilities in Minnesota are required to follow 21 FERC’s Uniform System of Accounts (“USoA”). 13 Mr. Minke explained that the USoA 22 “states that utilities must use a method of depreciation that allocates, in a systemic and 23 rational manner, the service value of depreciable property over the service life of the 24 property. It also states that the estimated useful service lives of depreciable property 11 OAG Information Request No. 127, Schedule SL-3. Id. 13 Minke Direct at 20; Minn. Rules part 7825.0300, subp. 2. 12 9 1 must be supported by engineering, economic, or other depreciation studies.” 14 2 Minke suggests that GAAP would treat depreciation in a similar manner. 15 Mr. 3 The Commission’s Rules are consistent with this understanding. According to 4 Minnesota Rules part 7825.0500, subpart 7, “‘Depreciation accounting’ means a system 5 of accounting which aims to distribute costs or other basic value of tangible capital 6 assets, less salvage, if any, over the estimated useful life of the unit . . . in a systematic 7 and rational manner.” The Rules also require that utilities use the “straight-line method” 8 for depreciation, which is a plan where “the original cost of an asset adjusted for net 9 salvage is charged to operating expenses . . . through equal annual charges over its 10 probable service life.” 16 The Rules further state that “[a]ny exception to these methods 11 will require specific justification and certification by the commission.” 17 12 It appears to me that MP’s proposal to separate the cost recovery of depreciation 13 expense for BEC from the operational life of BEC would not be consistent with the 14 depreciation procedures laid out in the Commission’s rules. It is my understanding that 15 the Commission typically applies a three-part test when it is asked to vary its rules. 18 It 16 does not appear that MP has requested a variance in this rate case proceeding, or 17 attempted to satisfy the three parts that are required for a variance. 14 Minke Direct at 21. Id. 16 Minn. Rules part 7825.0500, subp. 14; Minn. Rules part 7825.0800. 17 Minn. Rules part 7825.0800. 18 See Minn. Rules part 7829.3200. 15 10 1 Q. 2 3 If MP’s proposal does not follow the USoA or the Commission’s Rules, how does the Company support its proposal? A. Mr. Minke suggests that the Commission has the authority to “deviate from standard 4 FERC accounting when determining the remaining service life or recovery period of an 5 asset.” 19 By doing so, Mr. Minke asserts, the Commission can establish new GAAP for 6 depreciation expense. 20 I take no position on whether Mr. Minke’s assertions are correct. 7 I note, though, that Mr. Minke does not provide any citations to law, rule, or decisions of 8 the Commission, to support his claim. And, as I noted above, it does not appear that MP 9 has addressed the requirements that are used to obtain a variance from the Commission’s Rules. 21 10 11 I note my concerns regarding variance and legal requirements to ensure that MP 12 has an opportunity to address them if the Company wishes. The rest of my testimony, 13 however, will focus on whether the Company’s proposal is reasonable. 14 Q. Do you believe that MP’s proposal is reasonable? 15 A. No, I do not. There are multiple problems with the proposal, which I will explain in more 16 detail. Because the different BEC units are under relatively distinct situations, I will 17 discuss BEC 1 and 2 separately from BEC 3 and 4. I will begin with BEC 3 and 4 18 because they have the largest remaining plant balance. 19 Minke Direct at 21. Id. 21 See Minn. Rules part 7829.3200. 20 11 1 A. BEC 3 AND 4. 2 Q. What is the status of BEC 3 and 4? 3 A. BEC 3 and 4 are much larger and newer generators than BEC 1 and 2. MP has recently 4 completed significant emissions upgrades on both units. 5 Q. What is the current remaining life of BEC 3 and 4? 6 A. As I discussed above, the most recently approved depreciation schedule for BEC 3 and 4 7 is based on an estimated remaining life that would end in 2034 and 2035, respectively. 8 Under normal circumstances, this would indicate that the depreciation schedules for 9 which depreciation expense is charged and collected from ratepayers would follow the 10 operational life of BEC 3 and 4 and would end in 2034 and 2035. 11 Q. When does MP plan to retire BEC 3 and 4? 12 A. Retirement decisions for these generating units are normally handled in the Company’s 13 IRP proceedings. MP’s most recent IRP proceeding covered the years of 2016 – 2030 – 14 the remaining lives of BEC 3 and 4 were outside of the planning period, so there was not 15 significant discussion regarding MP’s plans in the IRP. I attempted to learn MP’s long- 16 term plans for BEC 3 and 4 through discovery. In OAG Information Request No. 907, I 17 asked the Company to share its current plan for retirement of BEC 3 and 4. 22 The 18 Company responded that it “has not made any plans for the future retirement of BEC 3 19 and 4,” and noted that it would discuss its plans as part of future IRP proceedings. 20 Q. What is MP’s proposal regarding BEC 3 and 4 in this case? 21 A. The Company proposes to keep the retirement dates for BEC 3 and 4 as the end of 2034 22 and 2035, but to extend the depreciation schedule for charging depreciation expenses for 22 OAG Information Request 907, Schedule SL-4. 12 1 BEC 3 and 4 to 2050. In other words, the Company is requesting to “separate the cost 2 recovery period for depreciation expense for the BEC units from the operational life of 3 these units.” 23 4 Q. Do you agree with MP’s depreciation proposal for BEC 3 and 4? 5 A. No, I do not. I have five specific concerns with the Company’s proposal for BEC 3 and 6 4. They are related to 1) stranded costs; 2) removal expenses; 3) uncertainty of future 7 O&M or replacement; 4) increased long-run returns for shareholders; and 5) delay of coal 8 retirements. I will address each of these concerns in turn. 9 1. Stranded Costs. 10 Q. What are stranded costs? 11 A. Stranded costs are the costs of capital investments that are left over when a generating 12 facility (or other kind of investment) is retired before it is fully depreciated. Under 13 normal utility ratemaking standards, stranded costs are not recoverable because utilities 14 are allowed to recover the costs of capital investments only when those investments are 15 “used and useful.” Stranded costs are not normally recoverable because they come from 16 retired plants that are not currently used and useful. 17 Q. Can you provide an example of stranded costs? 18 A. Yes. To provide a simple example, imagine a coal plant with a rate base balance of $100 19 and a straight-line depreciation schedule of 50 years. The plant would depreciate by $2 20 each year. If the plant is retired after 25 years (rather than the 50 that were originally 21 estimated), the plant will have a remaining, undepreciated rate base balance of $50 when 22 it is retired. This $50 in plant value is “stranded,” because it was not recovered before 23 OAG Information Request No. 127, Schedule SL-3. 13 1 the plant was retired. Under normal utility ratemaking standards, the $50 in stranded 2 costs would not be recovered, because the investment in question is not used and useful. 3 Q. How is MP’s proposal related to stranded costs? 4 A. If approved, MP’s proposal would provide the Company with a mechanism to recover 5 any current and future costs of BEC 3 and 4 that would have been stranded costs, had the 6 Company not been able to recover those costs before the end of the units’ useful lives. 7 The Company is proposing to separate the depreciation schedule of BEC 3 and 4 from its 8 operational life. In other words, the operational life of BEC 3 and 4 would end in 2034 9 and 2035 based on current estimates, but the depreciation expense for all current and 10 future costs would still continue to be charge to ratepayers and recovered by MP until 11 2050. That means that the plants would not be fully depreciated at the end of their 12 operational lives, and ratepayers would continue to pay for the units for many years after 13 they are expected to be retired and no longer used and useful. 14 Q. What are the problems with stranded costs? 15 A. There are two primary problems with allowing utilities to recover stranded costs. First, it 16 goes against many decades of traditional ratemaking principles. Normally, utilities are 17 only permitted to recover the costs of investments that are used and useful. Ratepayers 18 are required to pay for things that are currently being used to provide utility service. 19 Stranded costs, in contrast, are no longer providing benefits to ratepayers. 20 ratepayers are paying stranded costs, they are paying for investments that are no longer in 21 operation and are not providing a benefit to anyone. 22 23 The second problem is related to intergenerational inequity. When Normally, the Commission seeks to tie costs to ratepayers at the time those costs are necessary. In other 14 1 words, ratepayers in 2017 should be paying for the costs required to provide service in 2 2017. 3 ratepayers in 2049 would still be paying for coal plants that are expected to be closed 4 more than a decade earlier. 5 unfair—ratepayers in 2049 should be paying for the costs necessary to provide utility 6 service in 2049, not for plants that have been closed for more than a decade. MP’s proposal would upend this standard. Under the Company’s proposal, Intergenerational inequities such as this are inherently 7 Q. Has any other utility ever recommended the creation of stranded costs? 8 A. No. However, MP requested a somewhat similar treatment for the Sappi/Cloquet 9 Generator Number 5. The generator is located at a customer facility, and the customer, 10 Sappi, used to own parts of the facility with MP. As part of the initial agreement between 11 Sappi and MP, Sappi had the right to purchase the Sappi/Cloquet generator in 2016, 12 which it did. 24 13 In its 2015 Depreciation Petition, MP asked to be allowed to continue to 14 depreciate the Sappi/Cloquet generator until 2024, even though it would no longer own 15 the generator starting in 2016. 16 remaining life for S/C5 for depreciation purposes is one that matches the expected 17 operational life,” and recommended a two year depreciation so that the facility would be 18 fully depreciated at the time ownership was transferred to Sappi. 25 The Commission The Department recommended that “a reasonable 24 In the Matter of Minnesota Power’s 2015 Remaining Life Depreciation Petition, Docket No. E-015/D-15-711, ORDER APPROVING REMAINING LIVES AND SALVAGE RATES AS MODIFIED, AND REQUIRING FILINGS at 5 (Sept. 19, 2016). 25 In the Matter of Minnesota Power’s 2015 Remaining Life Depreciation Petition, Docket No. E-015/D-15-711, COMMENTS OF THE DEPARTMENT, at 5 (Oct. 30, 2015). 15 1 agreed with the Department, and stated that “it would not be reasonable to allow [MP] to 2 depreciate an asset it no longer owns.” 26 3 Following this decision, MP requested permission for deferred accounting related 4 to the incremental depreciation expense it had to charge for the Sappi/Cloquet generator 5 due to the acceleration of the generator’s useful life (from 2024 to 2016). 27 6 incremental depreciation expense represented stranded costs because while MP incurred 7 the increased depreciation expense, the depreciation expense being recovered from 8 ratepayers at the time was based on a useful life of 2024. The usual recovery mechanism 9 for depreciation expense is through base rates in a general rate case, and the Company 10 would have had to request recovery of the increased depreciation through a general rate 11 case proceeding. However, MP choose to file the deferred accounting request instead. 12 The Department recommended denial of MP’s deferred accounting request, 28 and the 13 Company withdrew its Petition before the Commission reached a decision. 29 This 14 Q. Has the Commission ever authorized the recovery of stranded costs? 15 A. I do not believe so. In OAG Information Request No. 908, I asked MP whether the 16 Commission had ever approved the recovery of stranded costs. The Company responded 17 that it had “not done an exhaustive search, but is currently not aware of any MPUC 26 , In the Matter of Minnesota Power’s 2015 Remaining Life Depreciation Petition, Docket No. E-015/D-15-711, ORDER APPROVING REMAINING LIVES AND SALVAGE RATES AS MODIFIED, AND REQUIRING FILINGS at 6 (Sept. 19, 2016). 27 In the Matter of a Petition for Approval of Deferred Accounting Treatment of Costs Related to Depreciation Expenses for Sappi-Cloquet Generator No. 5, Docket No. E-015/M-16-876, PETITION (Oct. 28, 2016). 28 Petition, In the Matter of a Petition for Approval of Deferred Accounting Treatment of Costs Related to Depreciation Expenses for Sappi-Cloquet Generator No. 5, Docket No. E-015/M-16-876, COMMENTS OF THE DEPARTMENT (No. 28, 2016). 29 In the Matter of a Petition for Approval of Deferred Accounting Treatment of Costs Related to Depreciation Expenses for Sappi-Cloquet Generator No. 5, Docket No. E-015/M-16-876, REQUEST TO WITHDRAW PETITION (Oct. Dec. 20, 2016). 16 1 orders that have authorized recovery of costs for electric generation units after their 2 retirement.” 30 3 Q. Does the Commission have the authority to deny recovery of stranded costs? 4 A. Yes. Minnesota law allows utilities to request the recovery of stranded costs under 5 certain conditions. But the same law also makes clear that the decision as to whether the 6 costs should be recovered is left to the discretion of the Commission. 7 Minnesota Statutes section 216B.16, subdivision 6 provides that “[i]f the 8 [C]ommission orders a generating facility to terminate its operations before the end of the 9 facility’s physical life in order to comply with a specific state or federal energy statute or 10 policy, the [C]ommission may allow the public utility to recover any positive net book 11 value of the facility as determined by the [C]ommission.” This statute makes it possible 12 for utilities to recover stranded costs, but does not require it. Instead, the statute requires 13 the Commission to decide on a case by case basis whether the recovery of stranded costs 14 would lead to just and reasonable rates. If not, then the Commission should deny that 15 recovery. 16 Q. Does the Commission have any other authority regarding stranded costs? 17 A. Yes, the Commission also has the authority to make regulatory decisions that will avoid 18 stranded cost problems in the first case. For example, rejecting MP’s proposal in this 19 case would avoid a stranded cost problem in the future. 20 Q. What is your conclusion regarding stranded costs? 21 A. I believe that this is a significant problem with MP’s proposal. I do not believe that it 22 would be reasonable to approve this proposal which appears likely to create a mechanism 30 OAG Information Request No. 908, Schedule SL-5. 17 1 by which MP would be able to recover potential future costs that would be stranded costs 2 once BEC 3 and 4 are expected to be retired at the end of 2034 and 2035. This would 3 limit the Commission’s future ability to review and decide on a case by case basis 4 whether recovery of those future costs would lead to just and reasonable rates. 5 2. Removal Costs. 6 Q. How are removal costs related to depreciation schedules? 7 A. As I discussed above, when utilities charge depreciation expense for a capital investment, 8 a piece of the depreciation expense is related to the removal costs. The amount of 9 removal costs charged to ratepayers and accumulated each year is based on two things: 10 the estimated cost of removing the investment after retirement, and the operational life of 11 the investment. Normally this removal cost is charged to ratepayers along with the 12 service value of depreciable property under the same depreciation schedule—over the 13 service life of the property. This results in the same amount of removal dollars being 14 charged to ratepayers each year for the remaining life of the investment, so that the entire 15 estimated removal costs are accumulated by the end of the investment’s operational life. 16 Q. Can you provide an example? 17 A. Yes. Imagine that a coal plant has an operational life of 50 years, with an expected 18 removal cost of $50. Each year, the utility will book $1 of removal expense, so that it 19 will have $50 available for removal when it is time to retire the facility. 20 Q. What is the problem with removal costs for BEC 3 and 4? 21 A. A problem would arise as a result of MP’s proposal to extend the depreciation schedule 22 for the units beyond their estimated operational lives. MP currently estimates that it will 18 1 cost approximately $80 million to decommission BEC 3 and 4. 31 MP’s proposal is to 2 extend the time period to fully recover the entire $80 million in removal expense by 3 2050. This means that MP will not have $80 million available for decommissioning until 4 2050—but the current operational life of the units is expected to end 15 years earlier in 5 2034 and 2035. 6 If MP’s proposal is approved and BEC 3 and 4 are retired any time earlier than 7 2050, then MP will not have sufficient removal dollars to fund the decommissioning of 8 the units. 9 Q. 10 11 What would happen if MP retired BEC 3 or 4 before it accumulated sufficient removal dollars to fund the decommissioning? A. It is unclear. The utility would either need to fund the decommissioning itself—which I 12 believe the utility would be unlikely to agree to—or it would need to request accelerated 13 payments from ratepayers at the time of retirement. This is the reason that depreciation 14 schedules and removal expenses are normally targeted to be based on the operational life 15 of the units. 16 Q. 17 18 What would happen to removal costs if BEC 3 or 4 were operated beyond 2034 and 2035? A. This is also somewhat unclear. I asked MP to provide an estimate of the removal costs 19 for BEC 3 and 4 if they were operated past their current operational lives. MP did not 20 have an updated estimate. In fact, it appears that the Company suggests that the cost of 31 OAG Information Request No. 1158 and OAG Information Request No. 1158.1, Schedule SL-6. 19 1 decommissioning BEC 3 and 4 would not change from the current estimate even if the 2 units are operated longer than expected. 32 3 The Company’s suggestion does not make much sense. Based on my experience, 4 delaying the decommissioning of units tends to increase the removal costs. This is partly 5 related to regular inflation for costs such as construction and labor. I believe it is likely 6 that decommissioning BEC 3 or 4 in 2050 would cost more than it would in 2035. While 7 the depreciation expense for both the removal cost and service value of the units will be 8 recalculated in the future as new estimates become available, the Company’s suggestion 9 that the cost will remain the same regardless of when the units are retired simply does not 10 make sense. 11 Q. What is your conclusion regarding removal costs for BEC 3 and 4? 12 A. MP’s proposal would extend the time period for accumulating dollars for removal costs 13 beyond the expected operational life of the units. This means that the removal dollars 14 necessary to fund decommissioning would likely not be available at the time the facilities 15 are expected to be retired. If the Commission decided to accelerate the retirement of the 16 units, because, for example, it wanted to reduce carbon emissions, the problem could be 17 even greater. I view this as a significant problem with MP’s proposal. 18 19 3. Q. 20 21 Estimated O&M And Replacement Costs. What is your concern regarding future O&M and replacement costs for BEC 3 and 4? A. 22 One of the justifications MP provides for its proposal is an opinion from the engineering firm Burns & McDonnell stating that the firm “see[s] no technical reasons that BEC 32 OAG Information Request No. 1159, Schedule SL-7. 20 1 could not physically be operated until 2050, with appropriate maintenance and 2 investments into replacements and upgrades.” 33 3 Even though the Company claims it is not seeking to extend the operational life of 4 BEC 3 and 4, it seems clear that the Company is positioning itself to do so in the future 5 by extending the depreciation schedule for the units until 2050. To the extent that the 6 Company is suggesting that the units could be operated longer than their current 7 operational lives, it is very important that the Commission have accurate information 8 about the costs of doing so. Since the Company hired Burns and McDonnell to evaluate 9 whether the units could be operated until 2050, I assumed that the Company had 10 11 estimates for the cost of doing so, and had requested them in discovery. Q. 12 13 What was MP’s estimate of the cost of operating BEC 3 and 4 past their current operational lives? A. The Company stated that it had no estimates for the cost of operating BEC 3 and 4 past 14 2034 and 2035. Based on the language in the opinion from Burns & McDonnell, in OAG 15 Information Request No. 1148, I asked the company for all estimates of the “maintenance 16 and investments into replacements and upgrades” that would be required. The Company 17 stated that it “has not conducted an estimate of the costs.” 34 The Company pointed out 18 that a major driver in the costs would be “ongoing maintenance and repair of the boilers 19 and turbine-generators for each unit.” 35 33 Minke Direct, Schedule 10. OAG Information Request No. 1148, Schedule SL-8. 35 Id. 34 21 1 Q. Did you conduct any additional discovery? 2 A. I followed up with additional discovery because I did not find it plausible that the 3 Company had no estimate at all, since it appears that MP would be able to request an 4 extension of the operational lives for the units. In OAG Information Request No. 1155, I 5 asked the Company to produce all documents and analysis it had regarding “potential 6 future maintenance,” including sensitivity analysis, or to confirm that it had no relevant 7 documents. The Company did not produce any cost estimates, but instead pointed to the 8 analysis included in its most recent IRP proceeding. 36 I do not believe this information is 9 responsive, however, because the planning horizon for the IRP goes from 2016 to 2030. 10 Information about the cost of operating BEC 3 and 4 until 2030 is not a good gauge of 11 how much it might cost to keep the units open until 2050. The only documents the 12 Company provided were technical reports about maintenance work that was required, 13 without any cost estimates included. 14 I also asked the Company for more information about the potential cost of 15 replacing the boilers and turbines at BEC 3 and 4. 16 assessment that replacement or repair of these types of equipment could be a very 17 significant expense. If operating the units until 2040 or 2050 would require the Company 18 to replace this equipment, but retiring the units in 2035 or earlier would not, that is 19 important information that the Commission should be aware of. In response to OAG 20 Information Request No. 1156, MP stated that it had no estimate of the physical life of 21 the boilers and turbines currently installed at BEC 3 and 4, had no information about the 22 lifespan of similar equipment at other facilities nationwide, had no information about 36 OAG Information Request No. 1155, Schedule SL-9. 22 I agree with the Company’s 1 manufacturer representations or warranties regarding the lifespan, and had no estimate of 2 the cost of replacing this type of equipment at similar facilities. 37 3 I also asked for more information about the estimated O&M costs from 2016 to 4 2050. In response to OAG Information Request No. 1157, the Company stated that it did 5 not have a detailed cost estimate. 38 6 Q. What do you conclude about estimates of future cost at BEC? 7 A. It appears that MP has no idea how much it would cost to operate BEC 3 or 4 past their 8 current operational lives. I find this very concerning, given that the Company hired an 9 engineering firm to give an opinion on whether doing so was feasible, and then used that 10 opinion to justify its proposal to extend the depreciation schedule of BEC 3 and 4. 11 The Company may not be asking to extend the operational life of the units now, 12 but the Company seems to believe that whether or not the units could remain functional 13 until 2050 is relevant to its request. This means that the cost of remaining functional is 14 also relevant to the depreciation schedule issue, and I find it concerning that the 15 Company has no estimate of those costs. 16 It is possible that the Company will take the position that I did not ask the right 17 questions in my information requests, but I sent multiple rounds of discovery to MP 18 about these issues. Regardless of what type of cost estimates I asked for, the Company’s 19 answer was that it did not have them. I view this as a problem with MP’s proposal. 20 In addition, I also wish to address the engineering opinion that MP provided, 21 which states that it may be possible to operate BEC 3 and 4 until 2050. While I have 22 described this document as an engineering opinion, it is important to recognize that it is 37 38 OAG Information Request No. 1156, Schedule SL-10. OAG Information Request No. 1157, Schedule SL-11. 23 1 only three pages long. It does not include any technical information or cost estimates. In 2 my opinion, this evidence falls short of what is needed to justify a significant life 3 extension for an electric generating facility. 4 4. Long-Run Increased Returns For Shareholders. 5 Q. How is depreciation expense related to returns for shareholders? 6 A. Like all of its capital investments, MP earns a return on the rate base value of BEC 3 and 7 4. Normally, the rate base booked for an investment is reduced by a set amount—the 8 depreciation expense—each year. 9 operating cost of the depreciation expense, plus the return on the average rate base, 10 In terms of ratemaking, the utility recovers the which reflects the depreciation expense charged in the Test Year. 11 To provide a simple example, imagine an investment with a value of $100, an 12 annual depreciation expense of $10, and a rate of return of 10%, during a Test Year. The 13 depreciation expense of $10 will be subtracted from the rate base value of $100, leaving a 14 remaining rate base of $90. The utility would be entitled to a return of $9.50—10% of 15 the average rate base. 16 If, instead, the depreciation expense was only $5 because the depreciation was 17 being charged over a longer period of time because the depreciation schedule is extended, 18 the utility would earn a return of $9.75—10% of the average rate base of $97.50. In this 19 example, the Company earns an extra $0.25 in the Test Year, and will still recover the 20 full depreciation expense over the life of the investment. 21 Q. What is your concern with returns for BEC 3 and 4? 22 A. I am concerned that extending the depreciation schedule for BEC 3 and 4 would increase 23 the amount of returns earned by shareholders as compared to returns shareholders would 24 earn under a shorter depreciation schedule. The Company will likely fully depreciate 24 1 BEC 3 and 4 no matter how long the depreciation schedule—it is only a question of 2 timing. Regardless of whether the remaining lives of the units run until 2034 and 2035, 3 or 2050, the Company will likely recover its full depreciation expense over that time 4 period unless the Commission disallows recovery of part or all of the expenses. 5 But if the depreciation schedule is extended, the rate base balance of the assets 6 will remain higher for longer. This would lead to increased returns for shareholders over 7 the life of the project, compared to the existing depreciation schedule. 8 Q. Can you provide an example? 9 A. Yes. Under the Company’s extended depreciation schedule, the average rate base 10 balance of BEC 4 is $263,876,140 (MN Jurisdiction) after incorporating depreciation 11 expense of $11,008,345 (MN Jurisdiction), with the Company earning a return of 12 $30,319,368 (MN Jurisdiction). 39 13 If, on the other hand, the existing depreciation schedule is used, the depreciation 14 expense would be $20,307,795 (MN Jurisdiction)—higher than the alternative. This 15 would lead to a lower average rate base of $261,150,006 (MN Jurisdiction) on which the 16 Company earns a lower return of $30,006,136 (MN Jurisdiction). 40 17 This pattern would be repeated each year under the Company’s proposal. It 18 would delay recovery of the depreciation expense, which the Company will get 19 eventually regardless of the depreciation schedule, but increase the return on rate base 20 earned by shareholders. 39 40 OAG Information Request No. 1154, Schedule SL-12. Id. 25 1 Q. Were you able to calculate the total amount of increased returns? 2 A. I asked the Company to do so for me, but its response to OAG Information Request No. 3 1154 was not the amount of returns for the entire period of the extended depreciation 4 schedule and I do not think the Company provided what I was asking for. 5 While I did not calculate the cost impact over the entire extended period of the 6 depreciation schedule, the Company did provide calculations to compare the costs for the 7 Test Year. The Company’s proposal for BEC 3 and 4 produces depreciation expenses of 8 $18,654,731 41 (MN Jurisdiction) which is $16,488,411 42 less than the depreciation 9 expense of $35,143,142 (MN Jurisdiction) for these units under the existing depreciation 10 schedule, but it also increased the Test Year returns earned on BEC 3 and 4 by 11 $555,377 43 (MN Jurisdiction) (using the Company’s proposed rate of return). 44 12 To clarify, my calculations demonstrate that MP’s depreciation proposal increases 13 the amount of returns earned on BEC 3 and 4 by $555,377 during the Test Year. By 14 delaying recovery of depreciation expenses, shareholders would get more than half a 15 million dollars in additional returns for the Test Year. 16 Q. What is your conclusion regarding increased returns for shareholders? 17 A. I view it as concerning. I do not think the problem would be sufficient, alone, to reject 18 MP’s depreciation proposal, but it is something that the Commission should be aware of. 19 It may be in the best interests of shareholders to delay recovery of depreciation expense 20 in return for increase capital returns over a longer period of time, but it is not necessarily 21 in the best interests of ratepayers. 41 $7,646,386 + $11,008,345 $18,654,731 – ($14,835,347 + $20,307,795) 43 ($20,492,055 + $30,319,368) – ($20,249,910 - $30,006,136) 44 OAG Information Request No. 1154, Schedule SL-12. 42 26 1 5. Delay Of Coal Retirements. 2 Q. How are coal retirements related to depreciation expense? 3 A. As the Commission is aware, there is often significant pressure to explore the possibility 4 of early retirement for coal-fired generating plants. One reason is related to emissions. 5 Environmental advocates often recommend that the Commission and other regulators 6 seek to replace carbon-emitting generation with carbon-free generation such as wind, 7 hydro, or solar. In addition, environmental advocates sometimes recommend that the 8 Commission require utilities to retire fossil fuel power plants, in particular coal-fired 9 plants, before the end of their operational lives in order to reduce the carbon emissions of 10 utilities in the state. 11 There has also been economic pressure to consider early retirement of coal plants. 12 Other types of generation, including fuel-less generation and the possibility for storage in 13 the future, are contributing to poor economics for coal plants. It is my understanding that 14 the Commission recently directed Xcel Energy to retire several coal-fired generators 15 early because they had become uneconomical to run, regardless of environmental 16 impacts. 45 17 While the relationship may not be direct, the Commission should be aware that 18 the extended depreciation schedule for BEC 3 and 4 could have an impact on future 19 conversations about early retirement of these coal units. 20 Q. Please explain further. 21 A. One problem when a plant is retired early is whether or not a utility can and should 22 recover its undepreciated plant balance. The remaining plant value that is undepreciated 45 See In the Matter of Minnesota Power’s 2016–2030 Integrated Resource Plan, Docket No. E-015/RP-15-690, ORDER APPROVING RESOURCE PLAN WITH MODIFICATIONS (July 18, 2016). 27 1 becomes a stranded cost to the utility, and the Commission must decide whether recovery 2 of this cost would be just and reasonable. It seems likely that the magnitude of the 3 undepreciated plant balance at the time of an early retirement could have an impact on 4 the options available to the Commission. 5 Q. Can you provide an example? 6 A. Yes. Imagine two coal plants that are both expected to close in 2035. In the year 2030, 7 Plant A has an undepreciated plant balance of $10, while Plant B has an undepreciated 8 plant balance of $100. 9 If Plant A were retired 5 years early, the Commission would need to decide what 10 to do with only $10 in remaining plant balance. In contrast, retiring Plant B early would 11 be significantly more troublesome because of its large undepreciated plant balance. The 12 Commission would likely face greater resistance from the utility, whose shareholders 13 would be expecting a return on their investment for several years and would have to deal 14 with stranded costs that may not be recoverable. 15 Q. How does this example relate to BEC 3 and 4? 16 A. Based on recent experiences, it seems likely that at some point the Commission will be 17 asked to retire BEC 3 and 4 before the end of their useful lives in 2034 or 2035. At the 18 very least, it is likely that the Commission will consider retirement before 2050. My 19 concern is that extending the depreciation schedules for these units would mean that they 20 would have significant, undepreciated plant balances if the decision to retire these units 21 earlier than 2050 is made. 22 facilities is complicated and would be made based on multiple factors not known at this 23 time, making such a decision for a facility with a large, undepreciated plant balance While any decision regarding retirement of generating 28 1 would be even more complicated. In such an event, the Commission would be forced to 2 choose whether to require accelerated depreciation expense for ratepayers, stranded costs 3 for the utility and its shareholders, or to keep facilities open longer than would otherwise 4 be in the public interest. 5 depreciation schedules in this rate case proceeding will have an impact on decisions 6 about plant retirements made ten or fifteen years down the road in other proceedings. The point that I want to make is that decisions about 7 I want to clarify that I am not recommending retirement at any particular time, but 8 I do want to make sure that the Commission recognizes that extending the depreciation 9 schedule for BEC 3 and 4 could have an impact on future decisions regarding the 10 retirement of these units. 11 6. Recommendation Regarding BEC 3 And 4. 12 Q. What is your recommendation regarding BEC 3 and 4? 13 A. I recommend that the Commission deny MP’s request to extend the depreciation schedule 14 of the units. MP’s proposal would lead to a mechanism by which it could recover 15 stranded costs limiting the Commission’s ability to review these costs on a case by case 16 basis to ensure just and reasonable rates. It would require ratepayers in the 2040s to pay 17 for power plants that are currently expected to be closed many years earlier. 18 proposal would deviate from normal accounting procedures that exist for good reasons. 19 For example, it could lead to insufficient removal dollars at the time of retirement, and 20 increase returns for shareholders compared to the existing depreciation schedule. On top 21 of that, there are no estimates about the costs of operating the plants past their current 22 useful lives, and the proposal could limit the Commission’s options regarding retirement 23 of the facilities in the future. 29 The 1 I recognize that this recommendation would have a significant impact on the 2 revenue requirement in this rate case, based on how the Company presented its initial 3 proposal. According to information provided by the Company, 46 this recommendation 4 would increase depreciation expense in the Test Year by $16,488,412 (MN 5 Jurisdiction),47 and reduce return on rate base by $555,378 (MN Jurisdiction), 48 for a net 6 impact of $15,933,034 (MN Jurisdiction). But I have reviewed this matter carefully and 7 find that the concerns I have discussed above are significant enough to recommend 8 rejection of MP’s proposal. Instead, I recommend that the Commission maintain the 9 existing depreciation schedule for BEC 3 and 4. 10 Further, I believe that there is a better framework in which to consider MP’s 11 proposal to separate and extend the depreciation schedule from the operational life of 12 plants. In some ways, MP’s proposal is a form of rate moderation. The Company 13 proposes lower rates today by delaying higher rates to the future through the extension, 14 thereby concealing the full impact of its rate increase proposal in this case. Through this 15 lens, rejecting MP’s proposal would be appropriate in order to make a decision based on 16 traditional ratemaking practices and standard accounting principles that allow recovery of 17 costs for assets that are used and useful, rather than a decision that uses non-standard 18 accounting practices to conceal and delay rate increases. 46 OAG Information Request No. 1154, Schedule SL-12. $35,143,142 - $18,654,731 48 $50,811,423 - $50,256,045 47 30 1 B. BEC 1 AND 2. 2 Q. What is the status of BEC 1 and 2? 3 A. As I discussed above, BEC 1 and 2 are older, smaller coal-fired generators. According to 4 the most recently approved depreciation filing, the operational life of the units is expected 5 to end in 2024. Other factors, however, have led MP to decide that it will retire the units 6 by the end of 2018. 7 Q. Can you describe the recent history of BEC 1 and 2? 8 A. Based on the most recently approved Commission orders, BEC 1 and 2 have a remaining 9 life that will end in 2024. On September 29, 2014, MP entered into a Consent Decree 10 with the Environmental Protection Agency (“EPA”) and the Minnesota Pollution Control 11 Agency (“MPCA”). The Consent Decree required MP to take some action to reduce SO2 12 (sulfer dioxide) emissions from BEC 1 and 2 no later than December 31, 2018. As I 13 understand it, the options available to MP included retiring the facilities or rerouting the 14 emissions from BEC 1 and 2 through the improved scrubbers installed at BEC 3. 15 In its most recent IRP, MP informed the Commission that it would prefer to 16 continue to operate BEC 1 and 2 until 2024 by rerouting exhaust through BEC 3, and that 17 doing so would require additional investment of $30 million. 18 determined that “the Company has not demonstrated at this time that its proposed $30 19 million investment in SO2 reduction is a reasonable investment to allow the units to run 20 for three years.” 49 Ultimately, the Commission ordered MP to “retire Boswell Energy 49 The Commission In the Matter of Minnesota Power’s 2016–2030 Integrated Resource Plan, Docket No. E-015/RP-15-690, ORDER APPROVING RESOURCE PLAN WITH MODIFICATIONS at 7–8 (July 18, 2016). 31 1 Units 1 and 2 when sufficient energy and capacity are available, but no later than 2 2022.” 50 3 After this order, MP decided that it would retire BEC 1 and 2 by the end of 2018. 4 According to Company witness Mr. Skelton, this decision was the result of the 5 Company’s strategy to reduce small coal-fired generation, as well as the EPA Consent 6 Decree and the Commission’s decision in the IRP. 51 7 Q. What is MP’s depreciation proposal for BEC 1 and 2? 8 A. MP is planning to retire BEC 1 and 2 at the end of 2018 rather than in 2024, but would 9 extend the depreciation schedule to 2050. 10 Q. Would MP’s proposal lead to stranded costs? 11 A. Yes. The Company is asking to recover the cost of depreciation for BEC 1 and 2 for 32 12 years after the facilities will be closed. Presumably, ratepayers would also continue to 13 pay a return to shareholders on the undepreciated plant balance for 32 years after the 14 units are closed. In other words, the Company is seeking recovery of stranded costs. 15 Recent changes to Minnesota law provide that the Commission has the legal 16 authority to allow recovery of stranded costs. But, as I discussed above, Minnesota 17 Statutes section 216B.16, subdivision 6 makes clear that the Commission is not required 18 to do so if it would not result in just and reasonable rates. I do not believe that MP’s 19 proposal to extend the depreciation schedule for BEC 1 and 2 would result in just and 20 reasonable rates. 50 51 Id. at 15, ¶6. Skelton Direct at 19–20. 32 1 Q. 2 3 Can you explain why MP’s proposal for BEC 1 and 2 would not result in just and reasonable rates? A. There are good reasons why the depreciation schedule for investments is normally tied to 4 the operational life of the facilities. It promotes intergenerational equity for customers, 5 by ensuring that the customers who pay for an investment are receiving benefits from 6 those investments. 7 Commission’s existing rules, as discussed previously. It also is consistent with normal accounting principles and the 8 MP’s proposal would deviate from this standard significantly by extending the 9 cost recovery period for the depreciation expenses for more than three decades after the 10 facilities will be closed. I do not believe that this proposal is reasonable, and recommend 11 that the Commission reject MP’s proposal to extend recovery of depreciation expense 12 until 32 years after BEC 1 and 2 will be retired. 13 Q. 14 15 What options does the Commission have if it does not adopt MP’s recommendation for BEC 1 and 2? A. The Commission has several options. First, the Commission could maintain its decision 16 for the depreciation schedule and operational life ending in 2022, as decided in MP’s IRP 17 proceeding. 52 18 Second, the Commission could allow recovery of the accelerated depreciation 19 expense associated with BEC 1 and 2 retiring at the end of 2018 so that the facilities are 20 fully depreciated by the time they are retired in 2018. This would increase depreciation 21 expense and reduce returns on rate base in the Test Year, but would have the significant 22 benefit of avoiding completely the issue of stranded costs. Effectively, the Commission 52 In the Matter of Minnesota Power’s 2016–2030 Integrated Resource Plan, Docket No. E-015/RP-15-690. ORDER APPROVING RESOURCE PLAN WITH MODIFICATIONS at 6–7 (July 18, 2016). 33 1 would be concluding that the new operational life of BEC 1 and 2 will end in 2018, and 2 adjusting the depreciation schedule to match it without separating the two as proposed by 3 MP. The rate impact of this option would be larger than the other options, and could 4 have a significant impact on the revenue requirement in this case. 5 There may be other options to move forward, and I am open to considering them 6 as they arise throughout the case. 7 Q. What is your recommendation for BEC 1 and 2? 8 A. I do not have a specific recommendation at this time because I believe it is important that 9 MP address my concerns about double-counting capacity and energy costs, outlined in 10 Section XIII, before reaching a decision on the useful lives for BEC 1 and 2. Regardless 11 of which proposal the Commission approves, I recommend that the Commission also 12 order ratepayer protections to end the recovery of depreciation expenses and rate base 13 earnings for these units once they are fully depreciated. In this circumstance, I believe it 14 would be reasonable to create sunset provisions to end recovery of the costs for BEC 1 15 and 2 so that ratepayers are not paying for these units after they are fully depreciated. 16 Once MP responds to my concerns outlined in Section XIII, I may update my 17 recommendation regarding BEC 1 and 2. 18 C. SUMMARY OF BEC RECOMMENDATIONS. 19 Q. Can you summarize your recommendations regarding depreciation at BEC? 20 A. I recommend that the Commission deny MP’s proposal to combine the BEC units into 21 one depreciation schedule and extend recovery of depreciation expenses to 2050, for the 22 reasons I have described above. 23 Commission reject MP’s proposal to extend the cost recovery of depreciation expense to 24 2050, but do not have a specific recommendation regarding how to handle the useful Regarding BEC 1 and 2, I recommend that the 34 1 lives and depreciation schedule at this time. After the Company addresses my concerns 2 regarding double-counting of capacity and energy costs, below, I may refine my 3 recommendation regarding BEC 1 and 2. Regarding BEC 3 and 4, I recommend that the 4 Commission reject MP’s proposal and take no action to separate the current existing 5 remaining lives from the depreciation schedules in this rate case proceeding. If the 6 Company seeks to change the depreciation schedule for BEC 3 and 4, I believe the only 7 reasonable way to do so would be to produce evidence that would justify a modification 8 of the estimated operational life. An appropriate venue to pursue that issue would likely 9 be in the Company’s IRP when long-term resource decisions are made. 10 Regarding the BEC Common Facilities, it is my understanding that the 11 operational life and depreciation schedule is based on an averaging of the remaining BEC 12 investments, 53 and I recommend that it continue to be treated in whatever manner is 13 currently applied. 14 The total cost impact of this recommendation would be an increase in the revenue 15 requirement of $15,936,118 (MN Jurisdiction) from the Company’s proposal. 54 While it 16 would not normally be in the best interest of ratepayers to recommend actions that cause 17 an increase to the revenue requirement, in light of the significant concerns with MP’s 18 proposal I believe that it is the most reasonable thing for the Commission to do in this 19 case. 53 In the Matter of Minnesota Power’s 2016 Remaining Life Depreciation Petition, Docket No. E-015/D-16-797, ORDER, at 7 (Apr. 21, 2017). 54 ($97,972,954 + $128,013,352) - ($91,025,090 + $119,025,098) 35 1 VI. COSTS RELATED TO EARLY RETIREMENT OF BEC 1 AND 2 2 3 Q. What is your concern related to the cost of early retirement of BEC 1 and 2? 4 A. As I discussed above, in MP’s most recent IRP the Commission ordered the Company to 5 retire BEC 1 and 2 “when sufficient energy and capacity are available, but no later than 6 2022.” 55 7 generation could be in place by 2022.” 56 The Company indicates that it has decided to 8 retire BEC 1 and 2 by the end of 2018, but I am not aware of any place in the record of 9 this proceeding which the Company discusses how it has obtained “sufficient energy and 10 The Commission noted that “The Department believed that replacement capacity” to replace electricity that would otherwise be generated by BEC 1 and 2. 11 My concern is that the Commission conditioned its order regarding BEC 1 and 12 2—MP was ordered to retire the facilities no later than 2022, but only after it had 13 obtained replacement energy and capacity. Based on my review of the record, I do not 14 see any discussion of how the Company has obtained replacement energy and capacity, 15 or the cost of doing so. 16 Essentially, my concern is that there could be a type of double recovery. BEC 1 17 and 2 produce approximately 134 MW in capacity, and the associated energy. 18 Ratepayers will continue to pay for the capacity and energy costs related to BEC 1 and 2 19 until a future rate case adjusts rates again. Because MP has decided to retire the facilities 20 in 2018, I assume that the Company must have complied with the Commission’s 21 requirement that it obtain replacement capacity and energy before the retirements take 22 place. My concern is that MP may have included the cost of both BEC 1 and 2 and the 55 In the Matter of Minnesota Power’s 2016–2030 Integrated Resource Plan, Docket No. E-015/RP-15-690. ORDER APPROVING RESOURCE PLAN WITH MODIFICATIONS at 7–8 (July 18, 2016). 56 Id. 36 1 replacement for BEC 1 and 2 in the Test Year. It is unclear whether the Company should 2 recover both types of costs at the same time. 3 Because I did not locate any testimony where the Company discussed the required 4 replacement for BEC 1 and 2, I was not able to confirm whether the Company had a plan 5 for replacement capacity and energy, whether its plan was reasonable, or whether its cost 6 recovery proposal was reasonable. For that reason, I request that MP provide testimony 7 regarding the requirement that it obtain replacement capacity and energy before retiring 8 BEC 1 and 2, the costs of doing so, and how those costs are reflected in this rate case. 9 10 11 VII. STORM DAMAGE AMORTIZATION EXPENSE Q. Is the Company requesting cost recovery for storm damage costs associated with 12 13 storms on July 21, 2016? A. Yes. The Company has included $732,272 in the 2017 Test Year to reflect the four-year 14 amortization of $2,929,088 in storm damage costs that were incurred as a result of the 15 storms on July 21, 2016. 16 Q. Did the Company seek approval to defer and amortize these storm damage costs? 17 A. Yes. The Company filed its request to defer these operating and maintenance costs totaling $2,929,088 on August 1, 2016 in a separate deferred accounting docket. 57 18 19 Q. What did the Commission order in that docket? 20 A. The Commission denied the Company’s request to defer and amortize the storm damage 21 costs and found that the Company did not demonstrate that these were “unusual and 57 In the Matter of a Petition for Approval of Deferred Accounting Treatment of Costs Related to the 2016 Storm Response and Recovery, Docket No. E-015/M-16-648 (Aug. 1, 2016). 37 1 unforeseen, and would have significant impact on its financial condition.”58 2 Furthermore, the Commission found that “while the impact of the 2016 storm was more 3 significant than past storms, there are years where Minnesota Power experiences no 4 storms or very small storms, and the Company therefore incurs less costs than those built 5 into rates.” 59 6 Q. 7 8 Why did the Company include amortization expense in the Test Year if the Commission denied the Company’s request? A. 9 The Company included this amortization expense in the 2017 Test Year for general rates because the Commission had not yet decided the 2016 deferred accounting docket at the 10 time the Company filed this rate increase request. 11 Q. What is your recommendation? 12 A. I recommend that the amortization expense of $732,272 should be excluded from the 13 2017 Test Year, consistent with the Commission’s decision to deny the Company’s 14 request to amortize this expense. 15 VIII. SAPPI/CLOQUET GENERATOR AMORTIZATION EXPENSE 16 17 Q. 18 19 Provide a summary of this amortization expense and a summary of the history of events. A. The Sappi/Cloquet generator is installed at a paper mill that is owned by a company 20 called Sappi. The generator was previously owned by the Company, but was purchased 21 by Sappi from the Company on July 1, 2016 for one dollar. The Company has included 58 In the Matter of a Petition for Approval of Deferred Accounting Treatment of Costs Related to the 2016 Storm Response and Recovery, ORDER DENYING PETITION FOR DEFERRED ACCOUNTING TREATMENT, Docket No. E015/M-16-648 (Jan. 10, 2017). 59 Id. 38 1 $275,745 in amortization expense associated with the increase in depreciation expense 2 for the Sappi/Cloquet generator. This increase in depreciation expense resulted from the 3 Commission’s order on September 19, 2016 that the Company shorten the useful life of 4 the Sappi/Cloquet generator from ten years ending in 2024, to two years ending in 2016 5 because the Company had already sold the Sappi/Cloquet generator and should not be 6 depreciating an asset it no longer owned. 60 The depreciation expense that would have 7 been charged over a ten year period would have to be accelerated and charged over two 8 years, which would lead to an increase in the amount of depreciation expense to be 9 charged each year. Since this increase in depreciation expense was not included in base 10 rates at that time, the Company filed a separate request for deferred accounting on 11 October 28, 2016 to request deferral of the increase in depreciation costs totaling 12 $2,205,958. 61 The Department recommended that the Commission deny the Company’s 13 deferred accounting request. Before the Commission was able to make its decision, 14 however, the Company withdrew its deferred accounting request on December 20, 2016. 15 Q. Why did the Company withdraw its deferred accounting request? 16 A. The Company explained that its decision to withdraw the request was based on the 17 Commission’s decision to deny the Company’s separate request for deferred accounting 18 treatment for storm damage costs, as well as the Company’s determination, through 19 further analysis, that no depreciation expense issues for Sappi/Cloquet needed to be 20 addressed. 60 In the Matter of Minnesota Power’s 2015 Remaining Life Depreciation Petition, Docket No. E-015/D-15-711, ORDER APPROVING REMAINING LIVES AND SALVAGE RATES AS MODIFIED, AND FILING REQUIREMENTS (Sept. 19, 2016). 61 In the Matter of a Petition for Approval of Deferred Accounting Treatment of Costs Related to Depreciation Expenses for Sappi-Generator No. 5, Docket No. E-015/M-16-876 (Oct. 28, 2016). 39 1 Q. What is your recommendation? 2 A. I recommend that the Company remove $275,745 of amortization expense associated 3 with the Sappi/Cloquet generator out of the 2017 Test Year. This is consistent with the 4 Commission’s decision to shorten the useful life of the generator to the end of 2016, and 5 to reflect the fact that the asset is no longer owned by the Company. 6 IX. CREDIT CARD PROCESSING FEES 7 8 Q. Explain what these credit card processing fees are. 9 A. The Company has included $350,000 in the 2017 Test Year to cover the costs that 10 customers currently have to pay a third-party credit card processor, for the convenience 11 of making electronic payments with a credit or debit card. 12 Q. 13 14 What is the Company’s justification for asking ratepayers to cover this convenience cost? A. The Company points to several sources, such as J.D. Powers, the National Association of 15 State Utility Consumer Advocates (“NASUCA”), and the Public Utilities Fortnightly, 16 that have published articles stating that eliminating payment fees for customers would 17 lead to “enhanced customer convenience, satisfaction, and improved quality of service,” 18 convenience fees eroding the purchasing power of debit cards and making it hard for 19 customers to pay for utility service, and that prepaid credit and debit cards are increasing 20 in popularity among younger customers and low-income customers. 62 The NASUCA 21 document that the Company cited to is a Resolution titled “Urging Utilities to Eliminate 22 ‘Convenience’ Fees for Paying Utility Bills with Debit and Credit Cards and Urging 62 Koecher Direct at 29. 40 1 Appropriate State Regulatory Oversight” (“Resolution”). 63 The OAG is a member of 2 NASUCA, so I reviewed this resolution to determine whether the Company’s proposal is 3 consistent with the concerns raised in the Resolution. 4 Q. Does the Company’s proposal address the concerns in the NASUCA resolution? 5 A. No. The Resolution pointed out that one of the reasons for the high fees attached to 6 utility payments by credit or debit cards is that many utilities process these charges 7 through third-party vendors that assess large fees. 64 The Resolution suggests that if 8 utilities would accept payments directly instead, the costs would be “likely comparable to 9 the cost of processing payments by other means, including traditional checks.” 65 10 Ultimately, the Resolution recommends that utilities drop third-party vendors and instead 11 accept debit and credit payments directly in order to reduce costs and protect low-income 12 customers. The Company’s proposal would do nothing to address this primary concern 13 in the Resolution because ratepayers would still be assessed third-party vendor 14 processing fees. 15 Q. Does the NASUCA Resolution address any other concerns? 16 A. Yes. The Resolution also points out that there should be cost savings from eliminating 17 credit card fees. The Resolution suggests that cost savings could come from “more 18 immediate receipt of payment, lower collection risks and uncollectible debt expense, 19 improved cash flow and reduced working cost of capital.” 66 I agree that increasing 20 payments from credit and debit cards, and particularly making it easier for low-income 63 Id. at 30. RESOLUTION 2012-07 URGING UTILITIES TO ELIMINATE ‘CONVENIENCE’ FEES FOR PAYING UTILITY BILLS WITH DEBIT AND CREDIT CARDS AND URGING APPROPRIATE STATE REGULATORY OVERSIGHT, NASUCA (Nov. 13, 2012), available at https://nasuca.org/2012-07-urging-utilities-to-eliminate-convenience-fees-for-paying-utility-bills-withdebit-and-credit-cards-and-urging-appropriate-state-regulatory-oversight/. 65 Id. at 2. 66 Id. 64 41 1 customers to make such payments, could create cost savings in these categories. MP has 2 made no attempt to calculate the cost savings from increased credit or debit payments, 3 and they are not reflected in this case at all. 4 Q. What is your conclusion regarding the NASUCA Resolution? 5 A. I conclude that the Company has not addressed the concerns of the NASUCA Resolution. 6 Specifically the suggestion that debit and credit card payment processing would cost less 7 overall if utilities would accept payments directly rather than through third party vendors, 8 and that there should be cost savings from increasing such payments. 9 Q. What is your recommendation? 10 A. Based on the specific facts of this case, at this time I recommend that MP’s proposal be 11 rejected, including its request to increase the revenue requirement by $350,000, because 12 the Company’s proposal does not address the concerns of the NASUCA Resolution. 13 Instead, I recommend that the Commission order the Company to investigate the 14 concerns in the NASUCA resolution regarding third-party vendor processing charges and 15 the cost savings associated with increased debit and credit card payments, and adjust its 16 proposal to accept debit and credit card payments directly if it is less expensive to do so. 17 I also recommend that the Commission order the Company to conduct a review of the 18 potential cost savings as discussed in the Resolution. 19 X. CHARITABLE CONTRIBUTIONS 20 21 Q. Is the Company requesting recovery of charitable contributions? 22 A. Yes. As shown in MP Exhibit_(MAP) Direct Schedule G-2, the Company included 23 $453,128 in the 2017 Test Year for charitable contributions. This amount represents 50 42 1 percent of Company’s three-year average spending for charitable contribution from 2013 2 to 2015. 3 Q. Why is only 50 percent included in the 2017 Test Year? 4 A. Including only 50 percent in the Test Year is consistent with Minnesota Statutes section 5 216B.16, subdivision 9, and the Commission’s Statement of Policy on Charitable 6 Contributions issued on June 14, 1982. 67 7 Q. 8 9 How did the Company calculate the 2017 Test Year amount of charitable contributions to be recovered from ratepayers? A. The Company first calculated a three-year average of its actual charitable contributions 10 from 2013, 2014, and 2015. The Company then adjusted its 2017 budget for charitable 11 spending of $512,000 downward by $58,872 so that its 2017 Test Year budget reflects 12 the three-year average of $453,128. 13 Q. 14 Did the Company provide how much was spent on charitable contributions in other years? 15 A. Yes. The Company spent $776,855 in 2012 and $292,080 in 2016. 68 16 Q. Are you concerned with the Company’s calculation of charitable contributions for 17 18 its 2017 Test Year? A. Yes. While the Company uses a three-year average, it appears that the Company’s actual 19 charitable contributions have fluctuated significantly between 2012 and 2016. 20 provide context, I included the charitable contributions from 2012 to 2016, and the 2017 21 budget, in Table 1. 22 significantly from year to year. For example, charitable spending increased by nearly 67 68 To This table shows that charitable contributions have changed Minnesota Power Workpapers, Volume 5, ADJ-IS-13c. See OAG Information Request 106, Schedule SL-13. 43 1 100% from 2013 to 2014, and then dropped by 74% from 2015 to 2016. And the amount 2 included in the Test Year is 75% greater than the amount spent in the most recent fiscal 3 year. 69 The Commission has considered variance of this level in other rate cases. In the 4 Company’s last rate case, the Commission reviewed significant fluctuation in actual 5 spending in 2007, 2008, and 2009. Table 1 Charitable Contributions Year 2012 Actual 2013 Actual 2014 Actual 2015 Actual 2016 Actual 2017 Budget 6 7 Q. 8 9 $ $ $ $ $ $ Amount % Variance 776,855 533,254 -31% 1,058,473 98% 1,127,042 6% 292,080 -74% 512,000 75% What information about the Company’s last rate case is pertinent for the current rate case? A. 10 The year-to-year variance in charitable contributions was also an issue in the Company’s last rate case, and is shown in Table 2. Table 2 Charitable Contributions Year Amount % Variance 2007 Actual $ 929,522 2008 Actual $ 1,068,702 15% 2009 Actual $ 665,707 -38% 2010 Budget $ 1,295,000 95% 11 12 In that rate case, the Company wanted to assume its 2010 budget for its 2010 Test Year. 13 The Commission denied the request, and instead determined that “a three-year average is 69 Podratz Direct at 23. 44 1 likely to have more predictive value than data from a single year.” 70 2 Commission was concerned that the Company had recovered more from ratepayers for 3 charitable contributions than was actually spent and stated that “relying more heavily on 4 factual data than stated intentions is clearly a reasonable strategy for preventing 5 recurrence of over-recovery.” 71 6 Q. 7 8 Further, the What three years did the Commission order the Company to use in its last rate case? A. The Commission ordered the Company to use its most recent three years of actual 9 spending to calculate a three-year average to be used to set Test Year charitable 10 contribution expense. In other words, the Company used actual spending from 2007, 11 2008, and 2009 to calculate the three-year average for its 2010 Test Year. 12 Q. What three years does the Company use for the calculation in its current rate case? 13 A. The Company uses actual spending from 2013, 2014, and 2015. 14 Q. Does the Company explain why it does not use the most recent three years of actual 15 spending? 16 A. No. 17 Q. Should the Company use its most recent three years of actual spending? 18 A. Yes, the Company should use actual spending in 2014, 2015, and 2016 to set its Test 19 Year charitable contribution expense. In addition to this method being consistent with 20 the methodology used in the Company’s last rate case, this method also considers the fact 21 that the Company has volatile levels in charitable spending from year to year which could 70 In the Matter of the Application of Minnesota Power for Authority to Increase Rates for Electric Utility Service in Minnesota, Docket No. E-015/GR-09-1151, FINDINGS OF FACT, CONCLUSIONS OF LAW, AND ORDER at 38 (Nov. 2, 2010). 71 Id. 45 1 result in actual future spending to be less than what the Company currently plans. 2 Additionally, as pointed out by the Company, charitable contributions are discretionary 3 spending for corporations and can be reduced when a Company experiences unfavorable 4 economic conditions. 72 5 income due to northern Minnesota’s challenging economic outlook,” it is reasonable to 6 use the most recent lower levels of actual spending to set its Test Year charitable 7 contribution expense. I also note that while including 2016 in the average would reduce 8 Test Year expenses somewhat, including 2014 and 2015 would capture two years of very 9 high spending. Since the Company has stated it expects “lower operating 10 Q. What is your recommendation? 11 A. I recommend that the three-year average is calculated using actual spending from 2014 to 12 2016 as shown below. This would result in an adjustment to the 2017 Test Year of 13 $99,068 to reduce the Company’s 2017 budget of $512,000 to $412,933. Table 3 3 Year Average Year 2014 Actual 2015 Actual 2016 Actual 3-year Average 50% Allowable in Rates 14 72 Id. 46 Amount $ 1,058,473 $ 1,127,042 $ 292,080 $ 825,865 $ 412,933 1 XI. MEMBERSHIP DUES 2 3 Q. Are there membership dues in the 2017 Test Year? 4 A. Yes. The Company has included its cost for corporate membership dues and individual 5 professional membership dues in its Test Year. 6 Q. How much is the amount in the 2017 Test Year for each type of membership dues? 7 A. It is not clear what amount is included in the Test Year for corporate membership dues 8 and individual professional membership dues, because the Company has provided several 9 types of information that are inconsistent. 10 While the Company has provided a one-page summary of its employee expenses 11 in the Test Year 73 which shows an amount of $1,418,853 74 under the “Dues and 12 Expenses for Memberships in Organizations or Clubs” category, the Company also 13 shows in a separate schedule that $789,962 is included in the Test Year for membership 14 dues. 75 Additionally, the Company states that it has made a Test Year adjustment of 15 $29,039 to organizational dues, 76 but the adjustment amount shown for the “Dues and 16 Expenses for Memberships in Organizational Dues” category in the one-page summary is 17 only $17,514. 18 $237,194 in the “Lobbying” category of the one-page summary of employee expenses in 19 the Test Year are related to various membership dues that are associated with lobbying 20 activities. 78 77 On top of that, it appears that $149,195 of the total adjustments of 73 MP Exhibit_(SWM) Direct Schedule 1 2017 Employee Expense Summary. $1,418,853 - $17,514 75 MP Exhibit_(MAP) Direct Schedule G-3. 76 MP Exhibit_(MAP) Supplemental Direct Schedule A-6. 77 MP Exhibit_(SWM) Direct Schedule 1 2017 Employee Expense Summary. 78 MP Exhibit_(MAP) Direct Schedule G-3. 74 47 1 It appears that the Company has included subsets of membership dues and 2 adjustments to membership dues in various expense categories, but it is not clear what 3 amount of the total expenses in the “Dues and Expenses for Memberships in 4 Organizational Dues” category pertain to corporate and individual membership dues. 5 These discrepancies suggests that the amount of $1,418,853 shown in the category “Dues 6 and Expenses for Memberships in Organizations or Clubs” may not capture all 2017 Test 7 Year costs of this type of expense. 8 Q. Did the Company provide a listing of its membership dues? 9 A. Yes. The Company provided a list of its 2015 corporate and individual membership dues 10 in MP Exhibit_(MAP) Direct Schedule G-3. The Company spent $621,791 on corporate 11 memberships in 2015. The Company spent $65,306 on individual memberships in 2015. 12 The Company spent $14,362 for other business dues. 13 Q. 14 15 Year, do you have any concerns about any specific membership dues? A. 16 17 Yes. There are additional membership dues associated with lobbying activities that have not been removed by the Company that should be excluded from the Test Year. Q. 18 19 Besides the lack of clarity on the total amount of membership dues in the 2017 Test What are the additional membership dues that should be disallowed that have not already been removed by the Company from the Test Year? A. There are membership dues where the entire annual cost should be removed due to the 20 organization’s lobbying activities and legislative efforts, and the inability of the Company 21 to provide information on how much of the membership dues are attributable to the 22 organization’s lobbying activities and to other activities that lead to favorable regulatory 48 1 and policy outcomes that benefit the utility. 79 The membership dues for the following 2 organizations should be disallowed. 3 • Edison Electric Institute, including USWAG and UARG 4 • Western Coal Traffic League 5 • Utility Water Act Group 6 • Mining Minnesota 7 • Minnesota Forest Industries 8 • Minnesota Timber Producer Association 9 • National Association of Manufacturers 10 • American Wood Protection Association 11 • National Coal Transportation Association 12 • World Steel Dynamics Incorporated 13 • National Hydropower Association 14 Q. 15 16 Which membership dues related to lobbying activities has the Company already removed from the 2017 Test Year? A. The Company has currently excluded the entire membership due for the Lignite Coal 17 Council, the entire membership due for the Center for Clean Air Policy, and a portion of 18 the membership due for the Edison Electric Institute (“EEI”) that is associated with 19 lobbying activity. 80 79 80 See OAG Information Request 152, Schedule SL-14. Id. 49 1 Q. 2 3 How much of the total cost of each of these memberships have been attributed to lobbying activities and excluded from the Test Year? A. This is unclear. While the Company stated in MP Exhibit_(MAP) Direct Schedule 3 that 4 it removed $149,195 associated with the lobbying portion of the membership dues for 5 these three organizations, the Company responded with a different amount in OAG 6 Information Request 141 of $153,262. I request that the Company provide the amount of 7 membership dues in the Test Year for EEI, Lignite Coal Council, and Center for Clean 8 Air Policy, in addition to the amount for each membership that was excluded from the 9 Test Year to reflect the lobbying activities of the associations that should not be 10 recovered from ratepayers including amounts that were moved “below-the-line” and the 11 amounts that had to be adjusted out of the 2017 budget. 12 Q. 13 14 How does the Company determine the portion of the annual membership dues associated with lobbying activities? A. The Company explained that “the lobbying portion of . . . [d]ues is calculated and 15 reported each year using the Internal Revenue Code’s (IRC) definition of “lobbying and 16 political activities” as required to be reported on IRS Form 990.” 81 17 Q. 18 19 What are the Internal Revenue Service (“IRS”) definitions for lobbying and political expenses? A. The IRS broadly defines lobbying and political expenditures in IRC section 162(e), 20 which includes those expenses in connection with “1. Influencing legislation, 2. 21 Participating or intervening in any political campaign on behalf of (or in opposition to) 22 any candidate for public office, 3. Attempting to influence the general public with respect 81 See OAG Information Request 117, Schedule SL-15. 50 1 to elections, legislative matters, or referendums, and 4. Any direct communication with a 2 covered executive branch official in an attempt to influence the person’s official actions 3 or positions.” 82 4 Q. 5 6 Do the organizations provide the Company with a notice on the portion of dues that is attributable to nondeductible lobbying expenses? A. In most instances, the organization provides the percentage of membership dues related 7 to the activities that have been defined under IRC section 162(e). 8 definition of lobbying expenses is used for tax purposes and for determining 9 nondeductible business expenses, it is not inclusive of all activities that lead to favorable 10 11 While this IRS regulatory and policy outcomes that benefit the utility. Q. Have there been any public utilities commissions that have found a larger portion of 12 an organization’s activities were attributed to lobbying and other political activities 13 than were reported by the organization? 14 A. Yes. There are at least two general rate cases in the state of California where the 15 California Public Utilities Commission (“CPUC”) found that a greater portion of the 16 organization’s activities was attributable to lobbying and political activities than was 17 reported by the organization. 18 Q. Provide a brief summary of those general rate cases. 19 A. The first is Pacific Gas & Electric’s (“PG&E”) general rate case in 2014. 83 PG&E had 20 proposed to exclude only 25 percent of its EEI annual membership dues associated with 82 INTERNAL REVENUE SERVICE, NONDEDUCTIBLE LOBBYING AND POLITICAL EXPENDITURES, https://www.irs.gov/charities-non-profits/other-non-profits/nondeductible-lobbying-and-political-expenditures (last visited May 24, 2017). 51 1 lobbying activities from recovery. However, information provided by an intervening 2 party 84 showed EEI lobbying and political activities in 2005 as audited by the National 3 Association of Regulatory Utility Commissioners (“NARUC”), and EEI lobbying 4 activities in 2009 as provided to the Arkansas Public Service Commission in a general 5 rate case in that state had exceeded the 25 percent that PG&E was proposing to exclude. 6 The CPUC found that EEI activity pertained to “lobbying, legislative policy research and 7 advocacy, regulatory advocacy, public relations, advertising, donations, and club dues” 8 were categories of expenses that offered no ratepayer benefits; therefore, the CPUC 9 disallowed 43 percent of the EEI annual membership dues. 10 The second is Southern California Edison’s (“SCE”) general rate case in 2015. 85 11 SCE had proposed to exclude only 24 percent of its EEI annual membership dues from 12 recovery. However, the CPUC found that SCE did not fully follow the methodology to 13 exclude all cost categories it had earlier disallowed in the PG&E 2014 general rate case 14 that offered no ratepayer benefits, and disallowed 48 percent of the EEI annual 15 membership dues. _________________________________ (Footnote Continued from Previous Page) 83 Application of Pacific Gas and Electric Company for Authority, Among Other Things, to Increase Rates and Charges for Electric and Gas Service Effective on January 1, 2014 (U39M), Application No. 12-11-009, DECISION 14-08-032, 2014 WL 4248558 (Cal. P.U.C. Aug. 14, 2014). 84 Application of Pacific Gas and Electric Company for Authority, Among Other Things, to Increase Rates and Charges for Electric and Gas Service Effective on January 1, 2014 (U39M), Application No. 12-11-009, DECISION 14-08-032, 2014 WL 4248558 (Cal. P.U.C. Aug. 14, 2014). 85 Application of Southern California Edison Company (U338E) for Authority to, among other things, Increase its Authorized Revenues for Electric Service in 2015, and to reflect that increase in Rates, Application No. 13-11-003, DECISION 15-11-021, 2015 WL 7351928 (Cal. P.U.C. Nov. 12, 2015). 52 1 Q. 2 3 Explain what the NARUC audit was and the operating expense categories used in the audit. A. According to the Resource Library on the NARUC website, the Committee on Utility 4 Association Oversight was formed on July 30, 1986 in response to concerns about 5 utilities recovering association dues. 86 There are nine operating expense categories used 6 in the NARUC audit to capture an organization’s activities. 87 They are: 7 • Legislative Advocacy 8 • Legislative Policy Research 9 • Regulatory Advocacy 10 • Regulatory Policy Research 11 • Advertising 12 • Marketing 13 • Utility Operations and Engineering 14 • Finance, Legal, Planning, and Customer Service 15 • Public Relations 16 Q. 17 18 What do the different operating expense categories suggest regarding the different types of political activities there are? A. The expense categories used by NARUC to categorize the activities an organization is 19 involved with suggests that there are many types of activities to influence the legislative 20 and regulatory process than just obvious direct lobbying activity. While the IRS has its 86 RESOLUTION REGARDING DISCONTINUATION OF THE COMMITTEE ON UTILITY OVERSIGHT, NATIONAL ASSOCIATION OF REGULATORY UTILITY COMMISSIONERS (Mar. 8, 2000), http://pubs naruc.org/pub/5398B543-2354D714-51D3-90ACAB1DA952. 87 Application of Southern California Edison Company (U338E) for Authority to, among other things, Increase its Authorized Revenues for Electric Service in 2015, and to reflect that increase in Rates, Application No. 13-11-003, DECISION 15-11-021, 2015 WL 7351928 (Cal. P.U.C. Nov. 12, 2015). 53 1 definition for determining lobbying activities for tax purposes, there are activities that 2 organizations can engage in that impact regulatory and policy outcomes that benefit the 3 utility, which the CPUC has determined do not benefit ratepayers. 4 Q. 5 6 What is the total amount associated with the corporate membership dues that should be disallowed in the Test Year? A. This is unclear. I request that the Company provide the amount of membership dues in 7 the Test Year for the organizations below, in addition to the amount for each membership 8 that was excluded from the Test Year to reflect the lobbying activities of the associations 9 that should not be recovered from ratepayers including amounts that were moved “below- 10 the-line” and the amounts that had to be adjusted out of the 2017 budget. 11 • Edison Electric Institute, including USWAG and UARG 12 • Western Coal Traffic League 13 • Utility Water Act Group 14 • Mining Minnesota 15 • Minnesota Forest Industries 16 • Minnesota Timber Producer Association 17 • National Association of Manufacturers 18 • American Wood Protection Association 19 • National Coal Transportation Association 20 • World Steel Dynamics Incorporated 21 • National Hydropower Association 54 1 Q. 2 3 Explain why the entire amount of EEI membership dues should be disallowed from recovery? A. There are two primary reasons why ratepayers should not have to pay for the EEI 4 member dues. First, the EEI is a national organization engaged in extensive lobbying 5 activities on behalf of its investor owned electric utility members. Its website indicates 6 that it “advocates on behalf of our investor-owned electric company members before 7 Congress, federal and state regulatory agencies, the courts, and various industry 8 organizations.” 88 Additionally, roughly 35 percent or $124,500 of Minnesota Power’s 9 annual EEI membership dues are to pay for activities furthered by the Utility Solid Waste 10 Activity Group (“USWAG”) and the Utility Air Regulatory Group (“UARG”). 89 11 USWAG engages in regulatory advocacy for its utility, energy, and industry association 12 members, including EEI and the American Gas Association (AGA). 90 UARG does not 13 have a website, but it has engaged in legal proceedings with the U.S. Environmental 14 Protection Agency (“EPA”) on the Clean Air Act 91 and the Clean Power Plan. 92 15 The second reason for disallowing recovery of EEI membership dues is that the 16 Company has not been able to provide a breakdown of the annual membership dues 17 based on the activities that EEI is engaged in that would benefit ratepayers. Further, 18 EEI’s funding of USWAG and UARG make it extremely difficult to determine the 88 EDISON ELECTRIC INSTITUTE, ISSUES AND POLICY, http://www.eei.org/issuesandpolicy/Pages/default.aspx (last visited May 24, 2017). 89 See OAG Information Request 117, Schedule SL-15. 90 UTILITY SOLID WASTE ACTIVITIES GROUP, ABOUT USWAG, http://www.uswag.org/About/Pages/default.aspx (last visited May 24, 2017). 91 Utility Air Regulatory Group v. Environmental Protection Agency, 134 S.Ct. 2427 (2014). 92 Paul Ciampoli, APPA and UARG seek review of final Clean Power Plan, AMERICAN PUBLIC POWER ASSOCIATION (Oct. 26, 2015), http://www.publicpower.org/Media/daily/ArticleDetail.cfm?ItemNumber=44701. 55 1 activities of these third-party organizations that benefit Minnesota ratepayers, for which 2 ratepayers should pay for. 3 Q. 4 5 Explain why the entire amount of Western Coal Traffic League (“WCTL”) membership dues should be disallowed from recovery? A. There are two primary reasons. First, this organization is located in Washington, DC in 6 close proximity to legislative activities and regulatory agencies, and it engages in 7 advocacy work for its investor-owned company members, cooperative, and governmental 8 members though legal proceedings. 93 Second, while the WCTL website states it is 9 involved in “significant matter impacting the delivered prices of western coal,” 10 Minnesota Power has not been able to separate WCTL activities that are related to 11 lobbying and those activities that do not influence legislative and regulatory policy that 12 benefit Minnesota ratepayers. 94 Minnesota Power should treat the membership dues for 13 this organization the same as they treated its membership dues for the Lignite Coal 14 Council, which is to remove it from the 2017 Test Year. 15 Q. 16 17 Explain why the entire amount of the Utility Water Act Group (“UWAG”) membership dues should be disallowed from recovery? A. There are two primary reasons. First, the organization is a lobbying group that represents 18 EEI and other national trade organizations and energy companies with a stated purpose 19 “to participate on behalf of its members in EPA’s rulemakings under the CWA and in 93 Our History, WESTERN COAL TRAFFIC LEAGUE, http://www.westerncoaltrafficleague.com /index.php?option=com_content&view=article&id=2&Itemid=2 (last visited May 24, 2017). 94 See OAG Information Request 152, Schedule SL-14. 56 1 litigation arising from those rulemakings.” 95 2 Minnesota Power ratepayers obtain from the activities of this organization. 3 Q. Second, it is not clear what benefits Explain why the entire membership dues for Minnesota Mining, Minnesota Forest 4 Industries, Minnesota Timber Producer Association, National Association of 5 Manufacturers, 6 Transportation Association, and World Steel Dynamics Incorporated should be 7 disallowed from recovery? 8 A. American Wood Protection Association, National Coal There are two primary reasons. First, these industry trade associations are not directly 9 involved in the electric utility industry, and it is unclear how membership in these 10 industry trade associations will benefit Minnesota Power ratepayers and are necessary for 11 the provision of utility service. Second, Minnesota Power has not provided a breakout of 12 the activities for each of these organizations that benefit Minnesota Power ratepayers and 13 are not related to lobbying and those activities that do not influence legislative and 14 regulatory policy. 96 15 Q. 16 17 Explain why the entire amount of the National Hydropower Association (“NHA”) membership dues should be disallowed from recovery? A. There are three primary reasons. First, NHA’s website suggests it has an influential 18 lobbying role in that it states it is “a powerful advocacy voice among U.S. decision 19 makers, the general public and the international community” and that “through 20 membership, individuals and organizations gain access to regulatory bodies, influence 95 Comments of the Utility Water Act Group on Revised Draft Permit for the Merrimack Station NPDES Permit No. NH0001465 (Aug. 18, 2014), available at www3.epa.gov/ region1/npdes/merrimackstation/pdfs/Comments2RevisedDraftPermit/UWAGComments.pdf. 96 See OAG Information Request 152, Schedule SL-14. 57 1 over energy and environmental policy. . .” 97 NHA’s 2015 Annual Report also lists a 12- 2 month legislative and regulatory timeline in which it was involved in many activities that 3 impacted regulatory and policy outcomes. 98 Second, while it appears that NHA has an 4 “Operational Excellence Program” that is a voluntary event reporting system that tracks 5 operational information, as well as best practices and lessons learned to be shared among 6 utility companies, it is unclear whether Minnesota Power participates in this program. 7 Furthermore, Minnesota Power has not provided a breakout of NHA activities that are 8 related to lobbying and those activities that do not influence legislative and regulatory 9 policy that benefit Minnesota ratepayers. 99 10 Q. 11 12 Are there any membership dues that the Commission have disallowed because of the potential lobbying activities of the organization? A. Yes. The Commission found in the 2015 CenterPoint Energy general rate case that the 13 utility’s request to recover its $177,584 annual membership dues in the American Gas 14 Association would lead to unjust and unreasonable rates for ratepayers. The reason for 15 denying the utility’s request was because it was “impossible to determine on this record 16 the portion of AGA dues that are used for lobbying, or to perform a reasoned analysis 17 about whether or to what extent the lobbying served ratepayer interests.” 100 18 Commission stated that “[t]he Commission does not wish to tacitly reward the 19 commingling of unrecoverable lobbying expenses with expenses that may otherwise be 97 The Who We Are, NATIONAL HYDROPOWER ASSOCIATION, http://www hydro.org/about-nha/who-we-are/ (last visited May 24, 2017). 98 NATIONAL HYDROPOWER ASSOCIATION, 2015 ANNUAL REPORT, available at http://anf5l2g5jkf16p6te3ljwwpk.wpengine.netdna-cdn.com/wp-content/uploads/2016/08/NHA-2015-AnnualReport.pdf. 99 See OAG Information Request 152, Schedule SL-14. 100 In the Matter of the Application of CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy Minnesota Gas for Authority to Increase Natural Gas Rates in Minnesota, Docket No. G-008/GR-15-424, FINDINGS OF FACT, CONCLUSIONS OF LAW, AND ORDER at 27 (June 3, 2016). 58 1 justified for recovery. The burden of justifying this expense rests on the Company, and 2 doubt must be resolved in the ratepayers’ favor.” 3 Q. 4 5 Besides the corporate membership dues above, are there individual membership dues that should be disallowed from the 2017 Test Year? A. Yes. The Company has included the cost of membership to the Nebraska State Bar 6 Association 101 and for a Wisconsin CPA renewal. 102 A $224 adjustment should be made 7 to decrease the Test Year membership dues for these two items. 8 Q. Why should this membership be disallowed? 9 A. These membership are for the benefit of the employees to practice in other states outside 10 of the Company’s service territory. Minnesota ratepayers should not have to pay for this 11 membership as it is not necessary for the provision of utility service. 12 Q. What is your recommendation? 13 A. I request that the Company provide the total amount of organizational dues included in 14 the 2017 Test Year, itemizing each membership under corporate dues and individual 15 memberships. Additionally, for future rate cases, I recommend the Commission order the 16 Company to report all association activity using the NARUC audit categories for the cost 17 of membership dues that the Company is requesting recovery for. Providing this detailed 18 level of information on the type of work an association is performing on behalf of the 19 utility would allow for a better analysis of whether that work is related to lobbying 20 activities or other activities that benefit ratepayers. Since this information is not provided 21 for the annual membership dues to the organizations I discussed above, I recommend the 22 disallowance of those entire annual membership dues. Additionally, the dues totaling 101 102 See OAG Information Request 107, Schedule SL-16. MP Exhibit_(MAP) Direct Schedule G-3. 59 1 $224 associated with practicing in other states should be removed from the Test Year. 2 The amount of membership dues to be disallowed will be determined once the Company 3 clarifies the amount of membership dues in the Test Year. 4 XII. EMPLOYEE GIFTS 5 6 Q. Does the Company include employee gifts in the 2017 Test Year? 7 A. Yes. The Company has requested recovery of employee gifts as shown in MP 8 Exhibit_(NRJ) Direct Schedule 3 of $25,823 for service awards, $20,110 for retirement 9 awards, and $2,887 for memorials for a total of $48,820. 10 Q. 11 12 Are there any discrepancies between MP Exhibit_(NRJ) Direct Schedule 3 and other information provided by the Company for employee gifts? A. Yes, there are discrepancies for various employee gift categories that the Company 13 should clarify and provide a reconciliation to explain the differences. Specifically, the 14 actual costs incurred for each gift category and shown for MP Exhibit_(NRJ) Direct 15 Schedule 3 is different from the actual costs shown in the Company’s request to an OAG 16 Information Request, 103 and the Company’s response to a Commission Information 17 Request. 104 It is unclear if the actual gift costs presented on MP Exhibit_(NRJ) Direct 18 Schedule 3 reflect all costs since the actual gift costs provided in response to OAG 19 Information Request are greater for each year from 2012 to 2016. The Company should 20 explain why the gift categories provided in the OAG and Commission Information 21 Requests do not appear to be included in MP Exhibit_(NRJ) Direct Schedule 3 and 103 104 See OAG Information Request 118, Schedule SL-18. See MPUC Information Request 3, Schedule SL-19. 60 1 provide the correct actual cost amount. Additionally, the Company needs to provide the 2 2017 Test Year amount for all categories that it has used in its different responses. 3 Q. 4 5 6 What are the gift categories and amounts shown in the Company’s responses to the Information Requests? A. Below is a table summarizing the actual costs for each gift category from 2012 to 2016 that was provided in the OAG Information Request 118. TABLE 4 Actual Employee Gift Costs, per OAG IR 118 2012 Retirement/Service Award Gift Cards 7 2013 2014 2015 2016 $ 39,771 $ 79,630 $ 84,479 $ 43,805 Spot Bonus - Gift Card $ 53,000 $ 127,786 $ 78,115 $ 45,210 $ 78,217 Total $ 53,000 $ 167,557 $ 157,745 $ 129,689 $ 122,022 8 Below is a table summarizing the actual costs for each gift category for the 2017 Test 9 Year that was provided in the Commission Information Request 3. TABLE 5 Employee Gift Costs, per MPUC IR 3 2017 Test Year Service Awards $ 8,710 Retirement Awards $ 6,880 Safety Awards $ 4,318 Total $ 19,908 10 11 The categories and actual costs from these two Information Requests are not comparable 12 to the actual cost information and categories shown in MP Exhibit_(NRJ) Direct 13 Schedule 3 summarized in Table 6 below. TABLE 6 Employee Gift Costs, per Direct Schedule 3 2012 Actual 14 Service Awards Retirement Awards Memorials Total N/A 2013 Actual $ 38,141 $ 11,194 $ 2,964 $ 52,299 61 2014 Actual $ 39,584 $ 20,478 $ 2,214 $ 62,276 2015 Actual $ 44,755 $ 22,781 $ 2,008 $ 69,544 2016 Proj $ 33,691 $ 20,378 $ 2,925 $ 56,994 2017 Test Year $ 25,823 $ 20,110 $ 2,887 $ 48,820 1 Q. 2 3 What was the Commission’s order regarding employee gifts from the Company’s last rate case? A. The Commission agreed with the Administrative Law Judge in the Company’s last 4 general rate case that “that the RUD-OAG had identified specific expenditures—for 5 example, restaurant and catered meals, gift cards, floral arrangements, travel for 6 employees’ family members – that clearly should not be charged to ratepayers.” 105 The 7 Commission ordered the disallowance of the entire amount of employee recognition 8 expenses, including gift cards, but allowed recovery of expenses related to employee 9 safety incentives. 10 Q. Which Minnesota statutes did the Commission cite in its decision? 11 A. There were three statutes used to determine the disallowance of this expense, the first 12 being Minnesota Statutes section 216B.03, 106 Minnesota Statutes section 216B.16, 13 subdivision 4, 107 and Minnesota Statutes section 216B.16, subd. 4, that the utility has the 14 burden of proof to prove the reasonableness of all Test Year expenses with any doubt as 15 to its reasonableness being resolved in favor of the consumer, and that any travel, 16 entertainment, or related employee expenses may only be allowed as a Test Year expense 17 if it is necessary for the provision of utility service. 18 Q. Does the Company state that employee gifts are permitted for recovery? 19 A. Yes. The Company states “the statute permits recovery of reasonable gift expenses” and 20 that “concern that such expenses must support the provision of utility service, limited 105 In the Matter of the Application of Minnesota Power for Authority to Increase Rates for Electric Utility Service in Minnesota, Docket No. E-015/GR-09-1151, FINDINGS OF FACT, CONCLUSIONS OF LAW, AND ORDER at 32-33 (Nov. 2, 2010). 106 Id. 107 Id. 62 1 years-of-service and retirement awards serve customers and the efficient provision of 2 utility service by supporting employee retention and recognizing longevity of employee 3 service.” 108 4 Q. How do you respond to this? 5 A. While the Company may state that these employee gifts are determined using established 6 internal Human Resources procedures and are considered a non-discretionary expense, 7 and while the Company may claim its service awards and retirement awards are required 8 for employee retention for the provision of utility service, it is evident from information 9 the Company has provided that the spending level for employee gifts has significantly 10 fluctuated from year to year, 109 and that the Company claims that its voluntary 11 terminations have increased over the 2010 to 2015 time period. 110 The evidence is 12 inconsistent with the Company’s claims and should not be used to justify expenses that 13 have been previously found by the Commission to be unnecessary for the provision of 14 utility service. 15 Q. What is your recommendation? 16 A. I recommend that the entire amount of employee gifts, including all gift cards, be 17 removed from the 2017 Test Year. I request that the Company reconcile the differences 18 between the various amounts it has provided in its Information Request responses, 19 provide the correct actual cost amount from 2012 through 2016 for all categories that it 20 has used in its responses, and provide the 2017 Test Year amount for these same 21 categories. 108 See MPUC Information Request 3, Schedule SL-19. See supra Table 4 at 59. 110 Johnson Direct at 7. 109 63 1 XIII. TRAVEL, ENTERTAINMENT, AND EMPLOYEE EXPENSES 2 3 Q. 4 5 Is the Company requesting to recover expenses for travel, entertainment and employee expenses (“T&E”)? A. Yes. The Company has a 2017 T&E budget of approximately $4,907,032 to cover travel 6 and Board compensation, in addition to $1,525,233 for membership dues and gifts for 7 recovery in this case. 111 The Company has made a downward adjustment of $1,523,277 8 for travel and Board compensation, in addition to a downward adjustment of $97,014 to 9 decrease the total amount of T&E expenses in the 2017 Test Year. The table below 10 provides a summary of the request. TABLE 7 Travel, Entertainment, and Employee Expenses 2017 Budget 2017 Adjustment (per DOC IR 115) (per OAG IR 315) Travel and Lodging $ 1,941,497 $ (495,679) Food and Beverage $ 677,413 $ (232,881) Board Expenses and Compensation $ 891,791 $ (60,341) Expenses of Ten Highest Paid Employees $ 265,161 $ (31,984) Recreation and Entertainment $ (99) $ Corporate Aircraft $ 385,851 $ (385,851) Registration/Fees/Parking/Other $ 745,418 $ (79,347) Lobbying $ $ (237,194) Subtotal, excluding Dues and Gifts $ 4,907,032 $ (1,523,277) Dues $ 1,422,726 $ (17,514) Gifts $ 102,507 $ (79,500) Total $ 6,432,265 $ (1,620,291) * Investor Relations added to Travel and Lodging category for 2017 Adjustment column 11 111 See Department Information Request 115, Schedule SL-20. 64 2017 Test Year $ $ $ $ $ $ $ $ $ $ $ $ Net of Adj 1,445,818 444,532 831,450 233,177 (99) 666,071 (237,194) 3,383,755 1,405,212 23,007 4,811,974 1 Q. 2 3 Are there statutory and other requirements the Company is required to follow to support its recovery of T&E expenses? A. Yes. The Legislature passed a law that is codified in Minnesota Statutes section 216B.16, 4 subdivision 17 which was added to the rate case filing requirements in 2010. This 5 requirement broadly expanded the filing requirements to support recovery of T&E 6 expenses. These are the same requirements that the Commission ordered the Company to 7 follow in its last general rate case due to “substantial doubt that it is reasonable, prudent, 8 and necessary for the provision of utility service for Minnesota Power to spend $1,841,000 9 on an annual basis for Board and employee expenses.” 112 10 Q. What are the more significant aspects of the statutory T&E filing requirements? 11 A. The general requirement for allowing any cost recovery by a utility is that costs must be 12 reasonable and necessary for the provision of utility service. Minnesota Statutes section 13 216B.16, subdivision 17 specifically prohibits the Commission from allowing recovery of 14 any T&E expenses that are unreasonable and unnecessary. The statute includes the 15 following filing requirements: • 16 separate itemization of nine specific categories of expenses including travel and 17 lodging, food and beverages, recreational and entertainment, gift, and lobbying 18 expenses; • 19 the itemization must identify the expenses in the most recently completed fiscal 20 year and include the date of the expense, the vendor name, and the business 21 purpose of the expense; 112 In the Matter of the Application of Minnesota Power for Authority to Increase Rates for Electric Service in Minnesota, Docket No. E-015/GR-09-1151, FINDINGS OF FACT, CONCLUSIONS, AND ORDER, at 32 (Nov. 2, 2010). 65 • 1 for travel and lodging and food and beverage expenses the total amount for each 2 category must be disclosed and separate itemization is required for these expenses 3 for or on behalf of any employee at the level of vice-president or above and all 4 board members; and • 5 6 the data is public data with limited exceptions regarding salaries for certain officers and employees. 7 Q. How has the Company reported its T&E expenses? 8 A. The Company has conducted a review of its actual T&E expenses from 2015, in order to 9 create schedules itemizing these expenses to comply with the statute. 113 The Company 10 has created “cost types” in its accounting system and a Chart of Accounts to track T&E 11 expenditures by the expense categories required by the statute. 114 The Company has also 12 reviewed its actual 2015 T&E expenditures to remove transactions that the Company 13 deemed as having a vague business purposes, or were not necessary for the provision of 14 utility service. 115 15 Q. Which expense categories are you including in your T&E analysis and discussion? 16 A. I discuss my concerns and recommendations for all the expense categories defined in 17 Minnesota Statutes section 216B.16, subdivision 17, except for membership dues and 18 gifts, as the budget and transactions for these two cost categories are discussed separately 19 above in Sections XI and XII. 113 Morris Direct at 41. See OAG Information Request 312, Schedule SL-21. 115 Morris Direct at 45–47. 114 66 1 Q. 2 3 What are your concerns regarding the Company’s T&E budget for the 2017 Test Year? A. I have five concerns regarding the methodology the Company used to calculate the T&E 4 amount for the Test Year. First, the Company’s 2017 budget for T&E, which serves as 5 the basis for the 2017 Test Year amount, is significantly greater than what the Company 6 has spent in previous years. Second, the Company does not properly apply the T&E 7 adjustment, which it has identified as expenditures that should not be recovered from 8 ratepayers, to the 2017 budget. Third, there are a few expense transactions that are not 9 required for the provision of utility service and do not benefit Minnesota ratepayers and 10 should not be recovered. These costs should be included in the T&E adjustment to 11 decrease the 2017 Test Year amount. 12 Minnesota Power as the credit card merchant, and it is not clear if the Company is 13 charging ratepayers for expenses classified as “employee expense” that may also have 14 already been included in the Test Year as “operating and maintenance expenses.” 15 Finally, while the Company has provided sufficient detail for most of its T&E expenses, 16 there are a few expense transactions do not include all of the information that is required 17 by law which I recommend the Company provide this information in the current rate 18 case, as well as for any future rate cases. Fourth, there are some transactions listing 19 Q. What is the Company’s 2017 Budget for T&E expenses? 20 A. The Company has indicated its 2017 budget for T&E expenses, excluding membership dues and gifts, to be $4,907,032. 116 This budget is significantly higher than the actual 21 116 See Department Information Request 115, Schedule SL-20. 67 1 expenditures the Company incurred for T&E expenses in the previous two years, as 2 shown in the table below. TABLE 8 Travel, Entertainment, and Employee Expenses 2015 Actual (per DOC IR 115) Travel and Lodging $ 1,606,403 Food and Beverage $ 542,107 Board Expenses and Compensation $ 1,040,184 Expenses of Ten Highest Paid Employees $ 192,228 Recreation and Entertainment $ (183) Corporate Aircraft $ 425,908 Registration/Fees/Parking/Other $ 418,280 Lobbying $ Total, excluding Dues and Gifts $ 4,224,927 % Increase over Previous Year 3 4 Q. 5 6 2016 Actual (per OAG IR 131) $ 1,651,194 $ 618,953 $ 1,070,118 $ 127,434 $ (242) $ 295,268 $ 459,632 $ $ 4,222,357 2017 Budget (per DOC IR 115) $ 1,941,497 $ 677,413 $ 891,791 $ 265,161 $ (99) $ 385,851 $ 745,418 $ $ 4,907,032 16.2% Is there a method that can be used to determine the reasonableness of the 2017 budget for T&E expenses? A. Yes. Calculating a historical average of the actual expenditures for certain types of 7 operating and maintenance expenses that do not reflect large capital expenditures would 8 be appropriate for determining whether the 2017 budget is consistent with previous years. 9 Q. 10 11 Do you recommend calculating a historical average to help determine whether the T&E budget is reasonable? A. Yes. I calculated the historical average for T&E expenses for the three-year period from 12 2014 to 2016 to help determine the reasonableness of the 2017 budget. The most recent 13 three-year period minimizes potential outlier data and captures the most recent spending 14 for T&E expenses (2016), including one year in which the Company reduced employee 15 expenses as a cost-saving measure (2015) as well as one year in which the Company 68 1 significantly increased employee expense spending (2014). 117 The table below shows the 2 actual T&E expenditures for this time period and the three-year average that should be 3 the amount in the 2017 Test Year for T&E expenditures, excluding dues and gifts. TABLE 9 Travel, Entertainment, and Employee Expenses 2014 Actual (per DOC IR 115) Travel and Lodging $ 2,178,372 Food and Beverage $ 679,495 Board Expenses and Compensation $ 1,077,193 Expenses of Ten Highest Paid Employees $ 286,466 Recreation and Entertainment $ (236) Corporate Aircraft $ 506,306 Registration/Fees/Parking/Other $ 715,577 Lobbying $ Total, excluding Dues and Gifts $ 5,443,173 Three-Year Average 4 5 Q. 6 7 2015 Actual (per DOC IR 115) $ 1,606,403 $ 542,107 $ 1,040,184 $ 192,228 $ (183) $ 425,908 $ 418,280 $ $ 4,224,927 2016 Actual (per OAG IR 131) $ 1,651,194 $ 618,953 $ 1,070,118 $ 127,434 $ (242) $ 295,268 $ 459,632 $ $ 4,222,357 $ 4,630,152 Are there other factors that must be considered for calculating the three-year average for the Test Year? A. Yes. I previously mentioned my concern regarding the Company improperly applying its 8 T&E adjustment to the 2017 budget. 9 adjustment of $1,523,277 to reduce the 2017 T&E budget. 118 This adjustment reflects the 10 T&E expenses from 2015 that the Company deems is not necessary for the provision of 11 utility service, and is representative of those types of expenses that should be excluded in 12 the Test Year and should not be recoverable from ratepayers. This adjustment proposed 13 by the Company should be factored into the calculation of the historical average, so that 14 an accurate level of expenditures that are appropriate for recovery is reflected in the 2017 15 Test Year. 117 118 The Company has proposed a downward See OAG Information Request 315, Schedule SL-22. $1,620,291 total adjustment less $97,014 adjustment for Dues and Gifts 69 1 Q. How does the Company currently treat this adjustment amount? 2 A. The Company reduces its 2017 T&E budget by the adjustment amount in order to 3 4 calculate the 2017 Test Year amount. Q. 5 6 Does the Company have more than one adjustment amount based on 2015 actual T&E transactions? A. Yes. The Company has identified that there are 2015 T&E transactions totaling 7 $1,767,936 that are unrecoverable. 119 In applying this adjustment to the 2017 T&E 8 budget, however, the Company substitutes the identified 2015 amounts for the “Board 9 Expenses,” “Corporate Aircraft,” and “Investor Relations” cost categories with the 2017 10 budget for these categories. 11 $1,767,936 that are inappropriate for recovery, it is only adjusting the 2017 T&E budget 12 by $1,620,291. 13 Q. 14 15 Therefore, although it identified transactions totaling Is the Company’s proposed application of the adjustment to the Test Year and the substitute of identified unrecoverable transactions reasonable? A. No. The adjustment should be applied to the year in which the transactions were 16 incurred, and the identified actual 2015 transactions should not be randomly substituted 17 with a budget amount for that cost category. As I explain below, the methodology for 18 calculating the 2017 Test Year amount should be based on a three-year average. 19 Q. 20 21 Are you recommending that the Company incorporate this adjustment amount a different way? A. 22 Yes. Rather than reducing the 2017 T&E budget by the amount of individual expenses from a previous year (2015) that it believes are not recoverable, the Company should 119 See OAG Information Request 315, Schedule SL-22. 70 1 reduce the previous year’s total amount of actual T&E expenses by the amount of 2 individual expenses that it has identified as not being recoverable. The result would be 3 the correct amount of T&E expenditures that should be recovered from ratepayers. This 4 adjusted actual level of T&E expenses for the previous year would then be used to 5 calculate the three-year historical average. 6 Q. Would this historical average serve as the 2017 Test Year budget? 7 A. Yes. Rather than using the Company’s current methodology of reducing its 2017 T&E 8 budget by the transactions that it deems as not recoverable from a previous fiscal year, it 9 is more reasonable to use a historical average that normalizes the level of employee 10 expenses. Incorporating the adjustment in the calculation of the historical average would 11 more accurately reflect the T&E amount that should be recovered from ratepayers in the 12 Test Year. 13 Q. Does this new method impact the way the Company prepares for a rate case? 14 A. No, it does not impact the Company’s preparation for rate cases. The Company would 15 still provide T&E schedules for the most recently completed fiscal year to comply with 16 the statute and the Company would use the same method it currently does to identify 17 unrecoverable transactions, but the way the Company applies the adjustment to the Test 18 Year would be different. Instead of just taking the adjustment off the top, the Company 19 would incorporate the adjustment into the calculation of a historical average. 71 1 Q. 2 3 Has the Company identified T&E transactions that are unrecoverable for the years 2014 and 2016? A. No. The Company has only created T&E schedules for transactions in 2015 as a filing 4 requirement. The Company has not created T&E schedules for 2014 or 2016. 5 Q. How should the adjustment amount be determined for 2014 and 2016? 6 A. Since the Company does not have transactional level data for these years, I used the ratio 7 of identified expenses from 2015 to calculate a representative amount that should be 8 excluded from the actual expenses in 2014 and 2016. 9 Q. Is this approach reasonable? 10 A. Yes. This approach is reasonable because the types of T&E expenses have remained 11 consistent during this time period. In addition, there have been no significant changes to 12 the Company’s employee expense policies, or the Company’s T&E allocations that 13 would impact the level of employee expenses. 14 Q. Provide the calculation of the 2014 and 2016 adjustment amounts. 15 A. The identified T&E expenses, excluding dues and gifts from 2015, is $1,670,922. 120 It is 16 unclear, however, whether the Company has included the T&E expenses for the 17 “Lobbying” category in the 2015 actual expenses provided in its response to the 18 Department’s Information Request 115. Therefore, in my current calculation of the 2015 19 ratio, I removed the adjustment of $237,194 for the “Lobbying” category from the 20 adjustment amount of $1,670,922. 21 approximately 34% of the 2015 actual T&E expenses of $4,224,927, excluding dues, 22 gifts, and lobbying. Applying this ratio to the actual T&E expenses of $5,443,173 in 120 The ratio of the adjustment of $1,433,728 is See OAG Information Request 315, Adjustments to 2015 Actuals, Schedule SL-22. 72 1 2014 results in an adjustment of $1,850,679 for 2014. 121 Applying this ratio to the actual 2 T&E expenses of $4,222,357 in 2016 results in an adjustment of $1,435,601 for 2016. 122 3 Q. 4 5 What is the three-year average for T&E expenses using these adjusted actual amounts? A. 6 The three-year average is $3,056,816, which is $509,331 less than the Company’s current request of $3,566,147 as shown in the table below. TABLE 10 Travel, Entertainment, and Employee Expenses 2014 Actual 2015 Actual 2016 Actual 2017 Test Year Net of Adj Travel and Lodging Food and Beverage Board Expenses and Compensation Expenses of Ten Highest Paid Employees Recreation and Entertainment Corporate Aircraft Registration/Fees/Parking/Other Lobbying (per DOC IR 115) $ 2,178,372 $ 679,495 $ 1,077,193 $ 286,466 $ (236) $ 506,306 $ 715,577 $ - (per DOC IR 115) $ 1,606,403 $ 542,107 $ 1,040,184 $ 192,228 $ (183) $ 425,908 $ 418,280 $ - (per OAG IR 131) $ 1,651,194 $ 618,953 $ 1,070,118 $ 127,434 $ (242) $ 295,268 $ 459,632 $ - (per OAG IR 315) $ 1,367,771 $ 423,544 $ 891,791 $ 221,659 $ $ $ 661,382 $ (237,194) Total, excluding Dues and Gifts $ 5,443,173 $ 4,224,927 $ 4,222,357 $ Adjustment, excluding Lobbying $ (1,850,679) $ (1,433,728) $ (1,435,601) $ 237,194 Adjusted Total $ 3,592,494 $ 2,791,199 $ 2,786,756 $ 3,566,147 3,328,953 Three-Year Average $ 3,056,816 * Investor Relations added to Travel and Lodging category for 2017 Test Year Net of Adjustment column 7 8 Q. Is your calculation based on accurate T&E expense amounts? 9 A. The Company has provided a variety of T&E schedules and has provided T&E budget, 10 actual, and adjustment amounts for the various cost categories for the different periods 11 between 2011 and 2017 in its responses to Information Requests. However, it appears 12 that amounts provided in one report may be different from amounts provided in another 13 report for the same year. 123 While I tried to cross reference the amounts between 121 ($5,443,173) * 34% ($4,222,357) * 34% 123 2017 Test Year and 2015 Actual amounts in Department Information Request 115 different from 2017 Test Year and 2015 Actual amounts in OAG Information Request 315. 122 73 1 different Company provided reports and schedules, I was not able to reconcile the 2 differences. I assume that this is because the budget, actual, and adjustment amounts 3 provided in the various reports may not be inclusive of all of the T&E cost categories. 4 Therefore, I request that the Company explain any variances between the T&E budget, 5 actual, and adjustment amounts shown in its responses to the Department’s Information 6 Request 115 and OAG Information Request 131 and 315, and provide the T&E budget, 7 actual, and adjustment amounts for all cost categories shown below for each year from 8 2014 to 2017. 9 • Travel and Lodging – Employee 10 • Travel and Lodging – VP/Ten Highest Paid 11 • Food and Beverage – Employee 12 • Food and Beverage – VP/Ten Highest Paid 13 • Board of Director Expenses and Compensation 14 • Expenses of VP/Ten Highest Paid 15 • Recreation and Entertainment 16 • Dues and Expenses 17 • Gifts 18 • Corporate Aircraft 19 • Lobbying 20 • Registration/Fees/Parking/Other 21 • Investor Relations 74 1 Q. 2 3 Will the three-year average amount change as a result of this information that will be provided by the Company? A. Pending the Company’s clarification of the budget, actual, and adjustment variances 4 between the reports, the three-year average amount I calculated above would change if 5 the T&E budget, actual, and adjustment amounts are different than the ones I relied on. 6 Q. 7 8 What are your concerns about additional T&E expenses from 2015 that should be included in the T&E adjustment identified by the Company? A. In reviewing the actual T&E transactions from 2015, I found a few transactions that 9 pertain to costs incurred in other states for the benefit of employees to practice in other 10 states. Since these costs are not required for the provision of utility service and do not 11 benefit Minnesota ratepayers, they should be disallowed. These transactions total $632 12 and are listed in Schedule SL-23 under the header “Transactions from Schedule I – 5B 13 All Other – VP - TT.” One transaction included in this listing is for the Nebraska State 14 Bar Association and it is unclear if this transaction is the same one that has been included 15 in the “membership dues” category in Section XI above. 16 Q. 17 18 What are your concerns about the transactions that list Minnesota Power as the credit card merchant? A. There are transactions listing Minnesota Power as the vendor and it is unclear why the 19 Company is listed as the vendor. I would be concerned if the Company was double 20 counting these expenses by recovering these costs under the “employee expense” cost 21 category in the Test Year, in addition to recovering these costs as normal operating and 22 maintenance expenses under a different expense category in the Test Year. 75 These 1 transactions total $6,301 and are listed in Schedule SL-23 under the header “Transactions 2 that List Minnesota Power as Pcard Merchant.” 3 Q. What is your recommendation for these transactions? 4 A. I request that the Company clarify why it is listed as the credit card merchant and whether 5 these costs have also been included under another operating and maintenance expense 6 category in the Test Year. The Company should confirm that it has not double counted 7 this expense for recovery in the Test Year. If the costs are double counted, then a 8 correcting adjustment should be made by increasing the 2015 T&E adjustment amount to 9 decrease the 2017 Test Year amount. 10 Q. What are the transactions that have insufficient details? 11 A. I found that there were some transactions that did not include all of the information 12 required by law, specifically the absence of the vendor name. These transactions total 13 $27,520 and are listed in the attached Schedule SL-23 under the header “Transactions 14 Without Vendor Name.” These transactions do not have a vendor name, other than the 15 name of the Minnesota Power employee. 16 subdivision 17 specifically requires that utilities provide the vendor name of each 17 expense they seek to recover from ratepayers. 18 merchant name for these transactions, but were told that these were Minnesota Power 19 employee reimbursements for expenses they already incurred and because the Company 20 did not pay the businesses directly, the Company would not be able to provide the 21 business names. 124 124 See OAG Information Request 313, Schedule SL-24. 76 Minnesota Statutes section 216B.16, The OAG requested the vendor or 1 Q. What other information should be provided for these transactions? 2 A. For most of the T&E transactions, the Company was able to provide either the Pcard 3 Merchant, Hotel Accommodation, Restaurant Name, Vendor Name, or identify the 4 transactions that were for mileage reimbursements. 125 Since the Company would have 5 required the employee requesting the reimbursement to substantiate the request with 6 original receipts and other documentation, the Company should easily be able to provide 7 the vendor name. Additionally, the Company should provide the subaccount, subaccount 8 title, cost type, and cost type title that each transaction is coded to. This subaccount, 9 subaccount title, cost type, and cost type title appears to be information requirements that 10 an employee must enter for employee expense reports and credit card reconciliations 11 through the Company’s Oracle iExpense system. 126 12 Q. What is your recommendation for these transactions? 13 A. I request that the Company provide the vendor names for these transactions. It appears 14 the Company was able to determine this information for all the other transactions using 15 either the employee reimbursement requests or the subaccount/cost types the transactions 16 were coded to because the Company provided the hotel name, restaurant name, as well as 17 identifying mileage reimbursement transactions. Further, I request that the Commission 18 order the Company to provide this information in its next rate case to assist in the review 19 of T&E expenses. 20 Q. Are the 2015 transactions in the T&E schedules incorporated into the Test Year? 21 A. The 2015 transactions in the T&E schedules are not directly incorporated into the Test 22 Year. These 2015 T&E expenses are provided at the transactional detail level in order to 125 126 See OAG Information Request 132, Schedule SL-25. MP Exhibit_(SWM) Schedule 10. 77 1 comply with Minnesota Statutes § 216B.16, subd. 17. However, the Company reviewed 2 all actual 2015 T&E expenses and identified $1,767,936 of transactions that are 3 inappropriate for recovery, and reduced the 2017 Test Year amount by that amount. 4 Therefore, any additional transactions identified in the 2015 T&E schedules as being not 5 recoverable from ratepayers would increase the Company’s adjustment and further 6 decrease the 2017 Test Year amount. 7 Q. 8 9 How will any 2015 actual transactions that you recommend disallowance for be incorporated into the 2017 Test Year? A. The transactions that I recommend disallowance for should be added to the $1,767,936 10 adjustment identified by the Company, to further reduce the 2015 actual employee 11 expenses that are recoverable, which is then used to calculate of the three-year average. 12 Q. 13 14 How would this methodology lead to a more reasonable level of employee expenses that ratepayers should pay for? A. For ratemaking purposes, reducing the actual employee expenses to account for 15 transactions that are not recoverable is the most accurate way to determine the 2017 Test 16 Year amount. This adjusted actual level of employee expenses can be used to calculate 17 the three-year average for the 2017 Test Year, and would reflect a normalized level of 18 T&E expense. 19 Q. What is your recommendation? 20 A. I recommend that $632 associated with expenses that are not required for the provision of 21 utility service be disallowed for recovery at this time. Since I have requested additional 22 information from the Company regarding the other transactions, I will include my 23 recommendation for those transactions in rebuttal testimony. The $632 amount will 78 1 increase the 2015 adjustment to $1,434,360 and be used to calculate the three-year 2 average of $ 3,056,606 which will serve as the T&E amount in the 2017 Test Year. The 3 table below shows the new calculation. TABLE 11 Travel, Entertainment, and Employee Expenses after OAG Adjustment 2014 Actual 2015 Actual 2016 Actual (per DOC IR 115) (per DOC IR 115) (per OAG IR 131) Travel and Lodging $ 2,178,372 $ 1,606,403 $ 1,651,194 Food and Beverage $ 679,495 $ 542,107 $ 618,953 Board Expenses and Compensation $ 1,077,193 $ 1,040,184 $ 1,070,118 Expenses of Ten Highest Paid Employees $ 286,466 $ 192,228 $ 127,434 Recreation and Entertainment $ (236) $ (183) $ (242) Corporate Aircraft $ 506,306 $ 425,908 $ 295,268 Registration/Fees/Parking/Other $ 715,577 $ 418,280 $ 459,632 Lobbying $ $ $ Total, excluding Dues and Gifts $ 5,443,173 $ 4,224,927 $ 4,222,357 Adjustment, excluding Lobbying $ (1,850,679) $ (1,433,728) $ (1,435,601) Adjustment, per OAG $ (632) Adjusted Total $ 3,592,494 $ 2,790,567 $ 2,786,756 Three-Year Average $ 3,056,606 * Investor Relations added to Travel and Lodging category for 2017 Test Year Net of Adjustment column 4 2017 Test Year Net of Adj (per OAG IR 315) $ 1,367,771 $ 423,544 $ 891,791 $ 221,659 $ $ $ 661,382 $ (237,194) $ 3,328,953 $ 237,194 $ 3,566,147 5 XIV. SUMMARY AND CONCLUSION 6 7 Q. Can you summarize your recommendations? 8 A. Yes. I recommend the following specific reductions to the revenue requirement: 9 • $1,604,396 for transmission capital projects; 10 • $732,272 for storm damage amortization expense; 11 • $275,745 for the Sappi/Cloquet amortization expense; 12 • $350,000 for credit card processing fees; 13 • $99,068 for charitable contributions. 14 The total impact of these adjustments is a reduction to the revenue requirement of 15 $3,061,481. 16 I also recommend reductions to the revenue requirement related to transmission 17 capital impacts on 2017 projects, generation capital projects, membership dues, employee 79 1 gifts, and travel and entertainment expenses, but do not have the information to calculate 2 the impact of these adjustments at this time. I will provide an update in my rebuttal 3 testimony. 4 In addition, I recommend that the Commission reject MP’s proposal related to 5 BEC 3 and 4, which has the impact of increasing the revenue requirement by 6 $15,936,118. At this time, I note that Minnesota Statutes section 216B.16, subdivision 5 7 provides that “[i]n no event shall the rates [set in a rate case] exceed the level of rates 8 requested by the public utility.” While I am not an attorney and I understand that the 9 OAG may provide further analysis on this section in its legal briefing, the plain meaning 10 of these words indicates that the final rates set in this proceeding, even when adjusted to 11 account for decisions related to the BEC units, cannot exceed the amount of revenue 12 requested by MP in its petition. 13 Q. Does this conclude your testimony? 14 A. Yes. 80