STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

Transcription

1 STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of DTE GAS COMPANY for authority to increase its rates, amend its rate schedules and rules governing the distribution and supply of natural gas, and for miscellaneous accounting authority. / Case No. U MICHIGAN PUBLIC SERVICE COMMISSION STAFF S INITIAL BRIEF DATED: July 27, 2016 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Amit T. Singh (P75492) Meredith R. Beidler (P78256) Graham Filler (P74995) Assistant Attorney General Public Service Division 7109 W. Saginaw Hwy., 3rd Floor Lansing, MI Telephone: (517)

2 Table of Contents Page No. I. Introduction... 1 II. Summary of Issues... 2 III. Staff recommends a total revenue deficiency of $120,822, A. Staff recommends a Rate Base of $3,724,426, Staff recommends a Utility Plant of $4,833,916, a. Contingencies Capital Expenditure Adjustment... 4 Gas Storage Operations, Integrity, and Planning... 8 b. Revenue Protection Capital Expenditure Adjustment... 9 c. AMI and AMR Programs i. Smart Grid Reporting Metrics d. Cut and Cap Fees e. Infrastructure Recovery Mechanism Program i. Pipeline Integrity ii. Meter Move Out iii. Main Renewal Program Staff recommends an Accumulated Depreciation Reserve of $2,166,437,000 for the projected test year Gas Stored Underground Non Current a. Reconversion of Base Gas b. Average Cost of Staff recommends a Working Capital requirement of $1,021,680,000 for the projected test year i

3 a. Gas in Underground Storage Current and GCC Deferred Asset b. Intercompany Notes Receivable c. Regulatory Asset Demolition Fees B. Capital Structure and Rate of Return Capital Structure and Overall Rate of Return Capital Structure and Ratemaking Component Development a. Staff recommends a common equity balance of $1,438,768, b. Staff recommends a long-term debt balance of $1,329,379,077and a cost rate of 4.98% c. Staff recommends a short-term debt balance of $137,815,000 and a cost rate of 1.54% d. Staff recommends a net deferred income tax balance of $800,814, e. Capital Structure Summary Return on common equity development a. Overall Analysis b. Staff s Discounted Cash Flow Model (DCF) yielded an ROE estimate of 8.90% c. Staff s Capital Asset Pricing Model (CAPM) produced an ROE estimate of 8.93% d. Staff s Risk Premium Method yielded ROE estimates between 8.09% % e. Staff s review of other state commission ROE decisions produced an average ROE estimate of 9.74% f. Summary of Results and Staff s Recommendation ii

4 g. DTE Gas s ROE rebuttal testimony lacks merit Staff s DCF analysis is straightforward and appropriate Staff s market risk premium in its CAPM analysis is proper and reasonable Staff s negative assessment of the Company s empirical CAPM (ECAPM) analysis is accurate Staff stands behind its credit rating assessment in its analysis h. ROE Recommendation C. Staff recommends a Projected Net Operating Income of $139,864, Staff supports a System Average heating Value of 1,045 Btu/cf Staff recommends that the Commission and the ALJ find that the Company s Total Operating Revenues are $797,214, a. Staff Recommends the Commission approve Distribution Revenue of $626,066, Staff recommends a $16,620,000 increase to the Company s Gas Sales projection Staff recommends a $1,836,000 increase to the Company s End-User Transportation projection b. Staff Recommends the ALJ and Commission approve Off-System Transportation and Storage Revenue of $76,579, c. Staff recommends the ALJ and Commission approve Other Operating Revenue of $94,569, i. Staff recommends an $855,000 increase to the Company s Miscellaneous Revenue projection iii

5 ii. iii. iv. Staff recommends a $6,000 increase to the Company s Gas In Kind projection Staff recommends a $1,176,000 increase to the Company s Grantors Trust Income Projection Staff recommends a $237,000 reduction to the Company s Inter-Company Notes Receivable Revenue Staff recommends the Commission Approve Total Expenses of $668,156, a. Staff Recommends the Commission approve Company Use and Lost Gas of $33,353, b. Staff recommends a combined total Operations and Maintenance expense and Gas Uncollectibles expense of $417,427, i. Staff recommends a reduction of $4,930,000 due to updated 2015 test-year and inflation ii. Staff recommends a reduction of $7,745,000 to Incentive Compensation expense iii. Staff recommends an increase of $1,017,000 to Uncollectibles expense iv. Staff recommends an increase of $674,000 to Injuries and Damages expense v. Staff recommends a reduction of $1,809,000 to Accrued Vacation expense vi. Staff recommends a reduction of $1,439,000 to SERP expense vii. Staff recommends a reduction of $1,202,000 to Shared Rent expense c. The Commission should approve Depreciation and Amortization expense of $119,649, d. Staff recommends Property and Other taxes of $65,746, iv

6 e. State and Local Income taxes f. Federal Income axes g. Other Expense Allowance for Funds used During Construction (AFUDC) IV. Cost of Service A. Gas Cost of Service Study B. The Commission should approve allocation of Uncollectible Expenses based on total Cost of Service plus Cost of Gas (COS+COG) V. Rate Design A.. Residential Rate Design The Commission should approve Staff s proposed residential customer charge of $11.25 per month RIA Program and LIA Credit Pilot GS Rate Design School Service Rate S Rate Design Transportation Service Rate Design Maximum monthly IRM charge for transportation customers The Commission should reject the Company s proposed meter reading surcharge VI. Other A. Revenue Decoupling Mechanism RDM revenue caps and reconciliation period start date B. Utility Cybersecurity Reporting C. OPEB Deferral Mechanism D. Bonus Depreciation v

7 VII. Conclusion vi

8 I. Introduction DTE Gas Company (DTE or Company) projects that it will experience a revenue deficiency of $182,927,000 while the Michigan Public Service Commission Staff (Staff) projects a revenue deficiency of $120,822,000. (Appendix A, line 8.) The $62,105,000 variance is primarily attributable to Staff s higher rate base, lower return on equity, operating revenue, and operating expense adjustments. DTE s projected rate base is $3,719,566,000, while Staff s projected rate base is $3,724,426,000. (Appendix A, line 1.) Staff s projected rate base is $4,860,000 higher than the Company s proposal primarily because Staff reduced the Company s plant-in-service by $11,437,000, net utility plant by $13,017,000, and underground gas storage by $4,072,000, and increased depreciation reserve by $1,581,000 and working capital allowance by $21,949,000. (Appendix B, lines 1, 5, 6, 8, and 12.) DTE s prosed return on equity (ROE) is which is 75 basis points higher than Staff s recommended ROE of 10.00% (Appendix D, line 2.) Staff s lower ROE is a product of Staff using several different ROE inputs. DTE projects that its total operating revenue will be $774,799,000, while Staff projects that total operating revenue will be $797,214,000 approximately $22 million more than the Company projects. (Appendix C, column e.) Staff s proposed operating revenues are higher because Staff adjusts the Company s gas sales, enduser transportation, grantor trust income miscellaneous revenue, and intercompany notes receivable revenue. 1

9 DTE projects that its total operating expense will be $671,936,000, while Staff projects that total operating expense will be $668,156,000 approximately $4 million less than the Company projects. (Appendix C, column o.) Staff s proposed operating expenses are lower because Staff made adjustments to company use and lost gas, operation and maintenance expense, uncollectible expense, depreciation and amortization expense, property and other tax expense, state and local income tax expense, and federal income tax expense. Staff recognizes that DTE needs some rate relief to continue supplying its customers with safe and reliable energy. However, Staff intends to argue that the Company can accomplish this important task with far less than a $182.9 million rate increase. II. Summary of Issues According to the Company, the following factors are largely responsible for its $182,927,000 revenue deficiency: i. the revenue requirement associated with increased investments in DTE Gas s infrastructure including increased costs associated with maintaining the integrity of the Company s natural gas pipeline system; ii. iii. iv. increasing customer conservation; decreasing consumption due to gas with increasingly higher system-average heating values; lower projected Midstream revenues resulting from the reduction in transportation value and exchange volume; and v. increasing operating costs. 2

10 The Company has asked the Commission to approve a number of other proposals and requests as well, including: i. A proposed return on common equity of 10.75%; and ii. Continued use of the revenue decoupling mechanism (RDM) approved in Case No. U III. Staff recommends a total revenue deficiency of $120,822,000. Staff calculated that DTE Gas s projected revenue deficiency is $120,822,000. (Appendix A, line 8.) This recommendation is $62,105,000 less than the Company s filed revenue deficiency of $182,927,000. (Id.) The difference is primarily attributable to Staff s higher rate base, lower return on equity, higher operating revenue, and lower operating expense. Based on Staff s thorough review and analysis of the various components of the revenue deficiency, Staff requests the Commission and the ALJ adopt a revenue deficiency of $120,822,000. A. Staff recommends a Rate Base of $3,724,426,000. Staff projects a gas rate base of $3,724,426,000 for the test year ending October 31, (Appendix A, line 1.) This represents an increase of $4,860,000 from the Company s initially filed request of $3,719,566,000. (Id.) This increase is the result of a decrease in plant in service, an increase in accumulated depreciation, a decrease in gas stored underground non-current, and an increase in working capital. (Appendix B, lines 1, 5, 8, 12.) 3

11 1. Staff recommends a Utility Plant of $4,833,916,000. Staff recommends a total utility plant of $4,833,916,000, which represents a decrease of $11,437,000 from the Company s request of $4,845,352,000. (Appendix B, line 4.) Differences between Company and Staff utility plant recommendations are due to Staff s downward capital expenditure adjustments related to contingencies and revenue protection. Staff witness Cole supports a capital expenditure disallowance of $11,975,000 related to contingencies, which reduces rate base by $9,610,000. Staff witness Creisher supports a capital expenditure disallowance of $2,472,000 related to revenue protection, which reduces rate base by $1,827,000. Contingencies Capital Expenditure Adjustment The Commission should not approve the Company s contingency expenditures. The nature of the forward-looking test year makes recovery of these contingency funds inappropriate. If the Commission were to allow recovery of these funds, the Company has the potential to earn return of and return on expenditures that are uncertain to incur in full if at all. Because contingency funds are by definition contingent on the unexpected, Staff feels it is inappropriate for the Company to recover these funds from ratepayers until the Company actually makes the investment. At that point, the Commission will have an opportunity to determine if the expenditures were reasonable and prudent. The Company s projected contingencies capital expenditures in this case total $11,957,000. This includes $6,803,000 for the bridge period of January October 4

12 2016, and $5,154,000 for the projected test year of November 2016 October (2 TR 741, Exhibit A-26, Schedule S1.) The Company requests the recovery of $931.2 million of routine and other capital expenditures from December 31, 2014, the end of the historical test year, through October 2017, the end of the projected test year. (2 TR 678.) The Company seeks to include projected capital expenditures which include projected contingency amounts in rate base for the following: Routine Transmission Plant, Routine Storage Plant, Belle River Compressor, Gordie Howe International Bridge, and the Milford Junction Loop. (2 TR 741, Exhibit A-26, Schedule S1.) Attorney General witness Sebastian Coppola agrees with Staff that the projected contingency costs of $11,957,000 should be excluded from rate base. (3 TR 1031, Exhibit AG-20.) Staff recommends that the Commission disallow the recovery of projected contingency expenditures in this case. Staff believes it is inappropriate for the Company to recover a return of and a return on projected contingency expenditures for the following reasons: (1) contingency expenditures may not be incurred at all; (2) if some expenditures are ultimately incurred, the final amount could be far less than what the Company projected; and (3) allowing contingency expenditures into rate base may dampen incentives for cost control. (3 TR 1130.) Staff witness Catherine Cole supported Staff s position by testifying: [W]hile the final amount expended is inherently unknown at the beginning of the test year, as is the case with any cost category, the fact that a projection of contingency expenditures is really a range of possible spending, and not a target, creates a much higher degree of uncertainty regarding future expenditures than is found with projected expenditures in other cost categories Id. 5

13 In other words, the possibility exists that the Company may not spend all of its requested contingency funds. If that were to happen, ratepayers would be paying the return of and return on expenditures that never materialized. The Company s position that contingency costs should be recovered is without merit. Company witness Sandberg testified that the contingency costs are a target rather than a range of spending. However, she also stated that contingency is included in the project estimate for the undefined amounts that a contractor identifies only after reviewing the scope of the work and submitting a bid. (2 TR 739, emphasis added.) Staff posits that estimates of undefined amounts lead to a range of possible future spending rather than a target; and it is entirely possible that the undefined items included in the contingency budget may not be necessary. Staff also believes that allowing projecting contingency expenditures into rate base may incentivize the Company to spend those contingency funds without regard to cost control. (3 TR 1130.) It is logical to surmise that if the Company knows it will receive cost recovery for contingency expenditures up to a certain point, there is less incentive to control costs. In fact, Ms. Sandberg testified, the Company has full intention of spending the entire project estimate including contingency, it budgets for the full amount. (2 TR 740.) Ms. Sandburg then argues that [t]he MPSC Staff s position actually would de-incentivize any manager who was expected to construct an asset at capital expenditure levels excluding the contingency as the manager may need to reduce scope or cut other projects. (Id.) Ms. Sandberg s argument fails to recognize that Staff maintains that contingency 6

14 expenditures would be recommended for recovery in a future rate case if they are found to be reasonable and prudent. (3 TR 1130.) Staff does not recommend that the Commission pre-approve estimates that include contingency costs for undefined expenditures. Rather, Staff recommends that the Company seek approval of actual contingency expenditures in its next rate case. Attorney General witness Coppola agrees, testifying, It is not fair or reasonable for the Company to recover the depreciation expense and the return on the investment on potential costs that may not be actually incurred but have been added to rate base. (3 TR 1032.) The Commission should note that Staff s recommendation is not a project management recommendation or a budgeting recommendation, but a ratemaking recommendation. The Company may consider contingency when budgeting for a project using whatever method it chooses but ratepayers should not pay in advance for contingency expenditures. Therefore, the Commission should not allow the Company to recover projected contingency expenditures associated with capital projects until after the expenditures have been incurred and reviewed for prudence. This does not leave the Company without any recovery of these expenditures because Staff is willing to recommend recovery of reasonable and prudent incurred contingency expenditures in future rate cases. 7

15 Gas Storage Operations, Integrity, and Planning In addition to the removal of contingency expenditures related to routine storage plant detailed above, Staff recommends that the Company provide Staff with additional information regarding DTE s gas storage operations, integrity, and planning on an annual basis. The recommended reporting is necessary due to the value and importance of DTE s gas storage system to its customers. DTE witness Sandberg testified that capital expenditures for routine storage plants are driven by risk-based analysis and market requirements: DTE Gas conducts risk-based assessment of the integrity of its wells and storage reservoirs to determine when or if any repair or replacement is warranted. Continuous performance monitoring and testing methods are also utilized to ensure current and future market requirements can be economically met from each storage field. (2 TR 689.) Staff Witness Cole recommends that DTE meet annually with Staff and provide a report on the results of the risk-based assessments and continuous performance monitoring and testing conducted, as well as provide updates to Staff on the capital projects undertaken or planned to ensure the integrity and deliverability of DTE s storage system. (3 TR 1136.) The Company did not rebut Staff s recommendation that the Company meet with Staff. Therefore, Staff recommends that the Commission adopt this request. 8

16 Revenue Protection Capital Expenditure Adjustment Staff recommends that the Commission adopt capital expenditures for the revenue protection program in the amount of $3,488,232 for 2015, $4,145,585 for 2016, and $4,569,027 for the January October 2017 period. (3 TR 1152.) This is a reduction from the Company s request of $4,335,000 for 2015, $4,457,000 for 2016, and $5,793,000 for the January October 2017 period. (Exhibit A-9, Schedule B-6.1.) The revenue protection program includes abandonment of natural gas service lines related to theft or non-payment as well as renewal of service lines previously disconnected under the revenue protection program. (2 TR 703.) Staff witness Creisher provided testimony proposing an adjustment to the 2015 capital expenditures based on actual program expenditures. Additionally she discussed the Company s historical performance and projections for 2016 and 2017 for service line adjustments and renewals. The Company s projections for service abandonments in 2016 and 2017 and line renewals for 2017 were based on a threeyear average from 2012 through However, actual service line abandonments in 2015 were significantly lower than the three-year average. (3 TR ) Therefore, Staff recommends using a five-year average instead. Although the Company argues that Staff did not provide adequate support for the use of a fiveyear average, Staff witness Creisher s testimony indicated that Staff used a fiveyear average to take into consideration the significant reduction of service line abandonments and renewal work completed in 2015, unlike the Company s proposed three-year average. (3 TR 1151.) 9

17 In rebuttal testimony, the Company also addressed the cost per unit for 2016 and 2017 service line abandonment and renewal for the revenue protection program. The Company s calculated unit cost per service abandonment is $603 in 2016 and $595 in 2017; and the Company s calculated unit cost per service renewal is $1,389 in 2016 and $1,861 in For service abandonment and renewal, Staff agrees with the Company s unit costs for 2016; and Staff s calculated unit cost for service abandonment is $648 in 2016 and $1,497 in (2 TR ) The Company sent a supplemental audit request regarding service abandonments and renewals, which Staff did not agree with and therefore did not take into consideration in its analysis. (2 TR 737.) Staff identifies that review of the unit costs, as presented by Company witness Sandberg, indicates a substantial increase in the Company s projected unit cost for service renewals from $1,389 in 2016 to $1,861 in The Company has not provided an adequate explanation to support this significant increase in cost per unit. Staff s adjustment allows for a more reasonable increase in capital expenditures. For these reasons, Staff recommends that the Commission and the ALJ find Staff s use of a five-year average for projection of service abandonments and renewals to be reasonable. Staff also recommends that the Commission adjust the capital expenditures for the revenue protection program to $4,145,585 for 2015, $5, 482,806 for 2016, and $4,569,027 for the January October 2017 period. 10

18 AMI and AMR Programs Staff recommends that the Commission grant recovery of costs presented by DTE Gas for the AMI and AMR programs. Company witness Sitkauskas presented two different meter-reading solutions for the Company s gas service territory. For overlap service territories receiving both gas and electric service from DTE Gas and DTE Electric, the Company plans to install AMI modules, which can read and monitor both gas and electric consumption, on the current gas meters. (2 TR 287.) In areas that only receive DTE Gas the Company plans to install AMR meters. (2 TR 288.) Staff reviewed the Company s cost benefit analysis, purchasing, and installation costs and considers the AMI/AMR costs to be prudent at this time. However, Staff urges the Commission to continue to rigorously evaluate in subsequent rate cases the reasonableness of these expenditures in light of the field s rapidly changing technology and resulting rapid obsolescence of existing technology. (3 TR 1171, 1173.) i. Smart Grid Reporting Metrics Staff recommends that the Commission adopt Staff s proposed smart grid reporting metrics with the additional recommendations made by the Company. Staff explained the importance of tracking DTE s progression to a smarter grid via the 43 metrics provided in Staff s Exhibit S-9, stating that [f]or Staff to fully analyze and track the progression to a smarter grid to ensure benefits are maximized, metrics are a logical accountability mechanism for the Company to provide. (3 TR 1173, Exhibit S-9.) Staff explained that these metrics will allow for 11

19 the measurement of reductions in peak energy demand, adoption levels of demand response and usage of smart devices on the grid thereby providing the Commission with necessary information to determine how upgrades to the grid are benefitting both customers and the Company. (Id.) The Company generally agreed with Staff but provided several recommendations to Staff s metric proposal. The Company s recommendations are as follows: (1) a single report encompassing DTE Gas, Electric, and Customer service; (2) an annual smart grid reporting cycle concurrent with the calendar year ending; (3) a review of the individual metrics during each reporting occurrence; and (4) ongoing informal update meetings with Staff during the year which will service to provide clarity and understanding of the metrics suggested. (2 TR ) Staff believes its smart grid reporting metrics with the additional recommendations by the Company will allow Staff to fully analyze and track DTE s progression to a smarter grid and ensure benefits are maximized. Therefore, Staff recommends that the Commission and the ALJ adopt Staff s proposed smart grid reporting metrics with the Company s additional recommendations. d. Cut and Cap Fees Staff recommends that the Commission direct the Company to limit the exemption of the cut and cap fees. Staff recommends that the $720 exemption of governmental cut and cap fees be limited to a quantity of 6,000 annual exemptions though (3 TR ) DTE Witness Stanczak testified that the Company proposed a tariff modification to exempt government requested cut and cap services from the cut and cap charge to facilitate blight related demolition in an effort to 12

20 reduce safety concerns, reduce theft, and support economic development in local communities for the benefit of all customers. (2 TR 83.) Staff recommends that the current limitation in the tariff of 6,000 waived cut and cap fees for governmental entities remain in place as an annual limitation. Staff also recommends waving cut and cap fees for governmental request demolitions through (3 TR 1138.) While Staff generally supports the facilitation of blight removal, Staff intendeds for these limitations to provide additional time to gather data on the actual number of governmental requested cut and caps and the rate impact on ratepayers of waiving the fees. Maintaining the limitation of 6,000 waived cut and cap fees will place an upper limit on the amount waived, effectively limiting the rate impact. Extending the waiver of cut and cap fees through 2018 will allow DTE to gather a sufficient amount of data of the number of waivers requested by governmental entities. Should DTE request that this limitation be removed in the future, Staff recommends that data on the number of waivers requested from and the impact on rates be included with the request. (3 TR 1139.) Staff also recommends that any additional amounts and sources of funding available to assist DTE with blight removal be provided with future requests to waive cut and cap fees for governmental entities. (3 TR 1139.) Staff s recommendation to limit the cut and cap fees to 6,000 waivers for governmental entities annually through 2018 was not rebutted by the Company. Therefore, Staff recommends that the Commission and the ALJ adopt this request. The revenue and rate impact of Staff s recommendation will be discussed later in the other operating revenues section of this brief. 13

21 e. Infrastructure Recovery Mechanism Program Staff recommends that the Commission approve the Company s infrastructure recovery mechanism (IRM) capital expenditures of $78.1 million, for 2015, $102.1 million for 2016, and $127.6 million annually for 2017 through However, the Commission should not approve the Company s request for increased flexibility of expenditures between the pipeline integrity program, Meter Move Out program, and Main Renewal Program. Staff agrees with the Company s level of capital expenditures in each of the IRM programs, but it does not agree with the increase in expenditure flexibility proposed by the Company. The Company is proposing an increase in flexibility of spending between programs from $2.5 million to $3.3 million in 2016 and $4.1 million in (2 TR 707.) If these programs are so important that they require the additional funds, then there should be no need to underspend on one program and move funds to another program. Staff recommends that the Commission and the ALJ find the capital expenditure levels requested by the Company to be prudent. However, Staff does not recommend that the Commission approve the Company s request to increase the expenditure flexibility level. Staff recommends that the Commission find that the expenditure flexibility level of $2.5 million is reasonable and prudent. (3 TR 1153.) i. Pipeline Integrity Staff recommends that the Commission and the ALJ approve the Company s proposed capital expenditures for the pipeline integrity program in the amount of $8,518,000 for 2015, $9,014,000 for 2016, and $11,100,000 annually for 2017 through (Exhibit A-9, Schedule B6.1.) Staff believes that these levels of 14

22 expenditures are reasonable and necessary to improve the integrity of the Company s gas transmission system, which will provide improved system reliability and enhanced safety for customers, landowners, and the public. ii. Meter Move Out Staff supports the Company s continued capital expenditures for the meter move out (MMO) program in the amount of $22,700,000 annually. (Exhibit A-9, Schedule B6.1.) However, the Commission should address the Company s performance in the MMO program specific to its original goal of moving inside meters outside through relocation or elimination of service. Staff recommends that the Commission require the Company to adhere to the original goal presented and approved in the Commission s September 13, 2011 Order in MPSC Case No. U The Company is expected to impact 229,750 inside meters through MMO, MRP, and other routine programs during the 10-year period from 2012 to DTE s MMO program was initiated as a result of Staff s recommendation to address DTE s system-related problems in case No The Commission s June 3, 2010 Order in Case No. U directed the Company to file in a new docket a detailed plan for moving inside meters to outside location. This plan will be reviewed by the Commission and made available for public comment. (6/3/10 Order, p 105.) On September 30, 2010, the Company filed its plan for a long-term meter move out in Case No. U Exhibit A-1 in Case U outlines the program work plan as follows: 15

23 MichCon plans to impact about 12,790 inside meters per year over the 10 year period of the initiative, ultimately impacting 127,900 inside meters, excluding the approximately 1,110 meters per year planned to be moved under the MRI. Based on historical data from the Pilot Program, the MMI assumes that within the impacted areas, MichCon will relocate the meter 72% of the time, cut and cap the meter for theft 18% of the time, and cut and cap the meter at demolition and vacant sites 10% of the time. In addition to the systematic, accelerated approach being utilized in the MMI, as part of its routine spending program, MichCon expects to initially impact 13,300 inside meters. As the MMI progresses and fewer inside meters remain, this number will decline. These meter move-outs will occur in areas throughout MichCon s statewide territory. If an inside meter is attached to the service line being renewed or retired, MichCon will relocate or remove the meter as part of its routine construction efforts. Routine meter relocation and removal is expected to remove another 90,750 inside meters from MichCon s distribution system infrastructure over the next 10 years. In summary, during the period, MichCon expects the following number of inside meters to be impacted through relocation or cut and cap: Year 1 Total Meter Move-Out Initiative 12, ,900 Main Renewal Initiative 1,109 11,100 Routine Construction Work 13,300 90,750 Total Inside Meters Impacted 27, ,750 The Commission s September 13, 2011 Order in Case No. U addressed the Company s prior lack of commitment to addressing inside meters: Thus, the Staff s concern that the company failed to utilize the capital expenditure amount approved for the Meter Relocation Program in 2010 is well taken. While Mich Con is correct that the $17.3 million was for capital expenditures in the test year only, the company fails to recognize the real issue: that Mich Con, as yet, failed to demonstrate that it is in fact committed to relocation or removing inside meters, despite repeatedly proposing to do so under various program aliases. The Commission agrees with the Staff and Mich Con that the company s MMO proposal for , if carried out as planned, meets the requirements of the June 3 order. However in light of the 16

24 concerns raised by the Staff with regard to the company s commitment to meter relocation, the Commission rejects Mich Con s argument that it should not have to report on its meter relocation efforts in 2011 (9/13/11 Order, p 14, emphasis added.) The Commission s Order in Case No. U clearly recognized DTE s failure to commit to its original plan. DTE has consistently shown a lack of commitment toward the MMO program. DTE effectively modified the scope of the MMO program in Case No. U when it expanded the definition of impacted meter: In addition to relocating meters to the outside building wall, the MMO Program also includes the cutting and capping of gas service at theft, demolition, and vacant sites within the block-by-block MMO area targeted by MichCon. While the meters are not physically moved outside, cutting services does impact and reduces the number of inside meters that are in service. Also, a residential meter located on the outside of the residence in the block-by-block MMO target area is considered an impacted meter if the service line is cut for idle, vacant, or theft reasons; or the service line is repaired due to an identified leak or there is a meter malfunction. (MPSC Case No. U-16999, 3 TR 332.) Before DTE inserted outside meters impacted into the definition of an impacted residential gas meter, expenditures related to outside meters impacted were considered reasonable in the MMO, although they were not counted toward the goal of 12,790 inside meters to be impacted annually. The Commission s April 16, 2013 Order in Case No. U stated that the Company s goal was to move approximately 12,790 meters. (4/16/13 Order, p 24, emphasis added.) The Order did not modify the 10-year goal to move 127,900 meters. While the Company is meeting its stated goals to impact over 12,790 meters, both inside and outside through the MMO, it appears to be failing to remove a 17

25 sufficient number of inside meters cumulatively through the MMO, MRP, and other routine programs to meet the goals originally defined in Case No. U to impact 229,750 inside meters over the course of the 10-year program. Furthermore, Staff witness Creisher testified that the number of inside meters that the Company impacts annually through the MMO a program initiated to systematically relocate inside meters to outside locations is declining year after year, as are inside meters impacted through MRP and other routine programs. In 2016, the Company projects that a mere 60% of the meters impacted through MMO will be inside meters. (3 TR 1158.) Staff maintains that the Company s current and projected performance related to the removal of inside meters through its MMO, MRP, and other routine programs are not being carried out as planned and therefore will not satisfy the requirements of the June 3, 2010 Order issued in Case No. U The Commission stated in case No. U that the Company s MMO proposal for , if carried out as planned, meets the requirements of the June 3 order. (9/13/11 Order, p 14, emphasis added.) The MMO plan has not been carried out as planned. The Company provided rebuttal testimony to Staff s position that the Company is accountable for the number of meters relocated. In his rebuttal testimony, Company witness VanderHeuvel argued that MRP and MMO programs were designed and approved by the Commission to meet targeted spending levels not to relocate a pre-specified number of meters. (2 TR 840.) This statement 18

26 mischaracterizes what the Commission has said about the MMO program in the past. The Commission stated, [a]nd to be clear, spending is not the only metric to be examined in the annual reconciliations. Mich Con is expected to spend at least $22.7 million with a goal to move approximately 12,790 meters. (4/16/13 Order, Case No. U-16999, p 14, emphasis added.) Witness VanderHeuvel s statement that the Commission has no expectation of performance is repeatedly contradicted by the Commission in Case Nos. U-15985, U-16451, and U Further, the Company s own Petition for Rehearing and Clarification in Case No. U and the Commission s subsequent Order Granting Clarification clearly recognize that the Company s overall performance of relocating inside meters would be evaluated. The Commission s Order states: The Commission agrees that the September 13 Order should be clarified as requested by Mich Con and that the record shows that Mich Con expects to move or remove a total of 11,100 meters over ten years (i.e., approximately 1,100 annually) as part of its Main Renewal Program and, as part of routine construction efforts, it expects to move or remove a total of approximately 90,750 inside meters, beginning with 13,300 meters the first year and declining each year thereafter. Because the Company has a history of lack of commitment to the program and has misconstrued the Commission s direction with regard to the number of meters to be moved, the Commission should again address the goal to impact 12,790 inside meters annually through the MMO program and 229,750 inside meters over 10 years through MMO, MRP, and routine construction work. Staff recommends that the Commission require the Company s March 31 st MMO performance report to clearly account the cumulative number of inside meters impacted by the Company through MMO, MRP, and other routine programs. The 19

27 report should also include a planned amount of inside meters to be impacted through the programs to support meeting the 10-year goal for accelerated removal of inside meters. In Case No. U the Commission acted on Staff s recommendation to require the Company to develop a plan to systematically move inside meters, including an opportunity to review the proposed program and monitor implementation. (MPSC Case No. U-15985, Order, 6/3/10, p 105.) The Commission addressed this in Case No. U-16451, the Commission agrees that MichCon should begin filing reports in 2012 covering activities related to meter removal in 2011, as recommended by the ALJ. (MPSC Case No. U-16451, Order, 9/13/11, p 15.) Additionally, the Commission should require the Company to submit monthly meter assembly check (MAC) progress reports to Staff that are consistent with the information provided on page 3 of Exhibit S-7.9. Staff witness Creisher addressed the state and federal regulatory requirements related to the MMO. While there are no specific regulations that require inside meters to be relocated, 49 CFR Part 192 does contain requirements that the Company periodically access all meters, regardless of location, on a prescribed schedule. (3 TR 1159.) DTE has experienced significant issues gaining access to complete MAC inspections specifically related to atmospheric corrosion control, continuing surveillance, and leak surveying. (3 TR 1159.) As of December 31, 2015, over one third of the approximately 300,000 inside meters remaining in the Company s distribution system were past due for MAC inspections. (Exhibit S-7.9.) Company 20

28 witness Tomina asserts that MAC progress reports are informally provided to Staff semi-annually and that a formal requirement of monthly reporting will not increase DTE Gas performance (2 TR 965.) MAC inspections are discussed as an operational benefit; however, the purpose of such inspections is to identify and mitigate the risk of safety issues that could potentially result in significant loss of life, injury, or property damage. Thus, Staff recommends that the Commission and the ALJ agree with Staff that the Company provide monthly reporting for MAC inspection activity. iii. Main Renewal Program Staff recommends that the Commission and the ALJ approve the Company s proposed capital expenditure associated with the Main Renewal Program (MRP). The Company proposed capital expenditures in the amount of $46,900,000 in 2015, $70,350,000 million in 2016, and $93,800,000annually for 2017 through (Exhibit A-9, Schedule B 6.1.) Staff disagrees with Attorney General Witness Coppola s assertion that the Commission should approve MPR capital expenditure levels of $62.53 million for 2016 and $78.32 million annually for 2017 through (3 TR 1034.) The Attorney General argues that the Commission recently ruled on the Company s MRP in its November 23, 2015 Order in Case No. U and that there has been no compelling information presented to increase the size of the program in the current proceeding. (3 TR 1034.) Staff reviewed the Company s demonstrated performance in 2015 and concluded that the Company s request was reasonable and consistent with the stepped approach to increasing the size of the MRP approved in Case No. U (3 TR ) 21

29 Staff supports the Company s commitment to renew or retire all high-risk metallic mains in a 25- to 30-year period. Staff agrees with eliminating the target mileage requirements as proposed by the Company with the caveat that the MRP s plan and performance must continue to progress toward the goal of eliminating cast iron and bare or unprotected steel mains from the Company s distribution system in the 25- to 30-year period. (3 TR ) Therefore, the Commission should approve the Company s proposed capital expenditures associated with the MRP. The Commission should also eliminate the annual target mileage requirements with the addition of Staff s caveat that the MRP s plan and performance must continue to progress toward the goal to eliminate cast iron and bare or unprotected steel mains from the Company s distribution system in the 25-to 30- year period. 2. Staff recommends an Accumulated Depreciation Reserve of $2,166,437,000 for the projected test year. Staff s projected accumulated depreciation reserve is $2,166,437,000 for the projected test year. (Appendix B, line 5.) This represents an increase of $1,581,000 from the Company s initially filed request of $2,164,856,000. The increase is the result of the capital expenditure adjustments supported by Staff in the utility plant section of this brief above, and also due to the correction of an error in the Company s filing related to depreciation expense, which is discussed in the depreciation expense section of this brief below. 22

30 3. Gas Stored Underground Non Current Staff s recommended projection for gas stored underground non current is $35,267,000. (Appendix B, line 8.) This represents a decrease of $4,072,000 from the Company s initially filed request of $39,339,000. a. Reconversion of Base Gas Prior to 2008, DTE Gas made improvements to gas storage fields that it determined had created additional cycling capacity and thus a lesser volume necessary for base gas. Due to operational limitations actually experienced in recent years, DTE Gas determined that it is necessary to make further improvements at Belle River. These improvements include additional compression and reconversion of 1.9 BCF of working gas to base gas. (3 TR 1219; Exhibit S-11.5) Staff recommends a reduction in the cost of gas that is being reconverted. Staff maintains that the cost of reconversion should be shared between DTE and customers. Customers should only be responsible for 50% of the costs related to the reconversion of working gas to base gas. (3 TR 1220.) b. Average Cost of Natural Gas Staff recommends the Commission and the ALJ adopt Staff s single average projected cost of natural gas of $3.6089/Mcf. The Company used NYMEX settlement prices of natural gas contracts on October 27, 2015 to determine the jurisdictional costs of natural gas. The Company projected the November 2016 through March 2017 costs as $3.9253/Mcf, and the April 2017 through October 2017 cost as $3.6053/Mcf. (2 TR 568.) These values also incorporate DTE Gas s proposed 23

31 system average heating value of million Btu (British Thermal Unit) per Mcf. (3 TR 1231.) Staff s approach to determine the November 2016 through October 2017 average cost of natural gas used one average cost of natural gas for the period. Staff s approach incorporates four monthly variables: 1) long-term/other spot purchases volumes; 2) long-term/other spot purchases costs; 3) citygate/spot purchases volumes; and 4) transportation costs. (3 TR 1232.) Staff s proposed average monthly cost of natural gas of $3.6089/Mcf is the sum of the monthly costs of the total system supply purchases divided by the monthly volumes of the total system supply purchases. (3 TR , Exhibit S-10.3 Revised, p 2) Staff used its $3.6089/Mcf average cost of natural gas to price the injection of 0.95 Bcf (50% of the Company s proposed1.9 Bcf reconverted base gas) into Belle River Mills storage facility. (3 TR 1235, Exhibit S-2, Schedule B-1, column D, line 8.) Importantly, Staff s price of $3.6089/Mcf incorporates Staff s system average heating value of 1045 Btu/cf, the development of which is detailed in the Projected Net Operating Income section below. 4. Staff recommends a Working Capital requirement of $1,021,680,000 for the projected test year. Staff s projected working capital requirement is $1,021,680,000, which is $21,949,000 greater than the Company s working capital requirement of $999,731,000. (Appendix B, Line 12.) Differences between the Staff s and the Company s projected working capital requirement are due to Staff s upward adjustments of $31,386,000 to gas in underground storage - current, and $9,764,000 24

32 to GCC deferred asset, and downward adjustments of $18,214,000 to intercompany notes receivable and $987,000 to regulatory asset demolition fees. (3 TR 1119.) a. Gas in Underground Storage Current and GCC Deferred Asset Staff based its monthly costs and volumes of natural gas in underground storage reservoirs on the most recent data DTE Gas had available at the time that Staff was assembling its case. (3 TR 1228.) Staff requested this recent data from DTE in order to update the projected monthly costs and volumes of natural gas in underground gas storage reservoirs. (Id.) Staff s recommendation used the following three adjustments from what DTE Gas originally filed: First, incorporating the actuals from October 2015 through December 2015; second, updating the five-day New York Mercantile Exchange (NYMEX) average settlement prices of January 11 through 15, 2016; and third, incorporating Staff s system average heating value to the monthly inventory balance. DTE Gas provided the data for adjustments one and two. (3 TR 1228.) As shown on Exhibit S-10.2, the October 2016 through October 2017 average ending inventory cost of working gas in underground gas storage reservoirs for GCR customers increased by $31,386,000 to $70,848,000 (Exhibit S-10.2, page 1, column F, line 11). The October 2016 through October 2017 average ending inventory volume of working gas in underground gas storage reservoirs increased by 6,755,000 Mcf to 44,233,000 Mcf (Exhibit S-10.2, page 1, column F, line 5). The October 2016 through October 2017 average ending balance for gas customer choice (GCC) deferred asset of working gas in underground gas storage reservoirs increased by $9,764,000 to $75,450,000 (Exhibit S-10.2, page 2, column F, line 20). The October 2016 through October 2017 average GCC ending inventory volume of 25

33 working gas in underground gas storage reservoirs increased by 1,929,000 Mcf to 9,753,000 Mcf (Exhibit S-10.2, page 2, column F, line 13). (3 TR 1229.) b. Intercompany Notes Receivable Staff recommends the disallowance of $18,214,000 of intercompany notes receivable which the Company included in working capital. Additionally, Staff recommends the disallowance of the$237,000 intercompany notes receivable interest revenue. (3 TR 1123.) Staff witness Nichols testified: The intercompany notes receivable already earn a return, therefore it should not be included in working capital earning a second return. Likewise, it is inappropriate to bring the offsetting interest revenue into the revenue requirement. Excess Cash, which the Company loans to subsidiaries, does not require a return from ratepayers because it already earns a return, which in the instant case is $237,000. Exhibit S-12.3 & Exhibit S (3 TR 1123.) Staff witness Nichols stated further: In general, items that earn a return are excluded from working capital so that they do not earn a return twice, once from the investment itself, and once from the return on working capital in rate base. The Commission adopted this treatment of cash equivalents in MPSC Case No. U-17735, November 19, 2015 Order, page 26, stating: The Commission is persuaded that the Staff s view is appropriate. The Commission has a long-standing practice of excluding balance sheet accounts from working capital that already earn a return. The prior cases cited by Consumers did not address temporary cash investments as a contested issue. The Commission finds that temporary cash investments should be excluded from projected working capital, since these investments already earn a return. 9 Tr ; Exhibit S To do otherwise would require ratepayers to fund an additional, and inappropriate, return. (3 TR ) The Company provided no rebuttal of the Staff recommendation. Staff urges the Commission and the ALJ to adopt Staff s position based on the same reasoning 26

34 demonstrated by the Commission in its order in MPSC Case No. U-17735, referenced in Staff s testimony above. c. Regulatory Asset Demolition Fees Staff recommends the Commission adopt the Company s updated projection for the regulatory asset demolition fees as presented in Exhibit S The Company updated its projection subsequent to the Company s initial filing. The Company s updated projection reduces working capital by $987,000 and demolition amortization expense by $713,000. (3 TR 1120.) The Company presented no rebuttal of the Staff recommendation. Therefore, Staff recommends that the Commission and the ALJ adopt Staff s position. B. Capital Structure and Rate of Return 1. Capital Structure and Overall Rate of Return Staff recommends an overall rate of return of 5.73%, which consists of a recommended return on equity (ROE) of 10.00% and a capital structure consisting of a 48% long-term debt and 52% permanent equity layer. (3 TR ) DTE Gas requested an overall cost of capital of 6.04% with an ROE of 10.75% and a permanent capital structure consisting of 48% long-term debt and 52% common equity. (2 TR 133.) The thirty-one basis points difference in the Company s and Staff s overall rate of return is predicated on Staff s adjustments to the Company s balances and cost rates for long-term debt, short-term debt, net deferred income taxes, and common equity. Staff will first summarize its capital structure development and cost rates in the first section below. Staff will then outline its ROE analysis and address the Company s ROE rebuttal. 27