7 1 State of Michigan 2 Before the Michigan Public Service

2 BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

3 In the matter of the application of DTE Electric Company for approval Case No. U-18150 4 of depreciation accrual rates and other related matters. Volume 2 5 ______/

6 CROSS-EXAMINATION

7 Proceedings held in the above-entitled

8 matter before Sharon L. Feldman, Administrative Law Judge

9 with MAHS, at the Michigan Public Service Commission,

10 7109 West Saginaw, Lake Michigan Room, Lansing, Michigan,

11 on Tuesday, October 24, 2017, at 9:00 a.m.

12 APPEARANCES:

13 JON P. CHRISTINIDIS, ESQ. DTE Energy 14 One Energy Plaza, 688WCB Detroit, Michigan 48226 15 On behalf of DTE Electric Company 16 STEPHEN A. CAMPBELL, ESQ. 17 CLARK HILL, PLC 212 East Grand River Avenue 18 Lansing, Michigan 48906

19 On behalf of Association of Businesses Advocating Tariff Equity 20 MEREDITH BEIDLER, 21 Assistant Attorney General 7109 West Saginaw Highway, Floor 3 22 Lansing, Michigan 48917

23 On behalf of Michigan Public Service Commission Staff 24

25 REPORTED BY: Marie T. Schroeder, CSR-2183 Metro Court Reporters, Inc. 248.360.8865 8

1 I N D E X

2 WITNESS: PAGE

3 ROBERT P. CHARLES Direct Testimony bound in 14 4 KEVIN J. CHRESTON 5 Corrected Rebuttal Testimony bound in 30

6 EDWARD T. HENDERSON Direct Testimony bound in 44 7 PAUL G. HORGAN 8 Direct Testimony bound in 58

9 KENNETH D. JOHNSTON Direct Testimony bound in 68 10 NEIL E. MORTENSEN 11 Direct Testimony bound in 91

12 DR. RONALD E. WHITE Direct and Rebuttal Testimony bound in 99 13 HOWARD R. COOPER 14 Direct and Rebuttal Testimony bound in 140

15 BRIAN C. ANDREWS Direct and Rebuttal Testimony bound in 173 16 RONALD J. ANCONA 17 Direct Testimony bound in 206

25 Metro Court Reporters, Inc. 248.360.8865 9

1 E X H I B I T S

2 NUMBER DESCRIPTION MRKD OFRD RECD

3 A-1 DTE Electric Retirement Unit Catalog 11 138 139 as of this filing 4 A-2 Historical Annual CPI and PPI 11 138 139 5 Escalation Rates

6 A-3 Projected Annual CPI and PPI 11 138 139 Escalation Rates 7 A-4 Schedule of Obsolete Inventory by 11 138 139 8 Plant

9 A-5 Account 397-Communication Equipment 11 138 139

10 A-6 Adjusted Summary of Decommissioning 11 138 139 Costs by Plant 11 A-7 Recommended DTE Electric 11 138 139 12 Depreciation Rates

13 A-8 Proposed Streetlighting & Signal 11 67 67 System Account Allocations 14 A-9 Proposed LED Luminaire Capital Cost 11 67 67 15 A-10 MEP Marysville Power Plant 11 90 90 16 Decommissioning Estimate

17 A-11 Recommended MERC Depreciation Rate 11 138 139

18 A-12 Marysville vs Harbor Beach Value 11 90 90 Analysis 19 A-13 Harbor Beach Land Appraisal 11 90 90 20 A-14 N-1, N-2, N-3, N-4 11 13 13 21 A-15 2016 Depreciation Study DTE 11 98 98 22 Energy by Foster Association

23 A-16 ABATE-2 Exhibit A-4 Schedule of 11 138 139 Obsolete Inventory with Detail 24 A-17 ABATE Decommissioning Costs 11 138 139 25 Metro Court Reporters, Inc. 248.360.8865 10

1 E X H I B I T S

2 NUMBER DESCRIPTION MRKD OFRD RECD

3 AB-1 (Sponsored by B. Andrews) 11 171 172

4 AB-2 (Sponsored by B. Andrews) 11 171 172

5 AB-3 (Sponsored by B. Andrews) 11 171 172

6 AB-4 (Sponsored by B. Andrews) 11 171 172

8 S-1 (Sponsored by R. Ancona) 11 205 205

25 Metro Court Reporters, Inc. 248.360.8865 11

1 Lansing, Michigan

2 Tuesday, October 24, 2017

3 9:00 a.m.

4 - - -

5 (Hearing resumed pursuant to the schedule.)

6 (Documents were marked for identification by the

7 Court Reporter as Exhibits A-1 through A-13, A-14

8 Schedules N-1, N-2, N-3, and N-4; A-15 through A-17;

9 AB-1 through AB-4, and S-1.)

10 - - -

11 JUDGE FELDMAN: On the record. Good

12 morning, all. Today is the date we set aside for

13 cross-examination in this case. May I ask counsel

14 present to place their appearances on the record, please.

15 MR. CHRISTINIDIS: Yes, your Honor. Jon

16 Christinidis on behalf of DTE Electric Company.

17 JUDGE FELDMAN: Thank you.

18 MS. BEIDLER: Good morning, your Honor.

19 Meredith Beidler on behalf of Michigan Public Service

20 Commission Staff.

21 JUDGE FELDMAN: Thank you.

22 MR. CAMPBELL: Good morning, your Honor.

23 Steve Campbell of Clark Hill on behalf of Assocation of

24 Businesses Advocating Tariff Equity.

25 JUDGE FELDMAN: Thank you. And since Metro Court Reporters, Inc. 248.360.8865 12

1 it's my understanding the parties have agreed to bind in

2 the testimony, we're not expecting anybody else to come

3 this morning, right?

4 MR. CHRISTINIDIS: I am not, your Honor.

5 JUDGE FELDMAN: All right. Mr.

6 Christinidis, you may proceed when you are ready.

7 MR. CHRISTINIDIS: Yes, your Honor.

8 Would you like me to sort of serially go through all of

9 the witnesses and identify their testimony and exhibits

10 or how would you like to --

11 JUDGE FELDMAN: I think any way that

12 makes sense to you, just so we get it all on the record.

13 I think I have notes that I can work from so we don't get

14 too lost. If you've got yours and I've got my notes, we

15 should be O.K.

16 MR. CHRISTINIDIS: All right, your Honor.

17 Consistent with the stipulation to bind in and waive

18 cross-examination, DTE Electric's first witness is Robert

19 P. Charles. He filed Qualifications and Direct Testimony

20 of Robert P. Charles, consisting of a cover sheet and 14

21 pages of questions and answers. He also sponsored an

22 exhibit and schedules that are designated as A-14

23 Schedule N-1 which is 144 pages, A-14 Schedule N-2, 103

24 pages, A-14 Schedule N-3, 132 pages, and Exhibit A-14

25 Schedule N-4, which is 27 pages. Metro Court Reporters, Inc. 248.360.8865 13

1 So with that, your Honor, the Company

2 would move to bind in the Qualifications and Direct

3 Testimony of Robert P. Charles and move the admission of

4 Exhibit A-14, Schedules N-1 through N-4.

5 JUDGE FELDMAN: All right. Let me ask

6 for the record if there are any objections to Mr.

7 Christinidis's request? Hearing no objections, the

8 prefiled direct testimony of Robert P. Charles will be

9 bound in the record and Exhibit A-14, including all four

10 Schedules N-1 through N-4, is admitted into evidence.

11 (Testimony bound in.)

25 Metro Court Reporters, Inc. 248.360.8865 14

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) DTE ELECTRIC COMPANY ) for approval of depreciation accrual rates ) Case No. U-18150 and other related matters )

QUALIFICATIONS

AND

DIRECT TESTIMONY

ROBERT P. CHARLES

15 DTE ELECTRIC COMPANY QUALIFICATIONS OF ROBERT P. CHARLES Line No.

1 Q. Will you please state your name and business address?

2 A. My name is Robert P. Charles. My business address is 55 East Monroe Street,

3 Chicago, Illinois, 60603.

5 Q. By whom are you employed and in what capacity?

6 A. I am employed by Sargent & Lundy, L.L.C. (Sargent & Lundy) as a Senior

7 Principal Consultant.

9 Q. What is your educational background?

10 A. I hold a B.S. in Electrical Engineering from Norwich University and an M.B.A.

11 from Benedictine University. I am a registered Professional Engineer in Illinois

12 and Pennsylvania.

14 Q. What are your responsibilities in your current position?

15 A. My responsibilities include planning, managing, and performing consulting and

16 engineering activities for power projects. As a senior project manager in the

17 consulting group I am responsible for the performance of consulting projects,

18 including: due diligence reviews, owner’s engineering services, and special

19 projects. Owners engineering services include conceptual design studies, feasibility

20 studies and economic evaluations, preparation of engineering, procurement, and

21 construction (EPC) specifications, evaluation of EPC bids, design review and

22 construction technical support. I am responsible for interfacing with the client on

23 progress, resolving emergent issues, and resolution of comments on the final

24 deliverable. I also managed the Sargent & Lundy Team that developed the DTE

25 Electric Company (DTE Electric or the Company) decommissioning cost estimate.

RPC-1 16 R. P. CHARLES Line U-18150 No.

1 Q. Have you or Sargent & Lundy previously conducted demolition studies for

2 other utilities?

3 A. Yes, I directed the Sargent & Lundy teams that performed the decommissioning

4 cost estimate of fossil-fueled and renewable power generating assets for Montana-

5 Dakota Utilities and San Diego Gas & Electric. I reviewed and developed

6 decommissioning cost estimates for nuclear facilities, including: the Krummel and

7 Brokdof nuclear plants in Germany, the La Crosse Boiling Water Reactor, Big

8 Rock Point, Calvert Cliffs, and Nine Mile. I also evaluated the decommissioning

9 cost estimates and developed independent cost estimates for 12 nuclear plants

10 associated with asset evaluation for potential purchase. In addition, Sargent &

11 Lundy has significant decommissioning cost experience, having conducted studies

12 for the following utilities:

13 • AEP/Public Service or Oklahoma: Eight power generating stations (19 units)

14 • AEP/Southwest Electric Power: 12 power generating stations (28 units)

15 • American Electric Power: Two power generating stations (five units)

16 • Dairyland Power: La Crosse Nuclear Power Plant

17 • Duke Energy: One power generating station (one unit)

18 • Public Service Indiana: 14 power generating stations (57 units)

19 • Montana Dakota Utilities: Seven power generating facilities (nine units)

20 • Salt River Project: One power generating facility (three units)

21 • San Diego Gas & Electric: Three power generating facilities (four units)

22 • Pacificorp: One power generating facility (two units)

24 My expert witness work has included:

RPC-2 17 R. P. CHARLES Line U-18150 No.

1 • 2012–Present: Providing an expert report and testimony in conjunction with

2 arbitration proceedings initiated by Vattenfall AB, Vattenfall GmbH, Vattenfall

3 Europe Nuclear Energy GmbH, Kernkraftwerk Krümmel GmbH & Co. oHG,

4 and Kernkraftwerk Brunsbüttel GmbH & Co. oHG (together “Vattenfall”)

5 against the Federal Republic of Germany. I evaluated the decommissioning cost

6 estimates for the Krümmel and Brokdorf nuclear power plants developed by

7 Vattenfall and issued an expert report in September 2013, with an update in

8 December 2014.

9 • 2015 –Present: Expert witness for power plant technology in a current lawsuit.

10 The trial proceedings are currently in process: Solargenix Energy vs. Acciona.

11 • 2003–2004: Expert witness for independent cost evaluation for rebuild of

12 damaged boiler and associated systems for Hawthorn Unit 5.

13 • 2004: Technical review of diesel generator equipment related to a commercial

14 dispute.

15 • 2001: Testimony at arbitration hearing in Beijing relative to construction and

16 commissioning status of the Zhuzhou Nanfang Cogeneration Power Plant in

17 China.

19 Q. Can you more fully describe Sargent & Lundy?

20 A. Yes. Sargent & Lundy is a full-service architect-engineering firm dedicated to the

21 electric power industry. It has been dedicated exclusively to serving electric power

22 clients since its founding in 1891, making it one of the oldest, largest, and most

23 experienced engineering companies in the United States. During this time, the firm

24 has developed, designed, managed procurement, and conducted construction

25 management for numerous power plants of all types. The facilities have included

RPC-3 18 R. P. CHARLES Line U-18150 No.

1 fossil-fueled (i.e., oil, gas, coal), hydro-, waste-, nuclear-, and solar-powered plants.

2 Sargent & Lundy has conducted numerous site-selection studies and technology

3 assessments, developed cost estimates, performed full design, and managed

4 construction for successfully operating units for many plants and clients. Sargent &

5 Lundy has been authorized to design more than 886 electrical generating units,

6 representing more than 135,000 MW of generating capacity. In recent years, the

7 firm has participated in more than 30,000 MW of new generation projects,

8 comprising approximately 75 units for 45 clients. The scope of services on these

9 projects has encompassed new unit design, plant modifications, owner’s

10 engineering, and due diligence. Sargent & Lundy’s main office is in Chicago,

11 Illinois, with about 2,600 employees in all offices. In addition to its headquarters,

12 Sargent & Lundy's global resources include several regional offices in the United

13 States and affiliated joint venture offices in Baroda, India, and Edmonton, Canada.

15 Q. Have produced any publications?

16 A. Yes, the following: 17 • Solar Vision Study, Chapter 5, Concentrating Solar Power for DOE. 18 Co-chairman for CSP technology review (2010). 19 • Assessment of Parabolic Trough, Power Tower and Dish 20 Technology Cost and Performance Forecasts, Department of Energy 21 and Sandia National Renewable Energy Laboratory (2009). 22 • Assessment of Parabolic Trough and Power Tower Technology Cost 23 and Performance Forecasts, Electric Power Conference (2005). 24 • Assessment of Parabolic Trough and Power Tower Technology Cost 25 and Performance Forecasts, Department of Energy, and National 26 Renewable Energy Laboratory (2003). 27 • Power Plant Performance and Acceptance Testing: An Independent 28 Engineer’s Perspective (1999). 29 • Optimized Nuclear Plant Decommissioning Economics through Re- 30 powering, American Power Conference (1996).

RPC-4 19 DTE ELECTRIC COMPANY DIRECT TESTIMONY OF ROBERT P. CHARLES Line No.

1 Q. What is the purpose of your testimony?

2 A. The purpose of my study is to present the decommissioning study performed by

3 Sargent & Lundy on behalf of DTE Electric Company (DTE Electric or the

4 Company) to support the Company’s depreciation case. The decommissioning

5 study includes a cost estimate and environmental review for the dismantlement and

6 scrap of a number of coal-fired Sites, gas-fired Sites, diesel-fired peakers, wind

7 farms, solar photovoltaic (PV) arrays, and landfill sites.

9 Q. Are you sponsoring any exhibits in the proceeding?

10 A. Yes. I am sponsoring all or parts of the following exhibits:

11 Exhibit Schedule Description

12 A-14 N1 Decommissioning Study Report (Renewable Energy

13 Sites)

14 A-14 N2 Decommissioning Study Report (Peak Energy Sites)

15 A-14 N3 Decommissioning Study Report (Steam Generation

16 Sites)

17 A-14 N4 Decommissioning Study Report (Landfills)

19 Q. Was this exhibit and the associated schedules prepared by you or under your

20 direction?

21 A. Yes, they were.

23 OVERVIEW OF THE DEMOLITION STUDY

24 Q. Will you provide an overview of the Study?

RPC-5 20 R. P. CHARLES Line U-18150 No.

1 A. The study evaluated the cost for the demolition of DTE Electric Company’s (DTE

2 Electric or the Company) coal/oil/gas/ fired power plants, as well as the Company’s

3 Wind and Solar projects

5 Q. What methodology did you use to study each plant?

6 A. The methodology used for developing the cost estimate includes a combination of

7 stochastic and deterministic methods. Stochastic means that which may be

8 statically analyzed but not precisely predicted. Deterministic methods were used

9 based on the quantity and size of equipment (e.g., the number of foundations, linear

10 feet of cable, equipment, and so forth). Stochastic methods were also used if

11 quantity information (e.g., miscellaneous electrical equipment, etc.) was not

12 available. The cost estimate was developed based on drawings, documents, and

13 data provided by DTE Electric. These drawings and documents were used to

14 estimate the foundation sizes, steel and copper quantities, quantity of cables, and

15 other equipment. The methodology I used for developing the cost estimate consists

16 of three elements: (1) our experience in developing plant demolition costs and our

17 existing database for numerous other projects; (2) the use of unit cost factor

18 methodology; and (3) quotes for previous projects for similar activities. Cost

19 estimates were created using the Sargent & Lundy cost model format and the

20 Sargent & Lundy cost database. The estimates developed include both summaries

21 and details for each type of work performed, indirect costs, and contingencies. The

22 cost estimate database report lists costs by material, activity, and several other

23 categories. An inventory of plant equipment, materials, and other items was

24 developed based on a review of drawings and data provided. Members of the

25 Sargent & Lundy staff at my direction visited representative sites and performed

RPC-6 21 R. P. CHARLES Line U-18150 No.

1 site walkdowns to conduct a review of the site for dismantlement. Sargent &

2 Lundy visited the Sigel Wind Park, as a representative of the portfolio of DTE wind

3 parks. All the wind turbines in DTE’s portfolio are GE-1.6 & 1.7 wind turbine

4 generators. DTE Greenwood Solar, and Riopelle Farm Solar sites were visited as

5 representatives of all the solar sites in DTE’s portfolio. This information was used

6 with unit cost factors developed by Sargent & Lundy based on industry data and our

7 experience. Unit cost factors for concrete removal, steel removal, cutting costs, and

8 other tasks were developed from labor and material cost information. Sargent &

9 Lundy estimated the quantities of recoverable metals that could be recovered and

10 sold for scrap. No salvage value was assumed for any equipment, only the scrap

11 value of metal from equipment.

13 Q. Was the study prepared under your direction?

14 A. Yes.

16 Q. When was the study performed?

17 A. The Study was performed in 2016 and provided to DTE Electric in August 2016.

19 Q. Which units are included in the study?

20 A. The sites are described on Tables 1-5.

RPC-7 22 R. P. CHARLES Line U-18150 No. 1 TABLE 1 2 STEAM GENERATING SITES 3 Summer Number of Site Capability Year in Service Location Units (MW) Coal Fired Belle River (81.39% 1,036 2 1984, 1985 East China, MI ownership) Monroe 3,080 4 1971, 1973, 1974 Monroe, MI River Rouge 542 2 1957, 1958 River Rouge, MI 1953, 1954, 1959, Saint Clair 1,416 6 East China, MI 1961, 1969 Trenton Channel 609 3 1949, 1968 Trenton, MI Original 7 units 1915; 2 units added 1951; Conner’s Creek 300 2 Detroit, MI Original 7 demo 1996; Gas conv. 1999 Natural Gas Fired Greenwood 785 1 1979 Avoca, MI 4 5 TABLE 2 6 PEAKER ENERGY SITES 7 Winter Number of Site Capability Year in Service Location Units (MW) Combustion Turbine Belle River 279 3 – GE Frame 7 1999 East China, MI Delray 159 2 – GE Frame 7 2000 Detroit, MI Greenwood 279 3 – GE Frame 7 1999 Avoca, MI Enrico Fermi 2 75 4 – GE Frame 5 1966 Newport, MI 4 – W-251A; 1967; 1969; Hancock 183 Commerce Twp., MI 2 – FT-4 Twin 1970 5 – GE Frame 1966; Northeast 150 5; Warren, MI 1971 2 – FT-4 Saint Clair 19 1 – FT-4 1968 Saint Clair, MI Superior 76 4 – GE Frame 5 1966 Superior Twp., MI 4-Siemens Renaissance 776 2002 Carson City, MI 501FD2

RPC-8 23 R. P. CHARLES Line U-18150 No. Winter Number of Site Capability Year in Service Location Units (MW) Dean 384 GE Frame 7 2002 East China, MI Diesel Engines Belle River 13.75 5 Pre-2009 East China, MI Colfax 13.75 5 Post-2009 Fowlerville, MI Monroe 13.75 5 Pre-2009 Monroe, MI Oliver 13.75 5 Post-2009 Oliver, MI Springfield Placid 13.75 5 Post-2009 Township, MI Putnam 13.75 5 Post-2009 Mayville, MI River Rouge 11.00 4 Pre-2009 River Rouge, MI Slocum 13.75 5 Pre-2009 Trenton, MI St. Clair 5.50 2 Post-2009 East China, MI Wilmot 13.75 5 Post-2009 Kingston, MI 1 2 TABLE 3 3 RENEWABLE ENERGY SITES 4 Nameplate Number Year in Site Capacity Location of Units Service (MW) Wind Farms Brookfield, Fairhaven, Grant, Oliver, Sebewaing, and Brookfield 74.8 44 2014 Windsor Townships - Huron County Elkton, Chandler, and Oliver Echo 112 70 2014 Townships - Huron County Breckenridge, Bethany, Gratiot County 102.4 64 2012 Wheeler, and Porter Townships - near Breckenridge, MI Thumb: McKinley 14.4 9 2012 Huron County Thumb: Minden 32 20 2012 Sanilac County Thumb: Sigel 64 40 2012 Huron County 5 6

RPC-9 24 R. P. CHARLES Line U-18150 No. 1 TABLE 4 2 SOLAR ENERGY SITES 3 Nameplate Number Year in Site Capacity Location of Panels Service (kW) Solar Installations Scio Township 60.48 270 2010 Scio Township, MI UM Information 241.4 1,006 2013 Ann Arbor, MI Science GM Orion 345.6 1,440 2012 Lake Orion, MI Assembly Plant DTE – Training and 391.4 1,716 + 24 2011 Westland, MI Development Center UM North Campus Research 430.56 1,794 2012 Ann Arbor, MI Complex (Plymouth Rd) Hartland Consolidated 443.88 1,728 + 12 2013 Hartland, MI Schools Will-Le Farms 483.84 2,016 2012 Bad Axe, MI Huron Clinton Metroparks – 495.36 2,064 2012 White Lake, MI Indian Springs Park Ford Wayne 502.32 2,184 2011 Wayne, MI Assembly Plant Brownstown 504 1,800 2015 Brownstown Township, MI Leipprandt 511.2 1,992 + 12 2013 Pigeon, MI Orchard Monroe County Community 513.24 2,184 2011 Monroe, MI College Riopelle Farms 514.08 2,016 2013 Harbor Beach, MI GM Hamtramck – Assembly 516.096 4,032 2011 Detroit, MI Plant St. Clair Regional 517.32 2,016 + 12 2013 Marysville, MI Education Service Agency

RPC-10 25 R. P. CHARLES Line U-18150 No. Nameplate Number Year in Site Capacity Location of Panels Service (kW) Sisters – Servants of 518.4 2,160 2012 Monroe, MI IHM Thumb Electric 663.24 2,592 + 12 2015 Caro, MI Romulus 752.4 2,736 2015 Romulus, MI McPhail 816.48 3,024 2014 Wixom, MI Properties Domino’s 1088.64 4,032 2015 Arbor, MI Farms DTE 1948.8 6,960 2016 Avoca, MI Greenwood DTE Energy 80.64 336 2012 Detroit, MI Headquarters Warren Consolidated 189 840 2012 Sterling Heights, MI Schools Blue Cross Blue 219.96 936 2011 Detroit, MI Shield Mercy High 402.3 1,788 2011 Farmington Hills, MI School Ford Head 1038.24 3,708 2015 Dearborn, MI Quarters 1 2 TABLE 5 3 LANDFILL SITES 4 Site Location

Landfill Sites Monroe Landfill Site Monroe, MI Sibley Landfill Site Riverview, MI (Sibley Quarry) Range Road Landfill Site St. Clair, MI

6 Q. Will you summarize the costs identified in the Decommissioning Study?

7 A. The site name and cost estimate for decommissioning are tabulated below:

RPC-11 26 R. P. CHARLES Line U-18150 No.

2 TABLE 6

Sites Cost ($-millions)

Solar 8.3

Wind 55.7

Peakers-CTG 8.0

Peakers-Diesel 4.6

Belle River 81.39% DTE 54.3

Monroe 190.4

St. Clair 110.0

Trenton 47.8

River Rouge 51.5

Connors Creek 35.0

Greenwood 37.6

Monroe Ash Pond 38.5

Sibley Quarry 24.5

Range Road 2.2

Total 668.4

4 Q. Was a contingency factor used in developing the costs in the study?

5 A. Yes, a contingency factor was applied against the estimated dismantling costs. The

6 factor utilized is standard in the industry.

8 Q. Why is this contingency factor applied?

RPC-12 27 R. P. CHARLES Line U-18150 No.

1 A. The Contingency factor is applied to estimate the unforeseeable elements that occur

2 during the actual execution of a project. Utilization of a contingency factor is a

3 well established, industry standard practice for both construction and demolition.

4 The amount of contingency is based upon the type of study being done, the degree

5 of information available and professional judgment. The contingency factor that I

6 applied is appropriate based on my professional judgment and the type of projects

7 involved.

9 Q. What is the plan for reuse of the sites?

10 A. Because of the uncertainty of the type and size of future generation, each site was

11 left as an improved industrial site.

13 Q. Can you summarize your conclusions?

14 A. The costs developed for this study of the dismantling of the DTE Electric plants

15 reasonably and accurately reflect the cost of removing the plant material from the

16 site and restoring the site.

18 Q. Does the study fairly represent the present day cost of demolishing each of the

19 plants in your opinion?

20 A. Yes.

22 Q. Does your decommissioning study address certain issues from MPSC Case No.

23 U-16991?

24 A. Yes. In the Commission’s July 8, 2014 Order (July 8th Order) in Case U-16991,

25 DTE Electric’s depreciation case for renewable energy assets, the Commission

RPC-13 28 R. P. CHARLES Line U-18150 No.

1 directed the Company to provide in its next depreciation case, the items below,

2 which I addressed in my decommissioning study:

3 1. An analysis of at least two dismantlement methods for wind turbines; (See

4 pages 30-31 of Exhibit A-14, Schedule N1);

5 2. The necessary clarity around the construction and removal of crane pads (See

6 pages 31-32 of Exhibit A-14, Schedule N1);

7 3. Details concerning the specific costs for overhead and profit, general conditions,

8 indirect and direct costs in the Company's decommissioning study (See pages

9 33-34 of Exhibit A-14, Schedule N1; pages 28-29 of Exhibit A-14, Schedule

10 N2; and pages 40-41 of Exhibit A-14, Schedule N3);

11 4. More support for the selection of transformer scrap value in the Company's

12 decommissioning study (See pages 33-34 of Exhibit A-14, Schedule N1; pages

13 28-29 of Exhibit A-14, Schedule N2; and page 41 of Exhibit A-14, Schedule

14 N3.); and,

15 5. A complete explanation of overhead costs for wind and for solar, including an

16 explanation of why these costs differ, if appropriate (See pages 33-34 of Exhibit

17 A-14, Schedule N1)

19 Q. Does this conclude your direct testimony?

20 A. Yes, it does.

RPC-14 29

1 MR. CHRISTINIDIS: Thank you, your Honor.

2 The Company's next witness would consist of the Corrected

3 Rebuttal Testimony of Kevin J. Chreston. That testimony

4 consists of a cover sheet and 12 pages of questions and

5 answers. Mr. Chreston is not sponsoring any exhibits.

6 The Company would move to bind into the record the

7 Qualifications and Corrected Rebuttal Testimony of Kevin

8 J. Chreston.

9 JUDGE FELDMAN: All right. Let me ask

10 for the record if there are any objections to Mr.

11 Christinidis's request regarding Mr. Chreston's

12 testimony? Hearing no objections, the prefiled Corrected

13 Rebuttal Testimony of Kevin J. Chreston will be bound

14 into the record.

15 (Testimony bound in.)

25 Metro Court Reporters, Inc. 248.360.8865 30

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) DTE ELECTRIC COMPANY ) for approval of depreciation accrual rates ) Case No. U-18150 and other related matters )

QUALIFICATIONS

AND

CORRECTED REBUTTAL TESTIMONY

KEVIN J. CHRESTON 31 DTE ELECTRIC COMPANY QUALIFICATIONS OF KEVIN J. CHRESTON Line No.

1 Q. What is your name, business address and by whom are you employed?

2 A. My name is Kevin J. Chreston. My business address is One Energy Plaza, Detroit,

3 Michigan 48226. I am employed by the DTE Electric Company (DTE Electric or

4 Company), formerly known as The Detroit Edison Company (Detroit Edison), as

5 Manager, IRP & Modeling.

7 Q. Please state your educational background.

8 A. My formal education consists of a Bachelor of Science degree in Mechanical

9 Engineering from Oakland University. I have also completed several Company

10 sponsored courses and have attended various seminars to further my development with

11 DTE Electric.

13 Q. What is your present position with DTE Electric Company?

14 A. In 2007, I was promoted to my current position, Manager – IRP & Modeling, where

15 I am responsible for developing and analyzing DTE Electric’s Integrated Resource

16 Plan, which includes the evaluation of environmental plans for the generation

17 portfolio. The IRP and Modeling team is part of Business Planning and Development

18 in DTE Electric.

20 Q. Please describe your business experience.

21 A. In 1982, I joined Detroit Edison and was assigned to the Production Organization

22 (later named Fossil Generation) as an assistant engineer at St. Clair Power Plant. In

23 this position, I worked on various projects related to improving unit operation and

24 maintenance. I also worked as the Waste Water Engineer and Fuel Supply Engineer.

25 In 1987, I was assigned to Belle River Power Plant and promoted to Engineer, where

KJC Rebuttal - 1 32 K. J. CHRESTON Line U-18150 No.

1 I provided technical support for daily operations and maintenance as well as managed

2 forced and periodic outages. In late 1988, I was assigned to the North Area Plants

3 and was responsible for Engineering and Outage Management duties at Marysville,

4 Harbor Beach and Greenwood Plants. In 1990, I returned to St. Clair Power Plant

5 and worked as the Thermal Performance Engineer and as the lead Turbine Engineer

6 on several periodic outages.

8 In 1991, I went on a temporary assignment with Energy Resources – Power Supply,

9 where I worked on business development projects in biomass, auto company energy

10 partnerships and PURPA Qualified Facility tracking. In 1992, I was promoted to

11 Senior Engineer, Resource Planning – Power Supply. I was responsible for

12 evaluating / recommending generation capacity additions and long-term power

13 purchases or sales. I also had an integral role in developing the Company’s Integrated

14 Resource Plan (IRP) and supported several cases before the Michigan Public Service

15 Commission (MPSC or Commission).

17 In 1996, I was promoted to Specialist Fuel Resources – Fuel Supply. While in Fuel

18 Supply, my responsibilities included coal procurement, contract negotiation and

19 administration, assisting in the generation of short and long-term fuel plans and

20 support of the Power Supply Cost Recovery (PSCR) Fuel witness.

22 In 2001, I was promoted to Technical Specialist, Generation Optimization, where I

23 was responsible for the development and evaluation of long-term strategies involving

24 fuel, power sales/purchases, generating assets and environmental issues, for the

25 power generation portfolio. I also served as generation representative on a multi-

KJC Rebuttal - 2 33 K. J. CHRESTON Line U-18150 No.

1 department team charged with the sale and operational transition of the transmission

2 system.

4 In 2002, I was promoted to Supervisor Portfolio Strategies – Generation

5 Optimization, where I was responsible for the long-term generation forecast, support

6 of the PSCR power supply witness, development and evaluation of long-term

7 strategies involving fuel, power sales/purchases, generating assets and environmental

8 issues. I also worked on the Capacity Needs Forum and 21st Century Energy Plans

9 as generation and modeling representative for Detroit Edison.

11 In 2007, I was promoted to my current position, Manager – IRP & Modeling.

13 Q. Have you been involved in prior proceedings before the Michigan Public Service

14 Commission (Commission or MPSC)?

15 A. Yes. I am a witness in:

16 U-18419 2017 CON Filing

18 I also supported testimony in the following cases:

19 U-11175 1997 PSCR Plan

20 U-14275 2005 PSCR Plan

21 U-13808 Main Electric Rate Case

22 U-17097 2013 PSCR Plan

23 U-17767 2014 Main Electric Rate Case

24 U-18091 PURPA Avoided Cost Filing

KJC Rebuttal - 3 34 K. J. CHRESTON Line U-18150 No.

1 Additionally, I was a rebuttal witness in the following case:

2 U-17319 2014 PSCR Plan

KJC Rebuttal - 4 35 DTE ELECTRIC COMPANY CORRECTED REBUTTAL TESTIMONY OF KEVIN J. CHRESTON Line No.

1 Q. Did you file direct testimony in this proceeding on behalf of DTE Electric?

2 A. No, I did not.

4 Q. What is the purpose of your testimony?

5 A. The purpose of my testimony is to rebut Commission Staff Witness Mr. Ronald J.

6 Ancona and Association of Businesses Advocating Tariff Equity (ABATE) Witness

7 Mr. Brian C. Andrews regarding statements relating to DTE’s proposed coal fleet

8 retirement dates.

10 Q. What are your thoughts with respect to Mr. Andrew’s statement, at page 9 of his

11 direct testimony, that DTE has not provided justification for the currently

12 proposed plant retirement dates?

13 A. I disagree. As requested in ABDE 1.7, DTE Electric has provided documentation of

14 economic analysis supporting the new proposed retirement dates (Exhibit AB-1).

16 Q. What are your thoughts with respect to Mr. Andrew’s statement, at page 9 of his

17 direct testimony, that DTE’s proposed early retirement dates are largely based

18 on the implementation of the Clean Power Plan?

19 A. I disagree. Due to changes to the Steam Electric Effluent Limitation Guidelines (ELG)

20 and the Cooling Water Intake Regulations (316(b)), the Company performed an

21 analysis to evaluate the impact of investing capital to comply with revised regulations

22 or retiring units prior to the compliance deadline dates. In, addition to that economic

23 analysis other integrated resource planning principles of Reliability, Clean, Flexible

24 and Balanced, Compliant, and Reasonable Risk were considered. Thus, the Clean

25 Power Plan was but one consideration among many others.

KJC Rebuttal - 5 36 K. J. CHRESTON Line U-18150 No.

1 Q. Can you elaborate on DTE’s integrated resource planning principles?

2 A. Reliability is an important integrated resource planning requirement. Plant age is a

3 major factor when considering the reliability of Tier II plants.

5 Affordability is another consideration. Details of the economic analysis of plant

6 retirements are described in sections below.

8 The IRP planning principle “Clean” refers to environmental sustainability and low

9 carbon aspirations, considered as major factors in the determination of the proposed

10 course of action. The Company is committed and has a long history of environmental

11 conservation and stewardship.

13 Flexible and Balanced refers an optimum mix of base, peaking, and non-dispatchable

14 generation that best serves our Company’s load profile and the rest of MISO.

16 The final integrated resource planning principle is Reasonable Risk. By establishing

17 and maintaining a resource portfolio that has a good balance of generation fueled by

18 coal, nuclear, gas and renewables, the Company believes risks around uncertain fuel

19 costs and fuel availability are mitigated.

21 Q. Mr. Andrews asserts, at page 9 of his direct testimony, that DTE has not

22 performed an integrated resource plan that justifies shortening the retirement

23 dates. How do you respond?

24 A. Mr. Andrews and ABATE is, or should be, well aware that DTE has completed

25 numerous economic evaluations of plant retirements over a period of years and within

KJC Rebuttal - 6 37 K. J. CHRESTON Line U-18150 No.

1 the Company’s integrated resource plan (IRP) and CON filing in Case No. U-18419

2 which was filed on July 31, 2017.

4 Q. How do you respond to Mr. Ancona’s belief, at page 10 of his direct testimony,

5 that the Commission should wait until the Commission has evaluated the

6 retirement decisions in an IRP before adjusting depreciation accrual rates

7 reflecting new retirement dates?

8 A. I see no reason to wait. The proposed plant retirements are no surprise to the

9 Commission as the Company has made its intentions clear over a period of years. In

10 fact, in anticipation of these plant retirements the Commission has directed the

11 Company to be especially cautious in making new capital investments in DTE

12 Electric’s Tier II plants. This is supported through the Commission’s statements in

13 Case No. U-16472; “Detroit Edison’s proposed capital expenditures for its marginal

14 generating units are relatively modest and appear reasonable at this point. Nevertheless,

15 the Commission agrees with the Staff and the Environmental Coalition that Detroit

16 Edison should be on notice that any capital investments made in the test year and

17 beyond in its marginal generating plants will be subject to particular scrutiny if a plant

18 is subsequently shut down with a positive plant balance.”

20 Furthermore, a very recent plant retirement analysis has already been completed as a

21 part of DTE’s IRP and CON filing (Case No. U-18419). A delay of a decision is not

22 necessary.

24 Q. How did your team perform the economic evaluation portion of the Retirement

25 Analysis?

KJC Rebuttal - 7 38 K. J. CHRESTON Line U-18150 No.

1 A. Where appropriate, the Company established groups of generation units with similar

2 operating characteristics and economics to evaluate together. Units that did not fit

3 into a group were considered individually. St. Clair units 1-4 were considered as a

4 group, Belle River units 1 and 2 as a group, and Monroe units 1-4 as a group; St.

5 Clair 6, St. Clair 7, Trenton Channel 9, and River Rouge 3 were all considered

6 individually.

8 The economic evaluation portion of the retirement analysis compared a case of

9 retirement of each of the unit groups and the other four individual units before 2023

10 when retrofits would be required versus a case that assumed the Company would

11 spend the capital to make the retrofits and extend unit retirements to a later date. In

12 all cases, the units were assumed to be replaced with natural gas combined cycle

13 units.

15 The later retirement dates used in the comparison to 2023 retirement dates are:

16 17 Modeled Retirement Date 18 Unit Group For Retirement Analysis

19 St. Clair 1-4 2028

20 St. Clair 6 2028

21 St. Clair 7 2028

22 River Rouge 3 2028

23 Trenton 9 2028

24 Belle River 1-2 2029 and 2030

25 Monroe 1-4 2040

KJC Rebuttal - 8 39 K. J. CHRESTON Line U-18150 No.

1 The later retirement dates were assumed to be five years past the ELG and 316(b)

2 regulation compliance date for St. Clair, River Rouge, and Trenton 9. This additional

3 period of operation is limited due to the age of the units, risk of failure, and

4 uncertainty about environmental regulations, including CO2. Years 2029 and 2030

5 were used for retirement of Belle River due to its more recent vintage compared with

6 the former units. For Monroe, the Company assumed retirement in 2040 since it is

7 equipped with Selective Catalytic Reduction (SCR) and scrubbers for NOX and SO2

8 which permit the plant to comply with all reasonably contemplated emissions

9 standards.

11 Q. What were the capital assumptions for the environmental retrofits?

12 A. The capital assumptions are shown in the chart below:

13 14 Figure 1: DTE Electric Capital Assumptions for Environmental Retrofits Needed 15 for Continued Operation of Coal Fired Units

Unit SC 1-4 SC 6 SC 7 TC9 RR3 BR MN

Capital (2016M$) ELG $60 $20 $20 $20 $20 $30 $200

316(b) $25 $10 $15 $25 $4 $1 $50

KJC Rebuttal - 9 40 K. J. CHRESTON Line U-18150 No.

1 Q. What were the results of the Economic evaluation portion of the Retirement

2 analysis?

3 A. The results of the base case are as follows:

5 Figure 2: Results of the Retirement NPV analysis

NPV (Million 2016$) Retirement Case minus Retrofit and keep unit in operation

Unit SC 1-4 SC 6 SC 7 TC9 RR BR MN

Base Retrofit Case ($84) ($50) ($32) ($31) ($36) $232 $2,085

7 Negative numbers indicate it is better to retire a unit in 2023 or before; positive

8 numbers indicate more value and a reasonable basis to keep the units in service until

9 2028 or later. The economics from this study indicate that it is better to retire St.

10 Clair, Trenton 9, and River Rouge before the Environmental Retrofits are required in

11 2023 and it is better to keep operating Belle River and Monroe and make them

12 compliant to the ELG and 316(b) regulations.

14 Q. What scenarios or sensitivities did you run on the economic evaluation?

15 A. The Company ran higher capital sensitivities, low capacity market price sensitivities,

16 and a CO2 sensitivity for each of the unit groups, with the exception of Monroe.

17 Monroe was economic in the Base scenario to the tune of $2 Billion NPV, so there

18 was no need to run additional sensitivities on that plant. The results are shown in

19 Figure 3, below:

KJC Rebuttal - 10 41 K. J. CHRESTON Line U-18150 No.

1 Figure 3: DTE Electric Results of NPV Analysis Sensitivity

Unit SC 1-4 SC 6 SC 7 TC9 RR BR

Base Retrofit Case ($84) ($50) ($32) ($31) ($36) $232

High ELG Capital ($108) ($58) ($40) ($39) ($44) $219

CO2 Prices ($127) ($68) ($52) ($62) ($63) $128

Low Capacity Price ($82) ($1) $10 $5 $11 $215

3 The results of the sensitivities agreed with the Base Retrofit case since the results

4 show it is better to avoid the capital expenditures to achieve environmental

5 compliance on St. Clair 1-4, 6, & 7, Trenton Channel 9, and River Rouge and retire

6 the units with a natural gas combined cycle replacement. For Belle River, the results

7 show it is better to spend the money on the retrofit and keep the unit at least another

8 five years. In the low capacity price case, the NPV is positive toward continued

9 operation for units St. Clair 7, Trenton 9, and River Rouge. However, the values are

10 still close to even and are outweighed by the other sensitivities summarized in Figure

11 3, above.

13 Q. Why are the results of the low capacity price sensitivity more favorable to keep

14 the coal units than the base case for St. Clair, Trenton and River Rouge units?

15 A. In this analysis, a smaller natural gas combined cycle was used when the units were

16 not retired. In these cases, more capacity purchases are needed in combination with

17 the longer lived coal unit to equalize the larger natural gas combined cycle in the

18 retire case. Therefore, when capacity prices are lower, this results in more favorable

19 economics to keep Tier II units in operation.

KJC Rebuttal - 11 42 K. J. CHRESTON Line U-18150 No.

1 Q. How do these results from Figures 2 and 3 translate to coal unit retirements?

2 A. Based on the economic analysis described above as well as factoring in the other

3 integrated resource planning principles of Reliability, Clean, Flexible and Balanced,

4 Compliant, and Reasonable Risk into the Retirement study, the following retirement

5 schedule for coal units was generated:

6 Announced Assumed Date 7 Unit Date for IRP Modeling

8 River Rouge 3 Before Dec 2023 May 31, 2020

9 St. Clair 1-4 Before Dec 2023 May 31, 2022

10 St. Clair 6 Before Dec 2023 May 31, 2022

11 St. Clair 7 Before Dec 2023 May 31, 2023

12 Trenton Chanel 9 Before Dec 2023 May 31, 2023

13 Belle River 1 2030 May 31, 2029

14 Belle River 2 2030 May 31, 2030

15 Monroe 1-4 2040 Post IRP study period (2040)

17 The date of May 31 is used in the IRP modeling, because that date is in alignment

18 with the MISO capacity year. The coal unit retirement dates shown above are

19 consistent with the assumptions used in the recent CON filing (U-18419).

21 Q. Does this complete your rebuttal testimony?

22 A. Yes, it does.

KJC Rebuttal - 12 43

1 MR. CHRISTINIDIS: The Company's next

2 witness, your Honor, is Edward T. Henderson. He

3 sponsored Qualifications and Direct Testimony consisting

4 of a cover page and 12 pages of questions and answers.

5 Mr. Henderson is not sponsoring any exhibits. And the

6 Company would move to bind into the record the

7 Qualifications and Direct Testimony of Mr. Henderson.

8 JUDGE FELDMAN: All right. Any

9 objections to binding in Mr. Henderson's prefiled

10 testimony? Hearing no objections, the prefiled Direct

11 Testimony of Edward T. Henderson will be bound into the

12 record.

13 (Testimony bound in.)

25 Metro Court Reporters, Inc. 248.360.8865 44

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) DTE ELECTRIC COMPANY ) for approval of depreciation accrual rates ) Case No. U-18150 and other related matters )

QUALIFICATIONS

AND

DIRECT TESTIMONY

EDWARD T. HENDERSON

45 DTE ELECTRIC COMPANY QUALIFICATIONS OF EDWARD T. HENDERSON Line No.

1 Q. What is your name, business address and by whom are you employed?

2 A. My name is Edward T. Henderson. My business address is: One Energy Plaza,

3 Detroit, Michigan 48226. I am employed by DTE Electric Company (DTE Electric

4 or the Company) within Business Planning & Development as Manager, Renewable

5 Energy Operations.

7 Q. On whose behalf are you testifying?

8 A. I am testifying on behalf of DTE Electric.

10 Q. What is your educational background?

11 A. I graduated from Western Michigan University with a Bachelor of Science degree

12 in Engineering (Mechanical). I graduated from University of Detroit Mercy with a

13 Master degree in Business Administration.

15 Q. Do you have any professional licenses or certifications?

16 A. Yes. I am a Registered Professional Engineer in the State of Michigan.

18 Q. What work experience do you have?

19 A. In 1981, I joined DTE Electric as an Associate Engineer in Fossil Generation.

20 From 1981 until 1987, I worked in the Company’s coal and nuclear facilities on

21 maintenance and operational activities. I progressed to a Senior Engineer during

22 this time. In 1987, I joined the Company’s Marketing Department as a Space

23 Conditioning Engineer. In this role I consulted with industrial and commercial

24 customers on their energy usage and ways to more efficiently use their energy.

ETH - 1 46 E. T. HENDERSON Line U-18150 No.

1 In 1992, I became a Principal Supervisor in Demand Side Management. I was

2 responsible for managing the energy efficiency audit and rebate programs for

3 commercial and industrial customers. In 1994, I became Principal Supervisor of the

4 Energy Partnership. I was responsible for a team of over twenty engineers and

5 energy managers co-located at General Motors, Ford and Chrysler automotive

6 facilities. The team was responsible for helping the automotive customers manage

7 their energy usage and manage projects to improve energy efficiency. I took on a

8 temporary assignment as a Principa1 Supervisor at DTE Energy Technologies Inc.

9 from 1999 until 2002. I was responsible for product development, product

10 management and service for gas and diesel emergency generators for homes and

11 businesses.

13 From 2002 to 2006, I worked in various supervisory roles in the Company’s

14 Marketing department. In these roles, I supervised teams that provided technical

15 support for industrial and commercial electric customers.

17 I became Manager of Community Lighting in 2006. The Community Lighting

18 department is responsible for the construction and asset maintenance of all of the

19 Company-owned streetlights and outdoor protective lights.

21 Q. What is your current position?

22 A. I am Manager of Renewable Energy Operations. I assumed this role in April 2014. I

23 am responsible for maintenance and operation of all DTE-owned wind and solar

24 facilities.

ETH - 2 47 DTE ELECTRIC COMPANY DIRECT TESTIMONY OF EDWARD T. HENDERSON Line No.

1 Q. What is the purpose of your testimony in this proceeding?

2 A. The purpose of my testimony is to describe the wind and solar projects that are

3 included in this depreciation case. I will also respond to certain directives from the

4 Commission’s July 8, 2014 order (2014 Order) in Case No. U-16991, including

5 alternative uses of wind and solar facilities at the expected end of their useful lives.

7 Q. Are you sponsoring any exhibits in this proceeding?

8 A. No, I am not.

10 Q. Which projects formed the basis of the DTE Electric renewable energy

11 depreciation study?

12 A. All wind and solar generating assets which are currently operational were considered

13 for the basis of the depreciation study. This includes six wind parks and twenty six

14 solar arrays. These projects are comprised of DTE Electric-owned generating assets

15 located both on Company-owned land and customer property secured via easement

16 agreement. A detailed list of these projects is located in Table 1.

18 TABLE 1: Nameplate Underlying Year in Capacity Wind Project Property Type Service (MW) 1 Gratiot 102.4 Easement 2012 2 Brookfield 74.8 Easement 2014 3 Echo 112.0 Easement 2014 4 Thumb: McKinley 14.4 Easement 2012 5 Thumb: Minden 32.0 Easement 2012 6 Thumb: Sigel 64.0 Easement 2012

ETH - 3 48 E. T. HENDERSON Line U-18150 No. Nameplate Underlying Year in

Solar Project Capacity (kW) Property Type Service Company- 1 Scio Township 60.00 2010 owned land 2 Ford Michigan Assembly (Wayne) 502.00 Easement 2011 Monroe County Community 3 513.00 Easement 2011 College 4 Blue Cross Blue Shield (Detroit) 220.00 Easement 2011 GM Chevy Volt Plant 5 516.00 Easement 2011 (Hamtramck) DTE Training & Development Company- 6 391.00 2011 Center (TDC) owned land 7 Mercy High School 394.00 Easement 2011 8 UM Information Science 241.40 Easement 2013 9 GM Orion Assembly Plant 345.60 Easement 2012 UM North Campus Research Easement 10 430.56 2012 Complex (Plymouth Rd) 11 Hartland Consolidated Schools 443.88 Easement 2013 12 Will-Le Farms 483.84 Easement 2012 Huron Clinton Metroparks – Easement 13 495.36 2012 Indian Springs Park 14 Brownstown 504.00 Easement 2015 15 Leipprandt Orchard 511.20 Easement 2013 16 Riopelle Farms 514.08 Easement 2013 St. Clair Regional Education Easement 17 517.32 2013 Service Agency 18 Sisters – Servants of IHM 518.40 Easement 2012 19 Thumb Electric 663.24 Easement 2015 20 Romulus 752.40 Easement 2015 21 McPhail Properties 816.48 Easement 2014 22 Domino’s Farms 1,088.64 Easement 2015 Company- 23 DTE Greenwood 1,948.80 2016 owned land Company- 24 DTE Energy Headquarters 80.64 2012 owned land 25 Warren Consolidated Schools 189.00 Easement 2012 26 Ford Headquarters 1,038.24 Easement 2015

2 Q. Why were these projects selected?

3 A. These projects comprised DTE Electric’s entire operating wind and solar portfolio at

4 the time of the depreciation study. As such, they represent wind and solar projects

ETH - 4 49 E. T. HENDERSON Line U-18150 No.

1 with well-understood costs and with characteristics that DTE Electric expects to be

2 representative of the Company’s (long-run) wind and solar generation portfolios.

3 These characteristics include technology and/or equipment type, system design,

4 project size, terrain, location, and decommissioning requirements.

6 Q. What is the structure of the rest of your testimony?

7 A. I will provide an overview of each of the aforementioned wind projects, as well as a

8 representative sample of solar projects.

10 WIND PARKS

11 Q. Please provide an overview of the Wind Parks listed in Table 1.

12 A. The Gratiot Wind Park is a DTE Electric wind-powered electric generating facility

13 located on approximately 16,000 acres near Breckenridge, MI, principally in Gratiot

14 County. It has a nameplate capacity of 102.4 MW and is comprised of sixty-four (64)

15 GE 1.6-xle wind turbines (82.5-meter rotors and 100-meter hub height) and associated

16 equipment and property. Power generated in the nacelle of the wind turbines is sent

17 down through the turbine towers, collected via underground cables and centralized at a

18 collector substation, where the voltage is stepped up from 34.5 kV to 138 kV. From

19 that point the 138-kV power travels along a generator lead line to the point of

20 interconnection with Michigan Electric Transmission Company’s (METC’s)

21 transmission network.

23 The Brookfield Wind Park is a DTE Electric wind-powered electric generating facility

24 located on approximately 14,000 acres in Brookfield, Grant, Sebewaing and Windsor

25 Townships, principally in Huron County, MI. It has a nameplate capacity of 74.8 MW

ETH - 5 50 E. T. HENDERSON Line U-18150 No.

1 and is comprised of forty-four (44) GE 1.7-100 wind turbines (100-meter rotors and

2 80-meter hub height) and associated equipment and property. Power generated in the

3 nacelle of the wind turbines is sent down through the turbine towers, collected via

4 underground cables and centralized at a collector substation, where the voltage is

5 stepped up from 34.5 kV to 345 kV. From that point the 345-kV power travels along

6 a generator lead line to the point of interconnection with International Transmission

7 Company’s (ITC’s) transmission network.

9 The Echo Wind Park is a DTE Electric wind-powered electric generating facility

10 located on approximately 18,000 acres in Chandler, McKinley, and Oliver Townships,

11 principally in Huron County, MI. It has a nameplate capacity of 112 MW and is

12 comprised of seventy (70) GE 1.6-100 wind turbines (100-meter rotors and 96-meter

13 hub height) and associated equipment and property. Power generated in the nacelle of

14 the wind turbines is sent down through the turbine towers, collected via underground

15 cables and centralized at a collector substation, where the voltage is stepped up from

16 34.5 kV to 41.57 kV. From that point the 41.57-kV power travels along a generator

17 lead line to the point of interconnection with DTE Electric’s distribution network.

19 The McKinley Wind Park is a DTE Electric wind-powered electric generating facility

20 located on approximately 2,200 acres in McKinley Township, principally in Huron

21 County, MI. It has a nameplate capacity of 14.4 MW and is comprised of nine (9) GE

22 1.6-100 wind turbines (100-meter rotors and 100-meter hub height) and associated

23 equipment and property. Power generated in the nacelle of the wind turbines is sent

24 down through the turbine towers, collected via underground cables and centralized at a

25 collector substation, where the voltage is stepped up from 34.5 kV to 41.57 kV. From

ETH - 6 51 E. T. HENDERSON Line U-18150 No.

1 that point the 41.57-kV power travels along a generator lead line to the point of

2 interconnection with DTE Electric’s distribution network.

4 The Minden Wind Park is a DTE Electric wind-powered electric generating facility

5 located on approximately 3,500 acres in Minden and Delaware Townships, principally

6 in Huron County, MI. It has a nameplate capacity of 32 MW and is comprised of

7 twenty (20) GE 1.6-100 wind turbines (100-meter rotors and 96-meter hub height) and

8 associated equipment and property. Power generated in the nacelle of the wind

9 turbines is sent down through the turbine towers, collected via underground cables and

10 centralized at a collector substation, where the voltage is stepped up from 34.5 kV to

11 41.57 kV. From that point the 41.57-kV power travels along a generator lead line to

12 the point of interconnection with DTE Electric’s distribution network.

14 The Sigel Wind Park is a DTE Electric wind-powered electric generating facility

15 located on approximately 8,600 acres in Port Hope, Harbor Beach, and Sigel

16 Townships, principally in Huron County, MI. It has a nameplate capacity of 64 MW

17 and is comprised of forty (40) GE 1.6-100 wind turbines (100-meter rotors and 100-

18 meter hub height) and associated equipment and property. Power generated in the

19 nacelle of the wind turbines is sent down through the turbine towers, collected via

20 underground cables and centralized at a collector substation, where the voltage is

21 stepped up from 34.5 kV to 120 kV. From that point the 120-kV power travels along

22 a generator lead line to the point of interconnection with International Transmission

23 Company’s (ITC’s) transmission network.

25 Q. Are there any shared assets associated with any of these wind parks?

ETH - 7 52 E. T. HENDERSON Line U-18150 No.

1 A. Yes. Next Era Energy Resources (Next Era) owns a 74.8 MW wind power-generating

2 facility adjacent to DTE Electric’s Brookfield Wind Park, and the two companies

3 (Next Era and DTE Electric) share certain assets that serve both projects, such as the

4 generator lead line, the interconnection with ITC, certain easements, etc., on a pro rata

5 undivided tenants-in-common basis.

7 Similarly, Gratiot County Wind, LLC (“GCW”, an affiliate of Invenergy, LLC), owns

8 a 110.4 MW wind power-generating facility adjacent to DTE Electric’s Gratiot Wind

9 Park, and the two companies (GCW and DTE Electric) share certain assets that serve

10 both projects, such as the generator lead line, the interconnection with METC, certain

11 easements, etc., on a pro rata undivided tenants-in-common basis.

13 Q. What are the major types of property that comprise these wind parks?

14 A. The properties encompassing these wind park projects are comprised of easements and

15 roadways, wind turbine generators (WTGs), pad-mounted transformers, an

16 underground collector system, a substation, an above-ground generator lead line, and

17 other ancillary property.

19 SOLAR PROJECTS

20 Q. Can you provide an overview of the solar projects that formed the basis for the

21 depreciation study?

22 A. Yes. Table 1 above summarizes the names of the projects, their nameplate capacities,

23 underlying land rights, and first year of service. Since the projects are otherwise

24 generally similar, the following details on one ground-mounted installation (U of M

25 North Campus Research Complex) and one roof-mounted installation (Warren

ETH - 8 53 E. T. HENDERSON Line U-18150 No.

1 Consolidated Schools) are representative of the details of the portfolio as a whole.

3 The U of M North Campus Research Complex project is located at 2800 Plymouth

4 Rd, in Ann Arbor, MI. The array consists of 1,794 SolarWorld 240W solar modules,

5 one Schneider/Xantrex GT500 inverter, and helical pier foundations with Solar

6 FlexRack racks and an interconnection to the Company’s medium voltage overhead

7 line on a nearby cable pole. The rights to use the land underlying the project are

8 secured by an easement agreement with an initial term of five years, with options to

9 extend the term up to another fifteen years. This agreement began on 3/23/2012.

11 The Warren Consolidated Schools project is located at 12200 15 Mile Road, in

12 Sterling Heights, MI. It is comprised of one roof-mounted, fixed array, with a 189 kW

13 nameplate capacity. The array consists of 840 BP3225T (225 Watt) solar modules,

14 one Solectria PVI-95 inverter, AET R430 Rayport racks with ballasts, and an

15 interconnection to the Company’s medium voltage overhead line on a nearby cable

16 pole. The rights to use the land underlying the project are secured by an easement

17 agreement with an initial term of twenty years, with options to extend the term up to

18 another ten years. This agreement began on 5/12/2011.

20 Wind Projects - Directives from the Commission

21 Q. What directives from the 2014 Order in Case No. U-16991 will you be

22 addressing?

23 A. The 2014 Order at page 31 required DTE Electric, in its next depreciation case, to

24 include “an assessment of the potential to reuse the towers with future wind turbine

25 generators, and a study assessing the aftermarket for used solar panels.” I will address

ETH - 9 54 E. T. HENDERSON Line U-18150 No.

1 these issues below.

3 Q. The decommissioning of a wind park consists of dismantling wind turbine

4 generators, and either scrapping or disposing of the components. Have there

5 been any changes in the industry to indicate that there may be alternatives to

6 this method?

7 A. Yes. Although in its infancy, General Electric, the OEM provider of all current

8 DTE Electric wind turbine generators, has created a program called “RePower.”

9 The aim of this program is to upgrade, through replacement, some of the

10 components of a turbine to increase nameplate output. Concurrently, this program

11 would allow an owner to theoretically extend the useful life of a wind turbine

12 generator. However, this program excludes any necessary modifications to ensure

13 the tower and foundation will continue to perform in a safe manner. Further

14 analysis on the viability of these components would be the responsibility of the

15 owner. DTE Electric has not conducted such an analysis and therefore continues to

16 assume the wind turbine generators will be dismantled when its wind park are

17 decommissioned.

19 Q. Do manufacturers appear to believe there is an opportunity to extend the

20 useful life of the tower and foundation without complete replacement?

21 A. Yes. As stated in case U-16991, wind turbine Original Equipment Manufacturers

22 (“OEMs”) are actively contemplating “life extenders” such as stiffener rings for

23 towers as product lines that they may be able to offer in the future. Similarly, there

24 are indications that technology exists to reinforce existing foundations to

25 accommodate tower design changes. In either case, thorough inspections would

ETH - 10 55 E. T. HENDERSON Line U-18150 No.

1 need to be conducted for any signs of fatigue and wear from previous loading

2 stress. Furthermore, extensive integrity and design testing would need to be carried

3 out by qualified professionals to ensure continued safety when operating extended

4 life wind turbine generators. Finally, engineering modeling would need to be

5 demonstrated to ensure the foundation and tower structure could safely withstand

6 future stress and loading that may occur throughout the duration of the extended life

7 period.

9 Q. Does DTE Electric foresee this type of wind turbine generator life extension

10 work being carried out with any of the existing Wind Park operating assets?

11 A. It is too early to make this type of determination. DTE Electric will continue to

12 monitor and review technological advancements. Our primary objective will be to

13 continue to focus on ensuring the most reasonable maintenance and operation of

14 existing company assets. This is to ensure that we get the most value out of the

15 current wind turbine generators, while providing the highest value to our customers.

17 Solar Projects – Directives from the Commission

18 Q. As explained in Case No. U-16991, at the time of decommissioning, solar

19 arrays would be deconstructed, with the materials either being sent to landfill

20 or salvaged for scrap. Given the continued deployment of solar photovoltaic

21 generation, have there been any significant changes in disposal alternatives?

22 A. No. At this point in time, landfill disposal would still be the most economically

23 viable means of handling end of life solar panels. However, many industry experts

24 believe that in time, recycling programs may become more common. It is

25 foreseeable that when DTE Electric’s solar assets reach the end of their useful life,

ETH - 11 56 E. T. HENDERSON Line U-18150 No.

1 there may be an alternative to sending them to a landfill. This is not to say that they

2 will have any material scrap value beyond what Company Witness Mr. Charles has

3 calculated in Exhibit A-14. This will continue to be a topic area that DTE Electric

4 will monitor.

6 Q. Did you supply Company Witness Dr. White with interim retirements for wind

7 and solar assets?

8 A. No, DTE Electric is not in a position now to reflect interim retirements for wind and

9 solar assets, due to the Company’s limited history with these assets. The Company,

10 however, reserves the right to reflect interim retirements in future proceedings.

12 Q. Does this complete your direct testimony?

13 A. Yes, it does.

ETH - 12 57

1 MR. CHRISTINIDIS: Your Honor, the

2 Company's next witness is Paul G. Horgan. Mr. Horgan

3 caused to be filed the Qualifications and Direct

4 Testimony of Paul G. Horgan, consisting of a cover sheet

5 and eight pages of questions and answers. He also is not

6 sponsoring any exhibits. The Company would move to bind

7 into the record the qualifications and direct testimony.

8 JUDGE FELDMAN: All right. Let me ask

9 for the record if there are any objections to binding in

10 Mr. Horgan's prefiled testimony? Hearing none, the

11 prefiled direct testimony of Paul G. Horgan will be bound

12 into the record.

13 (Testimony bound in.)

25 Metro Court Reporters, Inc. 248.360.8865 58

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) DTE ELECTRIC COMPANY ) for approval of depreciation accrual rates ) Case No. U-18150 and other related matters )

QUALIFICATIONS

AND

DIRECT TESTIMONY

PAUL G. HORGAN

59 DTE ELECTRIC COMPANY QUALIFICATIONS OF PAUL G. HORGAN Line No.

1 Q. Please state your name, business address and by whom you are employed.

2 A. My name is Paul G. Horgan. My business address is One Energy Plaza, Detroit,

3 Michigan 48226. I am employed by DTE Energy Corporate Services LLC, which

4 is a subsidiary of DTE Energy Company (DTE Energy) within Regulatory Affairs

5 as Directory Regulatory Operations.

7 Q. On whose behalf are you testifying?

8 A. I am testifying on behalf of DTE Electric Company (DTE Electric or the

9 Company).

11 Q. What is your education background?

12 A. I graduated from Michigan State University with a Bachelor of Arts degree in

13 Accounting. In addition, I received a Master of Business Administration degree

14 with a concentration in finance from Wayne State University.

16 Q. What work experience do you have?

17 A. I was employed by ANR Pipeline Company (ANR) for twenty-two years working

18 in a variety of departments within the Controller’s, Regulatory Affairs and

19 Corporate Development organizations. ANR is an interstate natural gas gathering,

20 storage and transmission company regulated by the Federal Energy Regulatory

21 Commission (FERC). In ANR’s Controller’s organization, I held a variety of Staff

22 and Supervisor Positions over seven years. I then worked in ANR’s Regulatory

23 Affairs organization for the next twelve years. Again during this period, I held

24 various positions of increasing responsibilities including positions within Gas

25 Supply, Rates Research, and Jurisdictional Rates. During this time I was promoted

PGH - 1 60 P. G. HORGAN Line U-18150 No.

1 to Manager of Jurisdictional Rates. I left ANR’s Regulatory affairs organization for

2 a promotion to Director/Consultant within ANR’s Financial Planning organization.

3 I remained in this position for three years until early 2001, when ANR, as part of a

4 merger, was moved to Houston and I left the Company.

6 Q. What was your work experience within ANR’s Jurisdictional Rates

7 Department?

8 A. While I was Manager of Jurisdictional Rates, my department was responsible for

9 the development, coordination, analysis, and resolution of general rate case filings

10 for ANR, High Island Offshore System (HIOS), and U-T Offshore System (UTOS).

11 In developing rate cases my department was responsible for determination of the

12 Cost of Service\Revenue Requirements, Cost Classifications/Allocations, and Rate

13 Design for the various regulated services offered by ANR. While in Jurisdictional

14 Rates, I actively participated in the preparation of two major ANR rate case filings

15 before the FERC: Docket Nos. RP89-161 and RP94-43. In both of these ANR

16 dockets, I presented testimony sponsoring various cost of service components and

17 participated as a witness in the rate case hearings. Further, I have presented

18 testimony in HIOS’ Docket Nos.: RP89-37, RP92-50 and RP94-162, as well as,

19 UTOS’ Docket No. RP94-161.

21 Q. What is your DTE Energy work experience?

22 A. I have been employed with DTE Energy since early 2001. Initially I accepted a

23 position in DTE Energy’s Corporate Development organization as a Project

24 Manager where I worked on the economic analysis and evaluation of DTE Energy’s

25 major regulated and non-regulated capital projects and acquisition opportunities. In

PGH - 2 61 P. G. HORGAN Line U-18150 No.

1 June 2005, I was appointed Manager Revenue Requirements group within DTE

2 Energy’s Regulatory Affairs organization. In this position I was responsible for

3 DTE Electric and DTE Gas Company (DTE Gas), formerly known as Michigan

4 Consolidated Gas Company, revenue requirement studies, depreciation rate studies,

5 cost of service studies, and regulatory analysis and research.

7 Q. What is your current position?

8 A. In January 2014, I was appointed Director of Regulatory Operations within DTE

9 Energy’s Regulatory Affairs organization. In this position I oversee the following

10 Regulatory groups; Revenue Requirements Team, Load Research / Rate Design

11 Team, and Rate Administration / Compliance / Power Supply Cost Recovery

12 (PSCR) team.

14 Q. Have you previously been involved in DTE Electric’s and DTE Gas’s general

15 rate case filings?

16 A. Yes. In 2003, I actively supported DTE Electric’s and DTE Gas’s general rate

17 cases (Case Nos. U-13808 and U-13898 respectively), relating to historic and

18 projected test period financial statements. I have been the revenue requirement

19 witness for DTE Electric sponsoring testimony regarding historical and projected

20 revenue deficiency in the following general rate case proceedings before the

21 Michigan Public Service Commission (MPSC or Commission):

22 U-14838 Show Cause Rate Case

23 U-15244 2008 General Rate Case

24 U-15768 2009 General Rate Case

25 U-16472 2010 General Rate Case

PGH - 3 62 P. G. HORGAN Line U-18150 No.

1 U-15768 2012 AMI Remand Case

2 U-16472 2014 AMI Remand Case

3 U-17437 PLD Transition Recovery Mechanism

4 U-18014 2016 DTE Electric General Rate Case

PGH - 4 63 DTE ELECTRIC COMPANY DIRECT TESTIMONY OF PAUL G. HORGAN Line No.

1 Q. What is the purpose of your testimony?

2 A. The purpose of my testimony is to discuss two adjustments that I directed Company

3 Witness Mr. Cooper to make to the Sargent & Lundy (S&L) decommissioning study

4 filed in this case and used in developing the Company’s proposed depreciation rates.

5 Specifically, I directed Company Witness Mr. Cooper to remove from the S&L

6 decommissioning study all embedded contingency amounts, as well as all DTE

7 Non-MEP direct labor and benefits. These Company adjusted S&L

8 decommissioning costs have been used by Company Witness Dr. White in his

9 development of the depreciation study, which he is sponsoring. Specifically, I

10 directed Witness Cooper to quantify both the S&L contingency amounts and the

11 DTE Non-MEP direct labor and benefits costs included in the S&L

12 decommissioning study prepared by Company Witness Mr. Charles and provided

13 these contingency/labor adjustments to Witness Dr. White for exclusion from his

14 depreciation study. Finally, I am also requesting that the Commission issue an

15 Order in this case authorizing the Company to: (1) retain and continue its present

16 depreciation accrual rates from Case Nos. U-16117 and U-16991 during the self-

17 implementation period in DTE Electric’s next general rate case filed subsequent to

18 November 1, 2016 and (2) implement the new depreciation accrual rates approved

19 in this Case No. U-18150 prospectively for financial reporting and rate making

20 purposes effective with a final Commission Order in DTE Electric’s next general

21 rate case filed subsequent to November 1, 2016.

23 Q. What do you mean by Non-MEP direct labor and benefits costs?

24 A. Non-MEP Labor is all labor charged to the project by personnel that are not part of

25 Major Enterprise Projects (“MEP”). Non-MEP Labor mainly includes: Fossil

PGH-4 64 P. G. HORGAN Line U-18150 No.

1 Generation Plant Labor, Distribution Operations Labor, and Corporate Services Labor.

3 Q. Are you sponsoring any exhibits in the proceeding?

4 A. No I am not.

6 Q. Why are you proposing that the contingency costs included by Witness Charles

7 in his S&L decommissioning study be excluded from the depreciation study

8 performed by Witness Dr. White?

9 A. First let me state that the Company believes that including contingency amounts in

10 a decommissioning study is appropriate and proper, and reflects a best practice

11 consistently used by consultants such as S&L in developing their cost projection for

12 decommissioning studies. However, in this case only, because these contingency

13 costs are more than seven years in the future they should be excluded from the S&L

14 decommissioning study as a means of mitigating the proposed depreciation

15 rate/expense increase to our customers. I continue to believe that while not

16 included in this case, contingency costs reflected in decommissioning studies as

17 part of future depreciation cases should be viewed as an appropriate

18 decommissioning cost.

20 Q. Why are you proposing that DTE’s non-MEP direct labor and benefits

21 included by Witness Charles in his S&L decommissioning study be excluded

22 from the depreciation study performed by Witness Dr. White?

23 A. MEP labor is included because it represents incremental labor directly tied into

24 specific decommissioning projects. While I believe that DTE’s non-MEP direct

25 labor and benefits will probably be an incremental expense when the

PGH - 6 65 P. G. HORGAN Line U-18150 No.

1 decommissioning of the plants takes place, it is not a certainty at this time. As

2 such, in this case I believe DTE’s non-MEP direct labor and benefits should be

3 excluded from the decommissioning study and should be reconsidered at a time

4 closer to the actual decommissioning of the specific plants. For this reason, and in

5 the interest of mitigating the proposed depreciation expense increase to customers I

6 directed Witness Cooper to provide Witness Dr. White the embedded costs of DTE

7 Non-MEP direct labor and benefits to be eliminated from the S&L

8 decommissioning study.

10 Q. What is the impact on the depreciation expense increase of eliminating the

11 S&L contingency costs and DTE Non-MEP direct labor and benefits costs

12 from the decommissioning study?

13 A. The elimination of $122.6 million in contingency costs lowers the annual

14 depreciation accrual by $14.9 million. Eliminating the non-MEP direct labor and

15 benefits costs of $48.1 million lowers the annual depreciation accrual by $5.9

16 million. In total, the two adjustments lower the annual depreciation accrual by

17 $20.8 million.

19 Q. When do you propose the final depreciation rates in this case become effective?

20 A. I propose that the Commission issue an Order in this case authorizing the Company

21 to: (1) retain and continue its present depreciation accrual rates from Case Nos. U-

22 16117 and U-16991 during the self-implementation period in DTE Electric’s next

23 general rate case filed subsequent to November 1, 2016 and (2) implement the new

24 depreciation accrual rates approved in this Case No. U-18150 prospectively for

25 financial reporting and rate making purposes effective with final Commission Order

PGH - 7 66 P. G. HORGAN Line U-18150 No.

1 in DTE Electric’s next general rate case filed subsequent to November 1, 2016.

3 Q. Does this complete your testimony?

4 A. Yes.

PGH - 8 67

1 MR. CHRISTINIDIS: Your Honor, the

2 Company's next witness is Kenneth D. Johnston. Mr.

3 Johnston sponsors Qualifications and Direct Testimony of

4 Kenneth D. Johnston consisting of a cover sheet and 21

5 pages of questions and answers. He sponsored two

6 exhibits. Those exhibits are designated as Exhibit A-8,

7 which is two pages, and A-9, which is also two pages.

8 With that, your Honor, I move to bind into the record the

9 qualifications and direct testimony of Kenneth D.

10 Johnston, and move the admission of Exhibits A-8 and A-9.

11 JUDGE FELDMAN: All right. Let me ask

12 for the record if there are any objections to Mr.

13 Christinidis's request regarding Mr. Johnston's prefiled

14 testimony and exhibits? Hearing no objections, the

15 prefiled direct testimony of Kenneth D. Johnston will be

16 bound into the record, and Exhibits A-8 and A-9 are

17 admitted into evidence.

18 (Testimony bound in.)

25 Metro Court Reporters, Inc. 248.360.8865 68

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) DTE ELECTRIC COMPANY ) for approval of depreciation accrual rates ) Case No. U-18150 and other related matters )

QUALIFICATIONS

AND

DIRECT TESTIMONY

KENNETH D. JOHNSTON

69 DTE ELECTRIC COMPANY QUALIFICATIONS OF KENNETH D. JOHNSTON Line No.

1 Q. What is your name, business address and by whom are you employed?

2 A. My name is Kenneth D. Johnston. My business address is 8001 Haggerty,

3 Belleville, Michigan 48111. I am employed by DTE Electric Company (DTE

4 Electric or Company) as Manager of Community Lighting.

6 Q. On whose behalf are you testifying?

7 A. I am testifying on behalf of DTE Electric Company (DTE Electric or Company).

9 Q. What is your educational background?

10 A. I graduated from Lawrence Technological University with a Bachelor of Science

11 Degree in Engineering in 1983. In 1991, I graduated with distinction from the

12 University of Michigan, Dearborn, with the degree of Master of Business

13 Administration in Finance and received the Distinguished Graduate MBA Student

14 Award. In addition, I have completed advanced level mathematics and mechanical

15 engineering courses at Lawrence Technological University.

17 Q. Have you completed other courses of study or attended any professional

18 seminars?

19 A. Yes, I have completed a Training Program titled Fundamentals of Energy

20 Management sponsored by the Association of Energy Engineers, completed a

21 training course offered by International Business Communications titled Energy

22 Industry Essentials, attended a workshop on Retail Open Access offered by the

23 Michigan Electric Power Coordination Center, attended the Lighting Upgrade

24 Workshop offered by the US Environmental Protection Agency (EPA), and

25 completed the Nuclear Utility Procurement Training sponsored by the Electric

KDJ -1 70 K. D. JOHNSTON Line U-18150 No.

1 Power Research Institute (EPRI). In addition, I graduated from Leadership

2 Oakland XI, 2000-2001 Program Year, a non-profit organization whose mission is

3 to ensure the continuing vitality of Oakland County by preparing motivated leaders

4 who are educated about the county and its issues.

6 Q. Do you belong to any professional organizations or hold any certifications?

7 A. Yes. I have received certifications as an Energy Manager through the Association

8 of Energy Engineers, a Green Lights Surveyor Ally through the US EPA, and as a

9 Nuclear Utility Procurement Instructor through EPRI.

11 Q. Please provide your employment history with DTE Electric Company.

12 A. My first work assignment for The Detroit Edison Company (Detroit Edison) was in

13 May 1983 as a contract engineer in the Applied Mechanics and Metallurgy Group,

14 Power Systems Division, Engineering Research Department. As a vibration

15 engineer, I was responsible for vibration monitoring, evaluation, and analysis of

16 rotating machinery at Detroit Edison Power Plants.

18 I was formally hired by Detroit Edison in August 1985 as a planning and scheduling

19 engineer at the Fermi 2 Nuclear Power Plant. In this capacity, I developed,

20 programmed, and directed the production of plant outage schedules, including

21 equipment maintenance and testing, plant system restoration, and plant startup.

23 In March 1989, I was assigned the duties of Preventive Maintenance Specialist,

24 Nuclear Production-Maintenance, and was responsible for evaluation and

25 implementation of the preventive maintenance program.

KDJ- 2 71 K. D. JOHNSTON Line U-18150 No.

1 In January 1990, I took a position as a materials engineer, Nuclear Materials

2 Management, and progressed to principal (lead) engineer. In this capacity, I was

3 responsible for the work direction of engineers and technicians in the performance

4 of material engineering, parts planning, and receipt inspection activities. I

5 represented the Company as a member of the EPRI Obsolete Items Database

6 Technical Working Group and the General Electric Boiling Water Reactor Pooled

7 Inventory Management Equipment Committees.

9 In August 1995, I was assigned the position of principal mechanical maintenance

10 engineer, Rotating Equipment, Maintenance Engineering, Nuclear Production. In

11 this capacity, I provided field-engineering support for mechanical maintenance

12 activities, managed the resolution of emerging technical issues, monitored and

13 evaluated the performance of rotating equipment and performed troubleshooting

14 and root cause analysis of equipment failures.

16 In January 1997, I became a facilitator with the Energy Partnership, Customer

17 Energy Solutions. In this position, I was responsible for the development,

18 implementation, and management of the Energy Conservation Program at the

19 General Motors Proving Ground in Milford, Michigan. Responsibilities in that

20 position included the identification, financial evaluation, and implementation of

21 natural gas and electric energy projects related to boiler and steam systems, lighting

22 systems, air compressors, and HVAC systems.

24 In June 1999, I became a Principal Supplier Account Manager with the Supplier

25 Transactions Group of the Electric Choice Implementation Team. In this capacity I

KDJ- 3 72 K. D. JOHNSTON Line U-18150 No.

1 was responsible for the management of relationships with Alternative Electric

2 Suppliers (AES) including supplier education, supplier qualification, supplier

3 billing, customer enrollment, customer billing, and electronic data management.

5 In January 2003, I transferred to Regulatory Affairs as a Principal Project Manager

6 and in September 2007, I was promoted to Consultant. In February 2011 I was

7 promoted to Manager of the DTE Electric Choice Program. As Manager of the

8 Electric Choice Program I was responsible for managing the processes that enable

9 customers to seamlessly migrate between DTE Electric Full Service and Electric

10 Choice Service in accordance with Michigan Compiled Laws (MCL), Michigan

11 Public Service Commission (MPSC or Commission) Orders, and DTE Electric’s

12 tariffs. In April 2015, I was promoted to Manager of Community Lighting.

14 Q. What are your duties and responsibilities as Manager of Community

15 Lighting?

16 A. In this capacity, I am responsible for managing the marketing & sales, planning &

17 construction and asset management of almost 200,000 DTE Electric-owned street

18 lights and outdoor protective lights, the maintenance and provision of energy to

19 municipally owned streetlights and the provision of energy-only service to

20 municipalities, in accordance with DTE Electric’s MPSC-approved tariffs. DTE

21 Electric’s assets include mercury vapor, metal halide, high pressure sodium, and

22 light-emitting diode (LED) luminaires.

24 Q. What has been your involvement in regulatory case activities?

25 A. I managed the following cases:

KDJ- 4 73 K. D. JOHNSTON Line U-18150 No.

1 U-13738 In the matter of the application of The Detroit Edison Company to

2 recover implementation costs for the period ended December 31,

3 2002

4 U-14079 In the matter of the application of The Detroit Edison Company to

5 recover implementation costs for the period ended December 31,

6 2003

7 U-13759 Review of Steam Rates

8 U-13808-R 2004 Power Supply Cost Recovery Reconciliation

9 U-14474 In the matter of the application of The Detroit Edison Company to

10 implement the Commission's final order in Case No. U-13808

11 concerning Inter Alia, 2004 Net Stranded Costs

12 U-14093 In the matter of the complaint of North Star Steel Company against

13 The Detroit Edison Company regarding credits for experimental

14 electric choice service

15 U-14124 In the matter of complaint of Nordic Marketing, LLC against The

16 Detroit Edison Company for violations of the Code of Conduct,

17 Public Act 141

18 U-15223 In the matter of the complaint of Commerce Energy Inc. against

19 The Detroit Edison Company

20 U-16400 In the matter of the application of Michigan Consolidated Gas

21 Company for the authority to increase its rates, amend its rate

22 schedules and rules governing the distribution and supply of

23 natural gas, and for miscellaneous accounting authority.

KDJ- 5 74 K. D. JOHNSTON Line U-18150 No.

1 I was the case manager and/or sponsored testimony in the following cases:

2 U-14025 In the matter of the complaint of Strategic Energy LLC against The

3 Detroit Edison Company

4 U-14054 In the matter of the complaint of Quest Energy against The Detroit

5 Edison Company

6 U-14070 In the matter of the complaint of Constellation NewEnergy, Inc.

7 against The Detroit Edison Company.

8 U-14275 2005 Power Supply Cost Recovery Plan

9 U-14275-R 2005 Power Supply Cost Recovery Reconciliation

10 U-14208 In the matter of the complaint of Nordic Marketing, L.L.C. against

11 The Detroit Edison Company for failure to comply with enrollment

12 processing requirements.

13 U-14817 2005 Pension Equalization Mechanism Reconciliation

14 U-14702 2006 Power Supply Cost Recovery Plan

15 U-14702-R 2006 Power Supply Cost Recovery Reconciliation

16 U-15259 2006 Pension Equalization Mechanism Reconciliation

17 U-15002 2007 Power Supply Cost Recovery Plan

18 U-15002-R 2007 Power Supply Cost Recovery Reconciliation

19 U-15081 In the matter of the complaint of FirstEnergy Solutions Corp.

20 against The Detroit Edison Company for violation of the Code of

21 Conduct

22 U-15417 2008 Power Supply Cost Recovery Plan

23 U-15417-R 2008 Power Supply Cost Recovery Reconciliation

24 U-15677 2009 Power Supply Cost Recovery Plan

25 U-15806 Detroit Edison 2008 PA 295 Renewable Energy Plan (RPS)

KDJ- 6 75 K. D. JOHNSTON Line U-18150 No.

1 U-16047 2010 Power Supply Cost Recovery Plan

2 U-16356 In the matter of the application of The Detroit Edison Company for

3 the authority to reconcile its renewable energy plan costs with the

4 plan approved in Case No. U-15806-RPS

5 U-16434 2011 Power Supply Cost Recovery Plan

6 U-17663 In the matter of the complaint of Severstal Dearborn, LLC against

7 DTE Electric Company

8 U-17734 In the matter of the Formal Complaint of AK Steel Corporation

9 (successor to Severstal Dearborn, LLC) against DTE Electric

10 Company for standby service.

11 U-17767 DTE Electric General Electric Rate Case Proceeding

12 U-18014 DTE Electric General Electric Rate Case Proceeding

14 In addition, I have submitted affidavits supporting changes to DTE Electric’s Retail

15 Access Service Rider and DTE Electric’s Rate Schedule D9 service, as well as the

16 approval of renewable energy, renewable energy engineering, procurement and

17 construction (EPC), and renewable energy credit (REC) contracts before the MPSC.

18 I was also the case manager and submitted several affidavits regarding energy

19 imbalance service and the recalculation of energy imbalance service costs in FERC

20 Docket EL04-31-000, “Complaint of Quest Energy, LLC to receive proper

21 compensation for imbalance services.”

KDJ- 7 76 DTE ELECTRIC COMPANY DIRECT TESTIMONY OF KENNETH D. JOHNSTON Line No.

1 Q. What is the purpose of your direct testimony?

2 A. The purpose of my testimony is to support the reallocation of certain street light

3 assets which are currently recorded in several existing FERC sub-accounts 373010:

4 Street Lighting and Signal System Overhead and 373020: Street Lighting and

5 Signal System Underground, to additional subaccounts for purposes of more

6 accurate ratemaking. Specifically, I will support the allocation of existing plant

7 assets into eight subaccounts, four each for overhead and underground fed street

8 light assets. The new subaccounts will include an account for High Intensity

9 Discharge (HID) luminaires and Light Emitting Diode (LED) luminaires for both

10 overhead and underground fed streetlights The HID luminaires include mercury

11 vapor (MV), high pressure sodium (HPS) and metal halide (MH) technologies. In

12 addition, I will support the recommendation for reducing the useful life of existing

13 mercury vapor technology luminaires based upon their obsolescence and current

14 rate of conversion to LED technology.

16 Q. Are you sponsoring any exhibits?

17 A. Yes. I am sponsoring the following exhibits:

18 Exhibit Description

19 A-8 Proposed Streetlighting & Signal System Account

20 Allocations

21 A-9 Proposed LED Luminaire Capital Cost

23 Q. Were these exhibits prepared by you or under your direction?

24 A. Yes, they were.

KDJ - 8 77 K. D. JOHNSTON Line U-18150 No.

1 Q. Can you provide an overview of DTE Electric’s Community Lighting

2 Business?

3 A. Yes. Community Lighting provides MPSC-approved tariff service to

4 approximately 162,000 street lights on its Rate Schedule E1 Option I,

5 approximately 500 municipally-owned street lights on its Rate Schedule E1 Option

6 II, and approximately 86,000 municipally-owned street lights on its Rate Schedule

7 E1 Option III. DTE Electric’s Rate Schedule E1 Option I provides for recovery of

8 costs associated with its ownership, maintenance and provision of energy to its

9 portfolio of mercury vapor, high pressure sodium, metal halide and LED street

10 lighting. Rate Schedules E1 Option II and Option III are for street lighting systems

11 owned by municipalities and are not relevant to this proceeding.

13 Approximately 48,000 or 30% of DTE Electric’s street light assets are mercury

14 vapor, which are obsolete and must be replaced with another lighting technology

15 upon failure. Currently it is the Company’s policy to convert failed mercury vapor

16 lighting (consisting of the luminaire, lamp, and photocell) to high pressure sodium

17 due to DTE Electric’s continuing obligation to provide service for Municipal Street

18 lighting (MSL) customers taking service under its E1 Option I Rate Schedule.

19 Another 78,000 or 48% of DTE Electric’s street light assets are high pressure

20 sodium, approximately 2,600 or 1.6% of DTE Electric’s street light assets are metal

21 halide and LED street lights represent the balance of Rate Schedule E1 Option I

22 assets.

24 In addition to its E1 Option I, II and III Rate Schedules, DTE Electric also provides

25 MPSC-approved tariff service to approximately 20,000 commercial outdoor

KDJ- 9 78 K. D. JOHNSTON Line U-18150 No.

1 protective lights (OPL) and 9,000 residential outdoor protective lights on its D9

2 Rate Schedule. DTE Electric’s proposed D9 Rate Schedule reflects recovery of

3 costs associated with its ownership, maintenance and provision of energy to its

4 portfolio of mercury vapor, high pressure sodium, metal halide and LED outdoor

5 protective lighting.

7 Finally, DTE Electric provides MPSC-approved tariff service for traffic and signal

8 lights to municipalities and other public authorities under its E2 Rate Schedule.

9 This service is an energy-only service and rates are currently based upon connected

10 wattage.

12 Q. Why is the Company proposing to create additional permanent sub-accounts

13 for both overhead-fed and underground-fed streetlight assets?

14 A. DTE Electric’s outdoor lighting business has experienced significant change over

15 the past 6 to 7 years with the emergence of more efficient LED lighting. The

16 saturation of LED lighting for DTE Electric has grown from a total count of 52

17 luminaires in 2009 to more than 33,000 at the end of 2015 and both the cost basis

18 and useful life of LED assets differ from that of HID lighting. Further, the useful

19 lives of both the HID and LED luminaires differ from those of the other street

20 lighting assets (i.e. posts, cable, wire, transformers, etc.) within the existing

21 subaccounts and, in order to more accurately attribute underlying costs

22 (depreciation, return, property and other taxes, etc.) to lighting rates by technology,

23 it makes sense to implement this improvement at this time. Finally, general

24 agreement was reached with all participants in the recently concluded “Municipal

25 Lighting Collaborative” that the creation of streetlight subaccounts would be

KDJ- 10 79 K. D. JOHNSTON Line U-18150 No.

1 proposed in the next depreciation case filing to support accurate ratemaking for

2 LED versus HID lighting technologies. The Municipal Lighting Collaborative was

3 initiated by the MPSC Staff pursuant to the December 11, 2015 Order in MPSC

4 Case No. U-17767.

6 Q. What are the proposed FERC subaccounts shown on Exhibit A-8 for lighting

7 assets which are fed through overhead wire?

8 A. Exhibit A-8 reflects the proposed overhead-fed lighting asset balances for both the

9 existing and new permanent FERC subaccounts as follows:

10 - Subaccount 373010, Street Lighting Infrastructure - Overhead, reflects the

11 asset balances for control assemblies & adapters, fuse carriers, ground rods

12 and extensions, insulator disks, lightning arresters, supports, brackets and

13 arms, switches and transformers, all of which are currently recorded in this

14 subaccount.

15 - Subaccount 373030, Street Lighting Wire - Overhead, reflects the asset

16 balances for wire which is currently recorded in subaccount 373010.

17 - Subaccount 373070, Street Lighting Luminaires – HID Overhead, reflects the

18 asset balances for overhead fed mercury vapor, metal halide and high pressure

19 sodium luminaires which are currently recorded in subaccount 373010.

20 - Subaccount 373080, Street Lighting Luminaires – LED Overhead, reflects the

21 asset balances for overhead fed LED luminaires which are currently recorded

22 in subaccount 373010.

24 Q. What are the proposed FERC subaccounts shown on Exhibit A-8 for lighting

25 assets which are fed through underground cable?

KDJ- 11 80 K. D. JOHNSTON Line U-18150 No.

1 A. Exhibit A-8 reflects the proposed underground-fed lighting asset balances for both

2 the existing and new permanent FERC subaccounts as follows:

3 - Subaccount 373020, Street Lighting Infrastructure - Underground, reflects the

4 asset balances for posts which are currently recorded in this subaccount.

5 - Subaccount 373040, Street Lighting Wire/Cable - Underground, reflects the

6 asset balances for wire and cable which is currently recorded in subaccount

7 373020.

8 - Subaccount 373050, Street Lighting Luminaires – HID Underground, reflects

9 the asset balances for underground fed mercury vapor, metal halide and high

10 pressure sodium luminaires which are currently recorded in subaccount

11 373020.

12 - Subaccount 373060, Street Lighting Luminaires – LED Underground, reflects

13 the asset balances for underground fed LED luminaires which are currently

14 recorded in subaccount 373020.

16 Q. What is reflected on Exhibit A-9; Proposed LED Luminaire Capital Cost?

17 A. Exhibit A-9 reflects the development of the proposed allocation of capital costs for

18 LED luminaires (vs. HID luminaires) currently recorded in subaccount 373010 or

19 373020 to newly created subaccounts for overhead-fed and underground-fed LED

20 luminaires. Column (a) reflects the account in which the net assets currently exist,

21 column (b) reflects the year during which costs were first recorded, and column (c)

22 reflects the total quantity of LED luminaires which were installed during a

23 particular year.

25 Q. How has DTE Electric’s LED lighting saturation increased during the period

KDJ- 12 81 K. D. JOHNSTON Line U-18150 No.

1 from 2009 through 2015?

2 A. LED lighting saturation has increased through one of three methods: (1) series

3 circuit conversion projects (reflected in column (d)), (2) HID (primarily mercury

4 vapor) to LED conversion projects (reflected in column (e)), and (3) new business

5 projects (reflected in column (f)). Both the total cost and the customer contribution

6 for each of these project types vary and, therefore, the amount of capital that DTE

7 Electric records on its books for these projects varies as well.

9 Q. What are series circuit conversion projects?

10 A. Series circuit conversion projects are the conversion of lights which are currently

11 fed through a series circuit loop to lights which are fed in a parallel circuit format.

12 The lights which were previously fed through series circuits were operated at high

13 primary voltage (4800V), required special high voltage ballasts called AO

14 transformers to lower voltage to appropriate levels and reflected older infrastructure

15 usually found in pre-1970s construction. Following conversion, the lights are

16 operated at low secondary voltage (120V) and no longer require AO transformers;

17 power regulation is accomplished through low voltage ballasts which are integral to

18 the luminaire. The series circuit projects were conducted to reduce high outage

19 restoration costs, long outage durations and reduce the frequency of outages for the

20 lights fed through these circuits. During the process of eliminating series circuits,

21 the lighting technology is converted from mercury vapor to either high pressure

22 sodium or LED.

24 Q. What are HID lighting to LED lighting conversion projects?

25 A. HID to LED conversion projects encompass the planned conversion of existing

KDJ- 13 82 K. D. JOHNSTON Line U-18150 No.

1 DTE-owned HID lighting to more efficient and economic LED technology lighting.

2 The primary focus of these planned conversion projects has been the obsolete

3 mercury vapor technology which DTE can no longer maintain due to the fact that

4 the Energy Policy Act of 2005 banned the manufacturing and sale of new mercury

5 vapor ballasts after January 1, 2008. However, the fact that LED lighting is also

6 more economic and efficient than both metal halide and high pressure sodium

7 lighting has led some municipalities to also replace those lighting technologies.

9 Q. What has DTE Electric contributed to the various project types during the

10 period from 2009 through 2015?

11 A. For series circuit conversion projects in which the existing mercury vapor lighting

12 technology is converted to LED lighting technology, DTE Electric pays the entire

13 project cost less the cost difference between a high pressure sodium luminaire and

14 the equivalent LED luminaire. For mercury vapor to LED conversion projects,

15 DTE Electric only directly expends an amount which is equal to the field

16 installation cost for mercury vapor technology only. For high pressure sodium or

17 metal halide to LED conversion projects, DTE Electric does not pay for any direct

18 costs associated with the project. For new business projects which include the

19 installation of new LED lighting, DTE Electric directly expends an amount equal to

20 3 years of the expected rate revenue for the installed lighting.

22 In addition to the direct costs associated with the three LED project types, DTE

23 Electric also incurs indirect capital labor costs associated with the planning,

24 supervisory and administrative costs for each of these project types, the allocation

25 of which I will discuss later in my testimony.

KDJ- 14 83 K. D. JOHNSTON Line U-18150 No.

1 Q. How does DTE Electric determine how much capital it contributes to projects?

2 A. DTE Electric’s calculation method for Contributions in Aid of Construction (CIAC)

3 varies depending on whether the DTE Electric project cost is for new business or

4 conversion of existing business (e.g. convert mercury vapor to LED). The

5 determination of CIAC for new business is simply the total estimated project cost

6 less three years of expected incremental revenues from the project based upon the

7 Company’s MPSC-approved tariffs. The determination of CIAC for conversion of

8 existing business is the total estimated project cost minus three years of expected

9 incremental revenues from the project plus a DTE Electric-provided labor credit.

10 The credit for three years of incremental revenue is zero in most cases because the

11 rates for the lighting technology to which customers are converting are typically

12 lower than the rates for their existing lighting technology. DTE Electric provides a

13 labor credit, equal to the labor charge from the installing contractor, to both

14 incentivize planned conversions from the obsolete mercury vapor lighting

15 technology to the LED lighting technology and to also recognize the economic

16 efficiencies gained by performing planned conversions of mercury vapor lighting

17 versus reactive conversions upon failure. The primary economic gain is DTE

18 Electric’s ability to convert multiple lights on either a single circuit or municipality

19 in a single work activity versus the conversion of a single light upon failure. In

20 addition to the incremental revenue and labor credits, the project cost for

21 conversion of existing business may also be eligible for an energy optimization

22 grant, further offsetting the customer’s contribution to the conversion project.

24 The underlying purpose of reducing the project cost for new business by three years

25 of incremental revenues is to recognize the impact of increased revenues from the

KDJ- 15 84 K. D. JOHNSTON Line U-18150 No.

1 project which are ultimately used to offset the revenue requirement from the new

2 assets that DTE Electric records on its books. In the determination of CIAC for

3 planned conversion of existing business, DTE Electric similarly determines total

4 project cost and similarly reduces this amount by 3 years of expected incremental

5 revenues. As I previously stated, because the rates for LED lighting are lower than

6 those for equivalent mercury vapor and/or metal halide lighting, no incremental

7 revenue is available to offset the recovery of additional assets recorded on DTE

8 Electric’s books and, therefore, no reduction in CIAC is provided. However,

9 because DTE Electric provides both a labor credit to customers requesting planned

10 conversion of obsolete mercury vapor lighting and also facilitates the process for

11 receipt of energy optimization grants for conversion of existing business to LED

12 lighting, the CIAC impact is reduced.

14 Q. Do DTE Electric’s proposed asset balances reflect any capital expense which

15 was offset by CIAC?

16 A. No. DTE Electric records customer CIAC as a direct offset to actual capital

17 expense for each of its new business and conversion projects. Therefore, DTE

18 Electric’s proposed asset balances do not reflect any capital expense which was

19 offset by CIAC.

21 Q. How did you determine the LED luminaire capital costs for series circuit

22 conversion projects reflected in column (g) on Exhibit A9?

23 A. The LED luminaire capital costs reflected in column (g), on Exhibit A-9 were

24 developed by taking the total number of series circuit lights which were converted

25 to LED during the year and multiplying that by the average cost of the HPS

KDJ- 16 85 K. D. JOHNSTON Line U-18150 No.

1 equivalent luminaire. In other words, DTE Electric funded the HPS luminaire; and

2 the customer, through CIAC, funded the difference between the HPS luminaire and

3 the LED luminaire.

5 Q. How did you determine the LED luminaire capital costs for mercury vapor to

6 LED conversion projects reflected in column (h) on Exhibit A9?

7 A. The LED luminaire capital costs reflected in column (h) on Exhibit A-9 were

8 developed by taking the total number of lights which were converted from mercury

9 vapor to LED during the year and multiplying that by the contractor field

10 installation cost. All other mercury vapor to LED conversion project costs, with the

11 exception of staff capital labor, were collected from the customer through CIAC.

13 Q. How did you determine LED luminaire capital costs for new business projects

14 reflected in column (i) on Exhibit A9?

15 A. The LED luminaire capital costs reflected in column (i) on Exhibit A9 were

16 developed by taking the total number of new LED luminaires which were installed

17 during the year and multiplying that quantity by the revenue credit that DTE

18 Electric provides for new business installations and the relative cost of the LED

19 luminaire for each project type. For overhead-fed lights, LED luminaires reflect

20 approximately 43% of the total project cost and for underground-fed lights, LED

21 luminaires reflect approximately 17% of the total project cost. As I previously

22 discussed, DTE Electric provides capital for new business projects based upon three

23 years of estimated revenue. All other new business project costs, with the exception

24 of staff capital labor, were collected from the customer through CIAC.

KDJ- 17 86 K. D. JOHNSTON Line U-18150 No.

1 Q. What do the total initial capital costs in column (j) on Exhibit A-9 reflect?

2 A. The total Initial LED luminaire capital costs in column (j) on Exhibit A-9 reflect

3 DTE Electric’s direct project costs associated with series circuit conversion,

4 mercury vapor to LED conversion and new business projects. As I previously

5 mentioned, all other costs from these projects were collected from the customer

6 through CIAC.

8 Q. Does DTE Electric continue to incur capital costs associated with LED lighting

9 after initial installation?

10 A. Yes. DTE Electric spends approximately $5 million annually to restore lighting

11 outages and the amount that DTE Electric spends on an annual basis to restore LED

12 lighting upon failure continues to grow due to the higher LED technology

13 saturation. The annual amounts reflected in column (k) on Exhibit A-9 reflect these

14 costs. Specifically, these costs reflect the capitalized outage labor and material

15 costs for various wattage LED luminaires which were replaced during the

16 performance of outage restoration work.

18 Q. How did you allocate the undepreciated book value of existing HID luminaires

19 which were retired through mercury vapor or series circuit conversion

20 projects?

21 A. Column (l) on Exhibit A-9 reflects the average net book value of the HID assets

22 which were retired during the period of this asset allocation. The amounts reflected

23 here are the result of the product of the average net book value of retired assets and

24 the percentage of retired assets as a result of series circuit or HID conversion

25 projects.

KDJ- 18 87 K. D. JOHNSTON Line U-18150 No.

1 Q. What costs have you allocated to the new LED luminaire subaccounts in

2 column (m) on Exhibit A-9?

3 A. Column (m) reflects the fact that DTE Electric also incurs indirect capital labor

4 costs associated with the planning, supervisory and administrative costs for each of

5 the three project types. In order to understand the proper allocation of staff capital

6 labor costs to LED luminaires, I performed an analysis of historical staff capital

7 labor costs. Based upon this analysis, I assigned an appropriate level of the staff

8 capital labor expense to new business, series circuit conversion and mercury vapor

9 conversion projects.

11 Q. What costs are reflected in column (n) on Exhibit A-9?

12 A. Column (n) reflects the total proposed capital costs allocated to the LED luminaires

13 which have been installed since 2009. The total allocated LED luminaire capital

14 costs reflect all LED lighting project costs, outage replacement costs, staff capital

15 labor costs and the undepreciated costs of existing HID luminaires which were

16 converted prior to their end of life, and is the sum of columns (j) through (m) of

17 Exhibit A-9.

19 Q. What are your thoughts concerning the proposed allocation of luminaire costs

20 to the new LED subaccounts reflected in column (n) on Exhibit A9?

21 A. I consider the allocation of luminaire costs to the new LED subaccounts reflected in

22 column (n) on Exhibit A-9 to be reasonable. These costs were developed based

23 upon a bottom up analysis for all of the LED luminaires which have been installed

24 since 2009 for each of the projects; series circuit conversion, mercury vapor

25 conversion and new business.

KDJ- 19 88 K. D. JOHNSTON Line U-18150 No.

1 Q. How have you reflected the proposed LED Luminaire capital costs on Exhibit

2 A-8?

3 A. As I previously discussed, Exhibit A-8 presents both the existing and the proposed

4 permanent accounts. Page 1 of this exhibit reflects existing account balances at

5 year end 2015 and Page 2 reflects proposed account balances at year end 2015. The

6 LED Luminaire capital costs developed on Exhibit A-9 are reflected on Page 2 of

7 this exhibit.

9 Q. Please describe the information contained on Exhibit A-8?

10 A. Column (a) reflects the account description, column (b) reflects the retirement units,

11 column (c) reflects the accumulated capital costs for each of the retirement units,

12 column (d) reflects the allocated depreciation reserve for each of the retirement

13 units, and column (e) represents the net book value for the particular retirement

14 unit.

16 Q. What information is reflected in columns (f) and (g) on Exhibit A8?

17 A. The reserve redistribution amount in column (f) reflects an adjustment to the

18 allocated depreciation reserve to reconcile the LED and HID luminaire net book

19 values of both overhead and underground luminaires. Column (g) reflects the

20 proposed net book value, as of December 31, 2015, for LED luminaires after this

21 adjustment is made. The resulting net book value for LED luminaires in column (g)

22 essentially reflects the total LED capital cost reflected in column (n) on Exhibit A9

23 less the accumulated depreciation reserve for the LED luminaires since their initial

24 installation.

KDJ- 20 89 K. D. JOHNSTON Line U-18150 No.

1 Q. What suggestions do you have regarding the useful life of DTE Electric’s

2 obsolete mercury vapor lighting?

3 A. As I mentioned previously, DTE Electric currently has a total population of

4 approximately 48,000 mercury vapor luminaires. DTE Electric has placed a

5 priority on partnering with its municipal customers in converting the mercury vapor

6 lighting to LED lighting. The pace of conversion is ultimately impacted by the

7 amount of work required for each municipality conversion project. Each

8 municipality project requires existing lighting evaluation, establishment and

9 execution of contracts, work planning (including the ordering of materials, updating

10 of drawings, receipt of permits, etc.), construction (including field coordination and

11 oversight), field verification as well as billing system updates, all of which is labor

12 intensive. At the current pace of conversion for street light mercury vapor

13 luminaires, all mercury vapor street lights could be converted within five years but

14 no longer than ten years. As a result, I suggest that the useful life for existing

15 mercury vapor assets be reduced to 10 years to ensure that the obsolete mercury

16 vapor assets are adequately depreciated prior to removal.

18 Q. Does this complete your direct testimony?

19 A. Yes, it does.

KDJ- 21 90

1 MR. CHRISTINIDIS: Your Honor, the

2 Company's next witness is Neil E. Mortensen. Mr.

3 Mortensen caused to be filed Qualifications and Direct

4 Testimony of Neil E. Mortensen, consisting of a cover

5 sheet and six pages of questions and answers. Mr.

6 Mortensen also sponsored Exhibits A-10 which is six

7 pages, A-12 which is one page, and A-13 which is one

8 page. The Company would move to bind into the record the

9 qualifications and direct testimony of Neil E. Mortensen

10 and move for the admission of Exhibits A-10, A-12, and

11 A-13.

12 JUDGE FELDMAN: All right. Let me ask

13 for the record if there are any objections to Mr.

14 Christinidis's request regarding Mr. Mortensen's prefiled

15 testimony and exhibits? Hearing no objections, the

16 prefiled direct testimony of Neil E. Mortensen will be

17 bound into the record, and Exhibits A-10, A-12, and A-13

18 are admitted into evidence.

19 (Testimony bound in.)

25 Metro Court Reporters, Inc. 248.360.8865 91

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) DTE ELECTRIC COMPANY ) for approval of depreciation accrual rates ) Case No. U-18150 and other related matters )

QUALIFICATIONS

AND

DIRECT TESTIMONY

NEIL E. MORTENSEN

92 DTE ELECTRIC COMPANY QUALIFICATIONS OF NEIL E. MORTENSEN Line No.

1 Q. What is your name, business address and by whom are you employed?

2 A. My name is Neil E. Mortensen. My business address is: One Energy Plaza, Detroit,

3 Michigan 48226. I am employed by DTE Energy Corporate Services, LLC (DTE

4 Energy or DTE) with MEP (Major Enterprise Projects), my title is Construction

5 Project Manager.

7 Q. On whose behalf are you testifying?

8 A. I am testifying on behalf of DTE Electric Company (DTE Electric or the

9 Company).

11 Q. What is your educational background?

12 A. I graduated from North Dakota State University with a Bachelor of Arts degree in

13 Construction Management and have a Master’s Degree in Organizational

14 Management from the University of Phoenix.

16 Q. What work experience do you have prior to your employment at DTE?

17 A. I was employed in 1989 as a Civil Field Engineer for John T. Jones Construction, a

18 medium size general contractor in Fargo, ND. My daily responsibilities consisted

19 of: scheduling, daily reporting, subcontractor coordination, inspector coordination,

20 testing coordination and managing field office activities on a $5 million waste water

21 control project in Omaha, NE.

23 The following year I worked as a Field Engineer for Ultra-Systems Western

24 Constructors, the construction division of Hadson Power, Irvine, CA. I held several

25 field engineering positions thru the years with Hadson Power. While at Hadson

NEM - 1 93 N. E. MORTENSEN Line U-18150 No.

1 Power, I was involved in constructing Fossil Fuel Power Plants (Coal & Natural

2 Gas) in several states. My position titles were Electrical Field Engineer, Mechanical

3 Field Engineer and Senior Site Superintendent.

5 In 1994 through 1996, I worked for MFS Technologies, the communication

6 division of Kiewit Construction as a Project Manager. I built two $30 million fiber

7 optic telecommunication switch facilities and several smaller fiber optic

8 telecommunication rooms in St. Louis, MO and Detroit, MI.

10 After completing the communication networks, in 1996, I then went to work for

11 Fluor Daniels Construction as a Construction Superintendent to launch AT&T

12 Wireless new network in Southeastern Michigan. After the launch of the wireless

13 communication network, I was offered a job with AT&T Wireless as a Project

14 Manager. I worked on the AT&T Wireless project from 1996 to 2000.

16 I then started working as Regional Director for Specialty Systems of Michigan to

17 form a new wireless tower construction company in 2000 for Fred Treadway,

18 Treadway Indy Racing. We also started a new wireless tower engineering division

19 of the company early the next year in Indianapolis, IN. I left the company in 2002

20 to build new alternative energy projects for DTE Energy.

22 Q. What is your DTE Energy work experience?

23 A. I have been employed with DTE and its subsidiary’s since 2002. My first DTE

24 Energy Technologies (DTECH) position was Sr. Project Manager performing turn-

25 key construction alternative energy power plants for various clients. My second

NEM - 2 94 N. E. MORTENSEN Line U-18150 No.

1 position was with The Detroit Edison Company as Sr. Project Engineer to perform

2 various large and small capital projects at Monroe Power Plant. My third position

3 is with DTE Energy Corporate Services, LLC as MEP Project Manager performing

4 large, multi-year, multi-million dollar capital projects. These projects included

5 several emission upgrade projects, demolition of two Monroe Power Plant 800’

6 chimneys, abatement/demolition of the St. Clair Unit 5 165’ chimney, St. Clair Unit

7 5 boiler asbestos abatement, as well as decommissioning, decontamination and sale

8 of the Marysville Power Plant. Currently, I am MEP Project Manager for

9 decommissioning, decontamination and demolition of the Conners Creek, Harbor

10 Beach, Trenton (High Side) and River Rouge (High Side) Power Plants.

12 Q. What is your current position?

13 A. My current position is Construction Project Manager, assigned to all the MEP

14 Fossil Generation decommissioning & demolition projects.

NEM - 3 95 DTE ELECTRI COMPANY DIRECT TESTIMONY OF NEIL E. MORTENSEN Line No.

1 Q. What is the purpose of your testimony in this proceeding?

2 A. I describe the decommissioning, decontamination and disposition of Marysville

3 Power Plant and future disposition of Harbor Beach Power Plant, including the

4 costs associated with both power plants.

6 Q. Are you sponsoring any exhibits in this proceeding?

7 A. Yes, I am sponsoring the following exhibits:

8 Exhibit Description

9 A-10 MEP Marysville Power Plant Decommissioning Estimate

11 A-12 Marysville vs. Harbor Beach Value Analysis

12 A-13 Harbor Beach Land Appraisal

14 Q. Were these exhibits prepared by you or under your direction?

15 A. Yes, they were.

17 Q. What was the actual net cost for demolition of the Marysville Power Plant?

18 A. DTE Electric sold the plant and property for $0.5 million in 2014. The sale

19 transferred the liability to remove and demolish the plant to the buyer and the

20 benefits of any resulting scrap.

22 Q. Do you believe the actual net cost of demolition of the Marysville Power Plant

23 should be used as a benchmark for the cost to decommission, decontaminate

24 and demolish other DTE Electric power plants?

25 A. No. Marysville power plant was an exception due to the location of the property

NEM - 4 96 N. E. MORTENSEN Line U-18150 No.

1 (potential reuse by future developers) and its scrap value. The Marysville Power

2 Plant property has railroad, major highway and deep water port potential for

3 Michigan that enhances its property reuse.

5 The MEP estimate to demolish the plant was $31.9M (See Exhibit A-10) excluding

6 DTE MEP overheads, with an estimated $9.7M worth of scrap metal. It made

7 financial sense to shift the cost of completing the decommissioning and demolition

8 of the plant to the developer. The difference between the price paid and the

9 demolition cost can be attributed to the developer’s future value from reuse of the

10 land and the scrap value.

12 Q. What is reflected on Exhibit A-12?

13 A. Exhibit A-12 is a comparison of the sales of the Marysville and Harbor Beach

14 Power Plants prepared by DTE Electric. I used these documents in my evaluation of

15 whether the Marysville and Harbor Beach Power Plants are representative of DTE

16 Electric’s remaining power plants.

18 Q. What is the cost for decommissioning, decontamination and demolition of the

19 Harbor Beach power plant that you are sponsoring?

20 A. As shown on Exhibit A-13, I support a cost of dispositioning the Harbor Beach

21 Power Plant to a demolition company of $3.8 million (Exhibit A-13, Line 5). In

22 addition, the cost to remove the remainder of the ash will be another $6 million

23 (Exhibit A-13, Line 7) . The cost for DTE to perform the disposition of the plant

24 using union labor, with DTE overhead, would be $1.9 million (Exhibit A-13, Lines

25 8 and 9). Finally, I have estimated the remaining Decontamination and

NEM - 5 97 N. E. MORTENSEN Line U-18150 No.

1 Decommissioning costs to be just under $0.9 million (Exhibit A-13, Line 1).

2 Resulting in a total disposition cost of $12.6 million.

4 Q. Do you believe the cost of demolition of the Harbor Beach Power Plant should

5 be used as a benchmark for the cost to demolish other DTE Electric power

6 plants?

7 A. No. The Harbor Beach Power Plant, built in the mid-to-late 1960’s, was a glorified

8 pole barn (or butler building) constructed with light weight steel and siding.

10 Q. Does this complete your direct testimony?

11 A. Yes, it does.

NEM - 6 98

1 MR. CHRISTINIDIS: Thank you, your Honor.

2 The Company's next witness is Dr. Ronald E. White.

3 Dr. White caused to be filed with the Commission the

4 Qualifications and Direct Testimony of Dr. Ronald E.

5 White, which consists of 13 pages of questions and

6 answers, along with Attachment REW-1, which is his

7 resume. He also sponsored one exhibit which has been

8 designated as Exhibit A-15 and consists of 95 pages.

9 Dr. White also sponsored rebuttal

10 testimony in this case consisting of a cover sheet and

11 ten pages of questions and answers. With that, your

12 Honor, the Company would move to bind into the record the

13 direct testimony and rebuttal testimony of Dr. Ronald E.

14 White, including his Attachment REW-1, and move the

15 admission of Exhibit A-15.

16 JUDGE FELDMAN: All right. Let me ask

17 for the record if there are any objections to Mr.

18 Christinidis's request regarding Dr. White's testimony

19 and exhibit? Hearing no objections, the prefiled direct

20 and rebuttal testimony of Dr. Ronald E. White will be

21 bound into the record, and Exhibit A-15 is admitted into

22 evidence. And the direct testimony does include Dr.

23 White's attached resume.

24 (Testimony bound in.)

25 Metro Court Reporters, Inc. 248.360.8865 99

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) DTE Electric Company ) Case No. U–18150 for approval of depreciation accrual rates ) and other related matters )

QUALIFICATIONS

AND

DIRECT TESTIMONY

DR. RONALD E. WHITE

100

DTE ELECTRIC COMPANY QUALIFICATIONS OF DR. RONALD E. WHITE

1 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 2 A. My name is Ronald E. White. My business address is 17595 S. Tamiami Trail, Suite 3 260, Fort Myers, Florida 33908.

4 Q. WHAT IS YOUR OCCUPATION? 5 A. I am President of Foster Associates Consultants, LLC. Foster Associates is a public 6 utility economic consulting firm offering economic research and consulting services 7 on issues and problems arising from governmental regulation of business. Areas of 8 specialization supported by the firm’s Fort Myers office include property service–life 9 forecasting, depreciation estimation, and valuation of industrial property.

10 Q. PLEASE BRIEFLY DESCRIBE YOUR EDUCATIONAL TRAINING AND 11 PROFESSIONAL BACKGROUND. 12 A. I was awarded a B.S. degree in Engineering Operations and M.S. and Ph.D. degrees 13 in Engineering Valuation from Iowa State University. I have taught graduate and un- 14 dergraduate courses in industrial engineering, engineering economics, and engineer- 15 ing valuation at Iowa State and previously served on the faculty for Depreciation 16 Programs for public utility commissions, companies, and consultants, sponsored by 17 Depreciation Programs, Inc., in cooperation with Western Michigan University. I also 18 conduct courses in depreciation and public utility economics for clients of Foster As- 19 sociates. 20 I have prepared and presented a number of papers to professional organizations, 21 committees, and conferences and have published several articles on matters relating 22 to depreciation, valuation and economics. I am a past member of the Board of Direc- 23 tors of the Iowa State Regulatory Conference and an affiliate member of the joint 24 American Gas Association (A.G.A.) – Edison Electric Institute (EEI) Depreciation 25 Accounting Committee, where I previously served as chairman of a standing com- 26 mittee on capital recovery and its effect on corporate economics. I am also a member 27 of the American Economic Association, the Financial Management Association, the

REW–1

101

1 Midwest Finance Association, and a founding member of the Society of Deprecia- 2 tion Professionals.

3 Q. WHAT IS YOUR PROFESSIONAL EXPERIENCE? 4 A. I joined the firm of Foster Associates in 1979, as a specialist in depreciation, the eco- 5 nomics of capital investment decisions, and cost of capital studies for ratemaking ap- 6 plications. Before joining Foster Associates, I was employed by Northern States 7 Power Company (1968–1979) in various assignments related to finance and treasury 8 activities. As Manager of the Corporate Economics Department, I was responsible for 9 book depreciation studies, studies involving staff assistance from the Corporate Eco- 10 nomics Department in evaluating the economics of capital investment decisions, and 11 the development and execution of innovative forms of project financing. As Assistant 12 Treasurer at Northern States, I was responsible for bank relations, cash requirements 13 planning, and short–term borrowings and investments.

14 Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE A REGULATORY BODY? 15 A. Yes. I have testified in numerous proceedings before administrative and judicial bod- 16 ies in over 30 jurisdictions, including several appearances in Michigan. I have also 17 testified before the Federal Energy Regulatory Commission, the Federal Power 18 Commission, the Alberta Energy Board, the Ontario Energy Board, and the Securities 19 and Exchange Commission. I have sponsored position statements before the Federal 20 Communications Commission and numerous local franchising authorities in matters 21 relating to the regulation of telephone and cable television. A more detailed descrip- 22 tion of my professional qualifications is contained in Attachment REW–1. 23 24 25 26 27 28 29

REW–2 102

DTE ELECTRIC COMPANY DIRECT TESTIMONY OF DR. RONALD E. WHITE

1 I. PURPOSE OF TESTIMONY

2 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? 3 A. Foster Associates was engaged by DTE Electric Company (“DTE Electric” or “Com- 4 pany”) to conduct a 2016 depreciation rate study for plant subject to the jurisdiction 1 5 of the Michigan Public Service Commission (“MPSC” or “Commission”). The pur- 6 pose of my testimony is to sponsor and describe the study conducted by Foster Asso- 7 ciates. Depreciation rates currently used by DTE Electric for non−renewable assets 8 were approved by the Commission in Case No. U−16117 (Order dated June 16, 9 2011). Current depreciation rates for renewable assets were approved in Case No, 10 U−16991 (Order dated July 8, 2014).

11 II. IDENTIFICATION OF EXHIBITS 12 Q. DO YOU SPONSOR ANY EXHIBITS IN SUPPORT OF YOUR TESTIMONY? 13 A. Yes. I sponsor Exhibit A−15, a document titled “2016 Depreciation Study.” This 14 document was prepared by me or under my direction and supervision.

15 III. DEVELOPMENT OF DEPRECIATION RATES

16 Q. PLEASE EXPLAIN WHY DEPRECIATION STUDIES ARE NEEDED FOR 17 ACCOUNTING AND RATEMAKING PURPOSES? 18 A. The goal of depreciation accounting is to charge to operations a reasonable estimate 19 of the cost of the service potential of an asset (or group of assets) consumed during an 20 accounting interval. A number of depreciation systems have been developed to 21 achieve this objective, most of which employ time as the apportionment base. 22 Implementation of a time–based (or age–life) system of depreciation accounting 23 requires the estimation of several parameters or statistics related to a plant account. 24 The average service life of a vintage, for example, is a statistic that will not be

1 The Commission directed DTE Electric in Case No. U–16991 to file its next depreciation case, including depreciation rates for wind and solar assets, by September 1, 2016.

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1 known with certainty until all units from the original placement have been retired 2 from service. A vintage average service life, therefore, must be estimated initially 3 and periodically revised as indications of the eventual average service life becomes 4 more certain. Future net salvage rates and projection curves, which describe the ex- 5 pected distribution of retirements over time, are also estimated parameters of a de- 6 preciation system that are subject to future revisions. Depreciation studies should be 7 conducted periodically to assess the continuing reasonableness of parameters and ac- 8 crual rates derived from prior estimates. 9 The need for periodic depreciation studies is also a derivative of the ratemaking 10 process which establishes prices for utility services based on costs. Absent regula- 11 tion, deficient or excessive depreciation rates will produce no adverse consequence 12 other than a systematic over or understatement of the accounting measurement of 13 earnings. While a continuance of such practices may not comport with the goals of 14 depreciation accounting, the achievement of capital recovery is not dependent upon 15 either the amount or the timing of depreciation expense for an unregulated firm. In 16 the case of a regulated utility, however, recovery of investor–supplied capital is de- 17 pendent upon allowed revenues, which are in turn dependent upon approved levels of 18 depreciation expense. Periodic reviews of depreciation rates are, therefore, essential 19 to the achievement of timely capital recovery for a regulated utility. 20 It is also important to recognize that revenue associated with depreciation is a 21 significant source of internally generated funds used to finance plant replacements 22 and new capacity additions. This is not to suggest that internal cash generation 23 should be substituted for the goals of depreciation accounting. However, internally 24 generated funds incur no financing costs and the potential for realizing a reduction in 25 the marginal cost of external financing provides an added incentive for conducting 26 periodic depreciation studies and adopting proper depreciation rates.

27 Q. PLEASE DESCRIBE THE PRINCIPAL STEPS INVOLVED IN CONDUCT- 28 ING A DEPRECIATION STUDY. 29 A. The first step in conducting a depreciation study is the collection of plant accounting 30 data needed to conduct a statistical analysis of past retirement experience. Data are al-

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1 so collected to permit an analysis of the relationship between retirements and realized 2 gross salvage and cost of removal. The data collection phase should include a verifi- 3 cation of the accuracy of the plant accounting records and a reconciliation of the as- 4 sembled data to the official plant records of the company. 5 The next step in a depreciation study is the estimation of service life statistics 6 from an analysis of past retirement experience. The term life analysis is used to de- 7 scribe the activities undertaken in this step to obtain a mathematical description of 8 the forces of retirement acting upon a plant category. The mathematical expressions 9 used to describe these forces are known as survival functions or survivor curves. 10 Life indications obtained from an analysis of past retirement experience are 11 blended with expectations about the future to obtain an appropriate projection life 12 curve. This step, called life estimation, is concerned with predicting the expected re- 13 maining life of property units still exposed to the forces of retirement. The amount of 14 weight given to the analysis of historical data will depend upon the extent to which 15 past retirement experience is considered descriptive of the future. 16 An estimate of the net salvage rate applicable to future retirements is most often 17 obtained from an analysis of gross salvage and cost of removal realized in the past. 18 An analysis of past experience (including an examination of trends over time) pro- 19 vides a baseline for estimating future salvage and cost of removal. Consideration, 20 however, should be given to events that may cause deviations from net salvage ob- 21 served in the past. Among the factors that should be considered are the age of plant 22 retirements, the portion of retirements that will be reused, changes in the method of 23 removing plant, the type of plant to be retired in the future, inflation expectations, the 24 shape of the projection life curve, and economic conditions that may warrant greater 25 or lesser weight to be given to the net salvage observed in the past. 26 A comprehensive depreciation study will also include an analysis of the adequa- 27 cy of the recorded depreciation reserve. The purpose of such an analysis is to com- 28 pare the current balance in the recorded reserve with the balance required to achieve 29 the goals and objectives of depreciation accounting if the amount and timing of fu- 30 ture retirements and net salvage are realized exactly as predicted. The difference be-

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1 tween the required (or theoretical) reserve and the recorded reserve provides a meas- 2 urement of the expected excess or shortfall that will remain in the depreciation re- 3 serve if corrective action is not taken to extinguish the reserve imbalance. 4 Although reserve records are typically maintained by various account classifica- 5 tions, the total reserve for a company is the most important indicator of the adequacy 6 (or inadequacy) of recorded depreciation reserves. Differences between theoretical 7 recorded reserves will arise as a normal occurrence when service lives, dispersion 8 patterns and net salvage estimates are adjusted in the course of depreciation reviews. 9 Differences will also arise due to plant accounting activity such as transfers and ad- 10 justments requiring an identification of reserves at a different level from that main- 11 tained in the accounting system. It is appropriate, therefore, and consistent with 12 group depreciation theory, to periodically redistribute recorded reserves among pri- 13 mary accounts based on the most recent estimate of service lives, retirement disper- 14 sion and net salvage rates. A redistribution of the recorded reserve will provide an 15 initial reserve balance for each primary account consistent with the estimates of re- 16 tirement dispersion selected to describe mortality characteristics of the accounts and 17 establish a baseline against which future comparisons can be made. 18 Finally, parameters estimated from service life and net salvage studies are inte- 19 grated into an appropriate formulation of an accrual rate based upon a selected de- 20 preciation system. Three elements are needed to describe a depreciation system. The 21 sub–elements most widely used in constructing a depreciation system are shown in 22 Figure 1 below.

Methods Procedures Techniques Retirement Total Company Whole-Life Compound-Interest Broad Group Remaining-Life Sinking-Fund Vintage Group Probable-Life Straight-Line Equal-Life Group Declining Balance Unit Summation Sum-of-Years'-Digits Item Expensing Unit-of-Production Net Revenue

Figure 1. Elements of a Depreciation System

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1 The above elements (i.e., method, procedure and technique) can be visualized as 2 three dimensions of a cube in which each face describes a variety of sub–elements 3 that can be combined to form a system. A depreciation system is therefore formed by 4 selecting a sub–element from each face such that the system contains one method, 5 one procedure and one technique.

6 IV. 2016 DEPRECIATION RATE STUDY

7 Q. DID DTE ELECTRIC PROVIDE FOSTER ASSOCIATES PLANT AC- 8 COUNTING DATA FOR CONDUCTING THE 2016 DEPRECIATION 9 STUDY? 10 A. Yes. The database used in conducting the 2016 study was created by appending annu- 11 al plant, net salvage, and depreciation reserve transactions to the database used in 12 conducting the 2009 study. Plant and net salvage transactions for 2009 through 2015 13 activity years and accumulated depreciation reserves at December 31, 2015 were ex- 14 tracted from the Company’s Continuing Property Record (CPR) system developed ® 15 and maintained by PowerPlan . 16 The database used in the 2009 study was obtained from two sources. Prior to July 17 2005, plant and reserve activity for generation assets were maintained in a plant ac- 18 counting system developed by PeopleSoft. In July 2005, generation records were up- 19 loaded to a plant accounting system developed by SAP. Non–generation plant and 20 reserve records were maintained in the PeopleSoft system prior to March 2007, at 21 which time the system was converted to SAP. Plant and reserve activity maintained 22 in the SAP system provided database transactions over the period July 1, 2005 23 through December 31, 2008 for generation assets and over the period March 2007 24 through December 31, 2008 for non–generation assets. The database assembled from 25 these sources included transactions recorded over the period 1996–2008. 26 Accounting transactions extracted from the CPR systems for both the 2009 and 27 2016 studies were assigned transaction codes describing the nature of the accounting 28 activity. Transaction codes for plant additions, for example, were used to distinguish 29 normal additions from acquisitions, purchases, reimbursements and adjustments.

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1 Similar transaction codes were used to distinguish normal retirements from sales, re- 2 imbursements, abnormal retirements and adjustments. Transaction codes were also 3 assigned to transfers, capital leases, gross salvage, cost of removal and other ac- 4 counting activity considered in a depreciation study. 5 The accuracy and completeness of the assembled data base was verified by Fos- 6 ter Associates by comparing additions, retirements, transfers and adjustments, and 7 the ending plant balance over the period 1996–2015 to the regulated investments re- 8 ported by DTE Electric in MPSC Form P–521 electric plant in service reports. De- 9 rived age distributions of surviving plant at December 31, 2015 were reconciled to 10 the CPR.

11 Q. DID FOSTER ASSOCIATES CONDUCT STATISTICAL LIFE STUDIES FOR 12 DTE ELECTRIC PLANT AND EQUIPMENT? 13 A. Yes. As discussed in Exhibit A−15, all plant accounts were analyzed using a tech- 14 nique in which first, second and third degree polynomials were fitted to a set of ob- 15 served retirement ratios. The resulting function was expressed as a survivorship 16 function, which was numerically integrated to obtain an estimate of the average ser- 17 vice life. The smoothed survivorship function was then fitted by a weighted least– 18 squares procedure to the Iowa–curve family to obtain a mathematical description or 19 classification of the dispersion characteristics of the data. Service life indications de- 20 rived from the statistical analyses were blended with informed judgment and expecta- 21 tions about the future to obtain an appropriate projection life curve for each plant 22 category. Plant accounts classified in Steam, Nuclear and Other Production (with the 23 exception of non−peakers) were identified by unit and treated as life–span categories 24 in the 2016 study.

25 Q. DID FOSTER ASSOCIATES CONDUCT A NET SALVAGE ANALYSIS FOR 26 DTE ELECTRIC PLANT AND EQUIPMENT? 27 A. Yes. A five–year moving average analysis of the ratio of realized salvage and remov- 28 al expense to the associated retirements was used in the 2016 study for transmission, 29 distribution and general plant categories to: a) estimate a realized net salvage rate; b)

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1 detect the emergence of historical trends; and c) establish a basis for estimating a fu- 2 ture net salvage rate. Cost of removal and salvage opinions obtained from Company 3 personnel were blended with judgment and historical net salvage indications in de- 4 veloping estimates of the future. 5 Average net salvage rates for all depreciable plant accounts were estimated using 6 direct−dollar weighting of historical retirements with the historical net salvage rate, 7 and future retirements (i.e., surviving plant) with the estimated future net salvage 8 rate. 9 The firm of Sargent & Lundy was retained by DTE Electric to develop cost esti- 10 mates for the demolition and abatement of steam, other production and renewable fa- 11 cilities. Costs estimated for dismantling these units were used in the current 12 depreciation study to formulate average and future net salvage rates. Exhibit A−15, 13 Statement G provides a computation of terminal dismantlement costs used in State- 14 ment F to derive future net salvage rates for steam and other production facilities.

15 Q. DID THE COMPANY DIRECT FOSTER ASSOCIATES TO EXCLUDE DTE 16 ELECTRIC’S NON–MAJOR ENTERPRISE PROJECTS (MEP) DIRECT LA- 17 BOR AND BENEFITS COSTS AND CONTINGENCY COSTS INCLUDED IN 18 THE SARGENT & LUNDY DECOMMISSIONING STUDY? 19 A. Yes.

20 Q. WHAT WAS THE IMPACT ON DEPRECIATION EXPENSE FROM EX- 21 CLUDING THESE COSTS FROM THE DEPRECIATION STUDY? 22 A. Excluding $122.6 million in contingency costs reduces the annual depreciation accru- 23 al by $14.9 million. Excluding the non-MEP direct labor and benefits costs of $48.1 24 million reduces the annual depreciation accrual by $5.9 million. In total, the two ex- 25 clusions reduce the 2016 annualized depreciation accrual by $20.8 million.

26 Q. DID FOSTER ASSOCIATES CONDUCT AN ANALYSIS OF RECORDED 27 DEPRECIATION RESERVES? 28 A. Yes. Statement C of Exhibit A−15 provides a comparison of recorded, computed and 29 redistributed reserves at December 31, 2015. The recorded reserve was

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1 $6,816,774,333 or 38.2 percent of the depreciable plant investment. The correspond- 2 ing computed reserve is $7,226,934,786 or 40.5 percent of the depreciable plant in- 3 vestment. A proportionate amount of the measured reserve imbalance of 4 $410,160,454 will be amortized over the composite weighted–average remaining life 5 of each rate category using the remaining life depreciation rates recommended in this 6 study. Statement D of Exhibit A−15 provides an estimate of the investment and net 7 salvage components of the rebalanced reserves.

8 Q. IS FOSTER ASSOCIATES RECOMMENDING A REBALANCING OF DE- 9 PRECIATION RESERVES FOR DTE ELECTRIC? 10 A. Yes. It is the opinion of Foster Associates that a redistribution of recorded reserves is 11 again appropriate for DTE Electric. Offsetting reserve imbalances attributable to both 12 the passage of time and parameter adjustments recommended in the current study 13 should be realigned among primary accounts to reduce offsetting imbalances and in- 14 crease depreciation rate stability. 15 Additionally, the Company’s request to amortize plant account 397.03 – Com- 16 munication Equipment – General necessitates a rebalancing of the recorded reserves 17 for the general plant function. The request for authorization to amortize this account 18 is addressed by Company Witness Cooper. 19 A redistribution of the recorded reserve for depreciable plant was achieved by 20 multiplying the calculated reserve for each primary account within a function (or 21 plant location) by the ratio of the function (or location) total recorded reserves (net of 22 amortizable accounts) to the function (or location) total calculated reserve. The sum 23 of the redistributed reserves within a function (or location) is, therefore, equal to the 24 function (or location) total recorded depreciation reserve before the redistribution. 25 Depreciation reserves for amortizable categories were redistributed by setting the 26 recorded reserves for the amortization accounts equal to the theoretical reserves de- 27 rived from the proposed amortization periods and distributing the residual imbalanc- 28 es to the remaining depreciable accounts within the appropriate function.

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1 Q. PLEASE DESCRIBE THE DEPRECIATION SYSTEM CURRENTLY AP- 2 PROVED BY THE COMMISSION FOR DTE ELECTRIC. 3 A. Current depreciation rates were developed for each primary account using a deprecia- 4 tion system composed of the straight–line method, vintage group procedure, remain- 5 ing–life technique. 6 The formulation of an account accrual rate using the currently approved system 7 is given by: 1.0−− Reserve Ratio Future Net Salvage Rate Accrual Rate = . Remaining Life

8 A remaining–life rate is equivalent to the sum of a whole–life rate and an amorti- 9 zation of any reserve imbalance over the estimated remaining life of a rate category. 10 Stated as an equation, a remaining–life accrual rate is equivalent to

1.0−− Average Net Salvage Computed Reserve Recorded Reserve Accrual Rate = + Average Life Remaining Life

11 where both the computed reserve and the recorded reserve are expressed as ratios to 12 the plant in service.

13 Q. DID DTE ELECTRIC REQUEST THAT FOSTER ASSOCIATES CHANGE 14 THE DEPRECIATION SYSTEM IN THE 2016 STUDY? 15 A. Yes. The Company requested that Foster Associates develop rates in the 2016 study 16 using a system composed of the straight–line method, broad group procedure, and 17 remaining–life technique. (The reason for this request is addressed by Company Wit- 18 ness Cooper). It remains the opinion of Foster Associates, however, that the formula- 19 tion of vintage−group and broad−group depreciation rates is identical and neither 20 procedure requires a minimum number of activity years of data to formulate a depre- 21 ciation rate. 22 Although the emergence of economic factors such as restructuring and perfor- 23 mance based regulation may eventually encourage abandonment of the straight–line 24 method, no attempt was made in the current study to address this concern. It is also 25 the opinion of Foster Associates that amortization accounting currently approved for

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1 selected general support asset accounts is consistent with the goals and objectives of 2 depreciation accounting and remains appropriate for these plant categories.

3 Q. HOW WERE RENEWABLE ENERGY FACILITIES TREATED IN THE 2016 4 STUDY? 5 A. Projection lives for the investment portion of accruals for the two major plant catego- 6 ries (346.01 – Solar Miscellaneous Power Plant Equipment and 344.01 – Generators) 7 were estimated by DTE Electric from a direct dollar–weighting of service lives esti- 8 mated for property units classified in each account. Projection lives for the disman- 9 tlement portion of accruals for the two accounts were estimated by DTE Electric from 10 a consideration of the project lives for each technology. 11 Projection curves for the investment portion of the two accounts were estimated 12 by Foster Associates from a statistical analysis of the timing of future retirements in- 13 dicated by the retirement frequency distribution of property–unit service lives esti- 14 mated by DTE Electric. 15 Dismantlement cost estimates for the two accounts were provided to Foster As- 16 sociates denominated in 2015 dollars. The salvage and cost of removal estimates 17 were escalated by Foster Associates to the estimated year of demolition using infla- 18 tion rates provided by DTE Electric. 19 Projection lives, projection curves and future net salvage statistics adopted for 20 other renewable energy plant categories (e.g., station equipment, structures and gen- 21 eral plant) are those recommended for the corresponding conventional accounts. De- 22 preciation rates recommended for these categories are, however, specific to the wind 23 and solar projects.

24 Q. PLEASE SUMMARIZE THE DEPRECIATION RATES AND ACCRUALS 25 FOSTER ASSOCIATES IS RECOMMENDING FOR DTE ELECTRIC IN 26 THE 2016 STUDY.

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1 A. Table 1 below provides a summary of the changes in annual rates and accruals result- 2 ing from adoption of the parameters and depreciation system recommended in the 3 2016 depreciation study.

Accrual Rate 2016 Annualized Accrual Function Current Proposed Difference Current Proposed Difference A B C D=C-B E F G=F-E Production Steam 1.99% 4.07% 2.08% $143,802,974 $293,404,195 $149,601,221 Nuclear 4.04% 4.26% 0.22% 34,735,617 36,642,187 1,906,570 Other 4.07% 1.93% -2.14% 22,666,585 10,740,736 (11,925,849) Renewables 3.79% 4.11% 0.32% 35,416,502 38,422,770 3,006,268 Transmission 1.65% 2.51% 0.86% 1,378,039 2,096,289 718,250 Distribution 3.93% 3.98% 0.05% 289,546,503 292,889,214 3,342,711 General Plant 5.47% 6.63% 1.16% 45,614,837 55,350,421 9,735,584

Total 3.21% 4.09% 0.88% $573,161,057 $729,545,812 $156,384,755

Table 1. Current and Proposed Rates and Accruals

4 Foster Associates is recommending primary account depreciation rates equiva- 5 lent to a composite rate of 4.09 percent. Depreciation expense is currently accrued at 6 rates that composite to 3.21 percent. The recommended change in the composite de- 7 preciation rate is, therefore, an increase of 0.88 percentage points. 8 A continued application of current rates would provide annualized depreciation 9 expense of $573,161,057 compared with an annualized expense of $729,545,812 us- 10 ing the rates developed in this study. The proposed 2016 expense increase is 11 $156,384,755. The computed change in annualized accruals includes an increase of 12 $39,218,444 attributable to an amortization of a $410,160,454 reserve imbalance. 13 The remaining portion of the change is attributable to adjustments in service life and 14 net salvage statistics recommended in the 2016 study.

15 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 16 A. Yes, it does. 17 18 19 20

REW–13 113 Attachment REW–1

Foster Associates Consultants, LLC Phone (239) 267-1600 17595 S. Tamiami Trail, Suite 260 Fax (239) 267-5030 Fort Myers, FL 33908 E-mail [email protected] Ronald E. White, Ph.D.

Education 1961 - 1964 Valparaiso University Major: Electrical Engineering 1965 Iowa State University B.S., Engineering Operations 1968 Iowa State University M.S., Engineering Valuation Thesis: The Multivariate Normal Distribution and the Simulated Plant Record Method of Life Analysis 1977 Iowa State University Ph.D., Engineering Valuation Minor: Economics Dissertation: A Comparative Analysis of Various Estimates of the Hazard Rate Associated With the Service Life of Industrial Property

Employment 2015 - Present Foster Associates Consultants, LLC President 2007 - 2015 Foster Associates, Inc. Chairman 1996 - 2007 Foster Associates, Inc. Executive Vice President 1988 - 1996 Foster Associates, Inc. Senior Vice President 1979 - 1988 Foster Associates, Inc. Vice President 1978 - 1979 Northern States Power Company Assistant Treasurer 1974 - 1978 Northern States Power Company Manager, Corporate Economics 1972 - 1974 Northern States Power Company Corporate Economist 1970 - 1972 Iowa State University Graduate Student and Instructor 1968 - 1970 Northern States Power Company Valuation Engineer 1965 - 1968 Iowa State University Graduate Student and Teaching Assistant

Publications A New Set of Generalized Survivor Tables, Journal of the Society of Depreciation Professionals, October, 1992. The Theory and Practice of Depreciation Accounting Under Public Utility Regulation, Journal of the Society of Depreciation Professionals, December, 1989. Standards for Depreciation Accounting Under Regulated Competition, paper presented at The Institute for Study of Regulation, Rate Symposium, February, Page 1 of 14

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1985. The Economics of Price-Level Depreciation, paper presented at the Iowa State University Regulatory Conference, May, 1981. Depreciation and the Discount Rate for Capital Investment Decisions, paper presented at the National Communications Forum - National Electronics Conference, October 1979. A Computerized Method for Generating a Life Table From the 'h-System' of Survival Functions, paper presented at the American Gas Association - Edison Electric Institute Depreciation Accounting Committee Meeting, December, 1975. The Problem With AFDC is …, paper presented at the Iowa State University Conference on Public Utility Valuation and the Rate Making Process, May, 1973. The Simulated Plant-Record Method of Life Analysis, paper presented at the Missouri Public Service Commission Regulatory Information Systems Conference, May, 1971. Simulated Plant-Record Survivor Analysis Program (User's Manual), special report published by Engineering Research Institute, Iowa State University, February, 1971. A Test Procedure for the Simulated Plant-Record Method of Life Analysis, Journal of the American Statistical Association, September, 1970. Modeling the Behavior of Property Records, paper presented at the Iowa State University Conference on Public Utility Valuation and the Rate Making Process, May, 1970. A Technique for Simulating the Retirement Experience of Limited-Life Industrial Property, paper presented at the National Conference of Electric and Gas Utility Accountants, May, 1969. How Dependable are Simulated Plant-Record Estimates?, paper presented at the Iowa State University Conference on Public Utility Valuation and the Rate Making Process, April, 1968.

Testifying Alabama Public Service Commission, Docket No. 18488, General Telephone Witness Company of the Southeast; testimony concerning engineering economy study techniques. Alabama Public Service Commission, Docket No. 20208, General Telephone Company of the South; testimony concerning the equal-life group procedure and remaining-life technique. Alberta Energy and Utilities Board, Application No. 1250392, Aquila Networks Canada; rebuttal testimony supporting proposed depreciation rates. Alberta Energy and Utilities Board, Case No. RE95081, Edmonton Power Inc.; rebuttal evidence concerning appropriate depreciation rates. Alberta Energy and Utilities Board, 1999/2000 General Tariff Application, Edmonton Power Inc.; direct and rebuttal evidence concerning appropriate depreciation rates. Arizona Corporation Commission, Docket No. T-01051B-97-0689, U S West Communications, Inc.; testimony concerning appropriate depreciation rates. Arizona Corporation Commission, Docket No. G-1032A-02-0598, Citizens Communications Company; testimony supporting proposed depreciation rates. Arizona Corporation Commission, Docket No. E–0135A–03–0437, Arizona Public Service Company; rebuttal testimony supporting net salvage rates.

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Arizona Corporation Commission, Docket No. E–01345A–05–0816, Arizona Public Service Company; testimony supporting proposed depreciation rates. Arizona Corporation Commission, Docket No. E–01345A–08–0172, Arizona Public Service Company; testimony supporting proposed depreciation rates.

Arizona Corporation Commission, Docket No. E–01345A–11–0224, Arizona Public Service Company; testimony supporting proposed depreciation rates.

Arizona Corporation Commission, Docket No. E–01345A–16–0036, Arizona Public Service Company; testimony supporting proposed depreciation rates.

Arizona Corporation Commission, Docket No. E–01933A–12–0126, Tucson Electric Power Company; testimony supporting proposed depreciation rates.

Arizona Corporation Commission, Docket No. E–01933A–15–0322, Tucson Electric Power Company; testimony supporting proposed depreciation rates.

Arizona Corporation Commission, Docket No. G–04204A–06–0463, UNS Gas, Inc.; testimony supporting proposed depreciation rates. Arizona Corporation Commission, Docket No. E–04204A–06–0783, UNS Electric, Inc.; testimony supporting proposed depreciation rates. Arizona Corporation Commission, Docket No. E–04204A–09–0206, UNS Electric, Inc.; testimony supporting proposed depreciation rates. Arizona Corporation Commission, Docket No. E–04204A–15–0142, UNS Electric, Inc.; testimony supporting proposed depreciation rates. Arizona State Board of Equalization, Docket No. 6302-07-2, Arizona Public Service Company; testimony concerning valuation and assessment of contributions in aid of construction. California Public Utilities Commission, Case Nos. A.92-06-040, 92-06-042, GTE California Incorporated; rebuttal testimony supporting depreciation study techniques. California Public Utilities Commission. Docket No. GRC A.05–12–002, Pacific Gas and Electric Company; testimony regarding estimation of net salvage rates. California Public Utilities Commission. Docket No. GRC A.06–12–009/A.06–12– 010, San Diego Gas & Electric Company and Southern California Gas Company; testimony regarding estimation of net salvage rates. Public Utilities Commission of the State of Colorado, Application No. 36883- Reopened. U S WEST Communications; testimony concerning equal-life group procedure. State of Connecticut Department of Public Utility Control, Docket No. 10–12–02, Yankee Gas Services Company; testimony supporting recommended depreciation rates. State of Connecticut Department of Public Utility Control, Docket No. 09–12–05, The Connecticut Light and Power Company; testimony supporting recommended depreciation rates. State of Connecticut Department of Public Utility Control, Docket No. 06–12PH01, Yankee Gas Services Company; testimony supporting recommended depreciation rates. State of Connecticut Department of Public Utility Control, Docket No. 05–03–17, The Southern Connecticut Gas Company; testimony supporting recommended

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depreciation rates. Delaware Public Service Commission, Docket No. 81-8, Diamond State Telephone Company; testimony concerning the amortization of inside wiring. Delaware Public Service Commission, Docket No. 82-32, Diamond State Telephone Company; testimony concerning the equal-life group procedure and remaining-life technique. Public Service Commission of the District of Columbia, Formal Case No. 842, District of Columbia Natural Gas; testimony concerning depreciation rates. Public Service Commission of the District of Columbia, Formal Case No. 1016, Washington Gas Light Company - District of Columbia; testimony supporting proposed depreciation rates. Public Service Commission of the District of Columbia, Formal Case No. 1054, Washington Gas Light Company - District of Columbia; testimony supporting proposed depreciation rates. Public Service Commission of the District of Columbia, Formal Case No. 1093, Washington Gas Light Company - District of Columbia; testimony supporting proposed depreciation rates. Public Service Commission of the District of Columbia, Formal Case No. 1115, Washington Gas Light Company - District of Columbia; testimony supporting proposed depreciation rates.

Public Service Commission of the District of Columbia, Formal Case No. 1137, Washington Gas Light Company - District of Columbia; testimony supporting proposed depreciation rates.

Federal Communications Commission, Prescription of Revised Depreciation Rates for AT&T Communications; statement concerning depreciation, regulation and competition. Federal Communications Commission, Petition for Modification of FCC Depreciation Prescription Practices for AT&T; statement concerning alignment of depreciation expense used for financial reporting and regulatory purposes. Federal Communications Commission, Docket No. 99-117, Bell Atlantic; affidavit concerning revenue requirement and capital recovery implications of omitted plant retirements. Federal Energy Regulatory Commission, Docket No. RP14-118-000, WBI Energy Transmission, Inc.; testimony supporting proposed depreciation rates. Federal Energy Regulatory Commission, Docket No. ER10-2110-000, ITC Midwest; testimony supporting proposed depreciation rates. Federal Energy Regulatory Commission, Docket No. ER10-185-000, Michigan Electric Transmission Company; testimony supporting proposed depreciation rates. Federal Energy Regulatory Commission, Docket No. ER09-1530-000, ITCTransmission; testimony supporting proposed depreciation rates. Federal Energy Regulatory Commission, Docket No. ER95-267-000, New England Power Company; testimony supporting proposed depreciation rates. Federal Energy Regulatory Commission, Docket No. ER11-3638-000, Arizona Public Service Company; testimony supporting proposed depreciation rates

Federal Energy Regulatory Commission, Docket No. RP89-248, Mississippi River

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Transmission Corporation; rebuttal testimony concerning appropriateness of net salvage component in depreciation rates. Federal Energy Regulatory Commission, Docket No. ER91-565, New England Power Company; testimony supporting proposed depreciation rates. Federal Energy Regulatory Commission, Docket No. ER78-291, Northern States Power Company; testimony concerning rate of return and general financial requirements. Federal Energy Regulatory Commission, Docket Nos. RP80-97 and RP81-54, Tennessee Gas Pipeline Company; testimony concerning offshore plant depreciation rates. Federal Power Commission, Docket No. E-8252, Northern States Power Company; testimony concerning general financial requirements and measurements of financial performance. Federal Power Commission, Docket No. E-9148, Northern States Power Company; testimony concerning general financial requirements and measurements of financial performance. Federal Power Commission, Docket No. ER76-818, Northern States Power Company; testimony concerning rate of return and general financial requirements. Federal Power Commission, Docket No. RP74-80, Northern Natural Gas Company; testimony concerning depreciation expense. Public Utilities Commission of the State of Hawaii, Docket No. 00-0309, The Gas Company; testimony supporting proposed depreciation rates. Public Utilities Commission of the State of Hawaii, Docket No. 94-0298, GTE Hawaiian Telephone Company Incorporated; testimony concerning the need for shortened service lives and disclosure of asset impairment losses. Idaho Public Utilities Commission, Case No. U-1002-59, General Telephone Company of the Northwest, Inc.; testimony concerning the remaining-life technique and the equal-life group procedure. Illinois Commerce Commission, Case No. 04–0476, Illinois Power Company; testimony supporting proposed depreciation rates. Illinois Commerce Commission, Docket No. 94-0481, Citizens Utilities Company of Illinois; rebuttal testimony concerning applications of the Simulated Plant-Record method of life analysis. Iowa State Commerce Commission, Docket No. RPU 82-47, North Central Public Service Company; testimony on depreciation rates. Iowa State Commerce Commission, Docket No. RPU 84-34, General Telephone Company of the Midwest; testimony concerning the remaining-life technique and the equal-life group procedure. Iowa State Utilities Board, Docket No. DPU-86-2, Northwestern Bell Telephone Company; testimony concerning capital recovery in competition. Iowa State Utilities Board, Docket No. RPU-84-7, Northwestern Bell Telephone Company; testimony concerning the deduction of a reserve deficiency from the rate base. Iowa State Utilities Board, Docket No. DPU-88-6, U S WEST Communications; testimony concerning depreciation subject to refund. Iowa State Utilities Board, Docket No. RPU-90-9, Central Telephone Company of Iowa; testimony concerning depreciation rates.

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Iowa State Utilities Board, Docket No. RPU-93-9, U S WEST Communications; testimony concerning principles of depreciation accounting and abandonment of FASB 71. Iowa State Utilities Board, Docket No. DPU-96-1, U S WEST Communications; testimony concerning principles of depreciation accounting and abandonment of FASB 71. Iowa State Utilities Board, Docket No. RPU-05-2, Aquila Networks; testimony supporting recommended depreciation rates. Kansas Corporation Commission, Docket No. 16-KGSG-491-RTS, Kansas Gas Service, a Division of ONE Gas, Inc.; testimony supporting proposed depreciation rates. Kansas Corporation Commission, Docket No. 12-KGSG-835-RTS, Kansas Gas Service, a Division of ONEOK, Inc.; testimony supporting proposed depreciation rates. Kansas Corporation Commission, Docket No. 12-WSEE-112-RTS, Westar Energy, Inc.; testimony supporting proposed depreciation rates. Kansas Corporation Commission, Docket No. 10–KCPE–415–RTS; Kansas City Power and Light; cross–answering testimony addressing the recording and treatment of third–party reimbursements in estimating net salvage rates. Kansas Corporation Commission, Docket No. 04–AQLE–1065–RTS, Aquila Networks – WPE (Kansas); testimony supporting proposed depreciation rates. Kansas Corporation Commission, Docket No. 03–KGSG–602–RTS, Kansas Gas Service, a Division of ONEOK, Inc.; rebuttal testimony supporting net salvage rates. Kansas Corporation Commission, Docket No. 06–KGSG–1209–RTS, Kansas Gas Service, a Division of ONEOK, Inc.; testimony supporting proposed depreciation rates. Kentucky Public Service Commission, Case No. 97-224, Jackson Purchase Electric Cooperative Corporation; rebuttal testimony supporting proposed depreciation rates. Maryland Public Service Commission, Case No. 9096, Baltimore Gas and Electric Company; testimony supporting proposed depreciation rates. Maryland Public Service Commission, Case No. 8485, Baltimore Gas and Electric Company; testimony supporting proposed depreciation rates. Maryland Public Service Commission, Case No. 9424, Delmarva Power and Light Company; testimony supporting proposed depreciation rates.

Maryland Public Service Commission, Case No. 9385, Potomac Electric Power Company; testimony supporting proposed depreciation rates. Maryland Public Service Commission, Case No. 9103, Washington Gas Light Company; rebuttal testimony supporting proposed depreciation rates. Maryland Public Service Commission, Case No. 8960, Washington Gas Light Company; testimony supporting proposed depreciation rates. Maryland Public Service Commission, Case No. 7689, Washington Gas Light Company; testimony concerning life analysis and net salvage. Commonwealth of Massachusetts Department of Public Utilities, D.P.U. 15–155, Massachusetts Electric Company/Nantucket Electric Company; testimony supporting proposed depreciation rates.

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Commonwealth of Massachusetts Department of Public Utilities, D.P.U. 10–70, Western Massachusetts Electric Company; testimony supporting proposed depreciation rates.

Commonwealth of Massachusetts Department of Telecommunications and Energy, D.T.E. 06–55, Western Massachusetts Electric Company; testimony supporting proposed depreciation rates. Massachusetts Department of Public Utilities, Case No. DPU 91-52, Massachusetts Electric Company; testimony supporting proposed depreciation rates which include a net salvage component. Michigan Public Service Commission, Case No. U–16991, The Detroit Edison Company; testimony supporting proposed depreciation rates. Michigan Public Service Commission, Case No. U–16117, The Detroit Edison Company; testimony supporting proposed depreciation rates. Michigan Public Service Commission, Case No. U–15699, Michigan Consolidated Gas Company; testimony supporting proposed depreciation rates. Michigan Public Service Commission, Case No. U–13899, Michigan Consolidated Gas Company; testimony concerning service life estimates. Michigan Public Service Commission, Case No. U-13393, Aquila Networks – MGU; testimony supporting proposed depreciation rates. Michigan Public Service Commission, Case No. U-12395, Michigan Gas Utilities; testimony supporting proposed depreciation rates including amortization accounting and redistribution of recorded reserves. Michigan Public Service Commission, Case No. U-6587, General Telephone Company of Michigan; testimony concerning use of a theoretical depreciation reserve with the remaining-life technique. Michigan Public Service Commission, Case No. U-7134, General Telephone Company of Michigan; testimony concerning the equal-life group depreciation procedure. Minnesota Public Service Commission, Docket No. E-611, Northern States Power Company; testimony concerning rate of return and general financial requirements. Minnesota Public Service Commission, Docket No. E-1086, Northern States Power Company; testimony concerning depreciation rates. Minnesota Public Service Commission, Docket No. G-1015, Northern States Power Company; testimony concerning rate of return and general financial requirements. Public Service Commission of the State of Missouri, Case No. ER-2009-0090, KCP&L Greater Missouri Operations, rebuttal testimony concerning depreciation rates. Public Service Commission of the State of Missouri, Case No. ER-2001-672, Missouri Public Service, a division of Utilicorp United Inc.; surrebuttal testimony regarding computation of income tax expense. Public Service Commission of the State of Missouri, Case No. TO-82-3, Southwestern Bell Telephone Company; rebuttal testimony concerning the remaining-life technique and the equal-life group procedure. Public Service Commission of the State of Missouri, Case No. GO-97-79, Laclede Gas Company; rebuttal testimony concerning adequacy of database for conducting depreciation studies.

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Public Service Commission of the State of Missouri, Case No. GR-99-315, Laclede Gas Company; rebuttal testimony concerning treatment of net salvage in development of depreciation rates. Public Service Commission of the State of Missouri, Case No. HR–2004–0024, Aquila Inc. d/b/a/ Aquila Networks–L & P; testimony supporting depreciation rates. Public Service Commission of the State of Missouri, Case No. ER–2004–0034, Aquila Inc. d/b/a/ Aquila Networks–L & P and Aquila Networks–MPS; testimony supporting depreciation rates. Public Service Commission of the State of Missouri, Case No. GR–2004–0072, Aquila Inc. d/b/a/ Aquila Networks–L & P and Aquila Networks–MPS; testimony supporting depreciation rates. Public Service Commission of the State of Montana, Docket No. 88.2.5, Mountain State Telephone and Telegraph Company; rebuttal testimony concerning the equal-life group procedure and amortization of reserve imbalances. Montana Public Service Commission, Docket No. D95.9.128, The Montana Power Company; testimony supporting proposed depreciation rates. Nebraska Public Service Commission, Docket No. NG–0041, Aquila Networks (PNG Nebraska); testimony supporting proposed depreciation rates. Public Service Commission of Nevada, Docket No. 92-7002, Central Telephone Company-Nevada; testimony supporting proposed depreciation rates. Public Service Commission of Nevada, Docket No. 91-5054, Central Telephone Company-Nevada; testimony supporting proposed depreciation rates. New Hampshire Public Utilities Commission, Docket No. DR95-169, Granite State Electric Company; testimony supporting proposed net salvage rates. New Jersey Board of Public Utilities, Docket No. GR07110889, New Jersey Natural Gas Company; testimony supporting proposed depreciation rates. New Jersey Board of Public Utilities, Docket No. GR 87060552, New Jersey Natural Gas Company; testimony supporting depreciation rates. New Jersey Board of Regulatory Commissioners, Docket No. GR93040114J, New Jersey Natural Gas Company; testimony supporting depreciation rates. New Jersey Board of Regulatory Commissioners, Docket No. GR15111304, New Jersey Natural Gas Company; testimony supporting depreciation rates.

New York Public Service Commission, Case No. 12–G–0202. Niagara Mohawk Power Corporation d/b/a National Grid; testimony supporting recommended depreciation rates. New York Public Service Commission, Case No. 10–E–0050. Niagara Mohawk Power Corporation d/b/a National Grid; testimony supporting recommended depreciation rates. North Carolina Utilities Commission, Docket No. E-7, SUB 487, Duke Power Company; rebuttal testimony concerning proposed depreciation rates. North Carolina Utilities Commission, Docket No. P-19, SUB 207, General Telephone Company of the South; rebuttal testimony concerning the equal-life group depreciation procedure. North Dakota Public Service Commission, Case No. 8860, Northern States Power Company; testimony concerning general financial requirements. North Dakota Public Service Commission, Case No. 9634, Northern States Power

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Company; testimony concerning rate of return and general financial requirements. North Dakota Public Service Commission, Case No. 9666, Northern States Power Company; testimony concerning rate of return and general financial requirements. North Dakota Public Service Commission, Case No. 9741, Northern States Power Company; testimony concerning rate of return and general financial requirements. Oklahoma Corporation Commission, Cause No. PUD 201500213, Oklahoma Natural Gas Company; testimony supporting revised depreciation rates. Oklahoma Corporation Commission, Cause No. PUD 200900110, Oklahoma Natural Gas Company; testimony supporting revised depreciation rates. Ontario Energy Board, E.B.R.O. 385, Tecumseh Gas Storage Limited; testimony concerning depreciation rates. Ontario Energy Board, E.B.R.O. 388, Union Gas Limited; testimony concerning depreciation rates. Ontario Energy Board, E.B.R.O. 456, Union Gas Limited; testimony concerning depreciation rates. Ontario Energy Board, E.B.R.O. 476-03, Union Gas Limited; testimony concerning depreciation rates. Public Utilities Commission of Ohio, Case No. 81-383-TP-AIR, General Telephone Company of Ohio; testimony in support of the remaining-life technique. Public Utilities Commission of Ohio, Case No. 82-886-TP-AIR, General Telephone Company of Ohio; testimony concerning the remaining-life technique and the equal-life group procedure. Public Utilities Commission of Ohio, Case No. 84-1026-TP-AIR, General Telephone Company of Ohio; testimony in support of the equal-life group procedure and the remaining-life technique. Public Utilities Commission of Ohio, Case No. 81-1433, The Ohio Bell Telephone Company; testimony concerning the remaining-life technique and the equal-life group procedure. Public Utilities Commission of Ohio, Case No. 83-300-TP-AIR, The Ohio Bell Telephone Company; testimony concerning straight-line age-life depreciation. Public Utilities Commission of Ohio, Case No. 84-1435-TP-AIR, The Ohio Bell Telephone Company; testimony in support of test period depreciation expense. Public Utilities Commission of Oregon, Docket No. UM 204, GTE of the Northwest; testimony concerning the theory and practice of depreciation accounting under public utility regulation. Public Utilities Commission of Oregon, Docket No. UM 840, GTE Northwest Incorporated; rebuttal testimony concerning principles of capital recovery. Pennsylvania Public Utility Commission, Docket No. R-80061235, The Bell Telephone Company of Pennsylvania; testimony concerning the proper depreciation reserve to be used with an original cost rate base. Pennsylvania Public Utility Commission, Docket No. R-811512, General Telephone Company of Pennsylvania; testimony concerning the proper depreciation reserve to be used with an original cost rate base. Pennsylvania Public Utility Commission, Docket No. R-811819, The Bell Telephone Company of Pennsylvania; testimony concerning the proper depreciation reserve to be used with an original cost rate base. Pennsylvania Public Utility Commission, Docket No. R-822109, General Page 9 of 14

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Telephone Company of Pennsylvania; testimony in support of the remaining-life technique. Pennsylvania Public Utility Commission, Docket No. R-850229, General Telephone Company of Pennsylvania; testimony in support of the remaining-life technique and the proper depreciation reserve to be used with an original cost rate base. Pennsylvania Public Utility Commission, Docket No. C-860923, The Bell Telephone Company of Pennsylvania; testimony concerning capital recovery under competition. Rhode Island Public Utilities Commission, Docket No. 2290, The Narragansett Electric Company; testimony supporting proposed net salvage rates and depreciation rates. South Carolina Public Service Commission, Docket No. 91-216-E, Duke Power Company; testimony supporting proposed depreciation rates. South Dakota Public Utilities Commission, Docket No. EL14–106, NorthWestern Energy; testimony supporting revised depreciation rates. Public Utilities Commission of the State of South Dakota, Case No. F-3062, Northern States Power Company; testimony concerning general financial requirements and measurements of financial performance. Public Utilities Commission of the State of South Dakota, Case No. F-3188, Northern States Power Company; testimony concerning rate of return and general financial requirements. Securities and Exchange Commission, File No. 3-5749, Northern States Power Company; testimony concerning the financial and ratemaking implications of an affiliation with Lake Superior District Power Company. Tennessee Public Service Commission, Docket No. 89-11041, United Inter- Mountain Telephone Company; testimony concerning depreciation principles and capital recovery under competition. The Railroad Commission of Texas, GUD Docket No. 9988, Texas Gas Service, testimony supporting recommended depreciation rates. The Railroad Commission of Texas, GUD Docket No. 10488, Texas Gas Service, testimony supporting recommended depreciation rates. The Railroad Commission of Texas, GUD Docket No. 10506, Texas Gas Service, testimony supporting recommended depreciation rates.

The Railroad Commission of Texas, GUD Docket No. 10526, Texas Gas Service, testimony supporting recommended depreciation rates.

State of Vermont Public Service Board, Docket No. 6596, Citizens Communications Company – Vermont Electric Division; testimony supporting recommended depreciation rates. State of Vermont Public Service Board, Docket No. 6946 and 6988, Central Vermont Public Service Corporation; testimony supporting net salvage rates. Commonwealth of Virginia State Corporation Commission, Case No. PUE-2002- 00364, Washington Gas Light Company; testimony supporting proposed depreciation rates. Public Service Commission of Wisconsin, Docket No. 2180-DT-3, General Telephone Company of Wisconsin; testimony concerning the equal-life group

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depreciation procedure.

Other Arbitrator in a Technical Dispute relating to classification of Capital Budget Consulting expenditures. Activities Moran Towing Corporation. In Re: Barge TEXAS-97 CIV. 2272 (ADS) and Tug HEIDE MORAN – 97 CIV. 1947 (ADS), United States District Court, Southern District of New York. John Reigle, et al. v. Baltimore Gas & Electric Co., et al., Case No. C-2001-73230- CN, Circuit Court for Anne Arundel County, Maryland. SR International Business Insurance Co. vs. WTC Properties et. al., 01,CV–9291 (JSM) and other related cases. BellSouth Telecommunications, Inc. v. Citizens Utilities Company d/b/a/ Louisiana Gas Service Company, CA No. 95-2207, United States District Court, Eastern District of Louisiana. Affidavit on behalf of Continental Cablevision, Inc. and its operating cable television systems regarding basic broadcast tier and equipment and installation cost-of-service rate justification. Office of Chief Counsel, Internal Revenue Service. In Re: Kansas City Southern Railway Co., et. al. Docket Nos. 971-72, 974-72, and 4788-73. Office of Chief Counsel, Internal Revenue Service. In Re: Northern Pacific Railway Co., Docket No. 4489-69. United States Department of Justice. In Re: Burlington Northern Inc. v. United States, Ct. Cl. No. 30-72. Minnesota District Court. In Re: Northern States Power Company v. Ronald G. Blank, et. al. File No. 394126; testimony concerning depreciation and engineering economics.

Faculty Depreciation Programs for public utility commissions, companies, and consultants, sponsored by Depreciation Programs, Inc., in cooperation with Western Michigan University. (1980 - 1999) United States Telephone Association (USTA), Depreciation Training Seminar, November 1999. Depreciation Advocacy Workshop, a three-day team-training workshop on preparation, presentation, and defense of contested depreciation issues, sponsored by Gilbert Associates, Inc., October, 1979. Corporate Economics Course, Employee Education Program, Northern States Power Company. (1968 - 1979) Perspectives of Top Financial Executives, Course No. 5-300, University of Minnesota, September, 1978. Depreciation Programs for public utility commissions, companies, and consultants, jointly sponsored by Western Michigan University and Michigan Technological University, 1973.

Professional Advisory Committee to the Institute for Study of Regulation, sponsored by the Associations American University and The University of Missouri-Columbia. American Economic Association. American Gas Association - Edison Electric Institute Depreciation Accounting Committee.

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Board of Directors, Iowa State Regulatory Conference. Edison Electric Institute, Energy Analysis Division, Economic Advisory Committee, 1976-1980. Financial Management Association. The Institute of Electrical and Electronics Engineers, Inc., Power Engineering Society, Engineering and Planning Economics Working Group. Midwest Finance Association. Society of Depreciation Professionals (Founding Member and Chairman, Policy Committee).

Moderator Depreciation Open Forum, Iowa State University Regulatory Conference, May 1991. The Quantification of Risk and Uncertainty in Engineering Economic Studies, Iowa State University Regulatory Conference, May 1989. Plant Replacement Decisions with Added Revenue from New Service Offerings, Iowa State University Regulatory Conference, May 1988. Economic Depreciation, Iowa State University Regulatory Conference, May 1987. Opposing Views on the Use of Customer Discount Rates in Revenue Requirement Comparisons, Iowa State University Regulatory Conference, May 1986. Cost of Capital Consequences of Depreciation Policy, Iowa State University Regulatory Conference, May 1985. Concepts of Economic Depreciation, Iowa State University Regulatory Conference, May 1984. Ratemaking Treatment of Large Capacity Additions, Iowa State University Regulatory Conference, May 1983. The Economics of Excess Capacity, Iowa State University Regulatory Conference, May 1982. New Developments in Engineering Economics, Iowa State University Regulatory Conference, May 1980. Training in Engineering Economy, Iowa State University Regulatory Conference, May 1979. The Real Time Problem of Capital Recovery, Missouri Public Service Commission, Regulatory Information Systems Conference, September 1974.

Speaker Depreciation Workshop, Oklahoma Corporation Commission, Public Utility Division, March 2015. Depreciation Workshop, ONE Gas, Inc. January 2015. Depreciation Training Seminar, Florida Public Service Commission, March 2013. Depreciation and Obsolescence (Isness and Oughtness), Ninety–Fifth Annual Arizona Tax Conference, August 2012. Group Depreciation Practices of Regulated Utilities (IAS 16 Property, Plant and Equipment), Hydro One Networks, Inc., November 2008. Economics, Finance and Engineering Valuation. Florida Gulf Coast University, April 2007. Depreciation Studies for Regulated Utilities, Hydro One Networks, Inc., April 2006.

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Depreciation Studies for Cooperatives and Small Utilities. TELERGEE CFO and Controllers Conference, November, 2004. Finding the “D” in RCNLD (Valuation Applications of Depreciation), Society of Depreciation Professionals Annual Meeting, September 2001. Capital Asset and Depreciation Accounting, City of Edmonton Value Engineering Workshop, April 2001. A Valuation View of Economic Depreciation, Society of Depreciation Professionals Annual Meeting, October 1999. Capital Recovery in a Changing Regulatory Environment, Pennsylvania Electric Association Financial-Accounting Conference, May 1999. Depreciation Theory and Practice, Southern Natural Gas Company Accounting and Regulatory Seminar, March 1999. Depreciation Theory Applied to Special Franchise Property, New York Office of Real Property Services, March 1999. Capital Recovery in a Changing Regulatory Environment, PowerPlan Consultants Annual Client Forum, November 1998. Economic Depreciation, AGA Accounting Services Committee and EEI Property Accounting and Valuation Committee, May 1998. Discontinuation of Application of FASB Statement No. 71, Southern Natural Gas Company Accounting Seminar, April 1998. Forecasting in Depreciation, Society of Depreciation Professionals Annual Meeting, September 1997. Economic Depreciation In Response to Competitive Market Pricing, 1997 TELUS Depreciation Conference, June 1997. Valuation of Special Franchise Property, City of New York, Department of Finance Valuation Seminar, March 1997. Depreciation Implications of FAS Exposure Draft 158-B, 1996 TLG Decommissioning Conference, October 1996. Why Economic Depreciation?, American Gas Association Depreciation Accounting Committee Meeting, August 1995. The Theory of Economic Depreciation, Society of Depreciation Professionals Annual Meeting, November 1994. Vintage Depreciation Issues, G & T Accounting and Finance Association Conference, June 1994. Pricing and Depreciation Strategies for Segmented Markets (Regulated and Competitive), Iowa State Regulatory Conference, May 1990. Principles and Practices of Depreciation Accounting, Canadian Electrical Association and Nova Scotia Power Electric Utility Regulatory Seminar, December 1989. Principles and Practices of Depreciation Accounting, Duke Power Accounting Seminar, September 1989. The Theory and Practice of Depreciation Accounting Under Public Utility Regulation, GTE Capital Recovery Managers Conference, February 1989. Valuation Methods for Regulated Utilities, GTE Capital Recovery Managers Conference, January 1988. Depreciation Principles and Practices for REA Borrowers, NRECA 1985 National Page 13 of 14

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Accounting and Finance Conference, September 1985. Depreciation Principles and Practices for REA Borrowers, Kentucky Association of Electric Cooperatives, Inc., Summer Accountants Association Meeting, June 1985. Considerations in Conducting a Depreciation Study, NRECA 1984 National Accounting and Finance Conference, October 1984. Software for Conducting Depreciation Studies on a Personal Computer, United States Independent Telephone Association, September 1984. Depreciation—An Assessment of Current Practices, NRECA 1983 National Accounting and Finance Conference, September 1983 Depreciation—An Assessment of Current Practices, REA National Field Conference, September 1983. An Overview of Depreciation Systems, Iowa State Commerce Commission, October 1982. Depreciation Practices for Gas Utilities, Regulatory Committee of the Canadian Gas Association, September 1981. Practice, Theory, and Needed Research on Capital Investment Decisions in the Energy Supply Industry, workshop, sponsored by Michigan State University and the Electric Power Research Institute, November 1977. Depreciation Concepts Under Regulation, Public Utilities Conference, sponsored by The University of Texas at Dallas, July 1976. Electric Utility Economics, Mid-Continent Area Power Pool, May 1974.

Honors and The Society of Sigma Xi. Awards Professional Achievement Citation in Engineering, Iowa State University, 1993.

August 2016

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STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) DTE ELECTRIC COMPANY ) for approval of depreciation accrual rates ) Case No. U-18150 and other related matters )

REBUTTAL TESTIMONY

DR. RONALD E. WHITE 128 DTE ELECTRIC COMPANY REBUTTAL TESTIMON OF DR. RONALD E. WHITE Line No.

1 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

2 A. My name is Ronald E. White. My business address is 17595 S. Tamiami Trail, Suite

3 260, Fort Myers Florida 33908.

5 Q. ARE YOU THE SAME RONALD E. WHITE WHO FILED DIRECT TESTI-

6 MONY ON BEHALF OF DTE ELECTRIC COMPANY IN THIS PROCEED-

7 ING?

8 A. Yes, I am.

10 I. PURPOSE OF TESTIMONY

11 Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY?

12 A. I was asked by DTE Electric Company (DTE Electric or Company) to respond to

13 portions of the pre–filed direct testimony of the Association of Businesses Advocat-

14 ing Tariff Equity (ABATE) Witness Mr. Andrews and the direct testimony of Staff

15 Witness Mr. Ancona. In particular, I will address technical/mathematical errors in

16 the formulation of depreciation rates recommended by each of these witnesses.1

18 II. SUMMARY

19 Q. PLEASE SUMMARIZE YOUR REBUTTAL TESTIMONY?

20 A. It is evident from the workpapers ABATE provided in response to Company Request

21 No. DEAB–1.2 that Witness Andrews simply added columns to my Excel spread-

1Other depreciation issues including disagreements with estimated retirement dates of steam production plants; the treatment of obsolete inventory; the escalation of estimated decommissioning costs beyond estimated retirement dates; the treatment of estimated decommissioning costs for retired power plants; the treatment of land values; and the timing of accruals for decommissioning costs will be addressed by other DTE Electric witnesses.

REW REBUTTAL - 1 129 R. E. WHITE Line U-18150 No.

1 sheets and attempted to scale remaining service–lives and interim retirements rigor-

2 ously calculated in the 2016 Depreciation Rate Study (Exhibit A-15). His scaling

3 exercise combined with incorrect depreciation reserves) yields mathematically incor-

4 rect depreciation rates that should be rejected in this proceeding.

6 Staff’s recommendation that “… any increase in accrual rates [should be] limited to

7 the reserve imbalance increase at this time”2 is opinion testimony regarding annual-

8 ized depreciation expense with no proposed depreciation rates. A calculation of de-

9 preciation rates designed to achieve Staff’s objective would require conflicting

10 service–life and net salvage assumptions yielding depreciation rates that are “results

11 driven.” I would strongly discourage such an approach to setting depreciation rates

12 in this proceeding.

14 III. REPLY TO ABATE WITNESS ANDREWS

15 Q. PLEASE EXPLAIN HOW ABATE CALCULATED REMAINING SERVICE–

16 LIVES FOR STEAM PRODUCTION PLANTS.

17 A. After extending the estimated year of final retirement (AYFR) for five (5) production

18 plants, ABATE attempted to derive remaining–lives for each affected plant account

19 using the following formula:

ABATE AYFR− 2016 ABATE Remaining-Life = [Company Remaining-Life] . Company AYFR− 2016

20 In other words, ABATE lengthened remaining–lives by scaling the Company’s re-

21 maining–lives using the ratio of a numerator larger than the denominator.3

2Ancona Direct Testimony, page 7, lines 19–21. 3Additionally, ABATE may want to revisit their recomputed remaining lives for the St. Clair plant.

REW REBUTTAL - 2 130 R. E. WHITE Line U-18150 No.

1 Q. DOES THE ABATE FORMULATION PRODUCE A CORRECT COMPUTA-

2 TION OF REMAINING–LIVES?

3 A. No. First, it should be noted that remaining–lives estimated in the 2016 Depreciation

4 Rate Study were derived at December 31, 2015 using the half–year convention.4 Ac-

5 cordingly, the ABATE year of 2016 should be reduced to 2015.5.

7 Second, the ABATE formula would remain incorrect even if the year 2016 is reduced

8 to 2015.5. The formula would be correct if and only if interim retirements are ignored

9 over the intervening years prior to the estimated year of final retirement. The ABATE

10 assumption of no interim retirements, however, is contrary to remaining lives calcu-

11 lated by Foster Associates in the 2016 study (that ABATE attempts to adjust) and

12 interim retirements recognized in ABATE’s computation of future net salvage rates.

13 The formula required to correctly “scale” an initial remaining–life (RL1) at December

14 31, 2015 to a revised remaining–life (RL2) reflecting an extended AYFR is given by:

XX− YY+  RL = 2 0 20RL 2   []1 X1−+ X 0  YY 10  Where

X O = Age of plant in service at December 31, 2015

X11= Age of plant in service at AYFR

X 22= Age of plant in service at AYFR

YX00= Proportion surviving at

YX11= Proportion surviving at and

YX22= Proportion surviving at .

4The half–year convention postulates that the age of plant additions and retirements is measured from the mid–point of a calendar or fiscal year.

REW REBUTTAL - 3 131 R. E. WHITE Line U-18150 No.

1 Third, it should be noted that ABATE applied the incorrect formula to the composite

2 remaining life of each plant account in which the estimated year of final retirement

3 was adjusted. The correct formula, however, must be applied to each vintage remain-

4 ing in service at December 31, 2015 for each adjusted plant account. Vintage re-

5 maining lives must then be composited to obtain an account adjusted average

6 remaining life. A composite remaining life is a function of the age distribution of

7 surviving plant, the slope of a straight-line (i.e., SC) dispersion used to estimate in-

8 terim retirements and an estimated year of final retirement.5

10 In short, ABATE has applied an incorrect formula that will overstate remaining lives

11 and understate the accrual rate for each plant account in which AYFRs were ex-

12 tended.

14 Q. PLEASE EXPLAIN HOW ABATE CALCULATED INTERIM RETIRE-

15 MENTS USED IN THE COMPUTATION OF FUTURE NET SALVAGE

16 RATES.

17 A. After extending the estimated year of final retirement (AYFR) for five (5) production

18 plants, ABATE attempted to derive interim retirements for each affected plant ac-

19 count using the following formula:

ABATE Interim Retirements = ABATE Remaining Life [Company Interim Retirements] . Company Remaining Life

20 In other words, ABATE derived interim retirements by scaling the Company’s in-

21 terim retirements by the ratio of a numerator larger than the denominator.

5Technically, the remaining life of a vintage using an SC dispersion is the area of a trapezoid bounded by X0, Xi, Y0, and Yi, divided by Y0.

REW REBUTTAL - 4 132 R. E. WHITE Line U-18150 No.

1 Q. IS THIS A CORRECT COMPUTATION OF INTERIM RETIREMENTS?

2 A. No. As discussed above, ABATE’s computation of remaining lives is incorrect

3 which, when corrected, produces an incorrect calculation of interim retirements. The

4 ABATE formula will derive correct interim retirements if and only if a) the wrong

5 formulation of composite remaining lives is used; and b) no vintages are retired prior

6 to the estimated year of final retirement.

8 The formula required to insure a correct computation of interim retirements for each

9 vintage in service at December 31, 2015 is given by:

Plant Interim Retirements=( Slope of SC Dispersion)()( AYFR−− 2015 1) . Y0

11 The above formula is consistent with correctly computed remaining lives and must

12 be applied to each vintage in service at December 31, 2015. The vintage application

13 is needed to recognize vintages that may be retired prior to the estimated year of final

14 retirement. The sum of vintaged interim retirements derived from the above formula

15 then becomes the correct total for a given plant account.

17 Q. WHERE DID ABATE OBTAIN DEPRECIATION RESERVES USED IN

18 THEIR FORMULATION OF DEPRECIATION RATES?

19 A. It is evident from the workpapers provided by ABATE that depreciation reserves

20 were obtained from the 2016 Depreciation Rate Study.

REW REBUTTAL - 5 133 R. E. WHITE Line U-18150 No.

1 Q. ARE THESE THE CORRECT RESERVES TO USE WITH ABATE’S EX-

2 TENDED YEARS OF FINAL RETIREMENT OR ADJUSTMENTS TO FU-

3 TURE NET SALVAGE RATES?

4 A. No. First, it is important to recognize that DTE Electric does not maintain deprecia-

5 tion reserves by primary account for each steam plant. Reserves are maintained (by

6 primary account) at the aggregate level of Steam Production Plant. The development

7 of remaining–life depreciation rates for each plant location therefore necessitates an

8 allocation of the Steam Production Plant reserve to the lowest level at which depre-

9 ciation rates are developed.

11 In the case of DTE Electric, depreciation rates are developed by primary account, for

12 each generating unit installed at a named steam production plant. The allocation of

13 reserves in the 2016 Depreciation Rate Study was achieved by allocating the total

14 Steam Production Plant recorded reserve to lower levels in proportion to the ratio of

15 lower level computed (or theoretical) reserves to the sum of lower level computed

16 reserves.

18 Computed reserves will change, however, if service lives or net salvage rates are

19 adjusted from those developed in the 2016 Depreciation Rate Study. Any change in

20 computed reserves will produce a change in the reserve amounts allocated to each

21 lower level primary account which, in turn, will produce a change in depreciation

22 rates.

24 The errors in accrual rates introduced by ABATE’s scaling of remaining lives and

25 interim retirements were, therefore, exacerbated by failing to reallocate depreciation

REW REBUTTAL - 6 134 R. E. WHITE Line U-18150 No.

1 reserves. In my view, the computation of accrual rates recommended by ABATE are

2 technically flawed to a degree they should be disregarded in this proceeding.

4 IV. REPLY TO STAFF WITNESS ANCONA

5 Q. WHAT IS YOUR UNDERSTANDING OF MR. ANCONA’S RECOM-

6 MENDED ADJUSTMENT TO THE COMPANY’S PROPOSED DEPRECIA-

7 TION EXPENSE?

8 A. According to Witness Ancona, Staff is concerned with: 1) Retirement dates assumed

9 for three (3) non–Belle River steam production plants; 2) The assumed period of time

10 before dismantlement begins; and 3) The treatment of obsolete inventory for plants

11 currently in service. Given these concerns, Staff recommends an increase in accruals

12 no greater than $39,218,444. The recommended increase represents amortization of

13 a $410,160,453 reserve imbalance measured by Foster Associates at December 31,

14 2015.

16 Q. DID STAFF PROPOSE DEPRECIATION RATES THAT WOULD LIMIT

17 ANY INCREASE IN DEPRECIATION EXPENSE TO $39.2 MILLION?

18 A. No. Staff declined to recommend a set of depreciation rates that would satisfy their

19 limiting criterion for an acceptable level of depreciation expense.

21 Q. PLEASE EXPLAIN HOW $39.2 MILLION WAS DERIVED IN THE 2016 DE-

22 PRECIATION RATE STUDY.

23 A. First, it is important to understand the concept of a computed or theoretical depreci-

24 ation reserve. The formulation of a theoretical reserve is given by:

Remaining Life Theoretical Reserve= Plant()() 1.0 − FNS −− 1.0 ANS  Average Life

REW REBUTTAL - 7 135 R. E. WHITE Line U-18150 No.

1 where FNS and ANS represent future and average net salvage rates, respectively.

2 Stated in words, the above formulation defines a theoretical reserve as:

Theoretical Reserve=−− Plant Investment Future Net Salvage Future Accruals.

4 The subtraction of future net salvage and future depreciation accruals (based on an

5 estimate of the life expectancy or average remaining life of plant currently in service)

6 provides a measurement of what the recorded reserve would be today if and only if

7 the timing of future retirements and realized net salvage occurs exactly as predicted

8 by a specified survivor curve.

10 A reserve imbalance is the difference between a theoretical reserve and a recorded

11 reserve at a given date. The total reserve imbalance for DTE Electric at December

12 31, 2015 was $410,160,453 (i.e., the difference between a theoretical reserve of

13 $7,226,934,786 and a recorded reserve of $6,816,774,333).

15 It is also important to understand the formulation of a remaining–life accrual rate and

16 its relationship to a reserve imbalance. The formulation of a remaining–life accrual

17 rate is given by: 1.0−− Recorded Reserve Ratio Future Net Salvage Rate Accrual Rate = . Remaining Life

18 The above formulation, however, is equivalent to the sum of a straight–line, whole–

19 life rate and a straight–line amortization of any reserve imbalance over the estimated

20 life expectancy or remaining life of a rate category. Stated as an equation, a remain-

21 ing–life accrual rate is equivalent to:

1.0−− Average Net Salvage Theoretical Reserve Recorded Reserve Accrual Rate = + Average Life Remaining Life REW REBUTTAL - 8 136 R. E. WHITE Line U-18150 No.

1 where both the computed reserve and the recorded reserve are expressed as ratios to

2 the plant in service. The product of an accrual rate and the associated plant invest-

3 ment yields an annualized depreciation accrual.

5 Note that the second term in the above equation (when multiplied by plant) is the

6 reserve imbalance of a plant category amortized over the estimated remaining life of

7 the category. In the case of DTE Electric, the sum of accruals derived from the sec-

8 ond term over all plant accounts was $39,218,444 at December 31, 2015.

10 Q. IS THE RESERVE IMBALANCE A STATIC AMOUNT THAT CAN BE

11 USED TO TARGET A DESIRED LEVEL OF DEPRECIATION EXPENSE?

12 A. No. It can be observed from the above equations that the reserve imbalance derived

13 at December 31, 2015 is a function of the service lives and net rates recommended in

14 the 2016 study. Given that Staff found that “… the increase [in accruals] attributable

15 to the reserve imbalance seems reasonable,” it is illogical to argue that the remaining

16 portion of the change in accruals “attributable to adjustments in service life and net

17 statistics” is unreasonable.6 Clearly, adjusting service lives and/or net salvage rates

18 to achieve an increase in depreciation expense no greater than $39.2 million would

19 change the reserve imbalance Staff found to be reasonable.

21 Q. IN YOUR OPINION, WOULD IT BE REASONABLE TO RETAIN CUR-

22 RENT DEPRECIATION RATES WITH AN ALLOWANCE OF $32.9 MIL-

23 LION ADDED TO ANNUAL DEPRECIATION EXPENSE?

6Ancona Direct Testimony, page 7, lines 19–20.

REW REBUTTAL - 9 137 R. E. WHITE Line U-18150 No.

1 A. No. Such an action would be “results driven” and abandon any mathematical disci-

2 pline in developing reasonable depreciation rates. I would strongly discourage using

3 a change in depreciation expense as the barometer for assessing the adequacy or in-

4 adequacy of competently derived depreciation rates.

6 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?

7 A. Yes, it does.

REW REBUTTAL - 10 138

1 MR. CHRISTINIDIS: Thank you, your Honor.

2 Finally, your Honor, the Company's last witness is Howard

3 R. Cooper. Mr. Cooper sponsored Qualifications and

4 Direct Testimony of Howard R. Cooper, which consists of a

5 cover sheet and 16 pages of questions and answers. He

6 also sponsored eight exhibits, and those exhibits have

7 been designated as Exhibit A-1, 182 pages; A-2, which is

8 two pages; A-3, which is one page; A-4, one page; A-5,

9 one page; A-6, two pages; A-7, two pages; and A-11, which

10 is one page.

11 Mr. Cooper also sponsored Rebuttal

12 Testimony in this case consisting of a cover sheet and 13

13 pages of questions and answers. And he sponsored two

14 exhibits associated with his rebuttal, which have been

15 designated as Exhibits A-16, which is comprised of 1,745

16 pages, and A-17, which is comprised of one page.

17 With that, your Honor, the Company would

18 move to bind into the record the qualifications and

19 direct and rebuttal testimony of Howard R. Cooper and

20 move the admission of Exhibits A-1, A-2, A-3, A-4, A-5,

21 A-6, A-7, A-11, A-16, and A-17.

22 JUDGE FELDMAN: All right. Let me ask

23 for the record if there are any objections to Mr.

24 Christinidis's request regarding Mr. Cooper's prefiled

25 direct and rebuttal testimony or his exhibits? Metro Court Reporters, Inc. 248.360.8865 139

1 Hearing no objections, the prefiled

2 direct and rebuttal of Mr. Howard R. Cooper will be bound

3 into the record, and Exhibits A-1 through A-7, A-11, and

4 A-16 and A-17 are admitted into evidence.

5 (Testimony bound in.)

25 Metro Court Reporters, Inc. 248.360.8865 140

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) DTE ELECTRIC COMPANY ) for approval of depreciation accrual rates ) Case No. U-18150 and other related matters )

QUALIFICATIONS

AND

DIRECT TESTIMONY

HOWARD R. COOPER

141 DTE ELECTRI COMPANY QUALIFICATIONS OF HOWARD R. COOPER Line No.

1 Q. What is your name, business address and by whom are you employed?

2 A. My name is Howard R. Cooper. I am employed by DTE Energy Corporate

3 Services, LLC, (DTE Energy or DTE). My address is One Energy Plaza, Detroit,

4 Michigan 48226.

6 Q. On whose behalf are you testifying?

7 A. I am testifying on behalf of DTE Electric Company (DTE Electric or the

8 Company).

10 Q. What is your educational background?

11 A. I graduated from University of Michigan-Dearborn in 1983 with a Bachelor of

12 Science and Arts in Business Administration with a major in Accounting.

14 Q. What is your DTE Energy work experience?

15 A. I joined Michigan Consolidated Gas Company (MichCon) in 1989 where I held

16 various positions, including Senior Staff Accountant, Senior Auditor, and Principal

17 Financial Analyst. In 2001, MichCon’s parent, MCN Energy, was purchased by

18 DTE Energy, DTE Electric’s (formerly The Detroit Edison Company) parent.

19 Subsequent to the acquisition I have held the positions of Principal Financial

20 Analyst, Principal Supervisor, Regulatory Accounting Expert, and Accounting

21 Expert in Asset Management. As a Principal Financial Analyst and Principal

22 Supervisor, I was responsible for recording DTE Gas Company’s and DTE

23 Electric’s provision for uncollectible expense and accrual for the Uncollectible

24 Expense True-Up Mechanism (UETM) from June 2008 through February 2012. In

25 March 2012, I was promoted to Regulatory Accounting Expert and was

HRC - 1 142 H. R. COOPER Line U-18150 No.

1 subsequently transferred to my current position of Accounting Expert in Asset

2 Management as of November 2012.

4 Q. What is your current position?

5 A. I am an Accounting Expert in the Asset Management department. As an

6 Accounting Expert I am responsible for determinations and updates related to DTE

7 Energy’s Capital Policy and Retirement Unit Catalog. I am also responsible for

8 providing financial support for Depreciation Case filings with the Michigan Public

9 Service Commission (Commission).

11 Q. What was your professional experience prior to joining DTE Energy?

12 A. I worked at Meadowdale Foods, Inc. as a Senior Accountant/Planner and Accounts

13 Receivable Supervisor from 1986 to 1989. Prior to that, I was an Auditor and

14 Senior Auditor at C.H. Rubin & Company (CPAs) from 1984 to 1986.

16 Q. Are you a member of any professional organizations?

17 A. I am a member of the EEI Property Accounting Committee.

19 Q. Have you previously testified before this Commission on behalf of DTE

20 Electric or DTE Gas Company?

21 A. Yes. I have sponsored testimony in the following cases:

22 U-16993 DTE Gas’s 2011 Uncollectible Expense True-up Mechanism

23 U-16769 DTE Gas’s 2012 Depreciation Rate Filing

HRC - 2 143 DTE ELECTRI COMPANY DIRECT TESTIMONY OF HOWARD R. COOPER Line No.

1 Q. What is the purpose of your testimony in this proceeding?

2 A. The purpose of my testimony is as follows:

3 1) Provide an overview of the case;

4 2) Introduce the Company’s witnesses who support the Company’s depreciation

5 case filing;

6 3) Identify Commission requirements from previous depreciation cases and the

7 witness who will address them in this filing;

8 4) Support the timing of decommissioning expenditures and the use of a blend of

9 the CPI and PPI rates to escalate current-year decommissioning costs;

10 5) Discuss decommissioning costs included in this filing that were excluded from

11 Case No. U-16117, DTE Electric’s previous depreciation case filing;

12 6) Discuss DTE Electric adjustments to Sargent & Lundy’s Decommissioning

13 Cost Study to arrive at DTE Electric’s filed position for estimated

14 Decommissioning Costs;

15 7) Discuss accounts included in this filing that were excluded from Case No. U-

16 16117;

17 8) Request amortization instead of depreciation accounting for General Plant

18 Communication Equipment in Account 397.

19 9) Request combining the remaining balances of conventional meters with the

20 AMI meters in Account 370;

21 10) Support forecasted, Fermi 2, annual, interim, removal expenditures; and

22 11) Recommend depreciation rates for DTE Electric and Midwest Energy

23 Resources Company (MERC).

25 Q. Are you sponsoring any exhibits in the proceeding?

HRC - 3 144 H. R. COOPER Line U-18150 No.

1 A. Yes. I am sponsoring all or parts of the following exhibits:

2 Exhibit Description

3 A-1 DTE Electric’s Retirement Unit Catalog as of this Filing

4 A-2 Historical Annual CPI and PPI Escalation Rates

5 A-3 Projected Annual CPI and PPI Escalation Rates

6 A-4 Schedule of Obsolete Inventory by Plant

7 A-5 Account 397 - Communication Equipment

8 A-6 Adjusted Summary of Decommissioning Costs by Plant

9 A-7 Recommended DTE Electric Depreciation Rates

10 A-11 Recommended MERC Depreciation Rate

12 Q. Were these exhibits prepared by you or under your supervision?

13 A. Yes, they were.

15 Q. Why is DTE Electric filing a depreciation rate case at this time?

16 A. In its July 8, 2014 Order in Case No. U-16991, DTE Electric’s depreciation case for

17 its renewable energy assets, the Commission ordered the Company to file a full

18 depreciation case including an update of rates for wind and solar assets.

20 Q. Who will present evidence in support of the Company’s Depreciation Case

21 filing?

22 A. The Company will present its case through six witnesses, in addition to me. In

23 alphabetical order:

25 Mr. Robert P. Charles, Project Manager, Sargent & Lundy, will sponsor

HRC - 4 145 H. R. COOPER Line U-18150 No.

1 testimony that presents the results of Sargent & Lundy’s Decommissioning Study

2 Report of DTE Electric’s steam production plants, wind & solar assets, landfill

3 facilities, and peaking units. Sargent & Lundy’s Decommissioning Study for DTE

4 Electric’s steam production plants excludes the Harbor Beach plant, which will be

5 covered by Mr. Mortensen (see below).

7 Mr. Edward T. Henderson, Manager-Marketing, Renewable Energy, will

8 describe the wind and solar projects that form the basis of the Company’s

9 depreciation study.

11 Mr. Paul G. Horgan, Director, Regulatory Affairs Operations, will discuss two

12 adjustments DTE Electric made to Sargent & Lundy’s Decommissioning Study to

13 arrive at the filed position for total removal costs. He will also address the timing

14 of implementation for the new depreciation rates approved in this case.

16 Mr. Kenneth D. Johnston, Manager, Community Lighting, will describe the

17 proposed changes related to the accounting for assets in Account 373, Street

18 Lighting, including the separation of Light Emitting Diode (LED) luminaires from

19 Non-LED luminaires to improve tracking, reporting of costs and ratemaking

20 associated with each type of asset.

22 Mr. Neil E. Mortensen, Construction Project Manager, Major Enterprise

23 Projects (MEP), will sponsor testimony regarding the removal costs of the Harbor

24 Beach Power Plant. He will also discuss the costs and salvage values associated

25 with the Marysville Power Plant that was sold to Commercial Development

HRC - 5 146 H. R. COOPER Line U-18150 No.

1 Company in comparison to the salvage values from the Company’s remaining

2 power plants.

4 Dr. Ronald E. White, President, Foster Associates Consultants, LLC will

5 sponsor and describe the depreciation study prepared for the Company in this case.

7 Q. Are there issues from the Orders in Cases U-16117 and U-16991 that will be

8 addressed by the witnesses in this filing?

9 A. Yes, in its Order in Case No. U-16117, the Commission directed the Company to

10 provide at least 40 vintage years of data when filing its next depreciation case for

11 the following accounts: 1) 352 - Transmission Structures & Improvements; 2) 361 -

12 Distribution Structures & Improvements; 3) 390 - General Structures &

13 Improvements; 4) 366 - Distribution Underground Conduit; 5) 367 - Underground

14 Conductors & Devices; 6) 368 - Line Transformers; 7) 369 - Services-overhead;

15 and 8) 370 - Meters. I will be addressing this issue.

17 In its Order in Case No. U-16991, the Commission specifically directed the

18 Company to provide additional information and analysis, in its next depreciation

19 case concerning the Company's experience with turbine towers, including an

20 assessment of the potential to reuse the towers with future wind turbine generators,

21 and a study assessing the aftermarket for used solar panels. This will be addressed

22 by Company Witness Mr. Henderson. Also in its U-16991 Order, the Commission

23 directed the Company to provide a more detailed analysis of the assumptions

24 underlying its survivor curves for wind generating plant. I will address this issue.

25 In addition, the Commission directed the Company to provide in its next

HRC - 6 147 H. R. COOPER Line U-18150 No.

1 depreciation case, the items below, which will be addressed by Witness Mr.

2 Charles:

3 1. An analysis of at least two dismantlement methods for wind turbines;

4 2. The necessary clarity around the construction and removal of crane pads;

5 3. Details concerning the specific costs for overhead and profit, general conditions,

6 indirect and direct costs in the Company's decommissioning study;

7 4. Provide more support for its selection of transformer scrap value in the

8 Company's decommissioning study; and,

9 5. Provide a complete explanation of overhead costs for wind and for solar,

10 including an explanation of why these costs differ, if appropriate.

12 Q. Will the Company provide at least 40 vintage years of data for the accounts

13 identified above in this filing as requested by the Commission?

14 A. Yes, the Company will provide far more than 40 vintage years of data for the

15 accounts identified above. To clarify, the Company provided far more than 40

16 vintage years of data for the accounts identified above in its last full depreciation

17 case, No. U-16117. The Company was not able to provide 40 activity years of data

18 in the last full depreciation case and will not be able to do so in the current filing.

19 In U-16117, there was apparent confusion as to the difference between the terms

20 vintage years of data and activity years of data. On pages 21 and 22 of his Direct

21 Testimony in U-16117, Staff witness Mr. Birkam stated that “Staff recommends

22 that the remaining lives proposed by the Company be accepted, with the condition

23 that the Company provide at least 40 vintage years of data in the next case for all

24 non-Steam and Nuclear production plant, or revert to the Broad Group method, as

25 per the pre-filed testimony of Staff witness Radke.” Witness Dr. White responded

HRC - 7 148 H. R. COOPER Line U-18150 No.

1 to Mr. Birkam’s recommendation on page 3 of his Rebuttal Testimony, where he

2 stated the following in Q&A:

3 “Q. DOES THE DATABASE USED IN CONDUCTING THE 2009

4 DEPRECIATION RATE STUDY PROVIDE AT LEAST 40 VINTAGE

5 YEARS OF DATA FOR ALL NON STEAM AND NUCLEAR

6 PRODUCTION PLANT?

7 A. Yes, it does. The earliest vintage for distribution Account 362.01

8 (Station Equipment), for example, is 1902 whereas the earliest vintage for

9 Account 365.01 (Overhead Conductors and Devices) is 1929. The earliest

10 vintage for all non-steam and nuclear production plant accounts, however,

11 is older than 1968, thus providing more than 40 vintage years of data for

12 each account.”

14 Q. What is meant by a vintage year of data as opposed to an activity year of data?

15 A. On pages 2 and 3 of his Rebuttal Testimony in U-16117, witness Dr. White

16 explained that a vintage year of data refers to the calendar year in which an item of

17 plant or equipment is placed in-service. He also explained that an activity year of

18 data refers to the calendar year in which a retirement, transfer, or adjustment is

19 posted to the plant or reserve ledger.

21 Q. Why is the company unable to provide 40 activity years of data in this filing?

22 A. In compliance with R.460.2507, Premature destruction or loss of records, the

23 Company notified the Commission in a December 9, 2014 letter that after an

24 exhaustive search, as of September 19, 2014, the Company was not able to locate

25 mortality records prior to 1996.

HRC - 8 149 H. R. COOPER Line U-18150 No.

1 Q. How does the loss of the mortality records prior to 1996 impact this filing?

2 A. The Company is unable to provide 40 activity years of data for the identified

3 accounts to satisfy what it believes to be the intent of the Commission’s request in

4 U-16117. The Company understands that the Commission’s request was related to

5 their concern that insufficient historical data was filed to effectively utilize the

6 Vintage Group Procedure employed to develop depreciation rates in the case. The

7 Company did not agree with the Commission’s position on this issue at the time of

8 the Order in Case No. U-16117 and still does not agree with it. However, as a

9 result of the failure to locate 40 activity years of data, the Company has instructed

10 Dr. White to utilize the Broad Group Procedure instead of the Vintage Group

11 Procedure in this filing. The Broad Group Procedure will be further discussed by

12 Dr. White in his testimony.

14 Q. What assumptions underlie the survivor curves for wind generating assets

15 used by Witness Dr. White in his depreciation study?

16 A. In its Order for Case No. U-16991, the Commission directed the Company to

17 provide a more detailed analysis of the assumptions underlying its survivor curves

18 for wind generating plant in its next depreciation case. DTE Electric has only had

19 wind generating plant since 2012, and as a result only has limited asset history of

20 interim and actual replacements and retirements. Therefore, at this time the

21 Company believes use of estimated data for wind generating plant survivor curves

22 is still appropriate.

24 Q. What accounts are included in this filing, which were not included in DTE

25 Electric’s last full Depreciation Case filing: U-16117?

HRC - 9 150 H. R. COOPER Line U-18150 No.

1 A. This filing includes Account 363, Storage Battery Equipment, as a result of new

2 investments since 2008. The Company is also requesting that new sub-accounts be

3 added in Account 373, Street Lighting, to support the accounting changes that will

4 be discussed by Witness Mr. Johnston. In addition, Accounts 392, Transportation

5 Equipment and 396 Power Operated Equipment are included this case after being

6 inadvertently excluded from Case No. U-16117.

8 Q. What costs are included in Sargent & Lundy’s Decommissioning Study that

9 were not in the study provided in Case No. U-16117?

10 A. The removal cost study in this case, reflected in Exhibit A-14, includes costs for all

11 three distinct phases of plant removal known industry wide as Plant DDD or Plant

12 Decommissioning, Decontamination, and Demolition. It is an industry standard to

13 include all three phases in removal cost studies. The removal costs included in

14 DTE Electric’s U-16117 filing were limited to the Demolition phase of plant

15 removal. A total of $121.1 million of costs related to the Decommissioning and

16 Decontamination phases are included in the removal cost study in Exhibit A-14

17 (Also see Exhibit A-6, Adjusted Summary of Decommissioning Costs by Plant).

18 These costs include DTE Electric’s internal labor and costs for third party services.

19 The Decommissioning and Decontamination phases and the associated costs can be

20 summarized as follows:

22 The Decommissioning phase involves isolating or islanding all plant systems and

23 equipment to prepare them for removal. This includes electrical, mechanical, plant

24 controls, gas and water service shutdown and disconnection of the plant from the

25 transmission system. The Decontamination phase involves draining oils, chemical,

HRC - 10 151 H. R. COOPER Line U-18150 No.

1 and fluids, cleaning tanks and pipelines, as well as cleaning and disposing of

2 hazardous materials.

4 In addition, the Demolition phase of Sargent & Lundy’s study includes $23.3

5 million of costs associated with DTE Electric’s Major Enterprise Projects (MEP)

6 internal project team which was not included in Case U-16117. This team will be

7 responsible for project management and administration, safety and quality

8 assurance, and environmental compliance.

10 Q. Did DTE Electric make any adjustments to the final report of Sargent &

11 Lundy’s Study to arrive at the current filed position for total removal costs?

12 A. Yes, Mr. Horgan instructed me to take out all non-MEP direct company labor and

13 benefits, which I determined to be $47.7 million. He also instructed me to take out

14 all contingency estimates that have been built into Sargent & Lundy’s projections,

15 which I determined to be $122.6 million (See Exhibit A-6).

17 In addition, DTE Electric added the remaining $12.2 million of removal costs for

18 the Harbor Beach plant, which was excluded from Sargent & Lundy’s Study. This

19 amount also excludes internal non-MEP labor (See Exhibit A-6).

21 At the time of the Study, DTE Electric had a pending sale of the Harbor Beach

22 plant which resulted in a number of third party bids for removal costs for the plant.

23 The pending sale was not completed so Harbor Beach removal costs had to be an

24 addition to Sargent & Lundy’s final removal cost estimates. See Mr. Mortensen’s

HRC - 11 152 H. R. COOPER Line U-18150 No.

1 testimony for a more detailed discussion of the Harbor Beach plant and associated

2 removal costs.

4 Also, in accordance with the Commission’s order dated May 20, 2016 in Case No.

5 U-18033, DTE Electric has included $61.8 million of costs related to Obsolete

6 Inventory in the removal costs for this filing. It is assumed that these costs are

7 incurred at the time of Plant demolition but the costs are not escalated from their

8 December 31, 2015 book values. See Exhibit A-4 for a schedule of Obsolete

9 Inventory by Plant. I instructed Witness Dr. White to make these adjustments to his

10 Depreciation Study for this case. Please see Exhibit A-6.

12 Q. Have any of the Steam Plants included in Case No. U-16117 been retired since

13 that filing?

14 A. Yes, the Harbor Beach Power Plant was retired in December 2013 and the Conner’s

15 Creek Power Plant was retired in December 2011.

17 Q. Have you incurred removal costs associated with these plants since they were

18 retired?

19 A. Yes, those costs are included in the actual reserve balance for the test period ending

20 December 31, 2015.

22 Q. Do you expect to incur future removal costs for these plants?

23 A. Yes, as shown in Exhibit A-6, we expect to incur $28.1 million of removal costs for

24 the Conner’s Creek Power Plant and $12.2 million of removal costs for Harbor

25 Beach Power Plant. These removal costs are expected to be incurred sometime

HRC - 12 153 H. R. COOPER Line U-18150 No.

1 between 2018 and 2020.

3 Q. How are these costs being treated?

4 A. These costs are being charged to the Non-Belle River group reserve and will impact

5 the Non-Belle River depreciation rates. Since Dr. White’s model tracks reserves

6 down to the specific steam plant or unit level, I have instructed him to include the

7 Conner’s Creek and Harbor Beach removal costs in with the River Rouge plant’s

8 removal costs. The River Rouge plant is scheduled to retire in 2020 and the

9 removal costs to be incurred in or around 2025. As a result, the timing of the River

10 Rouge Plant removal costs is the closest to when the Conner’s Creek and Harbor

11 Beach removal costs are expected to be incurred. See Statement G of Dr. White’s

12 Exhibit A-15 and Exhibit A-6.

14 Q. What removal cost escalation rate is appropriate for projecting future removal

15 costs?

16 A. Utility plant removal is very labor intensive. In addition, plant removal also includes

17 the use of equipment and the disposal of property. The Consumer Price Index for all

18 Urban Customers (CPI-U) is a good indicator of labor escalations and the Producer

19 Price Index for Finished Goods (PPI-FG) is a good indicator of the equipment and

20 disposal fee escalations. I believe a composite escalation rate consisting of 75% CPI-U

21 and 25% PPI-FG is an appropriate escalation rate for future removal costs. Exhibit A-2

22 shows the historical U.S. composite CPI-U and PPI-Finished Goods rates for 1961

23 through 2015 and a calculation of a 75% CPI-U/25% PPI-FG blended rate based on the

24 average rates. My source for these historical rates is the U.S. Department of Labor–

25 Bureau of Labor Statistic web site (www.bls.gov). Exhibit A-3 shows the projected

HRC - 13 154 H. R. COOPER Line U-18150 No.

1 CPI-U and PPI-FG for 2016 through 2040 and a calculation of a 75% CPI-U/25% PPI-

2 FG blended rate based on the average rates. My source for the projected rates is

3 Moody’s Analytics web site: https//www.economy.com. Based on this analysis, the

4 resulting escalation rate of 2.2% will be used to escalate the 2016 removal costs

5 provided by Sargent & Lundy’s study.

7 Q. What is the Company assuming for the timing of steam plant removal costs?

8 A. I instructed Dr. White to escalate Witness Mr. Charles’ 2016 steam production plant

9 removal costs five years past the projected final retirement date of the last unit at

10 each plant. The five-year period considers the planning for and actual

11 decommissioning of the plant after retirement.

13 Q. What is the Company assuming for Fermi 2 removal costs?

14 A. I am supporting a Fermi 2, average, annual, interim, removal expenditure estimate

15 of $10 million. Fermi 2 final decommissioning costs are provided through an

16 MPSC authorized surcharge. The recovery of Fermi 2 interim removal

17 expenditures is an adjustment that will be made to Fermi 2 depreciation rates in

18 each Case to establish an appropriate removal expenditure projection.

20 Q. What change are you requesting for General Plant?

21 A. The Company is requesting amortization, instead of depreciation, for Account 397,

22 Communication Equipment in General Plant. Many of these assets are difficult to

23 track and consistently report retirements because they are small and spread across

24 many Company locations. This change will simplify plant accounting and will result

25 in greater accuracy of plant reports. Under amortization accounting, property is

HRC - 14 155 H. R. COOPER Line U-18150 No.

1 automatically “written-off” at the end of the amortization period. This process

2 ensures that property that is old and no longer serving customers is removed from

3 rate base. As shown on Exhibit A-5, the recommended amortization of Account

4 397, Communication Equipment does not significantly change DTE Electric’s

5 depreciation rate or expense. This methodology is consistent with the treatment of

6 DTE Electric’s other general plant accounts like Account 391, Office Furniture and

7 Equipment, Account 393, Stores Equipment, and Account 394, Tools, Shop, and

8 Garage Equipment.

10 Q. What change are you requesting for Conventional Meters?

11 A. DTE Electric is requesting that the remaining balance in Conventional Meters,

12 Account 370.01, and the balance in AMI meters, account 370.02, be combined in

13 Account 370.00 with the account name of Meters. Conventional Meters are being

14 phased out and will no longer be in service by the end of 2017.

16 Q. What depreciation rates are being recommended for the Ludington hydraulic

17 production plant?

18 A. The recommended Company depreciation rates for Ludington hydraulic production

19 plant are based on the ordered rates in the joint Consumers Energy / DTE Electric

20 depreciation case; MPSC Case No. U-16055. Consumers Energy and DTE Electric

21 are scheduled to file a depreciation case for the Ludington hydraulic production

22 plant on November 10, 2016.

24 Q. What DTE Electric depreciation rates are being recommended in this Case?

25 A. DTE Electric’s proposed depreciation rates, excluding Ludington, are shown on

HRC - 15 156 H. R. COOPER Line U-18150 No.

1 Exhibit A-7. Commission approval of these rates will provide DTE Electric the

2 necessary cash flow to operate and maintain its business and appropriately reflect

3 the consumption of these assets over their average remaining life.

5 Q. What Midwest Energy Resources Company depreciation rate is being

6 recommended in this Case?

7 A. A MERC depreciation rate of 4.05% is being recommended in this Case as shown

8 on Exhibit A-11. The current rate is 2.81% per the Commission’s November 29,

9 1993 Order in Case No. U-10348. The increased depreciation rate is related to

10 having only about ten years remaining before MERC’s Land Lease expires on June

11 30, 2026.

13 Q. Does this complete your direct testimony?

14 A. Yes, it does.

HRC - 16 157

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) DTE ELECTRIC COMPANY ) for approval of depreciation accrual rates ) Case No. U-18150 and other related matters )

REBUTTAL TESTIMONY

HOWARD R. COOPER

158 DTE ELECTRI COMPANY REBUTTAL TESTIMONY OF HOWARD R. COOPER Line No.

1 Q. What is your name, business address and by whom are you employed?

2 A. My name is Howard R. Cooper. I am employed by DTE Energy Corporate Services,

3 LLC, (DTE Energy or DTE). My address is One Energy Plaza, Detroit, Michigan

4 48226.

6 Q. Did you file direct testimony in this proceeding on behalf of DTE Electric

7 Company (DTE Electric or Company)?

8 A. Yes, I did.

10 Q. What is the purpose of your rebuttal testimony in this proceeding?

11 A. The purpose of my rebuttal testimony is to rebut certain statements made by MPSC

12 Staff Witness Mr. Ancona and ABATE Witness Mr. Andrews.

14 Q. Are you sponsoring any rebuttal testimony exhibits?

15 A. Yes. I am sponsoring the following exhibits.

16 Exhibit Description

17 A-16 ABATE-2 Exhibit A-4 Schedule of Obsolete Inventory with Detail

18 A-17 ABATE Decommissioning Costs

20 Q. Were these exhibits prepared by you or under your supervision?

21 A. Yes, they were.

23 Q. What are ABATE Witness Andrews’ positions on DTE Electric recovering the

24 write-offs related to obsolete inventory in the cost of net salvage for retiring units

25 and or plants?

HRC Rebuttal - 1 159 H. R. Cooper Line U-18150 No.

1 A. First, on pages 14 and 15 of his direct testimony, Witness Andrews objects to DTE

2 including obsolete inventory in the calculation of future net salvage because, as he

3 states, “By including obsolete inventory in the calculation of future net salvage, DTE

4 is making the net salvage rates more negative, thus increasing depreciation accruals,

5 depreciation rates, and the cost of service to customers.” His position is that the

6 Commission’s May 20, 2016 Order in Case No. U-18033 precludes an increase to

7 customers’ cost of service because it states “The Commission finds that the

8 accounting authority approved by this order will not result in an increase in the cost

9 of service to customers and therefore, may be authorized and approved without notice

10 and approved without notice or hearing pursuant to MCL 460.6a(1).”

12 Second, on page 15 of his direct testimony Witness Andrews states that “DTE has

13 not sufficiently supported the level of obsolete inventory that it is attempting to

14 recover through the net salvage rates.”

16 Q. Do you agree with Witness Andrews’ positions regarding obsolete inventory?

17 A. No. First, in the Order for Case No. U-18033, the Commission’s statement that “the

18 accounting authority approved by this order will not result in an increase in the cost

19 of service to customers” cannot reasonably be interpreted to prohibit the recovery of

20 reasonable actual costs through utility rates. The Order in Case No. U-18033 was an

21 accounting order. The financial impacts of an accounting order are subject to review

22 in a contested case addressing cost of service and rate making issues. The Company

23 is now requesting recovery of these costs in this contested depreciation case. In its

24 filing, DTE Electric has followed the methodology approved by the Commission in

25 U-18033. The Company has reflected the obsolete inventory write-off as a cost of

HRC Rebuttal - 2 160 H. R. Cooper Line U-18150 No.

1 removal charge to accumulated depreciation to be recovered through the Depreciation

2 Rates set in this Case.

4 Second, DTE Electric thoroughly supported the level of obsolete inventory it is

5 requesting to be recovered through net salvage rates in its response to Discovery

6 Request ABATE-2, question number ABDE-2.1b. In that response, the Company

7 provided a file titled “ABATE-2 Exhibit A-4 Schedule of Obsolete Inventory with

8 Detail”, which is attached as Exhibit A-16. The file includes Exhibit A-4 Schedule

9 of Obsolete Inventory by Plant as filed, which shows a breakdown of DTE Electric’s

10 total obsolete inventory balance of $68.7 million by coal plant as well as amounts

11 associated with the peaking facilities. It provides DTE Electric’s calculation of the

12 estimated total write-off of $61.8 million to be recovered through net salvage rates

13 after deducting 10% of the inventory’s value in the form of salvage. It also provides

14 a detailed listing of the inventory by line item including the quantity, the unit price,

15 and the calculated cost of the inventory. The total value of the detailed inventory

16 listing is $71.8 million, which equals the balance on the Company’s books prior to

17 being adjusted for MPPA’s 18.61% interest in the Belle River Plant.

19 Q. What is Staff Witness Ancona’s position on DTE Electric’s recovering the write-

20 offs related to obsolete inventory in the cost of net salvage for retiring units and

21 or plants?

22 A. On page 7 of his direct testimony, Witness Ancona states “The projected balance

23 attributable to obsolete inventory for plants not subject to retirement for several years

24 is pure speculation. It is Staff’s recommendation that any recovery of amounts for

25 obsolete inventory be assessed after a plant is actually retired, and after all salvage

HRC Rebuttal - 3 161 H. R. Cooper Line U-18150 No.

1 options have been exhausted.”

3 Q. Do you agree with Witness Ancona’s position regarding obsolete inventory?

4 A. No. At page 2 of the Commission’s May 20, 2016 Order in Case No. U-18033, it

5 states: “The Commission considered the alternatives proposed by DTE Electric and

6 finds it reasonable for the inventory O&M expenses resulting from the write-down

7 of the inventory value to be charged to accumulated depreciation. By allowing the

8 company to charge amounts to accumulated depreciation as a cost of removal, DTE

9 Electric may recover the costs through depreciation rates when rates are reset in the

10 next depreciation case.” Case U-18150 is DTE Electric’s first filed depreciation case

11 since the Order in U-18033. The term write-down refers to the accrual of a reserve

12 based on an estimate of realizable value. The term write-off relates to removing assets

13 from the balance sheet, usually at the time of disposal, or upon a decision to not

14 pursue additional salvage or collection actitivies. This distinction is important

15 because the order refers to a write-down of inventory value. Write-downs are accrued

16 before assets are disposed. Staff’s position to exclude the reserve (i.e., the write-

17 down) from the net salvage estimates is inconsistent with the Order in U-18033.

18 Furthermore, Staff’s suggestion would effectively negate the intention for the original

19 accounting request. That is, the Company is required to write-down the inventory

20 value under both GAAP and regulatory accounting. Absent the accounting provided

21 by the order in U-18033, the Company would have to expense the write-down as it is

22 accrued. Clearly, the accounting provided by the Commission was intented to avoid

23 the immediate expensing of the write-down of obsolete inventory, and instead

24 recognize the cost over the remaining useful life of the assets.

HRC Rebuttal - 4 162 H. R. Cooper Line U-18150 No.

1 Q. What is Witness Andrews’ position concerning the treatment of the value of

2 Land at Power Plant sites when estimating decommissioning costs to be

3 recovered in depreciation rates?

4 A. On page 13 of his direct testimony, Witness Andrews first states “The sale of the land

5 at the end of decommissioning should be treated as gross salvage and an offset to the

6 cost of removal, similar to the treatment for interim retirements.” He also states that

7 “because the sites already have the existing infrastructure and permits, they are most

8 valuable to be utilized again for the next generation of power plants. If DTE builds

9 its next generation of power plants at these same sites and ignores the value of land

10 in the determination of net salvage rates, then current customers would both be

11 providing revenues to DTE for expenses that are not completely expended, and also

12 subsidizing the next generation of customers. In this scenario, the current and

13 previous generations, would have paid for all improvements that can be resused for

14 future power plants. This practice would decrease cost of service for future

15 generations of customers at the expense of current customers.

17 On page 14 of his direct testimony, Witness Andrews states, “In some instances, DTE

18 could sell the retired plant and the land prior to the final decommissioning, thus

19 removing any and all liabilities with the site, and avoid expending decommissioning

20 costs at all.”

22 Q. Do you agree with Witness Andrews’ position concerning the treatment of the

23 value of Land?

24 A. No. First, land is a non-depreciable asset. As a result, the sale of land has no impact

25 on depreciation rates. When land is sold, the transaction results in the recognition of

HRC Rebuttal - 5 163 H. R. Cooper Line U-18150 No.

1 a gain or loss depending on whether the land’s value has increased or decreased since

2 it was purchased. DTE Electric follows Plant Instruction 7, Paragraph E of the

3 Uniform System of Accounts which states “Any difference between the amount

4 received from the sale of land or land rights, less agents’ commissions and other costs

5 incident to the sale, and the book cost of such land or rights shall be included in

6 Account 411.6, Gains from Disposition of Property or 411.7, Losses from Disposition

7 of Utility Plan when such property has been recorded in account 105, Electric Plant

8 Held for Future Use, otherwise to account 421.1 Gain on Disposition of Property or

9 421.2, Loss on Disposition of Property as appropriate…” The entry has no impact

10 on depreciation rates or depreciation reserves. This contrasts with the accounting

11 treatment for depreciable assets where, upon retirement, any salvage amounts

12 collected for the remaining value of the asset are credited to the depreciation reserve

13 and will have the impact of reducing depreciation rates.

15 Witness Andrews’ statements related to the potential value of land are purely

16 speculative and unsupported by historical or reasoned accounting or depreciation

17 practice.

19 Q. What is Witness Andrews’ position regarding DTE Electric’s recovery of

20 Conner’s Creek and Harbor Beach plant decommissioning costs?

21 A. On page 16 of his direct testimony Witness Andrews states: 22 “Both Conner’s Creek and Harbor Beach are already retired …It is 23 DTE’s proposal to include these estimates with those of the River 24 Rouge Plant and recover the estimated expenses through the River 25 Rouge depreciation rates. For River Rouge, DTE is proposing a final 26 retirement date of 2020, and to escalate the decommissioning costs to 27 2025. Since DTE Expects to incur the decommissioning costs for 28 Harbor Beach and Conner’s Creek sometime between 2018 and 2020, 29 it is completely unjustified to escalate the decommissioning costs to

HRC Rebuttal - 6 164 H. R. Cooper Line U-18150 No. 1 2025. It is even more inappropriate for the estimated 2 decommissioning costs for the Harbor Beach plant to be included in 3 the River Rouge net salvage rates.”

4 Witness Andrews later states: 5 “DTE has received three RFP responses that included the purchase of 6 the property. If DTE has an offer to sell the property and relinquish 7 its liability to demolish the plant, thus saving DTE and its customers 8 the cost of decommissioning, then this would be the lowest cost option 9 and appears to be the best option for customers. Current customers 10 should not have to provide DTE with revenues to demolish Harbor 11 Beach, if there is a viable option to avoid this cost.”

13 Q. Do you agree with Witness Andrews’ position concerning Conner’s Creek and

14 Harbor Beach decommissioning costs?

15 A. No. There is no reason to exclude the Conner’s Creek and Harbor Beach

16 decommissioning costs from this filing. As mentioned on page 10 of my direct

17 testimony, the industry recognizes three distinct phases of the plant removal process:

18 decommissioning, decontamination, and demolition. The Conner’s Creek and

19 Harbor Beach plants are retired but as stated on Exhibit A-6 only half of the

20 decommissioning and decontamination phases have been completed for these plants.

21 In this case, DTE is seeking to recover the remaining costs to be incurred to remove

22 these plants, which is $28.1 million for Conner’s Creek and $12.2 million for Harbor

23 Beach as shown on Exhibit A-6. The Conner’s Creek and Harbor Beach costs are

24 included with the River Rouge costs in Witness Dr. White’s Depreciation Study to

25 recover these costs. Absent this treatment, there would be no plant base against which

26 to apply an accrual rate for the cost of removal. River Rouge was selected because

27 the timing of decommissioning this plant is closest to when the Conner’s Creek and

28 Harbor Beach costs will be incurred.

30 In addition, the following comments from page 16 of Witness Andrews’ testimony

HRC Rebuttal - 7 165 H. R. Cooper Line U-18150 No.

1 regarding the sale of Harbor Beach are misleading: “DTE has received three RFP

2 responses that included the purchase of the property. If DTE has an offer to sell the

3 property and relinquish its liability to demolish the plant, thus saving DTE and its

4 customers the cost of decommissioning, then this would be the lowest cost option and

5 appears to be the best option for customers. Current customers should not have to

6 provide DTE with revenues to demolish Harbor Beach, if there is a viable option to

7 avoid this cost.” The acquisition contracts being considered would require DTE

8 Electric to pay the potential acquirer an amount to demolish the plant. Plus, DTE

9 will incur additional internal costs to complete a sale of the Harbor Beach plant. See

10 Exhibit A-13, Harbor Beach Cost Summary which provides a detail of the costs the

11 Company would incur as a result of the potential acquisition that was open at the

12 time of this filing. It reflects that DTE Electric would incur $.9 million to complete

13 the Decommissioning and Decontamination phases of the plant, pay the purchaser

14 $3.8 million ($4.9 million less a $1.1 million credit for salvage) to demolish the

15 Harbor Beach plant, incur another estimated $6 million to remove a significant

16 amount of Fly Ash from the site, and pay $1.9 million for project management and

17 security. That is a total cost of $12.6 million and as reflected on Exhibit A-6, the

18 Company is filing to recover $12.2 million of these costs (excluding $.4 million of

19 internal plant labor). The Company would receive no proceeds from this transaction.

21 Q. What is Witness Andrews’ position related to escalating decommissioning costs

22 for five years after the final retirement year?

23 A. On page 12-13 of his direct testimony, Witness Andrews states: 24 “This is simply an attempt to unjustly collect additional revenues from 25 customers. There is no basis for this escalation. At the 2.2% inflation 26 rate used by the company, this results in the costs at the retirement 27 year to be further inflated by 11.5%. Mr. Cooper states this five-year

HRC Rebuttal - 8 166 H. R. Cooper Line U-18150 No. 1 period considers the planning for and actual decommission of the 2 plant after retirement. There is no reason that planning for the 3 decommissioning cannot occur prior to the final retirement date. 4 Furthermore, the year of final retirement is the year in which the last 5 generating unit and common facilities are retired, some of the 6 decommissioning work can likely be performed on the generating 7 units that retire prior to the final retirement year.”

8 In addition, Witness Andrews prepared a revised calculation of DTE Electric

9 decommissioning costs in his Excel file “BCA Work Paper - U-18150” which is

10 attached as Exhibit A-17. His calculation was used to support a reduction to DTE

11 Electric’s filed position and it assumes that all decommissioning costs are spent in

12 the year the final unit of each plant closes.

14 Q. What is Staff Witness Ancona’s position related to escalating decommissioning

15 costs for five years after the final retirement year?

16 A. On page 7 of his direct testimony, Witness Ancona states “Staff’s concern is that it

17 looks like an arbitrary decision, the effect of which increases the estimated

18 dismantlement costs through an additional five years of escalation.”

20 Q. What are your thoughts with regard to Witness Andrews’ and Staff Witness

21 Ancona’s positions related to escalating decommissioning costs for five years

22 after the final plant retirement year?

23 A. I disagree with their positions. With regard to Witness Andrews’ position, while it is

24 true that most planning and some decommissioning work can be completed on

25 generating units that retire prior to the year when the last generating unit is taken out

26 of service and the plant is retired, he is missing key factors in the timing and costs of

27 the work involved in decommissioning and removing plants. His assumption that all

28 decommissioning costs can be incurred during the final retirement year of the plant

HRC Rebuttal - 9 167 H. R. Cooper Line U-18150 No.

1 is not realistic. Staff Witness Ancona’s conclusion that DTE Electric is arbitrarily

2 increasing the estimated decommissioning costs for an additional five years,

3 demonstrates that his position is very similar to Witness Andrews’ and as a result, he

4 too is missing key factors in the timing and costs of the work involved in

5 decommissioning and removing plants.

7 As mentioned on page 10 of my direct testimony, the industry recognizes three

8 distinct phases to the project of fully decommissioning and removing a power plant.

9 They are: Decommissioning, Decontamination, and Demolition. Company Witness

10 Charles of Sargent & Lundy estimates that approximately 25% of the overall project

11 costs are incurred in the Decommissioning and Decontamination phases and 75% of

12 the costs are incurred during the Demolition phase. The Decommissioning and

13 Decontamination phases, which combined take a year or more to complete, can be

14 done on the units that retire prior to the year when the last generating unit and the

15 plant are retired. However, this work cannot begin on the last generating units and

16 common facilities until after they are taken out of service in the final year of plant

17 retirement. As a result, Decommissioning and Decontamination work on these assets

18 will go on for a year or more after the plant has been retired. In addition, the

19 Demolition phase, where an estimated 75% of overall decommissioning project costs

20 are incurred, cannot begin until after the Decommissioning and Decontamination

21 phases have been completed on all units and the common facilities. Demolition work

22 can take up to three years to complete depending on the size of the plant. Also, after

23 demolition has been completed, an additional one to two years of site restoration work

24 is required to satisfy the requirements of the Michigan Department of Environmental

25 Quality (MDEQ) and receive a “No Further Action” (NFA) letter. As an example,

HRC Rebuttal - 10 168 H. R. Cooper Line U-18150 No.

1 the Marysville plant implosion occurred in November 2015 developer Commercial

2 Development Corporation has still not received a final NFA as of the date of this

3 rebuttal testimony. As a result of the extensive work and cost incurred long after

4 power plants are retired as well as the uncertainty related to environmental issues,

5 DTE Electric utilizes the reasonable practice of escalating each plant’s

6 decommissioning costs for five years after retirement.

8 Q. What is ABATE Witness Andrews’ position regarding DTE’s decommissioning

9 costs and the impact of the time value of money?

10 A. On page 17 of his direct testimony, Witness Andrews states “Current policy does not

11 give customers the benefit of the time value of money; the only benefit is given to

12 utilities, including DTE. The current procedure, in the simplest terms is to estimate

13 the decommissioning cost in today’s dollars, inflate those costs to a future retirement

14 year, then divide the inflated cost estimate evenly over the remaining life of a power

15 plant. Under this procedure, customers in year 1 would pay the exact same dollar

16 amount as the customers in year 10 or 20 of 50. Although this calculation is

17 performed every time the depreciation rates are updated, the assumption remains that

18 an inflated cost estimate is evenly divided over the remaining life of the asset.

19 Current customers are given no benefit for the time value of money, even though the

20 value of a dollar now is greater than the valued of a dollar at any point in the future

21 if inflation is above 0%.” Witness Andrews continues on to suggest an alternative to

22 the Traditional Straight-Line Method for addressing the time value of money.

24 Q. Do you agree with ABATE Witness Andrews’ position regarding

25 decommissioning costs and the impact of the time value of money?

HRC Rebuttal - 11 169 H. R. Cooper Line U-18150 No.

1 A. No. I agree with the Commission’s policy set forth in the September 29, 2009 Order

2 in Case No. 15629, the March 18, 2010 Order in Case No. U-15699, and the June 16,

3 2011 Order in Case U-16117 (DTE Electric’s last full depreciation case). In all three

4 cases, the Commission rejected a “time value of money” formulation and supported

5 the continued use of the Traditional Straight-Line Method for addressing future

6 removal costs. On pages 11 and 12 of the Order in Case U-15699, the Commission

7 explains “The Commission agrees with the Staff that the continued use of the

8 traditional, straight-line depreciation method, coupled with the Staff’s proposed

9 SRU’s on a going-forward basis is the most appropriate means of addressing

10 MichCon’s future removal costs. As discussed by Dr. White in his rebuttal testimony,

11 neither the Attorney General nor ABATE offered a better method for allocating future

12 net salvage than the traditional straight-line method, and the Commission agrees that

13 the simplicity of the traditional method far outweighs the complexity of attempting

14 to change to either of the methods proposed by the Attorney General or ABATE.”

15 The Commission further provided at page 13 of the Order , “The Commission finds

16 that it is appropriate to ask current customers to pay for future costs of removal at

17 inflation adjusted price levels, and, as MichCon pointed out, the rate base offset

18 compensates ratepayers for the prior payment for the costs incurred by the utility.

19 The Commission finds that the Attorney General’s and ABATE’s proposed methods

20 decrease the cash flows available to utilities to meet their infrastructure and other

21 obligations. This, in turn, has a negative financial effect on both the utility and its

22 customers by requiring that such obligations be met with more expensive sources of

23 external financing and by driving up the cost generally of obtaining money in the

24 capital markets. The Commission finds that neither the Attorney General no ABATE

25 have shown that the adoption of these alternative methods would justify increased

HRC Rebuttal - 12 170 H. R. Cooper Line U-18150 No.

1 costs for utility consumers.”

3 Q. Does this conclude your rebuttal testimony?

4 A. Yes, it does.

HRC Rebuttal - 13 171

1 JUDGE FELDMAN: Anything further, Mr.

2 Christinidis?

3 MR. CHRISTINIDIS: Nothing further from

4 the Company, your Honor.

5 JUDGE FELDMAN: All right. Very good.

6 Who would like to go next? Mr. Campbell.

7 MR. CAMPBELL: Thank you, your Honor. In

8 this case ABATE filed the direct testimony of and

9 exhibits of Brian Andrews, which consists of a cover page

10 and 22 pages of testimony and Appendix A, consisting of

11 two pages of qualifications, and Exhibits AB-1, AB-2,

12 AB-3, and AB-4.

13 ABATE also filed the rebuttal testimony

14 of Mr. Andrews, which consists of a cover page and six

15 pages of testimony.

16 At this time ABATE would move to bind in

17 Mr. Andrews testimony and for the exhibits to be

18 admitted.

19 JUDGE FELDMAN: All right. Let me ask

20 for the record if there are any objections to Mr.

21 Campbell's request to bind in Mr. Andrews prefiled direct

22 and rebuttal testimony, or to admit his exhibits?

23 Hearing no objections, the prefiled

24 direct and rebuttal testimony of Brian C. Andrews will be

25 bound in the record, with the Appendix attached to his Metro Court Reporters, Inc. 248.360.8865 172

1 direct testimony included, and Exhibits AB-1 through AB-4

2 are admitted into evidence.

3 MR. CAMPBELL: Thank you, your Honor.

4 (Testimony bound in.)

25 Metro Court Reporters, Inc. 248.360.8865 173

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

) In the matter of the Application of ) DTE Electric Company for ) Case No. U-18150 approval of depreciation accrual ) rates and other related matters ) )

Direct Testimony and Exhibits of

Brian C. Andrews

On behalf of

Association of Businesses Advocating Tariff Equity

August 15, 2017

Project 10434

216001093.1 07411/315979 Brian C. Andrews 174 Page 1

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

) In the matter of the Application of ) DTE Electric Company for ) Case No. U-18150 approval of depreciation accrual ) rates and other related matters ) )

Direct Testimony of Brian C. Andrews

1 Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

2 A Brian C. Andrews. My business address is 16690 Swingley Ridge Road, Suite 140,

3 Chesterfield, MO 63017.

4 Q WHAT IS YOUR OCCUPATION?

5 A I am a Consultant in the field of public utility regulation with the firm of Brubaker &

6 Associates, Inc. (“BAI”), energy, economic and regulatory consultants.

7 Q PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE.

8 A This information is included in Appendix A to my testimony.

9 Q ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING?

10 A I am testifying on behalf of the Association of Businesses Advocating Tariff Equity

11 (“ABATE”), a group of businesses including many of Michigan’s largest employers

12 and energy users.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 175 Page 2

1 Q WHAT IS THE SUBJECT MATTER OF YOUR DIRECT TESTIMONY?

2 A My testimony addresses the proposed depreciation rates for the DTE Electric

3 Company (“DTE”) steam production accounts. For a variety of reasons, I will show

4 that DTE has greatly overstated the depreciation rates for its steam production assets

5 and will recommend adjusting the depreciation rates for these production assets.

6 My silence in regard to any issue should not be construed as an endorsement

7 of DTE’s position.

8 Q PLEASE SUMMARIZE YOUR CONCLUSIONS AND RECOMMENDATIONS.

9 A My conclusions and recommendations are summarized as follows:

10 1. DTE has overstated the depreciation rates for its steam production plants for two 11 main reasons. First, by proposing to significantly reduce the remaining lives of 12 the majority of its coal plants, and second, by proposing to recover an excessive 13 amount of decommissioning costs.

14 2. DTE is proposing to retire its Belle River, River Rouge, St. Claire, and Trenton 15 Channel Power Plants much earlier than was approved in the U-16117. These 16 retirement dates are not justified nor supported in testimony by DTE.

17 3. DTE is requesting to recover through the depreciation rates an excessive amount 18 of decommissioning cost. DTE’s request is excessive because it is proposing to 19 escalate the costs too far into the future, provides no offset for the land value of 20 the production sites and does not fairly account for the time value of money. A 21 significant reduction to the decommissioning costs that are recovered through 22 depreciation rates is appropriate.

23 4. DTE is attempting to recover the estimated decommissioning costs of the 24 Conner’s Creek and Harbor Beach Power Plants through the depreciation rates of 25 its River Rouge Power Plant. This proposal is inappropriate and should be 26 rejected.

27 5. DTE is attempting to recover “Obsolete Inventory” though the net salvage 28 component of the depreciation rates. This proposal is at odds with the 29 Commission order that DTE claims provides the support for the proposal and 30 should be rejected.

31 6. The adjustments I will propose in this testimony will result in depreciation rates for 32 DTE’s steam production accounts that will reduce DTE’s requested increase by 33 $101 million.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 176 Page 3

1 7. If DTE has significant unrecovered plant balances at the time of final retirements, 2 then DTE should explore the securitization of such balances in a similar manner 3 that the Commission approved in U-17473 for Consumers Energy, rather than 4 significantly burden its customers with the accelerated depreciation of its steam 5 production plants.

6 Book Depreciation Concepts

7 Q PLEASE EXPLAIN THE PURPOSE OF BOOK DEPRECIATION ACCOUNTING.

8 A Book depreciation is the recognition in a utility’s income statement of the consumption

9 or use of assets to provide utility service. Book depreciation is recorded as an

10 expense and is included in the ratemaking formula to calculate the utility’s overall

11 revenue requirement.

12 Book depreciation provides for the recovery of the original cost of the utility’s

13 assets that are currently providing service. Book depreciation expense is not

14 intended to provide for replacement of the current assets, but provides for capital

15 recovery or return of current investment. Generally, this capital recovery occurs over

16 the average service life of the investment or assets. As a result, it is critical that

17 appropriate average service lives be used to develop the depreciation rates so no

18 generation of ratepayers is disadvantaged.

19 In addition to capital recovery, depreciation rates also contain a provision for

20 net salvage. Net salvage is simply the scrap or reused value less the removal cost of

21 the asset being depreciated. Accordingly, a utility will also recover the net salvage

22 costs over the useful life of the asset.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 177 Page 4

1 Q BEFORE YOU BEGIN YOUR DISCUSSION ON THE COMPANIES’ PROPOSED

2 DEPRECIATION RATES, PLEASE FURTHER EXPLAIN NET SALVAGE.

3 A Net salvage is simply the value received from the sale or reuse of retired property

4 (salvage value), less the cost of retiring such property (cost of removal). Net salvage

5 can be either positive or negative. If the salvage value exceeds the cost of removal,

6 the net salvage is positive. If the cost of removal is greater than the salvage value

7 received as a result of retirement, the resulting net salvage is negative. For DTE,

8 negative net salvage is a significant component of its depreciation rates and expense.

9 Q ARE THERE ANY DEFINITIONS OF DEPRECIATION ACCOUNTING THAT ARE

10 UTILIZED FOR RATEMAKING PURPOSES?

11 A Yes. One of the most quoted definitions of depreciation accounting is the one

12 contained in the Code of Federal Regulations:

13 “Depreciation, as applied to depreciable electric plant, means the loss 14 in service value not restored by current maintenance, incurred in 15 connection with the consumption of prospective retirement of electric 16 plant in the course of service from causes which are known to be in 17 current operation and against which the utility is not protected by 18 insurance. Among the causes to be given consideration are wear and 19 tear, decay, action of the elements, inadequacy, obsolescence, 20 changes in the art, changes in demand and requirements of public 21 authorities.” (Electronic Code of Federal Regulations, Title 18, 22 Chapter 1, Subchapter C, Part 101)

23 Effectively, depreciation accounting provides for the recovery of the original cost of an

24 asset, adjusted for net salvage, over its useful life.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 178 Page 5

1 DTE Proposal

2 Q WHAT DEPRECIATION METHODOLOGY IS USED TO CALCULATE THE

3 DEPRECIATION RATES FOR LUDINGTON?

4 A As described in the Direct Testimony of Dr. Ronald E. White, the straight-line method,

5 broad group procedure, remaining-life technique was used to calculate the annual

6 and accrued depreciation DTE’s depreciable property.

7 Q DOES DTE’S PROPOSED CHANGE TO ITS DEPRECIATION RATES RESULT IN

8 AN INCREASE TO ITS ANNUAL DEPRECIATION EXPENSE?

9 A Yes, a significant increase. As a result of the change to depreciation rates, the DTE

10 depreciation expense based on plant balances as of December 31, 2015 would

11 increase by $156.4 million or 27%. The current and proposed accruals based on

12 DTE’s 2016 Depreciation Study (Exhibit A-15) are shown below in my Table 1.

TABLE 1

Current and Proposed Accruals ($000)

Accrual at Accrual at Group Current Rates Proposed Rates Difference

Steam Production $ 143,803 $ 293,404 $ 149,601 Nuclear Production $ 34,736 $ 36,642 $ 1,907 Other Production $ 22,667 $ 10,741 $ (11,926) Renewable $ 35,417 $ 38,423 $ 3,006 Production Transmission $ 1,378 $ 2,096 $ 718 Distribution $ 289,547 $ 292,889 $ 3,343 General $ 45,615 $ 55,350 $ 9,736 Total $ 573,161 $ 729,546 $ 156,385

13 As can be seen from Table 1, the majority of the increase, $149 million, is attributed

14 to the steam production plants. Of that $149 million increase, $114 million is for the

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 179 Page 6

1 recovery of investment and $35 million is for net salvage expense. The $149 million

2 increase for steam production is a 104% increase over current accruals.

3 Q WHAT ARE THE DRIVERS OF THIS PROPOSED INCREASE TO THE STEAM

4 PRODUCTION DEPRECIATION RATES?

5 A As I previously stated, $114 million of the $149 million increases is attributed to

6 recovery of investment and $35 million is attributed to increased net salvage expense.

7 There are three main drivers to this cost increase. First, DTE is proposing to shorten

8 the lifespan of its Belle River, River Rouge, St. Claire, and Trenton Channel Power

9 Plants relative to the final retirement dates approved in U-16117. DTE is proposing

10 for Belle River a final retirement year of 2030, 21 years sooner than previously

11 approved. For River Rouge, the proposed final retirement year is 4 years earlier. For

12 the St. Claire Plant, the proposal is 12 years earlier than previously approved. For

13 Trenton Channel, the retirement date has been moved up 11 years. The depreciation

14 expense increase related solely to the recovery of investment for these four plants

15 alone is $88.8 million.

16 Second, the proposed depreciation rates for the Monroe Plant result in an

17 increase of $37 million. Much of this is likely attributed to the significant investment at

18 Monroe related to environmental controls.

19 Third, increased levels of final decommissioning expenses, interim net

20 salvage and Obsolete Inventory are being proposed to be recovered through the

21 depreciation rates. I have not quantified the impact related to each item’s contribution

22 to the $35 million increase related to net salvage.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 180 Page 7

1 Q PLEASE PROVIDE A DISCUSSION OF DTE’S TREATMENT OF

2 DECOMMISSIONING COSTS AS IT RELATES TO THE STEAM PRODUCTION

3 PLANTS.

4 A DTE hired the firm of Sargent & Lundy to perform a study estimating final

5 decommissioning costs of all but one of its power plants. These decommissioning

6 cost estimates are contained in DTE’s Exhibit A-14. The decommissioning cost for

7 the Harbor Beach Power Plant was conducted by a DTE employee, Mr. Mortensen,

8 and is shown in his Exhibit A-13. The cost estimates, excluding Harbor Beach, were

9 then modified at the direction of Mr. Cooper, DTE’s Accounting Expert and overview

10 witness in this proceeding, to remove all non-Major Enterprise Projects (“MEP”) direct

11 company labor and benefits and contingencies built into the estimates. This resulted

12 in approximately $170.3 million being removed from the cost estimates. This is

13 shown in Mr. Cooper’s Exhibit A-6. This removal of contingency factors is likely due

14 to the Commission’s order in U-16077, in which the Commission found that the

15 proposed contingency was not supported on the record and that the ratepayers

16 should not be burdened by excessive depreciation expense.1 The modified cost

17 estimates were then provided to Mr. White and escalated at 2.2% annually until five

18 years after the final retirement date. What DTE has deemed “Obsolete Inventory” is

19 then added to the escalated decommissioning cost and the final net salvage rates are

20 calculated. This is shown on page 65 of Exhibit A-15. The final net salvage expense,

21 obsolete inventory, and future interim net salvage are all utilized to determine the

22 future net salvage rates, which are shown on pages 59 – 63 of Exhibit A-15.

23 Also, DTE is proposing to recover the estimated decommissioning costs of the

24 Harbor Beach and Conner’s Creek plants through the final net salvage rates for the

1June 16, 2011 Final Order in Case No. U-16117 at page 12.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 181 Page 8

1 River Rouge Power Plant; this is described in the direct testimony of Mr. Cooper at

2 pages 12 and 13. I will further discuss this later in my testimony.

3 ABATE’S Response to DTE’s Proposal

4 Q WHAT CONCERNS DO YOU HAVE WITH DTE’S PROPOSALS FOR STEAM

5 PRODUCTION?

6 A I take issue with several of DTE’s proposals. These include the shortening of the life

7 spans of four of its coal plants, the escalation of decommissioning costs five years

8 past the retirement date, the recovery of Obsolete Inventory through the net salvage

9 rates, including decommissioning costs for already retired plants in the depreciation

10 rates of the River Rouge Plant, and finally, not properly accounting for the time value

11 of money.

12 Q PLEASE ELABORATE ON THE ISSUE OF THE SHORTENING OF THE LIFE

13 SPANS OF THE COAL PLANTS.

14 A DTE is proposing to shorten the lives of several of its power plants relative to the lives

15 that were last approved in U-16117. The proposed changes are shown below in

16 Table 2.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 182 Page 9

TABLE 2

Proposed Reduced Coal Plant Lives

DTE Proposed Final Retirement Final Retirement Date Approved in Plant Date U-16117 Delta

Belle River 2030 2051 -21 River Rouge 2020 2024 -4 St. Claire 2023 2035 -12 Trenton 2023 2034 -11 Channel

1 The accelerated depreciation of these four plants results in an increase to the amount

2 of depreciation expense related only to the original investment, therefore excluding

3 net salvage, of $88.8 million.

4 Q HAS DTE PROVIDED JUSTIFICATION OF THE PROPOSED RETIREMENT

5 DATES IN THIS PROCEEDING?

6 A No. DTE has not presented any support in its filing to justify the new retirement dates

7 for these four plants. As I have stated, the shortening of the lives of these four plants

8 represents $88.8 million of the increase, or 57% of DTE’s request. The burden of

9 proof is on DTE, and to not provide a witness or any studies justifying these new

10 retirement dates is quite baffling.

11 I requested DTE to provide all supporting studies and workpapers that justify

12 the reduction in service life in ABDE 1.7. DTE responded with what appears to be a

13 few pages from a 2015 long term plan and a very brief explanation. I have attached

14 this response as Exhibit AB-1. DTE’s response to this discovery request indicates

15 that the proposed early retirement date for these plants is largely based on the

16 implementation of the Clean Power Plan, a proposed EPA regulation meant to reduce

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 183 Page 10

1 CO2 emissions, whose implementation is still pending and ultimate implementation is

2 now problematic based on the actions of the current administration in Washington

3 D.C. DTE’s decision to retire a portion of its coal fleet early appears to be premature

4 given there are no regulatory requirements and/or economic justification to retire the

5 plants early.

6 Q HAS DTE PERFORMED AN INTEGRATED RESOURCE PLAN THAT JUSTIFIES

7 SHORTENING THE RETIREMENT DATES OF THE PLANTS IN QUESTION?

8 A No. In fact, In DTE’s pending general rate case, U-18255, DTE is requesting a sum

9 of $3 million of O&M expenses to expand its integrated resource planning (“IRP”)

10 activities over and above its actual 2016 spending levels.2 DTE is requesting these

11 additional expenses so it can be adequately prepared to address a significant

12 transformation to its generation fleet in the coming years.3 Until such a study is

13 complete and thoroughly reviewed and scrutinized, it is premature to obligate

14 ratepayers to provide significant additional revenues to cover the accelerated

15 depreciation of DTE’s coal fleet.

16 Q WHAT IS YOUR RECOMMENDATION REGARDING THE RETIREMENT DATES

17 FOR THE STEAM PRODUCTION PLANTS IN QUESTION?

18 A For the Belle River, River Rouge, St. Claire, and Trenton Channel Power Plants, I

19 recommend that the retirement dates last approved in U-16117 remain in place in this

20 proceeding. This will provide DTE with ample time to complete its IRP and complete

21 and more definitive plan for the expected life of these units. Increasing depreciation

2Direct Testimony of I. M. Dimitry in U-18255 at page 25, lines 16-18. 3Id. page 26, lines 5-6.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 184 Page 11

1 rates before these definitive plans are completed produces an unjustified and

2 unreasonable burden on ratepayers.

3 Q ASSUMING THE IRP SUPPORTS SUBSTANTIALLY SHORTENING THE LIVES

4 OF THE PLANTS, DOES THE COMMISSION HAVE ANY REMEDIES AVAILABLE

5 THAT COULD REDUCE THE COST IMPACT TO RATEPAYERS?

6 A Yes. It may be possible for DTE to securitize any unrecovered plant balances and

7 potentially, actual decommissioning costs. In the Commission’s Order dated

8 December 6, 2013 in Case No. U-17473, the Commission granted Consumers

9 Energy (“CE”) the authority to issue securitization bonds up to a total amount of

10 $389.6 million of its qualified costs, which included up to $361.2 million for the

11 remaining book value of several generating units.4 CE was authorized to issue

12 securitization bonds and charge customers over a period not to exceed 15 years.5 If

13 DTE is forced to retire a portion of its coal fleet significantly earlier than previously

14 approved, it would be prudent for DTE to consider the issuance of securitization

15 bonds as an option that will reduce the cost to customers associated with the

16 shortening of the economic lines of coal plants. In fact, the Commission could

17 securitize a portion or all of the investment in these units while they are in service.

18 This is precisely what the Commission authorized in Case No. U-12478 for the Fermi

19 2 investment.

4Final Order dated 12/6/2013, Case No. U-17473, at page 62. 5Id. at 63.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 185 Page 12

1 Q WHAT CONCERNS DOES ABATE HAVE WITH THE TREATMENT OF

2 DECOMMISSIONING COSTS?

3 A ABATE has several concerns with DTE’s treatment of decommissioning costs. The

4 first concern is the escalation of decommissioning costs to five years after the final

5 retirement date. Second, a significant component of end-of-life transactions, the

6 value of the land, is missing in any final net salvage calculation. Third, DTE’s

7 proposal to recover “Obsolete Inventory” through the final net salvage rates appears

8 to be at odds with the Commission order that DTE claims provides the support for this

9 proposal. Fourth, ABATE does not agree that the estimated decommissioning costs

10 for Harbor Beach and Conner’s Creek Power Plants should be recovered through the

11 net salvage rate for the River Rouge plant.

12 The last concern is that the current methodology only gives DTE the benefits

13 of the time-value of money. As I will demonstrate later in testimony, current methods

14 do not give current customers proper benefits of the time value of money. I will

15 further explain all of these concerns.

16 Q WHY IS IT INAPPROPRIATE TO ESCALATE THE DECOMMISSIONING COSTS

17 TO FIVE YEARS AFTER THE FINAL RETIREMENT YEAR?

18 A This is simply an attempt to unjustly collect additional revenues from customers.

19 There is no basis for this escalation. At the 2.2% inflation rate used by the company,

20 this results in the costs at the retirement year to be further inflated by 11.5%.6 Mr.

21 Cooper states this five-year period considers the planning for and actual

22 decommissioning of the plant after retirement.7 There is no reason that planning for

23 the decommissioning cannot occur prior to the final retirement date. Furthermore, the

61.0225 = 1.115. 7Direct Testimony of H.R. Cooper at page 14, lines 8-11.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 186 Page 13

1 year of final retirement is the year in which the last generating unit and common

2 facilities are retired, some of the decommissioning work can likely be performed on

3 the generating units that retire prior to the final retirement year. DTE’s proposal is to

4 recover over the remaining lives of its steam production plants $758 million of

5 escalated, estimated decommissioning costs. Of that amount, $78 million8 is entirely

6 due to DTE’s supposed delay between the final retirement date and the time when

7 decommissioning costs are expended.

8 Q PLEASE EXPLAIN WHY IT IS IMPROPER TO IGNORE THE LAND VALUE OF

9 THE POWER PLANT SITES.

10 A It is improper to ignore the land value for several reasons. First, if the site is actually

11 brought to either Greenfield or Brownfield status, it will have significant value to a land

12 developer. The sale of the land at the end of decommissioning should be treated as

13 gross salvage and an offset to the cost of removal, similar to the treatment of net

14 salvage for interim retirements. Second, because the sites already have the existing

15 infrastructure and permits, they are most valuable to be utilized again for the next

16 generation of power plants. If DTE builds its next generation of power plants at these

17 same sites and ignores the value of land in the determination of net salvage rates,

18 then current customers would both be providing revenues to DTE for expenses that

19 are not completely expended, and also subsidizing the next generation of customers.

20 In this scenario, the current and previous generations, would have paid for all

21 improvements that can be reused for future power plants. This practice would

22 decrease cost of service for future generations of customers at the expense of current

23 customers.

8$758/1.115 = 680; 758-608 = $78 million.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 187 Page 14

1 Further, in some instances, DTE could sell the retired plant and the land prior

2 to the final decommissioning, thus removing any and all liabilities with the site, and

3 avoid expending decommissioning costs at all. This is exactly what occurred with

4 DTE’s Marysville plant. When DTE issued its Request for Proposal (“RFP”) in April

5 2012 to demolish the Maryville plant, with an option to buy the site as-is, it selected

6 the bidder that wished to purchase the site as-is. DTE was able to sell the site,

7 without having to pay for demolition costs, and receive positive cash flow. DTE has

8 also received three purchase offers, for its Harbor Beach plant, yet is still attempting

9 to recover estimated and escalated decommissioning costs for this plant. This is

10 discussed in DTE’s Exhibit A-12. Allowing current customers to provide revenues to

11 DTE for estimated decommissioning costs without any consideration of the land value

12 creates significant intergenerational inequities.

13 Q PLEASE EXPLAIN WHY DTE’S PROPOSAL TO RECOVER OBSOLETE

14 INVENTORY THROUGH NET SALVAGE RATES IS IMPROPER.

15 A DTE’s basis to recover obsolete inventory through the net salvage rates is the

16 Commission’s order dated May 20, 2016 in Case No. U-18033. It appears the

17 manner in which DTE is proposing to comply with this order is improper. The

18 Commission found that the accountancy authority approved in that order would not

19 result in an increase in the cost of service to customers and therefore, may be

20 authorized and approved without notice or hearing.9 The procedure DTE is utilizing in

21 this case will absolutely result in an increase in the cost of service to customers. By

22 including obsolete inventory in the calculation of future net salvage, DTE is making

9Final Order dated 5/20/2016, Case No. U-18033 at page 2.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 188 Page 15

1 the net salvage rates more negative, thus increasing depreciation accruals,

2 depreciation rates and the cost of service to customers.

3 Furthermore, DTE has not sufficiently supported the level of obsolete

4 inventory it is attempting to recover through the net salvage rates. As is shown in

5 Exhibit A-4, DTE has presented that it currently has $66.8 million in obsolete

6 inventory for its 6 coal plants as of December 31, 2015 and that it expects to receive a

7 positive 10% in gross salvage proceeds. That is, DTE expects to receive $6.8 million

8 for the sale of the obsolete spare parts and is proposing to write-off $60.1 million.

9 DTE has provided no explanation or support for these levels of obsolete inventory in

10 its application or testimony. The Commission Order in Case No. U-18033 allows for

11 DTE to charge to accumulated depreciation O&M expenses resulting from the

12 write-down of inventory value. It does not state that DTE should recover these costs

13 through the net salvage rates of these steam production plants.

14 Again, and importantly, the Commission order was approved on the

15 assumption that it would not increase the cost of service to customers10 DTE’s

16 proposed obsolete inventory methodology does in fact increase cost of service to

17 customers and should not be allowed.

18 Lastly, the Commission order stated that write down of inventory value

19 charged to accumulated depreciation in the depreciation case would allow for Staff

20 and other parties to review for prudence.11 DTE has provided no support for the level

21 of obsolete inventory in its testimony or application. These obsolete inventory levels

22 are not proven; and therefore should be rejected.

10Id. 11Id.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 189 Page 16

1 Q WHY DO YOU DISAGREE WITH THE RECOVERY OF THE DECOMMISSIONING

2 COSTS OF CONNER’S CREEK AND HARBOR BEACH?

3 A Both Conner’s Creek and Harbor Beach are already retired. Mr. Cooper has stated

4 that the cost to decommission these costs is to be expended in the 2018-2020

5 timeframe.12 The estimate for Conner’s Creek is $28.1 million and the estimate for

6 Harbor Beach is $12.1 million. It is DTE’s proposal to include these estimates with

7 those of the River Rouge Plant and recover the estimate expenses through the River

8 Rouge depreciation rates. Again, it is DTE’s proposal to inflate the estimated

9 decommissioning costs to a period five years after final retirement date. For River

10 Rouge, DTE is proposing a final retirement of 2020, and to escalate the

11 decommissioning costs to 2025. Since DTE expects to incur the decommissioning

12 costs for Harbor Beach and Conner’s Creek sometime between 2018 and 2020, it is

13 completely unjustified to escalate the decommissioning costs to 2025.

14 It is even more inappropriate for the estimated decommissioning costs for the

15 Harbor Beach plant to be included in the River Rouge net salvage rates. As it is

16 discussed in Exhibit A-6, DTE has issued an RFP to demolish Harbor Beach with an

17 option to purchase the site as-is. DTE received three RFP responses that included

18 the purchase of the property. If DTE has an offer to sell the property and relinquish its

19 liability to demolish the plant, thus saving DTE and its customers the cost of

20 decommissioning, then this would be the lowest cost option and appears to be the

21 best option for customers. Current customers should not have to provide DTE with

22 revenues to demolish Harbor Beach, if there is a viable option to avoid this cost.13

12Direct Testimony of H.R. Cooper at page 12, line through page 13, lines 1. 13According to the testimony of H.R. Cooper, there was a pending sale of Harbor Beach that was not completed, page 11, lines 23-24; however, DTE received multiple purchase offers (Exhibit A-6).

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 190 Page 17

1 Q PLEASE EXPLAIN HOW DTE’S PROPOSAL DOES NOT PROPERLY REFLECT

2 THE TIME VALUE OF MONEY.

3 A Current policy does not give customers the benefit of the time value of money; the

4 only benefit is given to utilities, including DTE. The current procedure, in the simplest

5 terms, is to estimate the decommissioning cost in today’s dollars, inflate those costs

6 to a future retirement year, then divide the inflated cost estimate evenly over the

7 remaining life of a power plant. Under this procedure, customers in year 1 would pay

8 the exact same dollar amount as the customers in year 10 or 20 or 50. Although this

9 calculation is performed every time the depreciation rates are updated, the

10 assumption remains that an inflated cost estimate is evenly divided over the

11 remaining life of the asset. Current customers are given no benefit for the time value

12 of money, even though the value of a dollar now is greater than the value of a dollar

13 at any point in the future if inflation is above 0%.

14 Q HAVE YOU CREATED AN EXHIBIT THAT SHOWS HOW THE TIME VALUE OF

15 MONEY IS NOT PROPERLY REFLECTED IN THE ANNUAL ACCRUAL OF

16 DECOMMISSIONING COSTS?

17 A Yes. Exhibit AB-2 provides an example that illustrates this point. This example

18 assumes that an estimate is performed in 2017 for a final retirement and

19 decommissioning to occur in 2036. The 2017 cost estimate to decommission a plant

20 is $10,000 in 2017 dollars. In 2036, when the work is performed, it is estimated that

21 the cost will be $15,121. The current policy is for the $15,121 to be divided evenly

22 over the remaining life of the plant. In this example, there are 20 periods to recover

23 the cost, so $756 is recovered from ratepayers each year 2017 though 2036. This is

24 shown in column 2, with the total recovered in nominal dollars being the

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 191 Page 18

1 $15,121 inflated cost estimate. What current policy does not consider, is the future

2 value of the annual accrual. This is shown in column 4. The $756 collected in 2017

3 will be worth $1,143 in 2036. Similarly, the $756 collected in 2018 would be worth

4 $1,119 in 2036 and the $756 collected in 2036 is only worth $756 in 2036. In total,

5 the future value of the annual accruals is $18,740, or 24% more than is required to

6 meet the 2036 estimated cost.

7 In this exhibit, I also provide a methodology to determine a time value of

8 money adjustment that will result in DTE collecting the $15,121 required to meet the

9 2036 decommissioning cost estimate, but in a manner that more fairly allocates costs

10 across generations of customers. In column 5, I present a time value of money

11 adjustment, which is calculated at the sum of column 4 divided by the sum of column

12 3, or 18,740/15,121 = 1.24. Column 6 shows the adjusted annual accrual, which is

13 calculated as the current policy annual accrual, column 1, divided by the time value of

14 money adjustment, column 5. This adjusted annual accrual is $610, which over the

15 20 year recover period yield $12,200 in nominal dollars. Column 7 shows the future

16 value of the annual accrual of the $610, which sums to $15,121 or exactly the value of

17 dollars needed in 2036.

18 In order to incorporate the time value of money adjustment into the net

19 salvage rates, the net salvage rate must be calculated using the $12,200 figure,

20 rather than the 2036 inflated cost estimate of $15,121. If this methodology is utilized

21 during each depreciation rate proceeding, customers will provide DTE enough

22 revenues to meet the 2036 requirement and costs will be allocated in a more

23 equitable manner. This proposal allows the time value of money to be properly

24 considered in the setting of depreciation rates and, as I will demonstrate, this

25 proposed adjustment is just and reasonable.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 192 Page 19

1 Q HAVE YOU CREATED AN EXHIBIT THAT SHOWS HOW UTILIZING YOUR

2 PROPOSED METHODOLOGY WILL PROVIDE DTE WITH ENOUGH REVENUE

3 AND ALLOCATE COSTS IN A MORE EQUITABLE MANNER?

4 A Yes. Utilities typical update the depreciation rates every five years. My proposal is to

5 alter the methodology under which the final decommissioning costs are recovered

6 through depreciation rates. My Exhibit AB-3 demonstrates that if the same procedure

7 is utilized for each generation of customers leading up to the final generation,14 then

8 the utility will recover the $15,121 to match the required decommissioning costs in

9 2036. This exhibit presents the annual accruals and the present values, or current

10 purchasing power, of those annual accruals under current policy and the ABATE

11 proposal. As shown in column 2, current policy will require customers in every

12 generation to provide $756 in order to reach the $15,121 requirement. The average

13 present value of the first generation of customers is $724 and the average present

14 value of the last generation is $522. This demonstrates that although ratepayers in

15 each year provide the exact same dollar amount, the purchasing power provided by

16 the first generation is significantly greater than what would be provided by the last

17 generation.

18 The ABATE proposal would result in customers in earlier generations paying

19 less nominally than the later generations; but the present values are much closer

20 together. Generation 1 customers would pay $610, with an average present value of

21 $584. Generation 4 customers would pay $945, with an average present value of

22 $653. This proposal will significantly diminish the level of intergenerational inequities.

23 Under my proposed methodology, the value provided from each generation is much

24 more uniform. DTE’s proposal and current policy significantly burdens the current

14In this instance, generation of customers means a period over which depreciation rates are in effect; therefore this example has 4 generations of customers, with a depreciation study conducted every five years.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 193 Page 20

1 generation for the benefit of the future generations. If my proposed methodology is

2 adopted, DTE will collect enough revenues from ratepayers to meet its

3 decommissioning expense needs, but in a manner that more fairly allocates costs

4 across generations of ratepayers, thus representing a just and reasonable proposal.

5 Q ARE OTHER OPTIONS AVAILABLE TO DTE TO RECOVER UNRECOVERED

6 PLANT BALANCES AND ACTUAL DECOMMISSIONING COSTS?

7 A Yes. It may be possible for DTE to securitize any unrecovered plant balances and

8 potentially, actual decommissioning costs. In the Commission’s order dated

9 December 6, 2013 in Case No. U-17473, the Commission granted CE the authority to

10 securitization bonds up to a total amount of $389.6 million of its qualified costs, which

11 included up to $361.2 million for the remaining book value of several generating

12 units.15 CE was authorized to issue securitization bonds and charge customers over

13 a period not to exceed 15 years.16 If DTE is forced to retire a portion of its coal fleet

14 significantly earlier than previously approved, it would be prudent for DTE to consider

15 securitization as an option, in order to give customers the least expensive cost of

16 service.

17 Recommendations

18 Q WHAT DO YOU RECOMMEND FOR TREATMENT OF THE ISSUES YOU HAVE

19 RAISED?

20 A I recommend that the retirement dates approved in U-16117 for the Belle River, River

21 Rouge, St. Claire, and Trenton Channel Power Plants remain in effect. I also

22 recommend the decommissioning costs that are recovered through deprecation rates

15Final Order dated 12/6/2013, Case No. U-17473, at page 62. 16Id. at 63.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 194 Page 21

1 be reduced such that, costs are not escalated past the final retirement date, no costs

2 related to the Harbor Beach or Conner’s Creek decommissioning costs are included,

3 no Obsolete Inventory be included in recovery, and current customers are given

4 proper credit for the time value of money.

5 Q HAVE YOU CALCULATED NEW DEPRECIATION RATES FOR DTE’S STEAM

6 DEPRECIATION ACCOUNTS?

7 A Yes. I have calculated new depreciation rates for DTE’s steam production account.

8 These calculations are shown in Exhibit AB-4. Table 3 below shows how ABATE’s

9 proposed depreciation rates compare to those proposed by DTE.

TABLE 3

Proposed Depreciation Rates – Steam Production

Account DTE Proposed ABATE Proposed Delta

311 3.56% 2.20% -1.36% 312 4.10% 2.77% -1.33% 314 4.50% 2.54% -1.96% 315 4.23% 2.27% -1.96% 316 4.81% 2.10% -2.71% Total 4.07% 2.64% -1.43%

10 Q WHAT IS THE IMPACT THE ANNUAL ACCRUAL BASED ON DECEMBER 31,

11 2015 PLANT BALANCES?

12 A The impact on the annualized accrual based on plant balances as of December 31,

13 2016 are shown below in Table 4.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Brian C. Andrews 195 Page 22

TABLE 4

Proposed Accruals – Steam Production ($000)

Account DTE Proposed ABATE Proposed Delta

311 $38,245 $23,625 ($14,621) 312 $212,078 $143,065 ($69,013) 314 $34,638 $19,568 ($15,070) 315 $6,203 $4,009 ($2,194) 316 $524 $423 ($101) Total $291,688 $190,689 ($100,999)

1 Q DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?

2 A Yes, it does.

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Appendix A 196 Brian C. Andrews Page 1

Qualifications of Brian C. Andrews

1 Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

2 A Brian C. Andrews. My business address is 16690 Swingley Ridge Road, Suite 140,

3 Chesterfield, MO 63017.

4 Q PLEASE STATE YOUR OCCUPATION.

5 A I am a Consultant in the field of public utility regulation with the firm of Brubaker &

6 Associates, Inc. (“BAI”), energy, economic and regulatory consultants.

7 Q PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND PROFESSIONAL

8 EMPLOYMENT EXPERIENCE.

9 A I received a Bachelor of Science Degree in Electrical Engineering from the

10 Washington University in St. Louis/University of Missouri - St. Louis Joint Engineering

11 Program. I have also received a Master of Science Degree in Applied Economics

12 from Georgia Southern University.

13 I have attended training seminars on multiple topics including class cost of

14 service, depreciation, power risk analysis, production cost modeling, cost-estimation

15 for transmission projects, transmission line routing, MISO load serving entity

16 fundamentals and more.

17 Additionally, I am a certified Engineer Intern in the State of Missouri, and I am

18 a member of the Society of Depreciation Professionals.

19 As a consultant at BAI, and as an Associate Consultant and Assistant

20 Engineer before that, I have been involved with several regulated and competitive

21 electric service issues. These have included book depreciation, fuel and purchased

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 Appendix A 197 Brian C. Andrews Page 2

1 power cost, transmission planning, transmission line routing, resource planning

2 including renewable portfolio standards compliance, electric price forecasting, class

3 cost of service, power procurement, and rate design. This has involved use of power

4 flow, production cost, cost of service, and various other analyses and models to

5 address these issues, utilizing, but not limited to, various programs such as

6 STRATEGIST, RealTime, PSS/E, MatLab, R Studio, ArcGIS, Excel, and the United

7 States Department of Energy/Bonneville Power Administration’s Corona and Field

8 Effects (“CAFÉ”) Program. Additionally, I have received extensive training on the

9 PLEXOS Integrated Energy Model.

10 BAI was formed in April 1995. BAI provides consulting services in the

11 economic, technical, accounting, and financial aspects of public utility rates and in the

12 acquisition of utility and energy services through RFPs and negotiations, in both

13 regulated and unregulated markets. Our clients include large industrial and

14 institutional customers, some utilities and, on occasion, state regulatory agencies.

15 We also prepare special studies and reports, forecasts, surveys and siting studies,

16 and present seminars on utility-related issues.

17 In general, we are engaged in energy and regulatory consulting, economic

18 analysis and contract negotiation. In addition to our main office in St. Louis, the firm

19 also has branch offices in Phoenix, Arizona and Corpus Christi, Texas.

\\Doc\Shares\ProlawDocs\MED\10434\Testimony-BAI\324273.docx

BRUBAKER & ASSOCIATES, INC. 216001093.1 07411/315979 198

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

) In the matter of the Application of ) DTE Electric Company for ) Case No. U-18150 approval of depreciation accrual ) rates and other related matters ) )

Rebuttal Testimony of

Brian C. Andrews

On behalf of

Association of Businesses Advocating Tariff Equity

September 18, 2017

Project 10434 3 216223399.1 07411/315979 Brian C. Andrews 199 Page 1

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

) In the matter of the Application of ) DTE Electric Company for ) Case No. U-18150 approval of depreciation accrual ) rates and other related matters ) )

Rebuttal Testimony of Brian C. Andrews

1 Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

2 A Brian C. Andrews. My business address is 16690 Swingley Ridge Road, Suite 140,

3 Chesterfield, MO 63017.

4 Q WHAT IS YOUR OCCUPATION?

5 A I am a Consultant in the field of public utility regulation with the firm of Brubaker &

6 Associates, Inc. (“BAI”), energy, economic and regulatory consultants.

7 Q ARE YOU THE SAME BRIAN C. ANDREWS WHO FILED DIRECT TESTIMONY ON

8 BEHALF OF ASSOCIATION OF BUSINESS ADVOCATING TARIFF EQUITY

9 (“ABATE”)?

10 A Yes, I am.

11 Q WHAT IS THE SUBJECT MATTER OF YOUR REBUTTAL TESTIMONY?

12 A My rebuttal testimony addresses the Direct Testimony of Ronald J. Ancona, who filed

13 testimony on behalf of the Michigan Public Service Commission (“MPSC”) Staff.

14 My silence in regard to any issue should not be construed as an endorsement

15 of DTE’s or Staff’s positions.

BRUBAKER & ASSOCIATES, INC. 216223399.1 07411/315979 Brian C. Andrews 200 Page 2

1 Q HAVE ANY OF YOUR CONCLUSIONS FROM YOUR DIRECT TESTIMONY

2 CHANGED DUE TO INFORMATION PRESENTED IN STAFF’S DIRECT

3 TESTIMONY?

4 A No. The conclusions presented in my direct testimony remain the same.

II.

5 Q PLEASE EXPLAIN YOUR CONCERNS WITH MR. ANCONA’s DIRECT

6 TESTIMONY

7 A My major concern with Mr. Ancona’s testimony is his conclusion that any increase in

8 accrual rates be limited to the reserve imbalance. On the surface, this may seem like

9 a reasonable suggestion; however, this suggestion would require implicit agreement

10 with DTE’s entire proposal. Mr. Ancona has stated three major concerns with DTE’s

11 filing. These three concerns are: (i) the retirement dates assumed for St. Clair, River

12 Rouge and Trenton Channel, (ii) the additional five years of escalation of dismantling

13 cost estimates, and (iii) the inclusion of obsolete inventory amounts in deprecation

14 rates for plants not yet retired.1 If Staff’s concerns with these three items are

15 remedied, the reserve imbalance would be significantly different from the $410 million

16 that Dr. White has presented in testimony.

17 Q BEFORE YOU PROCEED ANY FURTHER, PLEASE EXPLAIN THE CONCEPT OF

18 A RESERVE IMBALANCE?

19 A The reserve imbalance is a comparison of the company’s book accumulated

20 depreciation, or depreciation reserve, to a theoretical or computed reserve. The

21 depreciation reserve is the total depreciation account balance. It is equal to the sum

22 of all historical depreciation accruals minus all retirements and cost of removal, plus

1Direct Testimony of Ronald J. Ancona at page 6, line 8 through page 7 line 9.

BRUBAKER & ASSOCIATES, INC. 216223399.1 07411/315979 Brian C. Andrews 201 Page 3

1 any gross salvage proceeds. This depreciation reserve is what is subtracted from the

2 plant in service to determine the net plant component of rate base. The theoretical

3 reserve is a calculation of what the book reserve would have been, had the current

4 proposed depreciation parameters always been applicable.

5 When the book reserve and the theoretical reserve are not equal, then a

6 reserve imbalance exists.

7 Q IS ANY REMEDY TYPICALLY REQUIRED IF A RESERVE IMBALANCE EXISTS?

8 A No. In most cases, and in this particular case, depreciation rates are calculated

9 based on the remaining lives of the assets being depreciated. That is, all of the

10 unrecovered investment plus any net salvage is recovered over the remaining life.

11 This method of setting depreciation rates inherently has an adjustment for any

12 supposed reserve imbalance. Since any existing reserve imbalance will be

13 accounted for in the calculation of remaining life depreciation rates, there is no

14 additional action required.

15 Q PLEASE EXPLAIN THE RESERVE IMBALANCE IN THIS PROCEEDING?

16 A The reserve imbalance in this proceeding, as proposed by DTE is $410,160,454. I

17 have summarized the reserve imbalance by group below in Table 1, from data

18 sourced from DTE’s Exhibit A-1, pages 33-35.

BRUBAKER & ASSOCIATES, INC. 216223399.1 07411/315979 Brian C. Andrews 202 Page 4

TABLE 1

DTE’s Proposed Reserve Imbalance

Recorded Reserve Reserve Theoretical Reserve Accounts (12/31/2015) Imbalance

Steam Production Plant $3,114,534,276 $3,479,317,691 $364,783,415

Nuclear Production Plant $77,191,366 $73,205,834 ($3,985,532)

Other Production Plant $275,886,848 $119,078,012 ($156,808,836)

Renewables $104,765,731 $104,220,641 ($545,091)

Transmission Plant $19,911,204 $16,614,969 ($3,296,234)

Distribution Plant $3,037,386,315 $3,112,848,969 $75,462,654

General Plant $187,098,592 $321,648,670 $134,550,078

Total Utility $6,816,774,333 $7,226,934,786 $410,160,454

1 As can be seen from Table 1, $364 million or 89% of the reserve imbalance is due to

2 Steam Production Plant. This is the case because DTE has proposed to significantly

3 shorten the remaining lives and increase net salvage rates for several of its coal

4 plants. The Commission has the opportunity to evaluate DTE’s proposed retirement

5 dates for its coal plants in docket U-18419, in which DTE has requested to build

6 1,100 MW of new generation and retire early the majority of its coal plants.

7 Q SHOULD DTE TAKE ANY CORRECTIVE ACTION TO ADDRESS THE RESERVE

8 IMBALANCE IN THIS PROCEEDING?

9 A No. As I stated earlier, the depreciation rates in this proceeding are based on the

10 remaining lives of the assets, therefore any supposed reserve imbalance will be

11 corrected by the end of the useful lives of the utility plant. Furthermore, the majority

BRUBAKER & ASSOCIATES, INC. 216223399.1 07411/315979 Brian C. Andrews 203 Page 5

1 of the reserve imbalance is due to steam production. Both Staff and I, in our direct

2 testimonies, raised several concerns with the retirement dates and net salvage

3 parameters used for the determination of depreciation rates for the steam production

4 accounts. If the concerns raised with the steam production depreciation rates are

5 remedied, then any reserve imbalance would be significantly decreased.

6 Furthermore, the only way to support the $410 million reserve imbalance is to support

7 every single parameter proposed by DTE. Both my direct testimony and Mr.

8 Ancona’s testimony present positions that are in opposition to DTE’s position

9 regarding steam production lives and net salvage. I also agree with Mr. Ancona that

10 it would be reasonable to wait until after the Commission has evaluated the

11 retirement decisions for the coal plants in an Integrated Resource Plan (“IRP”) before

12 adjusting depreciation rates to reflect DTE’s proposed retirement dates.

13 Q MR. ANCONA’S EXHIBIT S-1 SHOWS THAT DTE’S DEPRECIATION RESERVE

14 HAS NOT KEPT PACE WITH PLANT IN SERVICE OVER THE PAST 10 YEARS.

15 IS THERE ANY SIGNIFICANCE TO THIS?

16 A No. There is no reason why the depreciation reserve should keep pace with plant in

17 service. Plant in service grows with new investment. The depreciation reserve grows

18 with the annual accruals of plant investment. Generally, when plant is placed into

19 utility service, 100% of that investment is added to plant in service. It would be

20 impossible for a utility to have its depreciation reserve “keep pace” with plant in

21 service, since the reserve only increases by the annual depreciation accruals, which

22 on average would be about 3% - 4% of plant in service. The growth plant in service

23 exceeds this amount.

BRUBAKER & ASSOCIATES, INC. 216223399.1 07411/315979 Brian C. Andrews 204 Page 6

1 Q WHAT IS YOUR RECOMMENDATION TO THE COMMISSION REGARDING

2 RESERVE IMBALANCES?

3 A I recommend the Commission to order DTE to take no action regarding the reserve

4 imbalances. Depreciation rates in Michigan are set based on the remaining lives of

5 utility property; therefore any reserve imbalance will be corrected by the end of the

6 useful lives of that property. Furthermore, the majority of the reserve imbalance is

7 due to the early retirement of DTE’s coal plants; it would be reasonable to make no

8 change to the depreciation rates due to a change in retirement dates of the coal

9 plants, until after the Commission makes a ruling on DTE’s IRP, which has been filed

10 in Docket U-18419. Lastly, authorizing depreciation rates that consider the

11 relationship between plant in service and depreciation reserve is inconsistent with

12 remaining life depreciation practices and sound ratemaking

III.

13 Q DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?

14 A Yes, it does.

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BRUBAKER & ASSOCIATES, INC. 216223399.1 07411/315979 205

1 JUDGE FELDMAN: Ms. Beidler.

2 MS. BEIDLER: Thank you, your Honor.

3 Staff had prefiled the Direct Testimony of Ronald J.

4 Ancona, consisting of a cover page and seven pages of

5 questions and answers. And Mr. Ancona sponsored one

6 exhibit, Exhibit S-1. Staff moves for the admission into

7 evidence of Exhibit S-1 and for the admission of the

8 prefiled direct testimony of Ronald J. Ancona.

9 JUDGE FELDMAN: All right. Let me ask

10 for the record if there are any objections to the

11 admission into evidence of Mr. Ancona's exhibit or to

12 binding in the prefiled testimony?

13 Hearing no objections, the prefiled

14 direct testimony of Ronald J. Ancona will be bound into

15 the record, and Exhibit S-1 is submitted into evidence.

16 (Testimony bound in.)

25 Metro Court Reporters, Inc. 248.360.8865 206

S T A T E OF M I C H I G A N

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

* * * *

In the matter of the Application of ) DTE ELECTRIC COMPANY ) for approval of depreciation accrual rates ) Case No. U-18150 and other related matters ) )

QUALIFICATIONS AND DIRECT TESTIMONY OF

RONALD J ANCONA

MICHIGAN PUBLIC SERVICE COMMISSION

August 15, 2017 207 QUALIFICATIONS OF RONALD J ANCONA CASE NUMBER U-18150 PART I

1 Q. Please state your name and business address.

2 A. My name is Ronald J. Ancona and my business address is 7109 W. Saginaw,

3 Lansing, Michigan 48917.

4 Q. Please give a brief summary of your educational background.

5 A. I earned a Bachelor of Science Degree in Geology in 1973 and a Master of

6 Science Degree in Resource Development in 1977, both from Michigan State

7 University. In 1978, I attended the Annual Regulatory Studies Program

8 sponsored by the National Association of Regulatory Utility Commissioners.

9 Q. Please state your place of employment and present position.

10 A. I am employed at the Michigan Public Service Commission (MPSC or

11 Commission) as Manager of the Act 304 and Sales Forecasting Section within the

12 Regulated Energy Division.

13 Q. What are your responsibilities as Manager?

14 A. I oversee MPSC Staff (Staff) participation in assignments involving the cost and

15 supply of fuels and purchased and net interchange power (PNI), as well as system

16 operations and depreciation issues. This participation is primarily in, but not

17 limited to, Power Supply Cost Recovery (PSCR) and Gas Cost Recovery (GCR)

18 cases. I also assist in formulating Staff policy positions on other issues within the

19 purview of the Regulated Energy Division.

20 Q. Briefly discuss your experience with the Commission.

21 A. Previously, I worked in the Electric Division, where I took part in the negotiations

22 that produced the Emergency Procedures adopted by the Commission in Case No.

23 U-4128. One of my contributions was the development of the Days Supply

1 208 QUALIFICATIONS OF RONALD J ANCONA CASE NUMBER U-18150 PART I

1 Formula that had been incorporated into the procedures. I also participated in the

2 formulation of Staff’s position as to the regulatory treatment of utility ventures in

3 mining operations. I developed mathematical formulas that were used in

4 forecasting fuel and PNI costs in several rate cases. It was my testimony in Case

5 No. U-9432 that led to the Commission's determination that recovery of the

6 Midland Cogeneration Venture purchased power agreement capacity charges

7 should be on an energy-delivered basis.

8 I have also served as Staff Case Coordinator in many cases, including U-6949 and

9 U-7660. Detroit Edison’s Belle River and Fermi 2 power plants were put into

10 rates in Case No. U-7660.

11 Q. Have you previously presented testimony to this Commission in addition to that

12 provided in Case No. U-9432?

13 A. Yes. I have presented testimony in the following cases:

14 Case Number Company Subject/Type

15 U-4840/4621 Consumers Energy (FCAC) Coal Costs

16 U-6006 Detroit Edison (rate) Utility Mining Ventures

17 U-6458 Upper Peninsula Power (rate) 1981 Projected Fuel Costs

18 U-6488 Detroit Edison (rate) 1981 Projected Fuel Costs

19 U-6785 Upper Peninsula Power (rate) 1982 Projected Fuel & PNI Costs

20 U-6923 Consumers Power (rate) 1982/83 Projected Fuel & PNI

21 U-6927 Indiana & Michigan (rate) Test Year Fuel & PNI Costs

22 U-6949 Detroit Edison (rate interim) Greenwood Uneconomic Burn

23 U-6949 Detroit Edison (rate final) 1982/83 Projected Fuel & PNI

2 209 QUALIFICATIONS OF RONALD J ANCONA CASE NUMBER U-18150 PART I

1 U-6006/6488 Detroit Edison (FCAC) Uneconomic Burning of Oil

2 U-7126 Detroit Edison (steam) Projected Fuel Costs

3 U-7775 Detroit Edison (PSCR) Buyback Treatment, Factor

4 U-7550-R Detroit Edison (PSCR) Staff Position on PSCR Issues

5 U-7526-R Cloverland Coop (PSCR) Settlement Agreement

6 U-7830 Consumers Power (rate) Test Year Fuel & PNI Costs

7 U-8020 Detroit Edison (PSCR) Buyback Disallowance

8 U-8272 Alpena Power (PSCR) 1986 Plan

9 U-8282 Southeastern Coop (PSCR) 1986 Plan

10 U-8249 Consumers Power (Midland) PSCR Cost Treatment of Fuel

11 U-8286 Consumers Power (PSCR) 1986 Plan

12 U-8387 Detroit Edison (Complaint) QF Energy Cost Methodology

13 U-8291 Detroit Edison (PSCR) Settlement Agreement

14 U-8291 Detroit Edison (PSCR) 1986 Plan

15 U-8042-R Consumers Power (PSCR) Settlement Agreement

16 U-7775-R Detroit Edison (PSCR) Buyback Disallowance

17 U-8020-R Detroit Edison (PSCR) Buyback Disallowance

18 U-8578 Detroit Edison (PSCR) 1987 Plan

19 U-7830, 3B Consumers Power (Abandonment) Nuclear Fuel Expense

20 U-8886 Consumers Power (PSCR) 1988 Plan

21 U-8880 Detroit Edison (PSCR) 1988 Plan Adjustment

22 U-9172 Consumers Power (PSCR) 1989 Plan

23 U-9432 Consumers Power (PSCR) 1990 Plan Adjustment

3 210 QUALIFICATIONS OF RONALD J ANCONA CASE NUMBER U-18150 PART I

1 U-9346 Consumers Power (rate) Test Year Fuel & PNI Costs

2 U-9172-R Consumers Power (PSCR) Wheeling Revenue/Disallowance

3 U-9732 Consumers Power (PSCR) 1991 Plan Adjustment

4 U-9432-R Consumers Power (PSCR) MCV Disallowance

5 U-9960 Consumers Power (PSCR) MCV Capacity Charges

6 U-10127/8871 Consumers Power (Remand) Contested Settlement Support

7 U-10335 Consumers Power (rate) Test Year Fuel & PNI Costs

8 U-10445 Consumers Power (PSCR) Compliance with U-10127

9 U-10155-R Consumers Power (PSCR) Compliance with U-10127

10 U-10710 Consumers Power (PSCR) Recalculation of Factor

11 U-10685 Consumers Power (rate) PSCR Base & MCV Recovery

12 U-10445-R Consumers Power (PSCR) Various PSCR Issues

13 U-10710-R Consumers Power (PSCR) SO2 Allowance Revenue

14 U-10973-R Consumers Energy (PSCR) Adjustments to Consumers’ Case

15 U-11453 Consumers Energy (suspension) Base Rate Adjustment

16 U-11180-R Consumers Energy (PSCR/suspen) Adjustments to Consumers’ Case

17 U-12615 Wisconsin Electric (PSCR) PSCR Base & Adjustments

18 U-13808 Detroit Edison (rate) PSCR Base & Mitigation

19 U-14274 Consumers Energy (PSCR) PSCR/Stranded Cost Interaction

20 U-14347 Consumers Energy (Rate) Sales Adjustments & Power Cost

21 U-13808-R/14474 Detroit Edison (PSCR/Stranded) Splitting of 3rd Party Sales Profit

22 U-13917-R Consumers Energy (PSCR) Splitting of 3rd Party Sales Profit

23 U-15002 Detroit Edison PSCR Under Recovery in Factor

4 211 QUALIFICATIONS OF RONALD J ANCONA CASE NUMBER U-18150 PART I

1 U-14992 Consumers Energy (Palisades) Palisades Plant Sale and PPA

2 U-15220 Wisconsin Electric (Point Beach) Point Beach PPA & PSCR Base

3 U-15506 Consumers Energy (Gas Rate) Test Year Cost of Gas

4 U-15645 Consumers Energy (Electric Rate) Sales, O&M, Cap. Expenditures

5 U-15768 Detroit Edison (Rate) Sales, PSCR, Cap. Expenditures

6 U-15981 Wisconsin Electric (Rate) Sales, Over capacity

7 U-16191 Consumers Energy (Electric Rate) O&M, Cap. Expenditures

8 U-16433 Indiana Michigan (PSCR) PSCR Base & Adjustments

9 U-16472 Detroit Edison (Rate) Deferral, Marg. Plants, One mil

10 U-16830 Wisconsin Electric (Rate) ERGS Cost Adjustment

11 U-17643 Consumers Energy (Gas Rate) Weather normalization

12 U-17999 DTE Gas (Gas Rate) BTU Adj.; Base Gas Adj.

5 212 DIRECT TESTIMONY OF RONALD J ANCONA CASE NUMBER U-18150 PART II

1 Q. What is the purpose of your testimony?

2 A. The purpose of my testimony is to present Staff’s position on the DTE Electric’s

3 (DTE’s) filing in this case.

4 Q. Is Staff providing its own depreciation study?

5 A. No.

6 Q. Is Staff providing its own demolition study?

7 A. No.

8 Q. Does Staff have concerns with DTE Electric’s filing in this case?

9 A. Yes. Staff has the following major concerns:

10 1) The retirement dates assumed for St. Clair, River Rouge, and Trenton Channel

11 2) The assumption of waiting five years past retirement before site dismantlement

12 begins, and the accompanying five additional years of cost escalation

13 3) The inclusion of projected obsolete inventory amounts for plants not yet retired

14 Q. What is Staff’s concern with the retirement dates assumed for St. Clair, River

15 Rouge, and Trenton Channel?

16 A. While the assumptions included in DTE’s study are consistent with DTE’s public

17 announcements, they are also a fundamental part of the Integrated Resource Plan

18 (IRP) process. Staff believes it would be reasonable to wait until the Commission

19 has evaluated the retirement decisions in an IRP before adjusting depreciation

20 accrual rates reflecting those retirement dates.

21 Q. What is Staff’s concern with the assumption to wait five years after retirement to

22 begin dismantlement?

6 213 DIRECT TESTIMONY OF RONALD J ANCONA CASE NUMBER U-18150 PART II

1 A. Staff’s concern is that it looks like an arbitrary decision, the effect of which

2 increases the estimated dismantlement costs through an additional five years of

3 escalation.

4 Q. What is Staff’s concern with the inclusion of projected obsolete inventory

5 amounts for plants not yet retired?

6 A. The projected balance attributable to obsolete inventory for plants not subject to

7 retirement for several years is pure speculation. It is Staff’s recommendation that

8 any recovery of amounts for obsolete inventory be assessed after a plant is

9 actually retired, and after all salvage options have been exhausted.

10 Q. What is Staff’s recommendations with respect to the approvals sought by DTE

11 Electric in this case?

12 A. DTE witness Ronald White summarizes the effect of DTE’s filing by stating:

13 “The proposed 2016 expense increase is $156,384,755. The computed change in

14 annualized accruals includes an increase of $39,218,444 attributable to an

15 amortization of a $410,160,454 reserve imbalance. The remaining portion of the

16 change is attributable to adjustments in service life and net salvage statistics

17 recommended in the 2016 study.” Exhibit S-1 shows DTE Electric’s Depreciation

18 Reserve has not been keeping pace with Plant in Service over the last ten years.

19 This being the case, the increase attributable to the reserve imbalance seems

20 reasonable. However, due to the concerns stated above, Staff recommends any

21 increase in accrual rates be limited to the reserve imbalance increase at this time.

22 Q. Does that complete your testimony?

23 A. Yes.

7 214

1 JUDGE FELDMAN: Anything further from

2 anybody at all before we close the record and adjourn?

3 Let's go off the record.

4 (Brief discussion was held off the record.)

5 JUDGE FELDMAN: Back on the record. Mr.

6 Christinidis, to the extent that any of the exhibits that

7 we have entered -- and I think particularly thinking of

8 Exhibit A-14 -- have the word "confidential" on them,

9 they're not considered confidential exhibits in this

10 proceeding, right?

11 MR. CHRISTINIDIS: That is correct, your

12 Honor.

13 JUDGE FELDMAN: All right. Very good.

14 Anything else at all from anybody? Thank you all very

15 much. Thank you for making this so easy this morning.

16 We are adjourned.

17 (At 9:15 a.m., the record was closed.)

18 - - -

25 Metro Court Reporters, Inc. 248.360.8865 215

2 C E R T I F I C A T E

3 I, Marie T. Schroeder (CSR-2183), do

4 hereby certify that I reported in stenotype the

5 proceedings had in the within-entitled matter, that

6 being Case No. U-18150, before Sharon L. Feldman,

7 Administrative Law Judge with MAHS, at the Michigan

8 Public Service Commission, Lansing, Michigan, on

9 Tuesday, October 24, 2017; and do further certify that

10 the foregoing transcript, consisting of Volume 2, Pages

11 7-215, is a true and correct transcript of my stenotype

12 notes.

15 ______

16 Marie T. Schroeder, CSR-2183 Notary Public, Oakland County 17 33231 Grand River Avenue Farmington, Michigan 48336 18

19 Dated: October 25, 2017

25 Metro Court Reporters, Inc. 248.360.8865