11 1 state of michigan 2 before the michigan public

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1 STATE OF MICHIGAN

2 BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

3 In the matter of the application of Consumers Energy Company for the Case No. U-17918-R

4 reconciliation of the Power Supply Cost Recovery (PSCR) costs and Volume 2

5 revenues for calendar year 2016.

6 _______________________________________/

7 CROSS-EXAMINATION

8 Proceedings held in the above-entitled

9 matter before Sharon L. Feldman, Administrative Law Judge

10 with MAHS, at the Michigan Public Service Commission,

11 7109 West Saginaw, Lake Michigan Room, Lansing, Michigan,

12 on Thursday, April 19, 2018, at 9:00 a.m.

13 APPEARANCES:

14 GARY A. GENSCH, JR., ESQ. Consumers Energy Company

15 One Energy Plaza, Room EP11-223 Jackson, Michigan 49201

16 On behalf of Consumers Energy Company

17 JOHN A. JANISZEWSKI,

18 Assistant Attorney General 525 W. Ottawa Street, 7th floor

19 P.O. Box 30755 Lansing, Michigan 48909

20 On behalf of Attorney General Bill Schuette

21 THOMAS J. WATERS, ESQ.

22 Fraser Trebilcock Davis & Dunlap, P.C. 124 West Allegan, Suite 1000

23 Lansing, Michigan 48933

24 On behalf of Biomass Merchant Plants

25 (Continued)

12

1 APPEARANCES Continued:

2 SPENCER A. SATTLER, Assistant Attorney General

3 7109 West Saginaw Highway, Floor 3 Lansing, Michigan 48917

4 On behalf of Michigan Public Service

5 Commission Staff

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24 REPORTED BY: Marie T. Schroeder, CSR-2183

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1 I N D E X

2 WITNESS: PAGE

3 JOSHUA W. HAHN

4 Direct and Rebuttal Testimony bound in 25

5 DAVID B. KEHOE / ROBERT T. SCHRAM

6 Adopted Direct Testimony bound in 39 Rebuttal Testimony bound in 56

7 MEAGAN L. METZ

8 Direct Testimony bound in 71

9 HANNAH L. PATTON

10 Direct and Supplemental Testimony bound in 79

11 JENNY L. RICKARD


13 DAVID F. RONK


15 RAYMOND T. SCAIFE


17 MICHAEL B. SHI


19 KEITH G. TROYER


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22 - - -

23 SEBASTIAN COPPOLA

24 Direct Testimony bound in 132 Confidential direct testimony bound in 170

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1 I N D E X

2 WITNESS PAGE

3 GRETCHEN M. WAGNER

4 Revised Direct Testimony bound in 207

5 - - -

6 THOMAS A. SCHMID (Cadillac)


8 KENNETH A. DESJARDINS (Genesee)


10 MICHAEL D. BEAN (Grayling)


12 DOUG A. AUDETTE (Hillman)


14 ROBERT JOE TONDU (TES Filer)


16 NEIL R. TARATUTA (Viking)


18 THOMAS V. VINE (Viking)


20 DONALD ADAMS (Viking)


22 THOMAS J. ALLEN (Cadillac, Hillman, and Viking)

23 Rebuttal Testimony bound in 385

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1 E X H I B I T S

2 NUMBER DESCRIPTION MRKD OFRD RECD

3 A-1 Forecasted and Actual Generation 19 23 24 Requirements and Purchased and

4 Interchange Expense - 2016

5 A-2 2016 Coal Receipts-Plan and Actual 19 23 24

6 A-3 Comparison of 2016 As-Burned Cost 19 23 24 of Fuel

7 A-4 2016 PSCR Reconciliation 19 23 24

8 A-5 PSCR Interest Calculation - 2016 19 23 24

9 A-6 Purchased, Interchanged, Renewable 19 23 24

10 Power Transactions

11 A-7 2016 Interchange Delivered by 19 23 24 Counterparties to MISO

12 A-8 Purchased Power and Cogeneration - 19 23 24

13 Energy and Expense

14 A-9 Purchased Power Contract Rates and 19 23 24 MPSC Approval Orders

15 A-10 2016 Summary of MISO Market and Tariff 19 23 24

16 Administration Charges/(Credits) Settlement

17 A-11 Event Summary Report, January 2016 19 23 24

18 to December 2016

19 A-12 Event Identification - Outages 19 23 24

20 A-13 Periodic Outage Reports 19 23 24

21 A-14 2016 Fossil and Pumped Storage 19 23 24 Outages Occurring for 28 days or more

22 A-15 Generation Performance Statistics 19 23 24

23 (Jan 1, 2016 to Dec 31, 2016)

24 A-16 Comparison of Consumers Energy and 19 23 24 GADS Averages for Similar Units

25

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1 E X H I B I T S


3 A-17 2016 Base Load Generation Power 19 23 24 Plant Cost Efficiency

4 A-18 2016 Expense and Revenue resulting 19 23 24

5 from Congestion, FTR and ARR transactions

6 A-19 PA 295 Purchased Power and New 19 23 24

7 Build Renewables Total 2016

8 A-20 Ludington Units Online 19 23 24 4/26/2016 - 12/31/2016

9 A-21 Ludington Units Online 19 23 24

10 1/1/2016 - 5/20/2016

11 A-22 Disc. Response 17918R-AG-CE-61 19 23 24

12 A-23 CONFIDENTIAL 19 23 24

13 A-24 U-17087 Testimony of Company Witness 19 23 24 DBKehoe - page 33

14 A-25 U-17678-R Testimony of Witness 19 23 24

15 DBKehoe - pages 9-12

16 A-26 Ludington Pump Storage Unit 5 19 23 24 Bearing Failure Economic Decision

17 A-27 CONFIDENTIAL 19 23 24

18 A-28 Disc. Response 17918R-AG-CE-67 19 23 24

19 A-29 Ludington Unit 4 work schedule - 19 23 24

20 January 2016 thru May 2016

21 A-30 2016 PSCR 19 23 24

22 A-31 PSCR Interest Calculation - 2016 19 23 24

23 - - -

24 AG-1 CECo Responses to Overhaul/Upgrade 19 130 131 of Ludington Unit 5

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1 E X H I B I T S


3 AG-2 CONFIDENTIAL 19 130 131

4 AG-3 CECo Response to Ludington Unit 4 19 130 131 Test Period

5 AG-4 CONFIDENTIAL 19 130 131

6 AG-5 Genesee Major Maintenance and 19 130 131

7 Turbine Overhaul costs

8 - - -

9 S-1-R PSCR Calculation 19 205 206

10 - - -

11 BMP-1 Summary Data for capped fuel and 19 215 216 Revised variable O&M costs recoverable

12 BMP-2 Reconciliation of Fuel and Variable 19 215 216

13 Revised O&M costs recoverable

14 BMP-3 Cadillac Renewable Energy, LLC 19 215 216

15 BMP-4 Genesee Power Station LP 19 215 216

16 BMP-5 Grayling Generating Station LP 19 215 216 Revised

17 BMP-6 Hillman Power Company LLC 19 215 216

18 Revised

19 BMP-7 TES Filer City Station LP 19 215 216

20 BMP-8 Viking Energy of Lincoln LLC 19 215 216

21 BMP-9 Viking Energy of McBain LLC 19 215 216

22 BMP-10 CPI Data from 1913-2017 19 215 216

23 BMP-11 Email Feb 9, 2016 19 215 216

24 BMP-12 45210 Federal Register 19 215 216


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1 E X H I B I T S





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1 Lansing, Michigan

2 Thursday, April 19, 2018

3 9:00 a.m.

4 - - -

5 (Hearing resumed pursuant to the notice.)

6 - - -

7 (Documents were marked for identification by the

8 Court Reporter as Exhibits A-1 through A-22,

9 Confidential A-23, A-24, A-25, A-26, Confidential

10 A-27, and A-28 through A-31; AG-1, Confidential

11 AG-2, AG-3, Confidential AG-4, and AG-5; Exhibit

12 S-1-R; and BMP-1 through BMP-16.)

13 JUDGE FELDMAN: On the record. Good

14 morning all. This is the time and place we set for

15 cross-examination in Case No. U-17918-R. May I have the

16 counsel present place their appearances on the record,

17 please, beginning with Mr. Gensch.

18 MR. GENSCH: Good morning, your Honor.

19 Gary Gensch on behalf of Consumers Energy Company.

20 JUDGE FELDMAN: Thank you. Mr.

21 Janiszewski.

22 MR. JANISZEWSKI: Good morning, your

23 Honor. John Janiszewski appearing on behalf of Attorney

24 General Bill Schuette.

25 JUDGE FELDMAN: Thank you. Mr. Sattler.

20

1 MR. SATTLER: Good morning, your Honor.

2 Spencer Sattler on behalf of Michigan Public Service

3 Commission Staff.

4 JUDGE FELDMAN: Thank you. And Mr.

5 Waters.

6 MR. WATERS: Thank you, your Honor. Tom

7 Waters on behalf of the BMPs.

8 JUDGE FELDMAN: All right. Now it's my

9 understanding, and we did adjust the schedule to allow

10 the parties to have an opportunity to discuss settlement,

11 it's my understanding, Mr. Gensch, that the parties

12 agreed to just bind in the testimony of the witnesses

13 this morning while they continue to work towards

14 finalizing settlement agreement.

15 MR. GENSCH: Yes, your Honor.

16 JUDGE FELDMAN: All right. So how would

17 you like to proceed?

18 MR. GENSCH: Well, your Honor, I can

19 start with binding into the record the testimony and

20 admitting exhibits of the Company witnesses.

21 JUDGE FELDMAN: Certainly.

22 MR. GENSCH: Would you like me to just

23 kind of go through the whole list?

24 JUDGE FELDMAN: In any order that you

25 think is sensible.

21

1 MR. GENSCH: Thank you. I'll start with

2 the direct testimony of Joshua W. Hahn. This consisted

3 of a cover page and five pages of questions and answers,

4 and he sponsors Exhibit A-1. We also have the rebuttal

5 testimony of Joshua W. Hahn, which consisted of a cover

6 page and seven pages of questions and answers, and

7 sponsored Exhibits A-20 and A-21.

8 JUDGE FELDMAN: All right. Would you

9 like to take these up one at a time or do you want to

10 keep going through?

11 MR. GENSCH: I can go through the whole

12 list, if that's okay with you.

13 JUDGE FELDMAN: Certainly. Absolutely.

14 MR. GENSCH: Thank you, your Honor. We

15 also had the rebuttal of David B. Kehoe which consisted

16 of a cover page and 14 pages of questions and answers,

17 and it sponsored Exhibits A-22, A-23, A-24, A-25, A-26,

18 A-27, A-28, and A-29. And I would just note that

19 Exhibits A-23 and A-27 are confidential exhibits.

20 We also have the direct testimony of

21 Meaghan L. Metz which consisted of a cover page and seven

22 pages of questions and answers, and it sponsored Exhibits

23 A-2 and A-3.

24 I also have the direct testimony of

25 Hannah L. Patton which consisted of a cover page and

22

1 eight pages of questions and answers, and sponsored

2 Exhibits A-4 and A-5. And Hannah L. Patton also

3 submitted supplemental testimony which consisted of a

4 cover page and four pages of questions and answers, and

5 sponsored Exhibits A-30 and A-31.

6 Also the direct testimony of Jenny L.

7 Rickard, which consisted of a cover page and four pages

8 of questions and answers. And there were no exhibits

9 associated with Ms. Rickard's testimony.

10 The direct testimony of David F. Ronk

11 which consisted of a cover page and 15 pages of questions

12 and answers, and sponsored Exhibits A-6, A-7, A-8, and

13 A-9.

14 We have the direct testimony of Raymond

15 T. Scaife which consisted of a cover page and four pages

16 of questions and answers, and sponsored Exhibit A-10.

17 We also have the direct testimony of

18 Robert C. Schram. And I'll just note that in Mr. Kehoe's

19 rebuttal testimony he sponsored the direct testimony of

20 Robert C. Schram. This testimony consisted of a cover

21 page and 16 pages of questions and answers, and sponsored

22 Exhibits A-11, A-12, A-13, A-14, A-15, A-16, and A-17.

23 The direct testimony of Michael B. Shi

24 which consisted of a cover page and three pages of

25 questions and answers, and sponsored Exhibit A-18.

23

1 And finally the direct testimony of Keith

2 G. Troyer which consisted of a cover page and six pages

3 of questions and answers, and sponsored Exhibit A-19.

4 And I move to bind into the record the

5 direct, rebuttal, and supplemental testimony as just

6 described, and to the admission of these exhibits into

7 evidence.

8 JUDGE FELDMAN: All right. Let me ask

9 for the record if there are any objections to

10 Mr. Gensch's request, including binding in the testimony

11 of those ten witnesses and the exhibits, including the

12 designated Confidential Exhibits A-23 and A-27?

13 Hearing no objection, the prefiled direct

14 and rebuttal testimony of Joshua W. Hahn will be bound in

15 the record. The prefiled rebuttal testimony of David B.

16 Kehoe will be bound into the record. The prefiled direct

17 testimony of Meagan L. Metz will be bound into the

18 record. The prefiled direct and supplemental testimony

19 of Hannah L. Patton will be bound into the record. The

20 prefiled direct testimony of Jenny L. Rickard will be

21 bound into the record. The prefiled direct testimony of

22 David F. Ronk will be bound in the record. The prefiled

23 direct testimony of Raymond T. Scaife with be bound into

24 the record. The prefiled direct testimony of Robert C.

25 Schram will be bound in the record, with the

24

1 acknowledgment that it's sponsored by Mr. Kehoe. The

2 prefiled direct testimony of Michael B. Shi will be bound

3 into the record. And the prefiled direct testimony of

4 Keith G. Troyer will be bound in the record. And

5 Exhibits A-1 through A-31 are admitted into evidence,

6 with the confidential designation for Exhibits A-23 and

7 A-27 and those exhibits to be filed accordingly.

8 (Testimony bound in.)

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S T A T E O F M I C H I G A N

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the application of ) CONSUMERS ENERGY COMPANY ) for the Reconciliation of Power Supply ) Case No. U-17918-R Cost Recovery (PSCR) Costs and Revenues ) for the Calendar Year 2016 ) )

DIRECT TESTIMONY

OF

JOSHUA W. HAHN

ON BEHALF OF

CONSUMERS ENERGY COMPANY

March 2017

25

JOSHUA W. HAHN DIRECT TESTIMONY

te0317-jwh 1

Q. Please state your name and business address. 1

A. My name is Joshua W. Hahn, and my business address is 1945 West Parnall Road, 2

Jackson, Michigan 49201. 3

Q. By whom are you employed? 4

A. I am employed by Consumers Energy Company (“Consumers Energy” or the 5

“Company”). 6

Q. In what capacity are you employed? 7

A. I am a Senior Engineer in the Electric Sourcing and Resource Planning Section of the 8

Energy Supply Operations Department. 9

Qualifications 10

Q. Please describe your educational background. 11

A. I received a Bachelor of Science Degree in Mechanical Engineering in 2008 from 12

Michigan Technological University. 13

Q. Please describe your business and professional experience. 14

A. I joined the Company’s Transactions and Resource Planning Department in January 15

2010. I was responsible for analysis of Financial Transmission Rights (“FTR”) and 16

acquisition of FTRs through monthly and annual allocations and auctions as well as 17

maintaining the Company’s short-term Load and Market Price models using Metrix IDR. 18

In June 2012, I assumed primary responsibilities for the maintenance of the PROMOD IV 19

Full Transmission production cost model. In January 2013, I began performing a support 20

role for the Company’s subject matter expert witness on fuel and purchased and net 21

interchange power and expense forecasting. By June 2013, I assumed primary 22

responsibilities for the maintenance of the PROMOD IV production cost model and all 23

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analysis developed using the tool. I served in this role on a temporary basis for a total of 1

nine months. Later, in June 2015, I was again assigned responsibility to maintain the 2

model and perform all analysis developed using PROMOD. Effective June 2015, my 3

primary responsibilities have been directly tied to PROMOD IV modeling. I have 4

supported all model development (including a detailed re-build of the model in an 5

upgraded version of the software program), as well as providing support for testimony 6

and exhibits filed with the Michigan Public Service Commission (“MPSC” or the 7

“Commission”). In January 2016, I assumed responsibilities as the primary PROMOD 8

IV modeler, for near-term fuel and purchased power expenses, continuing to work closely 9

with the Company’s current subject matter expert witness in this matter. 10

Q. What are your present responsibilities and duties as a Senior Engineer? 11

A. I am responsible for modeling and analysis of fuel and purchased and net interchange 12

power costs that are used in developing the Power Supply Cost Recovery (“PSCR”) Plan 13

and updating the PSCR factor. Additionally, I am responsible for generation unit outage 14

analysis, and related matters. 15

Q. What is the purpose of your testimony? 16

A. My testimony will address the projected costs in the Company’s 2016 PSCR Plan Case, 17

MPSC Case No. U-17918, and the actual generation requirements and purchased and 18

interchange expenses incurred by the Company in 2016. 19

Q. Are you sponsoring any exhibits? 20

A. Yes. I am sponsoring: 21

Exhibit A-1 (JWH-1) Forecasted and Actual Generation Requirements 22 and Purchased and Interchange Expense - 2016. 23

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Q. Was this exhibit prepared by you or under your direction and supervision? 1

A. Yes. 2

Q. Please describe Exhibit A-1 (JWH-1). 3

A. Exhibit A-1 (JWH-1) shows the forecasted amount of electric energy (measured in MWh) 4

generated and purchased, as presented in the Company’s 2016 PSCR Plan filed in MPSC 5

Case No. U-17918, and the actual amounts of electric energy generated and purchased. 6

This Exhibit also shows the Purchased and Net Interchange Power costs as forecasted in 7

the 2016 PSCR Plan case and the actual 2016 Purchased and Net Interchange Power 8

costs. 9

Q. How did the total amount of electric energy required to serve PSCR customers in 2016 10

vary from the Company’s PSCR Plan? 11

A. The total amount of electric energy required to service customers in 2016 was 1.26% 12

lower than forecasted as is shown on line 14, column (d). 13

Q. Please explain the reasons for the major increases or decreases in generation, by category, 14

shown on lines 1 through 13. 15

A. The Steam generation, shown on line 1 of Exhibit A-1 (JWH-1), is 16.08% lower than 16

planned, primarily due to lower economic dispatch from coal units, a result of lower than 17

expected unit availability. The Gas and Oil generation, shown on line 2, is 3.81% lower 18

than planned, primarily due to lower economic dispatch from gas and oil units, a result of 19

lower energy market prices. The Owned Renewable generation, shown on line 4, is 20

2.06% lower primarily due to lower production from the Cross Winds Wind Farm than 21

expected. The Combustion Turbine (Peaker) generation, shown on line 5, is 36.91% 22

lower due to lower production from the Zeeland simple cycle generators, compared to the 23

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2016 PSCR Plan forecast, again a result of lower than expected energy market prices. 1

Utilization of the Pumped Storage facility, shown on lines 6 and 8, was lower primarily 2

due to a smaller than projected spread between on-peak and off-peak energy market 3

prices. The Purchased Power Non-Utility Generation (“NUG”), shown on line 10, is 4

2.24% lower primarily due to decreased energy delivered from the Midland Cogeneration 5

Venture (“MCV”) power purchase agreement, a result of lower than expected energy 6

market prices. The Interchange Received energy from the Midwest Energy Market 7

operated by the Midcontinent Independent System Operator , Inc.(“MISO”), shown on 8

line 12, is 37.01% higher primarily in order to offset lower than forecasted energy 9

production provided from steam, owned renewable, combustion turbine, and MCV 10

delivered energy, as explained above. Similarly, the Interchange Delivered energy, 11

shown on line 13, is 27.02% lower, a result of the lack of economic production from 12

steam, owned renewable, combustion turbine, and MCV that would have otherwise been 13

sold in the energy market. 14

Q. Please explain the reasons for the major increases or decreases in purchased and 15

interchanged power expenses or revenues, by category, shown on lines 15 through 22. 16

A. The Purchased Power expense, shown on line 15, is 3.99% lower primarily due to the 17

decrease in delivered energy from MCV. The MISO Interchange Received expense, 18

shown on line 17, is 42.19% higher primarily due to the higher volumes of Interchange 19

Received energy. The expense for the Purchase of Zonal Resource Credits (“ZRCs”) is 20

49.76% lower than projected. The purchase of ZRCs in year 2016 is explained in detail 21

in the testimony of Company witness David F. Ronk. The Transmission Service expense, 22

shown on line 19, is 7.42% lower than expected primarily due to lower demand than 23

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expected and a lower peak MW than expected. The MISO Interchange Delivered 1

revenue, shown on line 21, is 20.99% lower primarily due to lower volumes of energy 2

delivered to MISO, as well as lower than expected energy market prices paid for energy 3

delivered to MISO. The revenue for Schedule 2-Reactive Supply, shown on line 22, is 4

38.67% lower due to the Company’s Reactive Power filing, Federal Energy Regulatory 5

Commission Docket No. ER16-1058, in 2016 to update its Reactive Revenue 6

requirements for its entire fleet and this led to the reduced revenues collected for 7

Schedule 2-Reactive Supply. 8

Q. Does this complete your testimony? 9

A. Yes. 10

30




REBUTTAL TESTIMONY

OF

JOSHUA W. HAHN

ON BEHALF OF


December 2017

31

JOSHUA W. HAHN REBUTTAL TESTIMONY

rte1217-jwh 1


A. My name is Joshua W. Hahn and my business address is 1945 West Parnall Road, 2


Q. Have you previously filed testimony in Case No. U-17918-R? 4

A. Yes, I filed direct testimony in this case in March, 2017. 5

Q. Are you sponsoring any exhibits with your rebuttal testimony? 6

A. Yes. I am sponsoring the following exhibits: 7

Exhibit A-20 (JWH-2) Ludington Units Online 4/26/2-16 – 12/31/2016; 8 and 9

Exhibit A-21 (JWH-3) Ludington Units Online 1/1/2016 – 5/20/2016. 10

Q. Were these exhibits prepared by you or under your supervision? 11

A. Yes. 12

PURPOSE OF TESTIMONY 13

Q. What is the purpose of your rebuttal testimony? 14

A. My rebuttal testimony will address the calculation of the proposed $3,145,310 15

disallowance attributable to Consumers Energy Company’s (“Consumers Energy” or the 16

“Company”) revised start date for the Ludington Pumped Storage Plant (“Ludington” or 17

“Ludington Plant”) Unit 5 major overhaul, as recommended in the direct testimony of 18

Attorney General witness Sebastian Coppola beginning on page 11, line 16, and the 19

calculation of Mr. Coppola’s proposed $384,490 disallowance due to the additional 20

109 days of outage for the Ludington Unit 4 beginning on page 13, line 7 of his direct 21

testimony. 22

Q. Do you agree with Mr. Coppola’s proposed disallowances? 23

A. No. The assumption of generation loss used in the calculation ignores actual operating 24

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limitations at the Ludington Plant. Additionally, for the majority of the outage period, 1

there would be no generation loss due to the uneconomic position of Ludington Units 4 2

and 5 in the market. 3

Q. What are your concerns with Mr. Coppola’s calculation of generation loss during the 4

Ludington Unit 5 outage? 5

A. On Page 11, line 10 of his direct testimony, Mr. Coppola shows an avoidable power 6

generation loss of 557,679 MWh. Mr. Coppola calculates this value by taking 28.8% of 7

the 1,936,384 MWh as shown on page 25 of Exhibit A-11 (RCS-1). The MWh values on 8

Exhibit A-11 (RCS-1) are calculated by taking the maximum generating capacity of a 9

Ludington unit multiplied by the hours of outage. This value does not take into account 10

the Company’s ownership share of the Ludington Plant, which is 51%. Any instance in 11

which a Ludington unit is on outage, the amount of derated capacity is shared by the 12

Company and the co-owner of the plant, according to the ownership ratios. After 13

applying the ownership percentage, the avoidable power generation loss is reduced to 14

284,416 MWh which represents $1,604,108 in replacement power costs. 15

Q. Are there any other limiting factors at Ludington not reflected in Mr. Coppola’s 16

calculation? 17

A. Yes. The 557,679 MWh calculated by Mr. Coppola assumes a 100% capacity factor for 18

Ludington Unit 5. The Ludington units are not physically able to achieve a 100% 19

capacity factor due to the limited amount of water stored in the pond. Once all water 20

stored in the pond at any given point is depleted, the Ludington units then need to pump 21

water back into the pond. While the units are pumping water they are not able to 22

generate. Additionally, during the period of outage, multiple remaining Ludington units 23

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were available to generate. Ludington Unit 5 would have only generated in hours when 1

all other available Ludington units were at full generating capacity. This is due to the 2

Ludington Plant having six generators. If five Ludington units are available, the first four 3

would need to be called online by the market to necessitate the fifth unit to generate. If 4

there is only enough market demand for four or less generators, then the fifth unit would 5

not operate. During the outage period of April 26, 2016 through December 31, 2016, in 6

only one hour, out of 6,000 were four or more Ludington units online. This is illustrated 7

on Exhibit A-20 (JWH-2) which provides online hours for the Ludington Plant units 8

between April 26, 2016 and December 31, 2016. 9

Q. What is the significance that there was only one hour out of the duration of the outage in 10

which four or more remaining Ludington units were economically dispatched? 11

A. This means that there was only one hour in which the Ludington Unit 5 might have been 12

called upon for economic production as the last Ludington unit available. Therefore, 13

there is no material loss of generation and correspondingly, no power to replace. This 14

would further reduce the total potential power generation loss to 0 MWh. 15

Q. Please discuss the lost power generation amount of 1,936,384 MWh referenced in 16

discovery response 17918R-AG-CE-62 and relied on by Mr. Coppola in calculating his 17

recommended cost disallowance. 18

A. The lost power generation amount of 1,936,384 MWh used by Mr. Coppola to assume a 19

maximum dispatch by Ludington Unit 5 for all hours of the outage. This value was taken 20

from Exhibit A-13 (RCS-3). This is typically where the lost power generation amounts 21

for Replacement Power Costs Studies are taken from, but due to the unique nature of the 22

Ludington Plant these are not applicable. As discussed above, this value does not take 23

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into account the unit limitations or market economics that would affect the dispatch of the 1

unit. It also does not take into account that Ludington Unit 5 would have been one of 2

five Ludington Units available to generate if it had been available, which as seen on 3

Exhibit A-20 (JWH-2) would not have had a significant impact on the economic dispatch. 4

Q. What are your conclusions regarding Mr. Coppola’s proposed disallowance related to the 5


A. Mr. Coppola’s calculation of replacement power cost required during the Ludington Unit 5 7

outage is flawed. Historical Ludington Plant availability and economic dispatch indicate 8

that there was only one occurrence (one hour) in which all available Ludington units were 9

economically dispatched. From that fact, the conclusion can be made that there would 10

only be one hour of potential generation from an additional Ludington unit, and resultantly, 11

negligible loss of generation resulting from the outage. Mr. Coppola’s proposed 12

disallowance of $3,145,310 should be rejected, since the replacement power cost would be 13

$0. Furthermore, I have shown that the generation loss calculated for Ludington Unit 5 by 14

Mr. Coppola is based on flawed analysis that does not take into account the operation and 15

market limitations from the Ludington Plant and as such, his proposed disallowance value 16

should be disregarded. Moreover, even if there were replacement costs attributable to the 17

Ludington Unit 5 outage, Company witness David B. Kehoe has demonstrated the 18

Ludington Unit 5 outage was reasonable and prudent. Therefore, there is no basis to 19

disallow any replacement power costs related to this outage. 20

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Q. What are your concerns with Mr. Coppola’s calculation of generation loss during the 1


A. Mr. Coppola assumes a 100% capacity factor for Ludington Unit 4 and, for the reasons 3

discussed above, the Ludington units are not physically able to achieve a 100% capacity 4

factor due to the limited amount of water stored in the pond. Ludington Unit 4 would have 5

only generated in hours when all other available Ludington units were at full generating 6

capacity, and for the outage period of January 1, 2016 through May 20, 2016 there were 7

zero hours with four or more Ludington units online. This is illustrated on Exhibit A-21 8

(JWH-3) which provides online hours for the Ludington Plant units between January 1, 9

2016 and May 20, 2016. 10

Q. What is the significance that there were no hours during the Ludington Unit 4 outage in 11

which four or more remaining Ludington units were economically dispatched? 12

A. This means that there were zero hours in which Ludington Unit 4 might have been called 13

upon for economic production as the last Ludington unit available. Therefore, there is no 14

material loss of generation and correspondingly, no power to replace. This would further 15

reduce the total potential power generation loss to 0 MWh. 16

Q. Please explain the Company’s response to discovery response 17918R-AG-CE-53b which 17

was relied on by Mr. Coppola to support his recommended cost disallowance. 18

A. This response shows the maximum costs that could be associated with the Ludington 19

Unit 4 outage that took place from January 1, 2016 through May 20, 2016. This value is 20

determined by taking the average gross margin and multiplying it by the MWh of Outage. 21

That value is then multiplied by the Company’s ownership share of the Ludington Plant. 22

The MWh of Outage in this response incorrectly assumes full dispatch in every hour of the 23

36


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outage period. It also does not take into account that Ludington Unit 4 would have been 1

one of five Ludington units available to generate if it had been available. While this 2

discovery response appropriately shows the maximum costs that could be associated with 3

the Ludington Unit 4 outage that took place from January 1, 2016 through May 20, 2016, it 4

does not represent the replacement power costs associated with that outage. When 5

responding to discovery response 17918R-AG-CE-53b, the Company interpreted the 6

response and provided information it believed appropriately responded to what was 7

requested. Upon further review during the development of this rebuttal testimony, the 8

Company has determined that other information would have more appropriately conveyed 9

the replacement power costs during the Ludington Unit 4 outage. What should have been 10

provided in discovery response 17918R-AG-CE-53b to more appropriately determine the 11

replacement power costs during the Ludington Unit 4 outage is a study that takes into 12

account the full availability of the Ludington Plant, instead of just the availability of 13

Ludington Unit 4. When taking into account the full availability of the Ludington Plant, as 14

discussed above, it can be determined that the Company did not incur any replacement 15

power costs attributable to the Ludington Unit 4 outage. 16

Q. What are your conclusions regarding Mr. Coppola’s proposed disallowance related to the 17


A. Similar to Mr. Coppola’s recommendation regarding the Ludington Unit 5 outage, 19

Mr. Coppola’s calculation of replacement power cost required during the Ludington Unit 4 20

outage is flawed. Historical Ludington Plant availability and economic dispatch indicate 21

that there were no occurrences in which all available Ludington units were economically 22

dispatched. From that fact, the conclusion can be made that there was no loss of 23

37


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generation resulting from the outage. Mr. Coppola’s proposed disallowance of $384,490 1

should be rejected, since the replacement power cost would be $0. Furthermore, I have 2

shown that the generation loss calculated for Ludington Unit 4 by Mr. Coppola is based on 3

flawed analysis that does not take into account the operation and market limitations from 4

the Ludington Plant, and as such, his proposed disallowance value should be disregarded. 5

Moreover, even if there were replacement costs attributable to the Ludington Unit 4 6

outage, Company witness Kehoe has demonstrated the Ludington Unit 4 outage was 7

reasonable and prudent. Therefore, there is no basis to disallow any replacement power 8

costs related to this outage. 9

Q. Does this complete your rebuttal testimony? 10

A. Yes, it does. 11

38



In the matter of the application of ) CONSUMERS ENERGY COMPANY ) for the Reconciliation of Power Supply ) Case No. U-17918-R Cost Recovery (PSCR) Costs and Revenues ) for the Calendar Year 2016 )

)

DIRECT TESTIMONY

ROBERT C. SCHRAM

ON BEHALF OF


March 2017

OF Adopted by DAVID B. KEHOE

39

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ROBERT C. SCHRAM DIRECT TESTIMONY

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A. My name is Robert C. Schram, and my business address is 2400 Weiss Street, Saginaw, 2

Michigan 48602. 3

Q. By whom are you employed and in what capacity? 4


“Company”) as the Director of Compliance & Quality Systems, Energy Resources 6

Business Services (“ERBS”). 7

Qualifications 8


A. I received a Bachelor of Science (Electrical Engineering) degree from Saginaw Valley 10

State University in 1988. I also received a Master’s degree in Manufacturing 11

Management from GMI Engineering and Management Institute (now Kettering 12

University) in 1995. 13

Q. Please describe your business experience. 14

A. Prior to joining Consumers Energy, I held operational, quality, and leadership positions 15

of progressing responsibility with Dow Chemical Company of Midland, Michigan. In 16

2004, I joined Consumers Energy as the Economic Based Reliability (“EBR”) Lead for 17

the JC Weadock (“Weadock”) generating facility. In 2007, I became the Maintenance 18

Manager for the DE Karn (“Karn”) and Weadock generating facilities. In 2009, I became 19

the EBR Lead for the Karn and Weadock generating facilities. From 2011 through 2014, 20

I assumed lead responsibilities in the Company’s Performance Excellence area. In 2015, 21

I was promoted to Director of Quality. In September 2015, I was named as Director of 22

Compliance & Quality Systems, ERBS. 23

Adopted by DAVID B. KEHOE 40

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Q. What are your responsibilities as Director of Compliance & Quality Systems, ERBS? 1

A. As Director of Compliance & Quality Systems, ERBS, I am responsible for regulatory 2

compliance, procedure writing, safety audits, Power Supply Cost Recovery (“PSCR”), 3

and PSCR Reconciliation filings for ERBS of Consumers Energy. 4

Q. Have you previously sponsored testimony before the Michigan Public Service 5

Commission (“MPSC” or the “Commission”)? 6

A. Yes. I sponsored testimony in Case Nos.: U-17918 (2016 PSCR Plan case) and U-18142 7

(2017 PSCR Plan case). 8

Purpose of Testimony 9

Q. What is the purpose of your testimony in this proceeding? 10

A. The purpose of my testimony is to describe the reasonableness and prudence of certain 11

fossil and Ludington Pumped Storage (“Ludington”) unit outages; and to explain 12

Nitrogen Oxide (“NOx”), Sulfur Dioxide (“SO2”), urea, aqueous ammonia, and lime 13

expenses. 14

Q. Are you sponsoring exhibits with your testimony? 15

A. Yes, I am sponsoring the following exhibits: 16

Exhibit A-11 (RCS-1) Event Summary Report, January 2016 to December 17 2016; 18

Exhibit A-12 (RCS-2) Event Identification – Outages; 19

Exhibit A-13 (RCS-3) Periodic Outage Reports; 20

Exhibit A-14 (RCS-4) 2016 Fossil and Pumped Storage Outages Occurring 21 For Twenty-Eight Days or More; 22

Exhibit A-15 (RCS-5) Generation Performance Statistics (January 1, 2016 23 to December 31, 2016); 24


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Exhibit A-16 (RCS-6) Comparison of Consumers Energy and GADS 1 Averages for Similar Units; and 2

Exhibit A-17 (RCS-7) 2016 Base Load Generation Power Plant Cost 3 Efficiency. 4

Q. Were these exhibits prepared by you or under your direction and supervision? 5

A. Yes. 6

2016 Outages 7

Q. Have you provided a listing of all 2016 outages? 8

A. Yes. The Event Summary Report, Exhibit A-11 (RCS-1), lists all unit outages and trips. 9

The report shows 61 events on the fossil units, 160 on the Ludington units, 27 on the 10

Combined Cycle units, 107 on the peaking units, and 179 on the hydro units. The total 11

number of outage events for the fleet was 534 in 2016. 12

Exhibit A-11 (RCS-1) provides a description of each event, including the event 13

start time, event end time, cause code, duration in hours, and MWh losses. The cause 14

code comes from the Data Reporting Instructions of the North American Electric 15

Reliability Corporation Generating Availability Data System (“GADS”).1 16

Q. Would you please define the words “outage,” “trip,” and “event”? 17

A. A unit “outage” on a base loaded unit is defined as the period from when the circuit 18

breaker opens, separating the unit from the system, to when it closes, tying the unit to the 19

system and making it available for dispatch. A unit “outage” on a cycling unit is defined 20

as the period from when the Company’s Electric Sourcing & Resource Planning 21

(“ES&RP”) department releases a unit, making it unavailable, to when the plant reports 22

to ES&RP that the unit is available for service. 23

1 Explanations for the cause codes can be found at: http://www.nerc.com/pa/RAPA/gads/DataReportingInstructions/Appendix_B1_Fossil_Steam_Unit_Cause_Codes.pdf


http://www.nerc.com/pa/RAPA/gads/DataReportingInstructions/Appendix_B1_Fossil_Steam_Unit_Cause_Codes.pdf

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A “trip” is a unit outage that begins when protective devices automatically 1

separate a unit from the system or the operator initiates a manual and immediate 2

separation. This is in contrast to the normal controlled shutdown process where operators 3

may spend up to a few hours slowly reducing temperature, pressure, and load before 4

separating the unit from the system. 5

An “event” is a one-line entry on the Event Summary Report. Each line on the 6

Report contains an outage “event.” Exhibit A-12 (RCS-2) explains the different types of 7

outages shown on Exhibit A-11 (RCS-1). The outage event classification is divided into 8

eight distinct event types. 9

Q. Have you documented any of these outages in more detail? 10

A. Yes. The Electric Generation staff prepared a Periodic Outage, Maintenance Outage, or 11

Forced Outage Information sheet for each of the events on the fossil, Ludington, peaking, 12

and hydro units shown on Exhibit A-11 (RCS-1) that lasted 28 days or more. Outage 13

information sheets were also prepared for generating units that had lower availability 14

averages than those shown in GADS data discussed later in my testimony. The 15

information sheets are provided as Exhibit A-13 (RCS-3). Each sheet contains the same 16

statistical data found on Exhibit A-11 (RCS-1). In addition, each information sheet 17

contains: (i) an expanded description of the event; (ii) a final root cause; (iii) the work 18

that was done to correct the root cause for forced outages or the work that was performed 19

during maintenance and periodic outages; (iv) other work, if any, that was performed; 20

(v) a description of work that extended the outage, if any extension occurred; and 21

(vi) why that work was performed. 22


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Fossil and Pumped Storage Outages Planned for 28 Days or More 1

Q. When testimony in MPSC Case No. U-17918 was filed in September 2015, how many 2

outages were planned for 28 days or more? 3

A. My testimony in MPSC Case No. U-17918 identified seven such outages. 4

Q. Were all seven outages completed during the plan year? 5

A. The Ludington 5 outage was not completed in the plan year as work continued into 2017. 6

Additionally, a five day maintenance outage at Karn 2 transitioned into a 38 day planned 7

outage that was completed in the plan year. 8

Q. In 2016, how many outages, 28 days or more, did the Company experience? 9

A. The Company experienced a total of seven outages that lasted 28 days or more. These 10

outages are identified in Exhibit A-14 (RCS-4). 11

Q. Are all seven outages included in Exhibit A-14 (RCS-4)? 12

A. Yes. Furthermore, Exhibit A-14 (RCS-4) lists the Ludington 1 outage which was 13

schedule for 112 days but only lasted 12 days. 14

Q. Which outages will you cover in your testimony? 15

A. I have provided detailed information on all outages listed in Exhibit A-14 (RCS-4). 16

Q. Has your review of the outages listed in Exhibit A-14 (RCS-4) led you to a conclusion 17

concerning these outages? 18

A. Yes. I have concluded that all of the outages listed in Exhibit A-14 (RCS-4) were 19

carefully planned, prudently managed, and free of negligence as to either causation or 20

extension of outage time. Below is a brief summary of each of the outages listed in 21

Exhibit A-14 (RCS-4). 22


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Ludington 4 1

The Ludington 4 outage began March 17, 2015 and the unit remained off-line the 2

remainder of 2015. The unit was scheduled to return to service on March 5, 2016 – or 3

64 days in 2016. The outage was for the overhaul and upgrade of Ludington 4 and was 4

the second outage in Ludington’s multi-year $800 million overhaul and upgrade project. 5

Most major components were replaced during this outage, including the water turbine 6

(aka – runner), wicket gates, generator/motor, and stator. The unit returned to service on 7

May 27, 2016 – 147 days in 2016 and 436 days from March 17, 2015. 8

Q. Why did the Ludington 4 outage take longer than planned? 9

A. The Ludington 4 outage took longer than planned due to a number of reasons. First, the 10

full scope of work was not able to be determined until the unit was fully disassembled. 11

Second, the scope and complexity of the Ludington overhaul is unprecedented. 12

Q. Please explain why the full scope of work was not able to be determined until the unit 13

was fully disassembled. 14

A. While the unit was fully assembled, access to many areas and/or parts of the unit were 15

not possible. 16

Q. Can you give an example? 17

A. Yes. One of the critical path activities was the turbine pit. This activity was not able to 18

be evaluated before the outage, as this area was not accessible until the turbine was 19

removed. 20

Q. What makes this outage unprecedented? 21

A. This is the first time any Ludington unit was completely disassembled since it began 22

operation more than 40 years ago. It is also the second of the Ludington units to be 23


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upgraded with new components. Finally, because the next overhaul is scheduled for 1

2045 (30 years), we believe that taking the necessary time now will pay off in the long 2

run in the form of the continued safe and reliable operation of the unit. 3

Q. Please identify some of the significant accomplishments that were achieved as a result of 4

the work that was completed during, or as a result of, this and all other Ludington 5

outages. 6

A. New 290-ton stainless steel runners will improve unit efficiency in both pumping and 7

generating modes, resulting in an additional 70 MWs of generating capacity per unit. 8

Further, new 610-ton generator stators are the largest stators ever built on-site anywhere 9

in the world. The stator bars were manufactured in a state-of-the-art facility in Japan and 10

are the highest voltage air-cooled bars (20 kV) ever created. Finally, each of Ludington’s 11

six new generator/motor units will be rated at 500,000 horsepower – making them the 12

world’s largest electric motors. 13

Q. Did Consumers Energy prudently manage this outage? 14

A. Yes, Consumers Energy prudently managed this outage. There are only a handful of 15

contractors in the world that are capable of performing this work. The Ludington team 16

contacted each of the qualified contractors, and after careful consideration and 17

evaluation, chose Toshiba. The Ludington team also selected owners’ engineering teams 18

to provide project oversight. These owners’ engineering teams have proposed timely 19

design solutions to each of the issues that were identified throughout the overhaul and 20

upgrade process. Site manpower is furnished by Toshiba and local union labor is utilized 21

through Newkirk Electric and Northern Boiler – frequent contractors of Consumers 22

Energy. 23


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Karn 1 1

The Karn 1 outage was scheduled to begin January 1, 2016 and was projected to take 2

74 days. The outage began on January 1, 2016 and was for boiler tube replacements, a 3

boiler chemical cleaning, and bunker repairs. The unit returned to service 122 days later 4

on May 1, 2016. 5

JH Campbell 1 6

The JH Campbell (“Campbell”) 1 outage was scheduled to begin January 9, 2016 and 7

was projected to take 35 days. The outage began on schedule and was for Air Quality 8

Control System (“AQCS”) tie-in and turbine valve work. The unit returned to service 36 9

days later on February 13, 2016. 10

Ludington 3 11

On January 11, 2016, Ludington 3 began a 35-day planned outage. The outage began 12

on-time and was for Nondestructive Evaluation and generator inspections. The unit 13

returned to service 50 days later on February 29, 2016. 14

Ludington 5 15

On June 9, 2015, Ludington 5 experienced an unplanned catastrophic thrust bearing 16

failure. The Company did not make the necessary repairs as the unit was scheduled to 17

begin its overhaul and upgrade in early 2016. The unit remained off-line (in a thrust 18

bearing outage) from January 1, 2016 through April 26, 2016 – at which time the unit’s 19

outage status was changed to Major Overhaul for the remainder of the year. 20

This is the third outage in Ludington’s multi-year $800 million overhaul and 21

upgrade project. Most major components will be replaced during this outage, including 22


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the water turbine (aka – runner), wicket gates, generator/motor, and stator. The unit is 1

scheduled to be returned to service in early 2017. 2

Campbell 3 3

The Campbell 3 outage was scheduled to begin March 4, 2016 and was projected to take 4

84 days. The outage began on schedule and was for AQCS tie-in, generator, and turbine 5

bearing work. The unit returned to service 117 days later on June 29, 2016. 6

Ludington 1 7

Ludington 1 was scheduled to be the third unit in Ludington’s multi-year $800 million 8

overhaul and upgrade project – this outage was scheduled to begin September 11, 2016. 9

However, when Ludington 5 experienced an unplanned thrust bearing failure, 10

Ludington 1’s overhaul and upgrade was delayed. Instead, on September 11, 2016, 11

Ludington 1 began a 12-day pond outage. The unit returned to service on September 23, 12

2016. 13

Karn 2 14

On March 11, 2016, Karn 2 transitioned from a five-day maintenance outage to a 38-day 15

planned outage for maintenance activities. The unit was returned to service on-time on 16

April 19, 2016. 17

Q. Have you reviewed the peaker and hydro unit outages? 18

A. Yes. I reviewed the events for each peaker and hydro unit shown on the Event Summary 19

Report, Exhibit A-11 (RCS-1). There were seven peaker outages greater than 28 days. 20

River hydro outages greater than 28 days included: Croton 2 – 42 days; Croton 3 – 21

34 days; Croton 4 – 49 days; Foote 2 – 130 and 29 days; Foote 3 – 38 days; Hardy 2 – 22

32 days; Rogers 1 – 365 days; Rogers 2 – 365 days; Webber 1 – 71 days; and Webber 2 – 23


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48 days. My review of these events and the additional information provided on Exhibit 1

A-13 (RCS-3) leads me to conclude that those outages were conducted in a prudent 2

manner. 3

Outages with a Duration of Less Than 28 Days 4

Q. How many periodic outages, less than 28 days but greater than one day in length, 5

occurred on the fossil and Ludington units in 2016? 6

A. As shown on Exhibit A-11 (RCS-1), 25 short periodic (planned) outages occurred on the 7

fossil and Ludington units in 2016. 8

Q. Generally speaking, what was the purpose of these periodic outages? 9

A. The outages varied from 1 to 27 days. They were planned to perform preventative 10

maintenance activities on equipment that will not operate for more than one to two years 11

without the need for attention. During these outages, any necessary corrective 12

maintenance that can be completed is also performed. 13

Availability 14

Q. How did the base load fossil availability in 2016 compare to 2015? 15

A. The 2016 fossil and hydro availability data is shown on Exhibit A-15 (RCS-5). 16

Compared to 2015 levels, the base load fossil MWh availability decreased from 78.19% 17

in 2015 (see MPSC Case No. U-17678-R, Exhibit A-12 (DBK-5), line 17, column (c)) to 18

66.90% in 2016 – see line 18, column (c). This decrease in availability was due to the 19

following units: Campbell 3 and Karn 1. 20


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Comparison to GADS Data 1

Q. Did you compare the availability of the Company’s base load fossil units to the five-year 2

average GADS data? 3

A. Yes. I compared the availability of the Company’s base load fossil units to the 2015 and 4

2011-2015 GADS data for comparable sized and fueled units. The results are shown on 5

my Exhibit A-16 (RCS-6). 6

Q. What did that comparison show? 7

A. The availability of Campbell 2, Campbell 3, BC Cobb 4, Karn 1 & 2, and Weadock 8 are 8

below both the one-year and five-year comparisons. The availability of all other units 9

was higher than either the one-year or five-year GADS average. 10

Q. Please explain the outages that contributed to lower than average availability on a MWh 11

basis. 12

A. Campbell 2 experienced four outages during 2016 – two planned, one maintenance, and 13

one unplanned. The two planned outages were to tie-in the AQCS and for overspeed 14

testing. The one maintenance outage was for valve and boiler work. The one unplanned 15

outage was due to a low condenser vacuum. 16

Campbell 3 experienced three planned outages during 2016. The first outage was 17

for turbine work and to tie-in the AQCS. The second outage was necessary for turbine 18

balancing. The third brief outage was necessary for tuning new Induced fan controls. 19

Cobb 4 experienced one boiler tube leak (maintenance outage) in 2016. 20

Karn unit 1 experienced 17 outages during 2016 – two planned, ten maintenance, 21

and five unplanned outages. The two planned outages were for boiler tube replacements 22

and removal of turbine valve screens. The ten maintenance outages were for leaks (drain 23


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line, boiler tube, and Reheat), throttle valve repairs and adjustments, conveyor gearbox 1

repairs, traveling screens, and turbine vibration during startup. The five unplanned 2

outages were the result of boiler tube leaks, switching, AQCS maintenance, and low 3

vacuum. 4

Karn unit 2 experienced 11 outages during 2016 – two planned, four maintenance, 5

and five unplanned outages. The two planned outages were for coal tripper repairs, boiler 6

feed pump, and balance of plant work. The four maintenance outages were for coal 7

tripper repairs, conveyor gearbox repairs, and traveling screens. The five unplanned 8

outages were for coal tripper issues, replacement of turning gear motor cable, transferring 9

station power, differential expansion, and a boiler tube leak. 10

Weadock unit 8 did not experience outages in 2016, however its availability was 11

below both the one-year and five-year GADS average due to derates that resulted from 12

burning 100% Western coal and reduced operation and maintenance spending prior to 13

retirement. 14

Q. Did you review all of the outages shown on Exhibit A-11 (RCS-1)? 15

A. Yes. I reviewed all the base load fossil and pumped storage outages that lasted longer 16

than 24 hours. 17

Q. In your opinion, did Consumers Energy act in a reasonable and prudent manner in 18

connection with the outages you reviewed on Exhibit A-11 (RCS-1)? 19

A. Yes. 20


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Adopted by DAVID B. KEHOE ROBERT C. SCHRAM DIRECT TESTIMONY

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NOx Allowance Expenses 1

Q. Did Consumers Energy forecast NOx expenses in the 2016 PSCR Plan case? If no, please 2

explain why. 3

A. No. Consumers Energy did not forecast NOx expenses in the 2016 PSCR Plan case 4

because Selective Catalytic Reduction units (“SCRs”) were installed and have 5

significantly reduced NOx emissions and the need to purchase allowances. The SCRs 6

were installed to comply with the Clean Air Interstate Rule (“CAIR”), which was 7

recently replaced by the Cross-State Air Pollution Rule (“CSAPR”). CSAPR is a cap and 8

trade rule much like CAIR. CSAPR governs the emission of SO2 and NOx from 9

fossil-fueled electric generating units through the use of an allowance based “cap and 10

trade” program. Under CSAPR, NOx is regulated on both an annual basis and during the 11

ozone season (May through September). Each allowance (annual or ozone) permits the 12

emission of one ton of NOx, with the emissions cap and number of allocated allowances 13

decreasing over time. SO2 is regulated on an annual basis only, with the emissions cap 14

decreasing over time. Phase I of CSAPR took effect on January 1, 2015 and Phase II will 15

become effective on January 1, 2017. No allowance purchases were required for either 16

the annual or ozone seasons and there were no expenses associated with the allowances 17

allocated by the Michigan Department of Environmental Quality. 18

Q. Did Consumers Energy incur NOx credits in 2016 related to the sale of NOx allowances? 19

A. Yes. The Company sold NOx emission allowances in 2016. 20

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Q. Are the actual expenses (for the sale of 2016 allowances) and credits for NOx contained 1

in Consumers Energy’s 2016 Reconciliation? 2

A. Yes. Company witness Hannah L. Patton includes the actual NOx expenses in Exhibit 3

A-4 (HLP-1). 4

SO2 Allowance Expenses 5

Q. Did Consumers Energy incur expenses or credits in 2016 related to the SO2 Allowance 6

Program? 7

A. Yes. Total actual SO2 allowance credits were $114. These proceeds were received from 8

the Environmental Protection Agency’s 2016 allowance auction. 9

Urea Expenses 10

Q. What was Consumers Energy’s estimate of urea expenses for the 2016 PSCR Plan case? 11

A. Consumers Energy projected the cost of urea for 2016 to be $2,741,000, based on 12

projected generation and SCR operations at Campbell units 2 and 3. 13

Q. What were the actual urea expenses? 14

A. Actual urea expenses for 2016 were $1,447,958. 15

Aqueous Ammonia 16

Q. What was Consumers Energy’s estimate of aqueous ammonia for the 2016 PSCR Plan 17

case? 18

A. Consumers Energy projected the cost of aqueous ammonia for 2016 to be $1,470,000 19

based on projected generation and SCR operations at Karn units 1 and 2 and Zeeland 20

unit 2. 21

Q. What were the actual aqueous ammonia expenses? 22

A. Actual aqueous ammonia expenses for 2016 were $860,841. 23


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Q. Why were aqueous ammonia expenses less than projected? 1

A. Aqueous ammonia expenses were less than protected as Karn units 1 and 2 did not 2

operate as projected. 3

Lime 4

Q. What was Consumers Energy’s estimate of lime for the 2016 PSCR Plan? 5

A. Consumers Energy projected the cost of lime for 2016 to be $11,058,000 based on 6

projected generation and Spray Dry Absorber (“SDA”) operations at Karn units 1 and 2 7

and Campbell units 1 through 3. 8

Q. What were the actual lime expenses? 9

A. Actual lime expenses for 2016 were $3,577,574. 10

Q. Why were lime expenses less than projected? 11

A. Lime expenses were less than projected as Karn units 1 and 2 and Campbell units 1 and 3 12

did not operate as projected. 13

Activated Carbon 14

Q. What was Consumers Energy’s estimate of activated carbon for the 2016 PSCR Plan 15

case? 16

A. Consumers Energy projected the cost of activated carbon for 2016 to be $2,689,000 17

based on projected generation and SDA operations at Karn units 1 and 2 and Campbell 18

units 1 through 3. 19

Q. What were the actual activated carbon expenses? 20

A. Actual activated carbon expenses for 2016 were $1,132,131. 21


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Q. Why were activated carbon expenses less than projected? 1

A. Activated carbon expenses were less than projected as Karn units 1 and 2 and Campbell 2

units 1 and 3 did not operate as projected. 3

2016 Base Load Power Plant Generating Cost Efficiency 4

Q. Why was Exhibit A-14 (RCS-7) included in this filing? 5

A. This information was provided in response to the MPSC’s Report on Status of Power 6

Quality in Michigan in MPSC Case No. U-15945. 7

Q. Does this conclude your testimony? 8

A. Yes. 9


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REBUTTAL TESTIMONY

OF

DAVID B. KEHOE

ON BEHALF OF


December 2017

56

DAVID B. KEHOE REBUTTAL TESTIMONY

rte1217-dbk 1


A. My name is David B. Kehoe, and my business address is 1945 W. Parnall Road, Jackson, 2

Michigan 49201. 3



“Company”) as the Executive Director Energy Resources Business Services (“ERBS”). 6


A. I received a Bachelor of Science in Chemistry degree in December 1977 from the 8

University of Michigan. In May of 1982, I received a Master’s degree in Business 9

Administration from the University of Detroit. 10

Q. Please describe your business experience. 11

A. In 1978, I began working as an Associate Engineer for The Detroit Edison Company 12

(“Detroit Edison”), the predecessor to DTE Electric Company. In this capacity, I worked 13

at Detroit Edison’s Engineering Research Department largely serving as an analytical 14

chemist specializing in instrumental analytical chemistry. From mid-1982 to 15

September 1989, I held the position of Fuels Engineer and was responsible for both the 16

operation of Detroit Edison’s Fuels laboratory as well as for consulting with the operating 17

power plants on fuel and combustion product impacts. Additionally, from 1985 until 18

1989, I was in charge of the Polychlorinated Biphenyls (“PCBs”) analysis laboratory. 19

This laboratory analyzed soil and oil samples for the presence of PCBs and was part of 20

Detroit Edison’s program to remove PCBs from existing equipment and to verify the 21

absence of PCBs from soil samples that came from remediation of transformer-oil spills. 22

While at Detroit Edison, I was also a member of the American Chemical Society, the 23

57


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American Society for Testing and Materials (“ASTM”) Committee on Corrosion and 1

Deposits from Combustion Gasses, and the ASTM D-5 Committee. 2

In 1989, I left the position of Senior Engineer at Detroit Edison and went to 3

CQ Inc., a subsidiary of the Electric Power Research Institute. While at CQ Inc., I held 4

the position of Project Manager and consulted with utilities, coal companies, and 5

engineering firms on fuel selection and fuel impacts. Additionally, I served on the 6

Department of Energy’s coal research project peer review panel. 7

In 1998, I left CQ Inc. and joined CMS Generation, a subsidiary of CMS Energy, 8

as a Plant Support Manager. My responsibilities included negotiating Long-Term 9

Service Agreements, power purchase agreements, Operation and Maintenance 10

agreements for new and existing power plants, providing operations review and cost 11

estimates for the development of new power plants, and providing technical assistance to 12

existing power-generating assets. In 2000, I became the Asset Manager for the Jorf 13

Lasfar Energy Company (“Jorf Lasfar”) in Morocco, and was responsible for 14

representing CMS Energy’s interests in that project. In that capacity, I also served on the 15

Management Committee of Jorf Lasfar, which functions as that project’s board of 16

directors. As such, I was responsible for dividend declarations, cash management policy, 17

setting annual goals and objectives, reviewing performance, and establishing salaries for 18

the project management. In addition, I also served in a similar capacity for the 19

GasAtacama Project in northern Chile. In April of 2004, I accepted the position of 20

Director of Staff, ERBS for Consumers Energy. In January 2016, I was promoted to 21

Executive Director ERBS. 22

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Q. What are your responsibilities as Executive Director ERBS? 1

A. As Executive Director ERBS, I am responsible for regulatory compliance, procedure 2

writing, safety audits, and rate case filings for ERBS of Consumers Energy. 3

Q. Have you previously sponsored testimony before the Michigan Public Service 4


A. Yes. I sponsored testimony in the following Commission cases: Case Nos. U-13917 and 6

U-13917-R (2004 Power Supply Cost Recovery (“PSCR”) Plan and Reconciliation 7

cases); Case Nos. U-14274 and U-14274-R (2005 PSCR Plan and Reconciliation cases); 8

Case Nos. U-14701 and U-14701-R (2006 PSCR Plan and Reconciliation cases); Case 9

No. U-14347 (2006 Electric Rate case); Case Nos. U-15001 and U-15001-R (2007 PSCR 10

Plan and Reconciliation cases); Case Nos. U-15415 and U-15415-R (2008 PSCR Plan 11

and Reconciliation cases); Case No. U-15245 (2008 Electric Rate case); Case 12

Nos. U-15675 and U-15675-R (2009 PSCR Plan and Reconciliation case); Case 13

No. U-15645 (2009 Electric Rate case); Case No. U-16113 (2009 Show Cause Order); 14

Case No. U-16054 (2009 Depreciation Practices for Electric and Common Utility Plant); 15

Case No. U-16055 (2009 Depreciation Practices for Ludington Pumped Storage Plant 16

(“Ludington”)); Case Nos. U-16045 and U-16045-R (2010 PSCR Plan and 17

Reconciliation cases); Case No. U-16191 (2010 Electric Rate case); Case Nos. U-16432 18

and U-16432-R (2011 PSCR Plan and Reconciliation cases); Case No. U-16536 (2011 19

Depreciation Practices for Lake Winds Energy Park); Case No. U-16794 (2011 Electric 20

Rate case); Case Nos. U-16890 and U-16890-R (2012 PSCR Plan and Reconciliation 21

cases); Case No. U-17087 (2013 Electric Rate case); Case Nos. U-17095 and U-17095-R 22

(2013 PSCR Plan and Reconciliation cases); Case No. U-17317 and U-17317-R (2014 23

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PSCR Plan and Reconciliation cases); Case No. U-17453 (2013 Accounting Practices for 1

certain Electric and Common Utility Plant); Case No. U-17473 (2013 Financing Order 2

Approving the Securitization of Qualified Costs); Case No. U-17624 (2014 Recovery of 3

Deferred Major Maintenance Expenses); Case No. U-17653 (2014 Depreciation Practices 4

for Electric and Common Utility Plant); Case No. U-17678 and U-17678-R (2015 PSCR 5

Plan and Reconciliation cases); Case No. U-17735 (2014 Electric Rate Case); Case No. 6

U-17990 (2016 Electric Rate Case); Case No. U-18124 (2016 Gas Rate Case); Case No. 7

U-18195 (2017 Depreciation Practices for Ludington); and Case No. U-18402 (2018 8

PSCR Plan Case). 9

Q. Are you sponsoring exhibits with your rebuttal testimony? 10


Exhibit A-22 (DBK-1) Discovery Response 17918R-AG-CE-61; 12

Exhibit A-23 (DBK-2) Confidential attachment to Discovery 13 Response 17918R-AG-CE-61; 14

Exhibit A-24 (DBK-3) MPSC Case No. U-17087, Testimony of 15 Company Witness DBKehoe - page 33; 16

Exhibit A-25 (DBK-4) MPSC Case No. U-17678-R, Testimony of 17

Company Witness DBKehoe, pages 9 18 through 12; 19

Exhibit A-26 (DBK-5) Ludington Pump Storage Unit 5 Bearing 20 Failure Economic Decision; 21

Exhibit A-27 (DBK-6) Confidential Ludington Pump Storage 22 Penstock Slope; 23

Exhibit A-28 (DBK-7) Discovery Response 17918R-AG-CE-67; 24 and 25

Exhibit A-29 (DBK-8) Ludington Unit 4 work schedule – January 26 2016 through May 2016. 27

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Q. Were these exhibits prepared by you or under your direction and supervision? 1

A. Yes. 2

Q. What is the purpose of your rebuttal testimony? 3

A. The purpose of my rebuttal testimony is to rebut the direct testimony of Sebastian 4

Coppola on behalf of the Attorney General, and explain why his recommendation to 5

disallow $3.1 million in replacement power costs for the Ludington Unit 5 outage and 6

$384,000 in replacement power costs for the Ludington Unit 4 outage should be rejected. 7

I am also adopting the direct testimony and exhibits of Company witness Robert C. 8

Schram as previously filed in this proceeding. 9

Q. Does your rebuttal testimony address Mr. Coppola’s replacement power calculations? 10

A. No. Company Witness Joshua W. Hahn addresses Mr. Coppola’s replacement power 11

calculations. 12

REBUTTAL OF ATTORNEY GENERAL WITNESS COPPOLA 13

Q. Beginning at page 7 of his direct testimony, Mr. Coppola discusses power plant outages. 14

At line 14, Mr. Coppola states, “After reviewing the outage reports in Exhibits A-11 15

(RCS-1) and A-13 (RCS-3), I have determined that there are two outage incidents where 16

the Company failed to exercise proper planning and diligence, resulting in higher power 17

costs to PSCR customers during the year 2016.” Does Mr. Coppola provide additional 18

detail on these outages? 19

A. Yes. Beginning on page 8, line 4 of his direct testimony, Mr. Coppola provides the 20

following, “The first outage incident occurred at the Ludington Unit 5 on June 9, 2015 21

and lasted nearly two years until May 24, 2017. According to the Company, on June 9, 22

2015, Ludington Unit 5 experienced an unplanned catastrophic thrust bearing failure. 23

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The Company decided not to undertake any repairs at that point on the basis that it had 1

planned a major overhaul and upgrade project for the generating unit beginning in April 2

of 2016. Thus, from June 9, 2015, Ludington Unit 5 was out of commission and had no 3

work done on it until April 5, 2016, at which time the Company began its major overhaul 4

of the unit.” 5

Q. Does Mr. Coppola identify why the Company did not repair Ludington Unit 5 between 6

June 9, 2015 and April 5, 2016? 7

A. Yes. On page 8, line 13, Mr. Coppola explains, “In discovery, the Company was asked to 8

explain why it delayed beginning the overhaul and upgrade work by nearly 10 months, 9

until April 5, 2016, for such a large and critical power generating unit. In its initial 10

response to discovery question AG-CE-46, the Company stated that the primary reason 11

for the delay was spatial constraints and conflicts with the overhaul project going on with 12

a different unit, the Ludington Unit 4.” 13

Q. Are there spatial constraints at Ludington? 14

A. Yes. As identified in my response to 17918R-AG-CE-61(c) (Exhibit A-22 (DBK-1)), 15

“Two purpose built maintenance buildings (one at each end of the Power House) were 16

constructed for the execution of the multi-year $800 million Ludington overhaul and 17

upgrade. These building were constructed to support one overhaul and upgrade at a time. 18

Furthermore, when one of the powerhouse turbine covers is removed . . ., the laydown 19

area is significantly reduced. Therefore, due to the: overall number of components, size 20

of these components (both physical and weight), and limited laydown area . . ., the 21

overhaul and upgrade project is limited to one unit at a time.” The confidential 22

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attachment to 17918R-AG-CE-61(c) is being provided as confidential Exhibit A-23 1

(DBK-2). 2

Q. How many Ludington units have been overhauled and upgraded? 3

A. The first Ludington unit overhaul and upgrade began in October 2013. Since then, half 4

of Ludington’s six units have been overhauled and upgraded – specifically Units 2, 4, 5

and 5. The Company is currently working on the fourth unit (specifically Unit 6) and 6

projects this overhaul and upgrade will be complete in April 2018. 7

Q. Has Consumers Energy preformed any “contemporaneous” overhaul and upgrades at 8

Ludington? 9

A. No. As stated above, the multi-year $800 million Ludington overhaul and upgrade 10

project was designed for one unit overhaul and upgrade at a time. 11

Q. Was the Company’s multi-year $800 million Ludington overhaul and upgrade plan 12

reviewed and approved by the Commission? 13

A. Yes. The Company addressed the Ludington overhaul and upgrade in the following cases 14

filed with the Commission – all of which were approved. 15

General Rate Case Nos.: U-17087 - filed September 2012; U-17735 - filed 16 December 2014; and U-17990 - filed March 2016. 17

PSCR Plan Case Nos.: U-17095 – 2013 Plan; U-17317 – 2014 Plan; 18 U-17678 – 2015 Plan; and U-17918 – 2016 Plan. 19

PSCR Reconciliation 20 Case Nos.: U-17905-R – 2013 Reconciliation and U-17317-R – 21

2014 Reconciliation. 22

Q. What did the Company indicate about the Ludington Overhaul and Upgrade Project in 23

the above filings? 24

A. In Case No. U-17087 (General Rates), beginning on page 33, line 9 of my direct 25

testimony (6 TR 1132 in that case), I stated that: “In 2011 through 2019, Consumers 26

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Energy will invest in a major overhaul and upgrade of the Ludington Pumped Storage 1

Plant. The first unit upgrade will begin in 2013 and be completed in 2014. One 2

additional unit will be upgraded each year, with the final unit being completed in 2019 – 3

Ludington has six (6) generating/pumping units.” Exhibit A-24 (DBK-3). 4

Also, in Case No. U-17678-R (2015 PSCR Reconciliation), beginning at page 9, 5

line 17 of my direct testimony (3 TR 544 in that case), I stated that: “On November 9, 6

2013, Ludington 2 began a 238-day planned outage. This was the first outage in 7

Ludington’s multi-year $800 million overhaul and upgrade project. Most major 8

components were replaced during this outage, including the water turbine (aka – runner), 9

wicket gates, generator/motor, and stator. The unit was returned to service 488 days later 10

on March 12, 2015.” Exhibit A-25 (DBK-4). 11

Q. At page 9, line 6 of his direct testimony, Mr. Coppola states, “The Company has not 12

presented any engineering analysis or assessment of all available options that would have 13

allowed it to undertake the overhaul work of Unit 5 contemporaneously with the overhaul 14

work going on with Unit 4.” Did Consumers Energy preform an engineering analysis or 15

assessment to determine the lowest cost option for returning Ludington Unit 5 to service? 16

A. Yes. As stated in response to AG-CE-61(a) (Exhibit A-22 (DBK-1)), “Consumers 17

Energy reviewed the available options for returning Ludington Unit 5 to service and 18

determined the lowest cost option for the customer was to declare a catastrophic bearing 19

failure.” Additional detail as to how the Company determined that declaring a 20

catastrophic bearing failure was the lowest cost option is provided as Exhibit A-26 21

(DBK-5). 22

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Q. At page 10, line 16 of his direct testimony, Mr. Coppola states, “My conclusion is that the 1

Company did not act prudently in undertaking all reasonable steps to begin the overhaul 2

and upgrade of the Ludington Unit 5.” Did Mr. Coppola support his conclusion with an 3

engineering analysis or assessment? 4

A. No. Mr. Coppola’s conclusion is not supported by an engineering analysis or assessment. 5

Q. Should the Commission accept Mr. Coppola’s conclusion? 6

A. No. The Company’s response to 17918R-AG-CE-61 (Exhibit A-22 (DBK-1)) clearly 7

identifies that Consumers Energy reviewed the available options for returning Ludington 8

Unit 5 to service, and that review determined the lowest cost option for the customer was 9

to declare a catastrophic bearing failure. Furthermore, because the Ludington Overhaul 10

and Upgrade Project was designed to support one unit upgrade at a time, and this design 11

was included in multiple case filings, Mr. Coppola’s suggestion that the Company could 12

have performed “contemporaneous” Ludington outages lacks merit and therefore should 13

be rejected. 14

Q. At page 9, lines 10 through 15 of his direct testimony, Mr. Coppola asserts “It is apparent 15

from the photograph that sufficient open space existed in the parking lot and land 16

adjoining the plant where turbine covers and temporary work areas could have been 17

staged to undertake the overhaul and upgrade of Unit 5 much earlier than April 5, 2016. It 18

is also not clear why the two temporary work buildings built at each end of the plant 19

could not accommodate work for both Unit 4 and 5.” Does Mr. Coppola identify the 20

basis for the statement, “[t]hat sufficient open space existed in the parking lot and land 21

adjoining the plant…”? 22

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A. Yes. Mr. Coppola’s statement is based on an overhead photograph of Ludington that 1

Consumers Energy submitted in response to discovery question 17918R-AG-CE-61. 2

Exhibit A-22 (DBK-1). 3

Q. Did Mr. Coppola provide documents, drawings, or designs that identify how the parking 4

lot and land adjoining the plant could have been used? 5

A. No. 6

Q. Is there a parking lot in the overhead photograph of Ludington that Consumers Energy 7

submitted in response to discovery question 17918R-AG-CE-61? Exhibit A-22 (DBK-1). 8

A. No. Contrary to Mr. Coppola’s statement, there is no parking lot in the overhead 9

photograph of Ludington. Presumably, Mr. Coppola erroneously identifies the Ludington 10

Generating Step-Up (“GSU”) transformer bank and 345kV overhead powerlines (located 11

on the East side of the turbine covers – Lake Michigan is on the West side of the turbine 12

covers) as “the parking lot”. 13

As for the land adjoining the plant, this land slopes up to the Ludington Reservoir 14

at a 3 to 1 ratio - which means for every 3 foot of run, the ground rises 1 foot. 15

Furthermore, just below the ground level, there are six large penstocks that carry water 16

between Lake Michigan and Ludington’s Upper Reservoir. Ludington’s slope is 17

confirmed in the attached Confidential Exhibit A-27 (DBK-6). 18

Q. Is there any merit to Mr. Coppola’s statement, “It is also not clear why the two temporary 19

work buildings built at each end of the plant could not accommodate work for both Unit 4 20

and 5”? 21

A. No. For the reasons discussed above, it was not possible to work on two Ludington units 22

at once. Furthermore, Mr. Coppola incorrectly identifies the two buildings at each end of 23

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the plant as “temporary.” These buildings are not temporary, but rather purpose built to 1

support one overhaul and upgrade at a time. 2

Q. At page 11, line 16 of his direct testimony, Mr. Coppola recommends the Commission 3

disallow $3,145,310 in PSCR costs related to the Ludington Unit 5 bearing failure. 4

Should the Commission adopt Mr. Coppola’s recommendation? 5

A. No. For the above stated reasons, the Commission should reject Mr. Coppola’s 6

recommendation. 7

Q. At page 12 of his direct testimony, Mr. Coppola identifies the second power plant outage 8

incident. At line 3, Mr. Coppola states, “On page 13 of Exhibit A-13 (RCS-3), the 9

Company reported that it experienced an extended outage of the Ludington Unit 4 from 10

January 1, 2016 to May 20, 2016 due to testing of the generating unit, after it had 11

completed a major overhaul.” Is page 13 of Exhibit A-13 (RCS-3) correct? 12

A. No. Page 13 of Exhibit A-13 (RCS-3) is not correct because it does not include a 13

description of the overhaul and upgrade work completed on Ludington Unit 4 in addition 14

to the testing of the generating unit. As discussed below, there was a significant amount 15

of overhaul and upgrade work which occurred on Ludington Unit 4 between January 1, 16

2016 and April 26, 2016. The Company identified the error on this page of Exhibit A-13 17

(RCS-3) and attempted to clarify it in response to discovery request 17918R-AG-CE-67 18

(Exhibit A-28 (DBK-7)). However, the Attorney General appears to have mistakenly 19

interpreted this response as justifying, “[t]he additional outage time as part of the planned 20

extension of the overhaul and upgrade project.” Mr. Coppola’s direct testimony, page 12, 21

line 17. 22

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Q. If page 13 of Exhibit A-13 (RCS-3) is not correct, what was done between January 1, 1

2016 and May 20, 2016? 2

A. Exhibit A-29 (DBK-8) identifies the work completed during the Ludington Unit 4 3

Overhaul and Upgrade between January 1, 2016 and May 20, 2016. This 22-page 4

document provides 502 lines which identify the specific types of work that was 5

completed during this 140-day Planned Outage Extension. 6

Q. In response to discovery request 17918R-AG-CE-67 (Exhibit A-28 (DBK-7)), the 7

Company indicates that Ludington Unit 4 testing occurred between April 26, 2016 and 8

May 27, 2016. Are the testing dates identified in Exhibit A-28 (DBK-7) consistent with 9

the testing dates identified in Exhibit A-29 (DBK-8)? 10

A. Yes. The testing dates in Exhibit A-29 (DBK-8) begin on page 18, line 391 and end on 11

page 22, line 496. 12

Q. How many total days did it take to complete the Ludington Unit 4 Overhaul and 13

Upgrade? 14

A. It took 436 days to complete the Ludington Unit 4 Overhaul and Upgrade. The 15

Ludington Unit 4 Overhaul and Upgrade began on March 17, 2015 and concluded on 16

May 27, 2016. 17

Q. How does the Ludington Unit 4 Overhaul and Upgrade, which was second in the 18

Ludington Overhaul and Upgrade sequence, compare with the first Ludington Overhaul 19

and Upgrade – Ludington Unit 2? 20

A. As stated above, the Ludington Unit 2 Overhaul and Upgrade was completed in 21

488 days – beginning November 9, 2013 and concluding March 12, 2015. 22

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Q. What is the significance of this comparison? 1

A. This comparison shows that the Company reduced the overhaul and upgrade time by 2

52 days (or approximately 10%) and addresses Mr. Coppola’s contention that it took 3

unreasonably long for the Company to complete the Ludington Unit 4 Overhaul and 4

Upgrade. 5

Q. At page 13, beginning on line 1 of his direct testimony, Mr. Coppola opines that “[t]he 6

Company has not adequately justified the additional 109 days of the outage for the 7

Ludington Unit 4. As a result, the additional outage time is not reasonable and appears 8

imprudent. Therefore, the value of the power loss attributable to the 109-days needs to 9

be removed from the power costs that the Company seeks to recover in this case.” Did 10

Consumers Energy prudently manage the work completed during the 109 days in 11

question? 12

A. Yes. As shown in Exhibit A-29 (DBK-8), Consumers Energy did more than just testing 13

during the 109 days in question. 14

Q. Should the Commission accept Mr. Coppola’s position regarding the 109-day 15

disallowance? 16

A. No. Mr. Coppola’s position regarding the 109-day disallowance does not take into 17

account the Company’s response to discovery request 17918R-AG-CE-67. Exhibit A-28 18

(DBK-7). Furthermore, as shown above, Consumers Energy completed more than just 19

testing during the time between January 1, 2016 and May 20, 2016. 20

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Q. At page 13, line 9 of his direct testimoy, Mr. Coppola recommends that the Commission 1

disallow $384,490 in this case. Should the Commission adopt Mr. Coppola’s 2

recommendation? 3

A. No. For the above stated reasons, the Commission should not adopt Mr. Coppola’s 4

recommendation. 5

Q. Does this conclude your rebuttal testimony? 6

A. Yes, it does. 7

70




DIRECT TESTIMONY

OF

MEGAN L. METZ

ON BEHALF OF


March 2017

71

MEGAN L. METZ DIRECT TESTIMONY

te0317-mlm 1

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

A. My name is Megan L. Metz, and my business address is 1945 West Parnall Road, 2




“Company”) as the Fuel Procurement Director in Fossil Fuel Supply. 6

Q. Would you please describe your educational background and business experience? 7

A. I graduated from the University of Michigan in 2002 with a Bachelor of Science in 8

Engineering Degree in Industrial and Operational Engineering and from Spring Arbor 9

University in 2007 with a Master of Business Administration. I began working for 10

Consumers Energy in 2002 and have held positions of increasing responsibility in 11

Electric Generation. I began work in my current role within the Fossil Fuel Supply group 12

of Energy Supply Operations in May of 2014. 13

Q. What are your duties as the Fuel Procurement Director? 14

A. My responsibilities include purchasing the coal, oil, and gas used at the Company’s 15

electric generating plants; managing associated contracts; assuring coal quality standards 16

are met; administering the Fuels Management System that tracks all coal shipments, 17

inventory levels, coal consumption, and accounting information; and the preparation of 18

testimony and filings for presentation before the Michigan Public Service Commission 19

(“MPSC” or the “Commission”). 20


A. I am sponsoring testimony with respect to the Company’s 2016 actual volumes and costs 22

of coal, oil, and gas used for electric generation. 23

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Q. Are you sponsoring any exhibits with your testimony? 1


Exhibit A-2 (MLM-1) 2016 Coal Receipts – Plan and Actual; and 3

Exhibit A-3 (MLM-2) Comparison of 2016 As-Burned Cost of Fuel. 4

Q. Were the exhibits prepared by you? 5

A. Yes. 6

Coal Procurement Strategy 7

Q. Can you describe the Company’s coal procurement strategy it employed to provide its 8

coal supply for 2016? 9

A. Yes. The Company’s strategy for coal procurement provides for purchasing and securing 10

quantities of coal over time that typically enable the Company to have approximately 11

70% to 90% of its anticipated volume requirements secured by the fall of each year for 12

the following calendar year. The Company employs this strategy because the coal supply 13

chain does not operate in such a manner that allows large volumes of coal to be procured 14

and delivered in the year of delivery. This is because the coal producers and the coal 15

transportation providers plan their operational resources based on known commitments 16

from utilities, well in advance of the physical act of mining and delivering the coal. 17

Because of this, the spot coal market can be unpredictable and can easily become 18

constrained by forces affecting both supply and demand. Accordingly, the Company 19

believes it is best to manage its coal supply in a manner such that the risk of having an 20

insufficient supply of coal is minimized while at the same time balancing pricing 21

considerations by retaining some exposure to the spot market. To manage this risk, the 22

Company limits its exposure to the spot market by contracting for a large percentage of 23

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its projected requirements ahead of time because it does not believe it is reasonable or 1

prudent to speculate that large quantities of coal will be available when needed from the 2

spot market. Furthermore, this strategy provides coal supply volume protection should 3

the Company’s actual coal requirements change from its projected requirements. 4

In addition, the Company layers its coal purchases in such a way that each year it 5

has a portfolio of coal purchase contracts that provides dollar cost averaging. This 6

strategy is instrumental in minimizing price risk to Consumers Energy’s customers and 7

limits their exposure to price volatility in the market. The portfolio for a given year 8

consists of contracts of various vintages, volumes, length of term, and prices. Exhibit 9

A-2 (MLM-1) outlines the contracts the Company had in place during 2016. 10

Q. Can you provide a more detailed comparison of volumes actually received versus those 11

that were planned? 12

A. Yes. Exhibit A-2 (MLM-1) details the 2016 planned coal receipts, the 2016 actual coal 13

receipts, and the number of tons by which each contract varied from the plan. Variations 14

between planned and actual contract volumes received are typical and occurred for 15

various reasons, including: (1) volume tolerances allowed by contract; (2) shipments that 16

loaded in 2015 but were not received at a Company generating plant until 2016; 17

(3) shipments that loaded in 2016 but were not received at a Company generating plant 18

until 2017; (4) provisions that allowed the Company to receive any remaining contracted 19

quantities in 2016 that were not delivered in 2015; and (5) provisions that allowed the 20

Company to receive any remaining contracted quantities in 2017 that were not delivered 21

in 2016. 22

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te0317-mlm 4

Q. In general, how was coal evaluated for purchase? 1

A. For all coal purchases, the Company solicited competitive bids. All such bids were 2

evaluated on a delivered cost basis with purchases made from the lowest cost eligible 3

suppliers. 4

Delivered Coal Volumes and Costs 5

Q. How did actual 2016 delivered coal volumes and costs compare with projected 2016 6

delivered coal volumes and costs presented by the Company in the 2016 PSCR Plan? 7

A. During 2016, 952,059 fewer tons of coal was delivered than projected. The projected and 8

actual 2016 delivered coal costs are as follows: 9

Plan $/MMBtu Actual $/MMBtu Variation 10

Western $2.406 $2.307 (4.1%) 11

Eastern $3.079 $2.631 (14.6%) 12

Total $2.413 $2.312 (4.2%) 13

Q. Please elaborate on the volumes received and the prices paid for coal in 2016. 14

A. The Company projected the delivered price of western coal to average $2.406/MMBtu 15

for 6,255,922 tons. The actual average price for western coal delivered was 16

$2.307/MMBtu for 5,286,702 tons. The price difference of western coal was primarily 17

due to: (1) lower transportation costs than anticipated and (2) receiving coal with a 18

higher average heat content than anticipated (Btu/lb of coal) which therefore lowers the 19

total delivered cost on a MMBtu basis. 20

The Company projected the delivered price of eastern coal to average 21

$3.079/MMBtu for 48,252 tons. The actual average price for eastern coal delivered was 22

$2.631/MMBtu for 65,414 tons. The price difference of eastern coal was primarily due 23

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te0317-mlm 5

to: (1) lower commodity costs than anticipated and (2) lower transportation costs than 1

anticipated. 2

Q. Based on your previous responses, do you believe that the Company’s 2016 coal 3

purchases were reasonable and prudent? 4

A. Yes, I do. 5

Burned Coal Volumes and Costs 6

Q. How did actual coal burn volumes and costs compare with those projected in 2016? 7

A. For 2016, the Company projected its coal burn requirements to be 6,678,268 tons. To 8

support this coal burn, the Company anticipated receiving 6,304,174 tons of coal of 9

which 4,777,652 tons (75.8%) were from contract receipts and 1,526,522 tons (24.2%) 10

were from spot receipts. This plan was consistent with the Company’s general strategy 11

for coal procurement and was instrumental in minimizing supply and price risk as 12

discussed previously in this testimony. The Company’s actual 2016 coal burn was 13

5,708,760 tons, 969,508 tons (14.5%) lower than projected with as-burned costs 14

$49,327,290 (16.9%) lower than those projected in the 2016 PSCR Plan case. Exhibit 15

A-3 (MLM-2) shows a comparison by generating plant of the as-burned volumes and 16

costs of coal projected in the 2016 PSCR Plan filing with the actual as-burned volumes 17

and costs incurred during 2016. 18

Q. Why were the as-burned volumes and costs lower than projected? 19

A. On a system-wide basis, coal fired generating units experienced a lower capacity factor 20

than was projected which translated into the need to consume less coal. 21

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Q. Based on your previous responses and on your familiarity with the Company’s coal 1

purchases, do you believe that 2016 as-burned coal costs were reasonable and prudent? 2

A. Yes, I do. 3

Burned Oil and Gas Volumes and Costs 4

Q. What were the projected and actual oil and gas burn values for electric generation during 5

2016? 6

A. The projected and actual burn volumes and costs are shown on Exhibit A-3 (MLM-2). 7

Q. Would you please explain the major differences between the projected and actual costs of 8

oil and gas burned for electric generation during 2016 as outlined in your Exhibit A-3 9

(MLM-2)? 10

A. In total, the actual costs of oil and gas burned on the Consumers Energy system were less 11

than projected mainly because the actual overall levels of generation for two of the major 12

gas units (Zeeland and D.E. Karn units 3 & 4) were less than projected. 13

Q. Please elaborate on the actual costs for oil burned for electric generation in 2016. 14

A. All of our oil purchases were made through a competitive bidding process, selecting the 15

lowest cost bidder. The Company projected a burn of 68,800 barrels of No. 6 fuel oil at 16

Karn units 3 & 4; they actually consumed 26,364 barrels at an average cost of $38.35 per 17

barrel. The Company’s 2016 PSCR Plan projected no consumption of No. 2 fuel oil at 18

the J.H. Campbell (“Campbell”) peaker; however, the Campbell peaker did end up 19

consuming a small amount (649 barrels) at an average cost of $67.28 per barrel. 20

Q. Please elaborate on the actual costs for gas burned for electric generation in 2016. 21

A. The arrangements for gas purchases for Zeeland, Jackson, and Karn units 3 & 4 were 22

made pursuant to competitive bidding processes, with Zeeland and Jackson both utilizing 23

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gas management services agents. The projected cost of gas burned at Zeeland was 1

$3.540 per MCF, while the actual cost was $2.832 per MCF. The projected cost of gas 2

burned at Jackson was $3.788 per MCF, while the actual cost was $3.075 per MCF. The 3

price differences for gas burned at Zeeland and Jackson were due to lower than 4

anticipated natural gas prices. 5

The projected cost of gas burned at Karn units 3 & 4 was $6.591 per MCF, while 6

the actual cost of gas was $6.648 per MCF. The cost of gas burned for Karn units 3 & 4 7

is higher than Zeeland and Jackson plants because there are some fixed cost contracts 8

associated with delivery of natural gas to Karn 3 & 4 and when the MWh production of 9

these units are low the fuel cost in $/MMBtu is higher. In addition, the Karn 3 & 4 heat 10

rates are higher than Zeeland and Jackson plants, meaning that the units require more gas 11

supply to produce the same number of MWh. For all other gas peakers, the cost of gas 12

burned by the Company was billed according to MPSC approved tariffs. 13

Q. Based on your previous responses and on your familiarity with the Company’s oil and 14

gas purchases, do you believe that 2016 oil and gas purchases were made in a reasonable 15

and prudent manner and that the costs incurred were reasonable and prudent? 16

A. Yes, I do. 17


A. Yes. 19

78




DIRECT TESTIMONY

OF

HANNAH L. PATTON

ON BEHALF OF


March 2017

79

HANNAH L. PATTON DIRECT TESTIMONY

te0317-hlp 1


A. My name is Hannah L. Patton, and my business address is One Energy Plaza, Jackson, 2

Michigan 49201. 3



“Company”). 6

Q. What is your position at Consumers Energy? 7

A. I am a Senior Accounting Analyst II in the Electric Revenue and Fuel Reconciliation 8

section of the General Accounting Department. 9

Q. Please state your educational background and work experience. 10

A. I graduated from Albion College in May 2009 with a Bachelor of Arts Degree in 11

Economics and Management. I began working for the Company in January 2012 in the 12

Electric Revenue and Fuel Reconciliation section of the General Accounting Department. 13

I was an external auditor employed by Rehmann Robson from December 2007 through 14

December 2011. I obtained my Certified Public Accountant license in February 2011. 15

Q. What are your responsibilities in your present position? 16

A. My primary responsibilities include the accounting for power supply expenses, power 17

supply cost, over- or (under-) recoveries, and the Company’s mandatory and voluntary 18

Renewable Energy (“RE”) programs, as well as electric revenue and gross margin 19

analysis. 20

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Q. Have you previously filed testimony with the Michigan Public Service Commission 1

(“MPSC” or the “Commission”)? 2

A. Yes. I filed testimony in the following cases: 3

• MPSC Case No. U-17631 (direct), the Company’s 2013 RE 4 Reconciliation Case; 5

• MPSC Case No. U-17803 (direct), the Company’s 2014 RE 6 Reconciliation Case; and 7

• MPSC Case No. U-18081 (direct), the Company’s 2015 RE 8 Reconciliation Case. 9


A. The purpose of my testimony is to provide the methodology and calculation of the 11

Company’s over- or underrecovery amount related to the operation of the Power Supply 12

Cost Recovery (“PSCR”) clause during 2016. 13



Exhibit A-4 (HLP-1) 2016 Power Supply Cost Recovery Reconciliation; and 16

Exhibit A-5 (HLP-2) PSCR Interest Calculation – 2016. 17


A. Yes. 19

PSCR 20

Q. Would you please describe the procedures used by the Company to derive the amount of 21

over- or underrecovery recorded each month during 2016 under the PSCR clause? 22

A. The monthly over- or underrecovery amounts were derived by comparing the Company’s 23

PSCR revenues for a given month with the PSCR costs for the same month. 24

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te0317-hlp 3

Q. How did the Company determine the monthly amount of PSCR Revenue as shown on 1

line 16 of Exhibit A-4 (HLP-1)? 2

A. The PSCR cycle billed sales revenue as shown on line 13 of Exhibit A-4 (HLP-1) (PSCR 3

cycle billed sales multiplied by the sum of the current month PSCR factor and the base 4

cost recovery factor) is added to the current month’s unbilled PSCR revenue as shown on 5

line 14 of Exhibit A-4 (HLP-1) (current month’s unbilled PSCR sales multiplied by the 6

sum of the next month’s PSCR factor and the base cost recovery factor). From this sum 7

is subtracted the prior month’s unbilled PSCR revenue as shown on line 15 of Exhibit 8

A-4 (HLP-1) (prior month’s unbilled PSCR sales multiplied by the sum of the prior 9

month’s PSCR factor and the base cost recovery factor). 10

Q. How were recoverable power supply costs determined? 11

A. Recoverable power supply costs are power supply costs actually incurred during 2016, 12

which include costs incurred in accordance with the Company’s 2016 PSCR Plan filed in 13

MPSC Case No. U-17918. These costs consist of the Company’s fuel and purchased 14

power costs, transmission costs, urea and aqueous ammonia costs, lime, net Nitrogen 15

Oxide (“NOx”) and Sulfur Dioxide (“SO2”) allowance costs, and “Transfer Costs” 16

associated with RE, less the cost of non-PSCR sales. Recoverable power supply costs 17

also include activated carbon expenses for which the Company has requested approval to 18

recover in this and all future PSCR cases. 19

Q. Are all Company sales included in this PSCR Reconciliation case? 20

A. No. 21

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Q. Please describe non-PSCR sales and identify how the costs of these sales are determined. 1

A. Non-PSCR sales include three categories of sales: (1) sales to our non-jurisdictional 2

interruptible wholesale customer, which are priced at the current monthly incremental 3

fuel and purchased and interchanged power cost; (2) firm non-jurisdictional wholesale 4

sales and the Grand Rapids special contract sales, both of which are priced at the average 5

monthly power supply cost excluding the cost of the incrementally priced sales; and 6

(3) sales to Rate GSG-2 customers, which are priced at the Midcontinent Independent 7

System Operators, Inc’s real-time locational marginal price plus allocated capacity and 8

transmission charges. 9

Q. Have you prepared an exhibit that sets forth the Company’s PSCR revenues and the 10

recoverable costs for 2016? 11

A. Yes, Exhibit A-4 (HLP-1) provides this information. This exhibit has been prepared on 12

the same basis and using the same methodology that the Company has presented in 13

previous PSCR Reconciliation cases. As shown on line 27, column (n) of this exhibit, the 14

2016 PSCR Reconciliation results in a total net overrecovery of $2,817,173. Including 15

statutory interest, as set forth on Exhibit A-5 (HLP-2), the total net overrecovery for 2016 16

is $5,093,198. This overrecovery includes the 2015 overrecovery discussed later in my 17

testimony. 18

Q. How does the Company propose to treat this overrecovery? 19

A. The Company has rolled- in the overrecovery amount into the calculation of its 2017 20

PSCR factors. This roll-in approach was approved by the Commission in its 21

December 21, 2006 Order in MPSC Case No. U-15001. 22

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te0317-hlp 5

Q. Please continue. 1

A. Exhibit A-4 (HLP-1) details the PSCR Reconciliation Report for the 12-month period 2

ended December 31, 2016, for all classes of customers. Lines 1 through 3 show PSCR 3

sales in kWh by month and in total. Lines 5 through 7 calculate total sales less 4

interruptible wholesale and Rate GSG-2 sales for each of the 12 months and in total. 5

Line 8 depicts the percentage of PSCR sales to system sales less interruptible wholesale 6

and Rate GSG-2 sales for each of the 12 months. Lines 9 through 12 show the authorized 7

PSCR factor for the entire year 2016, including the base recovery factor (line 9) as well 8

as the monthly factors (lines 10 through 12) per kWh for each of the 12 months. Lines 13 9

through 15 show PSCR revenues for each of the 12 months and in total. The total for 10

lines 13 through 15 is shown on line 16. Lines 17 and 18 show fuel for generation and 11

purchased and interchange power costs for each month and in total. Line 19 shows 12

environmental costs for each month and in total. Line 19 includes costs related to urea, 13

NOx and SO2 allowances, aqueous ammonia, lime, and activated carbon. The total for 14

lines 17 through 19 is shown on line 20. Line 21 shows the reduction to PSCR costs for 15

the costs related to the interruptible wholesale and Rate GSG-2 sales. Line 22 is the 16

difference between line 20 and line 21. Line 23 is the same as line 8 described above. 17

Line 24 is the product of lines 22 and 23 and represents the costs allocated to PSCR 18

customers. Line 25 shows the over- or underrecovery for each month and for the 19

12-month period. Line 26 shows the roll-in of the 2015 overrecovery. Line 27 shows the 20

cumulative over- or underrecovery by month during the PSCR year. 21

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te0317-hlp 6

Q. How was the percentage on line 8 (Percentage PSCR Sales to Net of Incremental Total) 1

determined? 2

A. This percentage was determined by dividing total PSCR calendar sales by total system 3

sales less interruptible wholesale and Rate GSG-2 sales (i.e. line 4 divided by line 7). 4

Q. How were PSCR revenues shown on line 16 determined? 5

A. Monthly PSCR revenues consist of billed PSCR revenues and net unbilled PSCR 6

revenues. Billed PSCR revenues result from multiplying current cycle billed sales by the 7

sum of the base fuel factor and the billed PSCR factor (line 1 multiplied by the sum of 8

line 9 and line 10). Current month unbilled PSCR revenues result from multiplying 9

current month unbilled sales by the sum of the base fuel factor and the current month 10

unbilled PSCR factor (line 2 multiplied by the sum of line 9 and line 11). Prior month 11

unbilled PSCR revenues result from multiplying prior month unbilled sales by the sum of 12

the base fuel factor and the prior month PSCR factor (line 3 multiplied by the sum of 13

line 9 and line 12). The sum of lines 13 through 15 equals the total PSCR revenue 14

amount on line 16. 15

Q. Did the Commission issue any orders in 2015 that affected the calculation of PSCR 16

revenues? 17

A. Yes. The Commission’s November 19, 2015 Order in MPSC Case No. U-17735 18

established a new Transmission and Line Loss Factor of $0.000010792 per kWh effective 19

for service rendered on and after December 1, 2015. The Transmission and Line Loss 20

Factor is used to derive the base recovery and PSCR factors. Accordingly, the January 21

PSCR revenue calculation reflects blended base recovery and PSCR factors based on the 22

number of days customers were subject to the base fuel and PSCR factors in effect prior 23

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te0317-hlp 7

to the Commission’s Order in Case No. U-17735 and the number of days the Case No. 1

U-17735 base recovery and PSCR factors were in effect. 2

Q. Please discuss the derivation of the power supply costs allocated to PSCR customers on 3

line 24. 4

A. This amount was derived by adding fuel for generation costs with net purchased and 5

interchange power costs (which include transmission costs) and environmental costs. 6

Total costs were then reduced by the costs associated with interruptible wholesale and 7

Rate GSG-2 sales. This result was then multiplied by the jurisdictional percentage to 8

arrive at the total recoverable power supply costs allocated to PSCR customers. 9

Q. How is the over- or underrecovery amount shown on line 25 calculated? 10

A. The amount on line 25 is the difference between line 16 and line 24. When line 16 is 11

larger than line 24 there is an overrecovery. When line 16 is smaller than line 24 there is 12

an underrecovery. 13

Q. Please explain line 26. 14

A. In its Order in MPSC Case No. U-15001 dated December 21, 2006, the Commission 15

granted the Company authority to roll in prior year under- and overrecoveries into its 16

future PSCR plans. The amount on line 26 represents the Company’s 2015 PSCR 17

overrecovery of $12,184,568 as described in Company witness Stanley Hunley’s rebuttal 18

testimony in MPSC Case No. U-17678-R. 19

Q. How were the monthly interest amounts on Exhibit A-5 (HLP-2) calculated? 20

A. The monthly interest amounts on Exhibit A-5 (HLP-2) were calculated in a manner 21

consistent with the assumption that each month’s over- or underrecovery was incurred 22

uniformly over the current month. Monthly interest was calculated using the following 23

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te0317-hlp 8

formula: (1/2 of the current month’s over- or underrecovery plus the over- or 1

underrecovery balance at the beginning of the current month) multiplied by (the 2

applicable annual interest rate divided by 12). The applicable interest rate is the 3

Company’s monthly average short-term annual interest rate of borrowing for 4

underrecoveries, or the authorized rate of return on common equity in the electric 5

business for overrecoveries. The monthly over- or (under) recovery amounts on 6

Exhibit A-5 (HLP-2) are from Exhibit A-4 (HLP-1). 7

Q. What does the total interest amount on Exhibit A-5 (HLP-2) represent? 8

A. This exhibit sets forth the interest owed to the Company or to our customers as a result of 9

any under- or overrecovery. The total interest amount on line 13, column (f) of Exhibit 10

A-5 (HLP-2) represents the amount of interest owed to customers for the 2016 PSCR 11

overrecovery. 12

Q. Does this conclude your direct testimony in this proceeding? 13

A. Yes. 14

87




SUPPLEMENTAL TESTIMONY

OF

HANNAH L. PATTON

ON BEHALF OF


March 2018

88

HANNAH L. PATTON SUPPLEMENTAL TESTIMONY

ste0318-hlp 1


A. My name is Hannah L. Patton, and my business address is One Energy Plaza, Jackson, 2

Michigan 49201. 3

Q. Are you the same Hannah L. Patton who submitted direct testimony in this case? 4

A. Yes. 5

Q. What is the purpose of your supplemental testimony? 6

A. The purpose of my supplemental testimony is to address the recovery of insurance 7

proceeds related to outages at the Company’s Karn units in 2015 and present the 8

following exhibits to reflect certain adjustments I have made in response to the Michigan 9

Public Service Commission’s (“MPSC” or the “Commission”) February 5, 2018 Order in 10

Case No. U-17678-R: 11

Exhibit A-30 (HLP-3) 2016 Power Supply Cost Recovery Reconciliation; 12 and 13

Exhibit A-31 (HLP-4) PSCR Interest Calculation – 2016. 14


A. Yes. 16

Q. Did Consumers Energy Company (“Consumers Energy” or the “Company”) receive any 17

replacement power insurance proceeds in 2016 as an offset to the Karn 2015 outages 18

which were disallowed in the Commission’s February 5, 2018 Order in Case 19

No. U-17678-R? 20

A. Yes. The Company received $1,529,436 in August 2016. That amount was credited or 21

netted against the Purchased and Interchange Power costs in that month, as shown in 22

line 18 of Exhibit A-4 (HLP-1), thereby reducing such power costs. 23

89


ste0318-hlp 2

Q. Why did the Company record these insurance proceeds as reduction to power supply 1

costs in 2016? 2

A. These insurance proceeds were recorded as a reduction to power supply costs in 2016 3

because the Company received the insurance proceeds in 2016. Additionally, at the time 4

the Company received these insurance proceeds, the Company believed that the Karn 5

outages experienced in 2015 were reasonably incurred outages. As reasonably incurred 6

outages, the Company would be permitted to recover the replacement power costs. Since 7

the Company expected to recover the replacement power costs associated with the Karn 8

outages, the Company credited the insurance proceeds to customers to prevent a partial 9

double recovery of the outage costs. 10

Q. What is the Company’s request in this case with respect to the insurance proceeds which 11

were credited to customers in 2016? 12

A. The Company requests that it be permitted to recover the insurance proceeds which were 13

credited to customers in 2016. This is a reasonable approach because the Commission 14

found in the Company’s 2015 PSCR Reconciliation, Case No. U-17678-R, that the 15

Company could not recover the replacement power costs related to the 2015 Karn 16

outages. If the Company is not permitted the opportunity to recover the insurance 17

proceeds which have already been credited to customers, it would unreasonably result in 18

compensating customers as an offset for a replacement power expense that they did not 19

incur. The Company’s request is also consistent with the Commission’s Order in Case 20

No. U-17678-R, which adopted Staff’s position that replacement power costs related to 21

the Karn outages should be disallowed with “any business interruption insurance 22

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ste0318-hlp 3

proceeds accruing to the company.” MPSC Case No. U-17678-R, February 5, 2018 1

Order, pages 11-13. 2

Q. Please describe Exhibit A-30 (HLP-3). 3

A. Exhibit A-30 (HLP-3) is based on the information in my original Exhibit A-4 (HLP-1); 4

however, it contains two adjustments to account for the recovery of insurance proceeds 5

which were credited to customers in 2016. 6

Q. Please describe the first adjustment. 7

A. Line 20 of Exhibit A-30 (HLP-3) shows the total amount of the insurance proceeds 8

received by the Company in that month. As described above, included in line 18 was a 9

credit of this same dollar amount. This adjustment is included to increase purchase 10

power costs and remove the total amount of insurance proceeds received by the Company 11

in 2016 from the Power Supply Cost Recovery (“PSCR”) Reconciliation. 12

Q. Please describe the second adjustment. 13

A. The total prior year underrecovery shown on line 27 of Exhibit A-4 (HLP-1), has been 14

adjusted on line 27 of Exhibit A-30 (HLP-3), to the total amount noted in the 15

Commission’s February 5, 2018 Order in Case No. U-17678-R. 16

Q. Please summarize the impact of these revisions. 17

A. As shown on line 28 column (n) of Exhibit A-30 (HLP-3), the 2016 PSCR Reconciliation 18

results in a total net overrecovery of $10,295,126. Including statutory interest, as set 19

forth on Exhibit A-31 (HLP-4), the total net overrrecovery for 2016 is $13,438,971. 20

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ste0318-hlp 4

Q. Please describe Exhibit A-31 (HLP-4). 1

A. Exhibit A-31 (HLP-4) provides the PSCR interest calculation for 2016 based on the 2

adjustments presented in Exhibit A-30 (HLP-3). 3

Q. Does this conclude your supplemental testimony? 4

A. Yes. 5

92




DIRECT TESTIMONY

OF

JENNY L. RICKARD

ON BEHALF OF


March 2017

93

JENNY L. RICKARD DIRECT TESTIMONY

te0317-jlr 1


A. My name is Jenny L. Rickard, and my business address is 1945 West Parnall Road, 2




“Company”) as a Senior Business Support Consultant in the Electric Transactions and 6

Wholesale Settlements Section of the Energy Supply Operations Department. 7

Q. Please describe your educational background and work experience. 8

A. I received a Bachelor of Science Degree in Accounting from Indiana University in 1987. 9

In 2009, I earned a Master of Business Administration from Spring Arbor University. I 10

was hired by Consumers Energy in August 2013 as a Technical Analyst supporting the 11

Non-Utility Generation Contract Settlements Group. This support consisted of 12

programming settlement templates for virtually all of the Company’s Power Purchase 13

Agreements (“PPAs”). In May 2014, I was promoted to supervise the Contract 14

Settlements Group. 15

Prior to my employment at Consumers Energy, I worked for 30 years in various 16

accounting positions. The majority of my experience is in the legal, real estate, and 17

publishing industries. The position I most recently held before I began work at 18

Consumers Energy was Controller at The Daily Telegram, an Adrian, Michigan based 19

daily newspaper and a subsidiary of Gatehouse Media, Inc. 20

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Q. What are your responsibilities as Contract Settlements Supervisor? 1

A. The Contract Settlements Group settles approximately 70 contracts each month and 2

recommends payment of approximately $950,000,000 per year for the purchase of over 3

13,000 gigawatt hours of electricity. 4

Q. Have you previously provided testimony before the Michigan Public Service 5


A. Yes, I provided direct testimony in MPSC Case No. U-17678-R, Consumers Energy’s 7

2015 Power Supply Cost Recovery Reconciliation Case, regarding settlements with the 8

Biomass Merchant Plants (“BMPs”)1 and billing adjustments. 9


A. The purpose of my testimony is to address settlements with certain suppliers, referred to 11

as BMPs, in accordance with the MPSC’s Order in Case No. U-16048 pursuant to MCL 12

460.6a(7), (8), and (9). 13


A. No. 15

BMPs 16

Q. Please describe the Company’s transactions with the BMP’s. 17

A. Consumers Energy has PPAs with seven wood waste fueled electric generation facilities, 18

which are generally referred to as the “BMPs.” In 2016, the BMPs performed in 19

accordance with their respective PPAs and were paid in accordance with their respective 20

PPAs. The amount of energy delivered and payments booked are shown on Exhibit A-8 21

(DFR-3), being sponsored by Company witness David F. Ronk, Jr. Additionally, the 22 1 The BMPs include: Cadillac Renewable Energy, LLC; Genesee Power Station, Limited Partnership; Grayling Generating Station, Limited Partnership; Hillman Power Company, LLC; T.E.S. Filer City Station, Limited Partnership; Viking Energy of Lincoln, LLC; and Viking Energy of McBain, LLC.

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BMPs invoiced Consumers Energy for recovery of certain operating costs under MCL 1

460.6a(7), (8), and (9), in accordance with the Commission’s August 11, 2009 Order in 2

MPSC Case No. U-16048, in excess of the variable energy payments they receive under 3

their PPAs with the Company. 4

Q. What amount was booked by the Company for the certain operating costs invoiced that 5

are in excess of the amount provided by the PPAs? 6

A. Exhibit A-8 (DFR-3), line 50, includes the booked expense for the time period November 7

2015 through October 2016 in accordance with the procedure approved by the 8

Commission in MPSC Case No. U-16048. Based on invoices received, the Company 9

believes that the BMPs are allowed to recover approximately $12 million for expenses 10

incurred in 2016, subject to the adjustment due to the limitation in monthly recoverable 11

expense. 12

This amount consists of monthly expenses of not more than $1 million resulting 13

in annual recoverable expense of $12 million, increased by $45,851 for recoverable 14

expense incurred in 2016, as a correction to 2015 adjustment amounts related to the June 15

2015 corrections the Company made to its MPSC Form P-521 for years 2008 through 16

2014. These corrections were discussed in my direct testimony in MPSC Case No. 17

U-17678-R. 18

To the extent that the amount recorded on the Company’s books for payments to 19

the BMPs is different than the amount invoiced or expected to be invoiced by the BMPs, 20

in accordance with the procedure approved by the Commission in MPSC Case No. 21

U-16048, that difference is also included in the values presented in Exhibit A-8 (DFR-3). 22

96


te0317-jlr 4


A. Yes. 2

97




DIRECT TESTIMONY

OF

DAVID F. RONK, JR.

ON BEHALF OF


March 2017

98

DAVID F. RONK DIRECT TESTIMONY

te0317-dfr 1


A. My name is David F. Ronk, Jr., and my business address is 1945 West Parnall Road, 2

Jackson, Michigan 49201 3



“Company”) as the Executive Director of Transactions and Wholesale Settlements in the 6


QUALIFICATIONS 8


A. I received the degree of Bachelor of Science in Engineering with a specialty in Civil 10

Engineering from the University of Michigan in 1975. Since 1980, I have been a 11

Registered Professional Engineer in the state of Michigan. I have practiced engineering 12

while employed by Consumers Energy since January 1976, with assignments associated 13

with: (1) the construction of Campbell Unit No. 3; (2) construction of a wood-fired 14

generating station proposed to be constructed in the early 1980s near Hersey, Michigan; 15

(3) construction of the Midland Nuclear Plant; (4) assistance to attorneys defending the 16

Company in litigation with the Dow Chemical Company; (5) development of what 17

ultimately became known as the Midland Cogeneration Venture Limited Partnership; 18

(6) design and procurement of utility motor vehicles; (7) operation of a fleet of rail cars 19

used to haul coal; and (8) development of the Company’s Acid Rain Program compliance 20

strategy and program. Since August 1997, I have been responsible for the development 21

of strategies to manage the Company’s exposure to financial risks associated with the 22

operation of its generating units and the purchase of capacity and energy from others to 23

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serve the demand for electricity from Consumers Energy customers. Between 2007 and 1

2012, I was also responsible for the Company’s resource planning activities. Beginning 2

in 2012, I was also responsible for the Company’s electric wholesale settlements 3

activities. 4

Q. Have you testified in other cases? 5

A. Yes. I presented testimony before the Michigan Public Service Commission (“MPSC” or 6

the “Commission”) in numerous proceedings since 1995. Some recent MPSC 7

proceedings in which I have testified are: 8

• Case No. U-17631 (direct and rebuttal), the Company’s 2013 Renewable Cost 9 Reconciliation Case, regarding renewable energy costs incurred in 2013; 10

• Case No. U-17678 (direct and rebuttal) regarding the Company’s 2015 Power 11 Supply Cost Recovery (“PSCR”) Plan, specifically addressing electric 12 capacity requirements and costs for 2015; 13

• Case No. U-17725 (direct and rebuttal) regarding the acquisition of long term 14 capacity contracts for Midcontinent Independent System Operator (“MISO”) 15 Planning years 2015 through 2020; 16

• Case No. U-17735 (direct and rebuttal) regarding the expenses associated with 17 power supply issues for the test year beginning June 1, 2015, including the 18 purchase of the Jackson Plant; 19

• Case No. U-17792 (direct) regarding the Company’s 2015 Application for 20 biennial review of the Renewable Energy Plan, regarding various changes to 21 the Renewable Energy Plan; 22

• Case No. U-17918 (direct and rebuttal) regarding the Company’s 2016 PSCR 23 Plan, specifically addressing electric capacity requirements and costs for 24 2016; 25

• Case No. U-17990 (direct and rebuttal) regarding the expenses associated with 26 power supply issues for the test year beginning September 1, 2016; 27

• Case No. U-18142 (corrected direct and second supplemental) regarding the 28 Company’s 2016 PSCR Plan, specifically addressing electric capacity 29 requirements and costs for 2016; 30

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• Case No. U-18194 (direct) regarding the acquisition of long term capacity 1 contracts for MISO Planning year 2017; and 2

• Case No. U-18250 (direct) regarding the acquisition of long term capacity 3 contracts for MISO Planning Year 2018, the capacity asset purchase 4 solicitation to be effective beginning in Planning Year 2019, the proposed 5 amendment of the T.E.S. Filer City Station Power Purchase Agreement 6 (“PPA”), and certain spent fuel disposal trust fund issues associated with the 7 Palisades PPA Termination Agreement. 8



A. My testimony will address: (1) Purchased Power Supply Costs incurred by the Company 11

in 2016; (2) Allocation of Costs to the Renewable Resource Fund (“RRF”); and 12

(3) Purchases and Sales with third parties in 2016; 13



Exhibit A-6 (DFR-1) Purchased, Interchanged, and Renewable Power 16 Transactions; 17

Exhibit A-7 (DFR-2) 2016 Interchange Delivered by Counterparties to 18 MISO; 19

Exhibit A-8 (DFR-3) Purchased Power and Cogeneration – Energy and 20 Expense; and 21

Exhibit A-9 (DFR-4) Purchased Power Contract Rates and MPSC 22 Approval Orders. 23

Q. Were these exhibits created by you or under your supervision? 24

A. Yes. 25

2016 Purchased, Interchange, and Renewable Power Transactions 26

Q. Please describe Exhibit A-6 (DFR-1). 27

A. Exhibit A-6 (DFR-1) provides a summary of the Company’s Purchased, Interchanged, 28

and Renewable Power Transactions booked for 2016. 29

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te0317-dfr 4

Q. Please describe line 1 of Exhibit A-6 (DFR-1). 1

A. Line 1 of Exhibit A-6 (DFR-1) “Purchased Power” provides volumes and costs for 2

capacity and energy that was purchased by Consumers Energy from cogenerators, small 3

power producers, and independent power producers who had agreements to sell capacity 4

and energy to Consumers Energy on a long-term basis. For purchases from the 5

Company’s Renewable Resource Program (“RRP”) suppliers, only the average PSCR 6

cost associated with those purchases is included in line 1, which is described in more 7

detail later in my testimony. 8


A. Line 2 of Exhibit A-6 (DFR-1) “Purchased Power – PA 295” provides volumes and costs 10

for capacity and energy that was purchased under PPAs that provided Renewable Energy 11

Credits in accordance with MCL 460.1033(i)(b) and from purchases under the 12

Company’s Experimental Advanced Renewable Pilot Program. Consumers Energy 13

witness Keith G. Troyer discusses renewable transfer costs associated with Public Act 14

295 of 2008 in more detail in his testimony. 15

Q. Please explain line 3, “Interchange Received – Non-MISO” and line 8, “Interchange 16

Delivered – Non-MISO,” of Exhibit A-6 (DFR-1). 17

A. The entry for “Interchange Received – Non-MISO,” shown on line 3 of Exhibit A-6 18

(DFR-1) provides the volumes and costs for the purchase of energy and capacity from a 19

counterparty other than purchases from the Company’s long-term contract suppliers 20

(shown on line 1). The entry “Interchange Delivered – Non-MISO,” shown on line 8 of 21

Exhibit A-6 (DFR-1), provides the volumes and revenues for sales of energy and capacity 22

to a counterparty, other than sales to the energy market operated by the MISO. With the 23

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exception of the capacity sale revenue discussed below, Company witness Raymond T. 1

Scaife discusses the energy expenses and revenues in more detail in his testimony. 2

Q. Can you describe the capacity sale revenues shown on line 8, column (g)? 3

A. Yes. In 2015 the Company purchased replacement capacity used in 2016 for Ludington 4

Unit No. 5 on behalf of both Consumers Energy and DTE Electric, the joint owners of the 5

Ludington Pumped Storage (“Ludingtion”) Plant, and these revenues are the result of 6

providing DTE Electric Company (“DTE Electric”) with its share of the purchased 7

replacement capacity. I will discuss these transactions later in my testimony. 8

Q. Please explain line 4, “Interchange Received – MISO” and line 9, “Interchange Delivered 9

– MISO” of Exhibit A-6 (DFR-1). 10

A. The entry for “Interchange Received – MISO,” shown on line 4 of Exhibit A-6 (DFR-1), 11

includes the purchase of energy from MISO in column (e) and the MISO capacity 12

purchases described later in my testimony in column (g). The entry for “Interchange 13

Delivered – MISO,” shown on line 9 of Exhibit A-6 (DFR-1) includes the sale of energy 14

to the MISO energy market in column (e) and the MISO capacity sales described later in 15

my testimony in column (g). The amount of Interchange Energy Received and Delivered 16

is a result of the operation of the MISO energy market and the Security Constrained 17

Economic Dispatch that is performed by MISO. Company witness Scaife discusses the 18

net of lines 4 and 9, column (h), as shown on line 16, column (h), of Exhibit A-6 (DFR-1) 19

in greater detail in his testimony. 20

Q. Please describe the transmission expenses included in Exhibit A-6 (DFR-1), line 5. 21

A. The transmission expenses included in Exhibit A-6 (DFR-1), line 5, are charges to 22

transmission customers based on the MISO tariff approved by the Federal Energy 23

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Regulatory Commission. Company witness Scaife provides more detail on this topic in 1

his testimony. 2


A. Line 6 of Exhibit A-6 (DFR-1), “Short-Term Capacity Purchases,” includes bilateral 4

purchases made to meet or maintain Consumers Energy’s reserve margin requirements 5

for the MISO 2015 Planning Year that ended on May 31, 2016 and for the MISO 2016 6

Planning Year that began on June 1, 2016. 7

Q. What is the total short-term bilateral capacity expense associated with the MISO 2015 8

and 2016 Planning Years for which recovery is sought in this proceeding? 9

A. That expense is described later in my testimony in connection with: (1) purchases from a 10

reverse capacity auction that the Company conducted in September 2014; and (2) the 11

purchase of capacity to replace Ludington Unit No. 5 due to a catastrophic outage of that 12

unit. 13

Q. Please describe line 10, “Interchange Delivered by Counter-parties – MISO,” of Exhibit 14

A-6 (DFR-1). 15

A. Line 10 of Exhibit A-6 (DFR-1), includes energy sales to MISO executed on behalf of the 16

Company by the Company’s Renewable Energy Counter-Parties for 2016 and is 17

discussed in detail below. 18

Q. Please describe line 11, “Schedule 2 Reactive,” of Exhibit A-6 (DFR-1). 19

A. Line 11 of Exhibit A-6 (DFR-1), includes the revenue received pursuant to MISO’s 20

Schedule 2 for reactive service which the Company provides as a service necessary for 21

the transmission of power. 22

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Q. Please describe line 13, “PA 295 New Build Renewables,” of Exhibit A-6 (DFR-1). 1

A. Line 13 of Exhibit A-6 (DFR-1), includes the transfer costs calculated in accordance with 2

MCL 460.1047(2)(b)(iv) associated with provider-owned renewable energy systems as 3

provided by MCL 460.1033(1)(a). Consumers Energy witness Troyer discusses this item 4

in more detail in his testimony. 5

2016 Interchange Delivered by Counterparties to MISO 6


A. Exhibit A-7 (DFR-2) details the production delivered to the MISO energy market and 8

revenue received from each of the Company’s Renewable Energy contract generators for 9

2016. The Renewable Energy purchase agreements applicable to these generators are 10

designed to limit the Company’s exposure to market participation risks, while providing 11

the economic benefits to the Company’s customers. The contracts require the generator 12

owners to be the Market Participant for their generators. The generator owner sells the 13

energy produced into the MISO energy market on behalf of the Company. The Company 14

receives the revenue for these sales at the Day Ahead locational marginal prices. Exhibit 15

A-7 (DFR-2) details the revenue received from these suppliers. The totals from lines 8 16

and 16, of Exhibit A-7 (DFR-2), are reported on line 10 of Exhibit A-6 (DFR-1). 17

Allocation of Costs to the RRF 18

Q. Please explain the RRP. 19

A. In Case No. U-13843, the Commission directed the Company to develop a RRP in which 20

the Company purchases renewable energy from various suppliers and recovers the cost of 21

such purchases through several funding mechanisms, including the PSCR, voluntary 22

contributions from customers, and an RRF. 23

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Q. How will the purchase of renewable energy for this program be treated for purposes of 1

the PSCR reconciliation? 2

A. In Case No. U-13843, the Commission authorized Consumers Energy to implement a 3

renewable resource funding mechanism to recover Green Power Program costs. The 4

Commission established a RRF to be used exclusively for compensating Consumers 5

Energy for costs associated with offering the program as follows: 6

“The fund will be used to compensate Consumers Energy for costs 7 that are not recovered from customers who voluntarily choose the 8 Green Power Program or are not recovered through the PSCR 9 process. Renewable energy contracts entered into by Consumers 10 Energy will be included in its PSCR factor at the average PSCR 11 cost so that inclusion of these contracts will have no effect on the 12 PSCR factor. The difference between the contract price and the 13 average PSCR cost will be recovered through the fund, except for 14 those costs that are being recovered from customers who 15 voluntarily choose the Green Power Program. Consumers Energy 16 should enter into renewable contracts commensurate with the 17 anticipated amount of the fund.” May 18, 2004 Order in Case No. 18 U-13843, at 20-21. 19

The energy purchased for the RRP is recognized as part of the total mix of energy 20

supplied by Consumers Energy to its customers. However, the purchase cost of the 21

renewable energy in excess of the average PSCR costs will not have any impact on the 22

PSCR because the cost of the energy purchased for the RRP is included in this 23

reconciliation at the average PSCR cost. 24

Q. How have the Company’s RRF credits been reflected in the calculation of the Company’s 25

Purchased and Interchange (“P&I”) Power Expense? 26

A. The cost of energy delivered by suppliers under this program consists of two 27

components: (1) the average PSCR cost, which is booked as P&I Power Expense; and 28

(2) the cost in excess of average PSCR costs, which are paid from the RRF and are not 29

booked as P&I Power Expense. 30

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Q. Did any new generating facilities associated with the RRP’s PPAs commence operations 1

in 2016? 2

A. No. 3

Q. How many facilities are currently operating to supply energy for the RRP? 4

A. The Company has six Green Generation Program supply facilities in operation with total 5

contracted annual output of approximately 241,600 MWh in 2016. These facilities are 6

identified on Exhibit A-9 (DFR-4) page 3 of 5. 7

Q. How much energy was delivered from operating the RRP facilities during 2016? 8

A. There were 210,805 MWh of energy purchases received by Consumers Energy under the 9

RRP agreements during 2016. Expense for the RRP deliveries during the year totaled 10

$16,152,640. 11

Q. How is the cost of energy purchased under these agreements handled so that the PSCR is 12

not impacted, as directed by the Commission? 13

A. The RRP PPAs are structured such that payment occurs in two parts: (1) an energy 14

purchase expense; and (2) a renewable purchase expense. The renewable purchase 15

expense of $5,215,265 is offset by the RRF and is not a PSCR expense. The energy 16

purchase expense of $10,937,375 is based on the estimated average PSCR cost of energy. 17

The PSCR will not be impacted by the energy purchase expenses under these agreements 18

since these expenses are equal to the average PSCR expense that would have been 19

incurred absent these expenses. 20

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Q. You stated that the energy purchase expense is based on the estimated average PSCR cost 1

of energy. How is Consumers Energy proposing to handle the difference between the 2

actual average PSCR cost of energy and the estimated average PSCR cost of energy? 3

A. Since the actual average PSCR cost of energy for 2016 is being determined by this 4

proceeding, Consumers Energy cannot reconcile the difference between estimated and 5

actual until the Commission issues an order in this case and the actual cost has been 6

established. Any reconciled amount will be booked in the year that the Commission’s 7

order is issued and reconciliation occurs. 8

Purchases and Sales With Third Parties in 2016 9


A. Exhibit A-8 (DFR-3) summarizes the capacity and energy charges recoverable as PSCR 11

costs in accordance with prior Commission orders paid to each Purchased Power and 12

Cogeneration entity in 2016. Additionally, Exhibit A-8 (DFR-3), line 50, includes the 13

booked expense associated with payments invoiced or expected to be invoiced by the 14

Biomass Merchant Plants for certain expenses as explained by Consumers Energy 15

witness Jenny L. Rickard’s testimony. 16

Line 20 of Exhibit A-8 (DFR-3), shows a credit for administrative charges for the 17

Scenic View Dairy (Fennville) facility which is not included in the renewable transfer 18

costs because this revenue is credited to PSCR. 19

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Q. How much replacement capacity and energy did the Company receive under its PPA with 1

Entergy Nuclear Power Marketing (“ENPM”)? 2

A. In 2016, the Company received a total of 6,926,933 MWh under its PPA with ENPM, all 3

of which was generated by the Palisades Nuclear Plant. There was no replacement 4

capacity and energy provided under the PPA in 2016. 5

Q. Have you prepared a summary of the purchased power contract rates and the MPSC 6

approval orders for facilities that were in operation during 2016? 7

A. Yes. Exhibit A-9 (DFR-4) summarizes the capability, energy, and capacity rates for each 8

of the Company’s purchased power contracts along with the MPSC orders which 9

approved the capacity rates for each facility. 10

Q. During 2016, were there any capacity charges paid to third parties under transactions with 11

terms exceeding six months in duration that have not been previously approved by the 12

Commission? 13

A. Yes. These transactions include: purchases of Zonal Resource Credits (“ZRCs”) in 14

MISO’s annual Planning Resource Auctions (“PRAs”). 15

Q. Has Consumers Energy entered into any other contracts which have not yet been 16

approved by the Commission? 17

A. No. 18

Purchases and Sales of ZRCs in MISO’s Annual PRAs 19

Q. Please describe the purchases and sales of ZRCs made by the Company in MISO’s annual 20

PRAs. 21

A. The 2016 expense associated with the purchase of ZRCs from the Planning Year 2015 22

PRA was offset by the revenue associated with the sale of an identical amount of ZRCs 23

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from the Company’s generators and capacity resources to which the Company had 1

acquired the rights to use in the PRA. The 2016 expense associated with the purchase of 2

approximately 7900 ZRCs from the Planning Year 2016 PRA was completely offset by 3

the sale of approximately 7930 ZRCs. Additionally the revenue received from the sale of 4

the ZRCs in the 2016 PRA was greater on a per unit basis than the charge for the 5

comparable purchase due to the payment of a Zonal Deliverability Benefit to all load in 6

certain MISO zones including MISO Zone 7, the zone in which the Company receives 7

transmission service. Thus while there were no actual purchase expenses from MISO’s 8

annual PRA incurred in 2016, had there been any they would have been booked as part of 9

the $1,113 as shown on line 4, column (g), of Exhibit A-6 (DFR-1). 10

The approximate 2016 revenue from the sale of 146.5 ZRCs from the Planning 11

Year 2015 PRA during 2016, and the sale revenue associated with the Zonal 12

Deliverability Benefit and net sale of ZRCs in the 2016 PRA, was approximately 13

$2.2 million. The revenue from these sales was included in the $2,418,428 as shown on 14

line 9, column (g), of Exhibit A-6 (DFR-1). 15

Q. Can you explain the difference between the expenses and revenues from the PRAs and 16

the actual expenses and revenues booked? 17

A. In addition to the transactions that occur in the PRA, additional capacity transactions 18

occur through out the year. For instance on April 1, 2016, MISO recognized the addition 19

of the ZRCs associated with the purchase of the Jackson Plant. At that point 20

approximately 525 additional ZRCs were credited to the Company’s accounts and over 21

the next 61 days those ZRCs earned the Auction Clearing Price adding approximately 22

$111,400 in revenue to the Interchange Delivered that appears in line 9, column (g), of 23

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Exhibit A-6 (DFR-1). Similarly, in retail load switching states such as Michigan capacity 1

transactions occur thorough out the year as customers switch from one Load Serving 2

Entity to another. In 2016, customer switching resulted in the Company’s capacity being 3

used by other suppliers resulting in settlements by MISO of approximately $100,000. 4

Reverse Capacity Auction 5

Q. Did Consumers Energy incur any expense in 2016 for ZRCs purchased to meet its PRMR 6

for Planning Year 2015 or 2016? 7

A. Yes. The Company purchased 350 ZRCs for use in Planning Year 2015 through a 8

reverse capacity auction that was conducted on September 23, 2014. The Company also 9

purchased 150 ZRCs for use in Planning Year 2016 in that same reverse capacity auction. 10

Q. Did the Company receive approval from the Commission for these purchases? 11

A. Yes, the Commission approved the purchases made in that auction in its January 27, 2015 12

Order in Case No. U-17725. 13

Q. How much expense did the Company incur for the purchase of these ZRCs during 2016? 14

A. The Company booked $8,804,106 for the purchase of these ZRCs during 2016, which is 15

included in the $10,211,771 of short-term capacity purchase expense shown on line 6, 16

column (g), of Exhibit A-6 (DFR-1). 17

Demand Response Pilot Program Expense 18

Q. Did the Company incur any expense in 2016 for capacity associated with its Demand 19

Response Program? 20

A. Yes. The Company booked $106,703 in payments (or revenue credits) paid to customers 21

for their participation in the Company’s Demand Response Pilot Program in Planning 22

Year 2015. The amounts booked are included as part of the $10,211,711 of short-term 23

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te0317-dfr 14

capacity purchase expense shown on Line 6, column (g), of Exhibit A-6 (DFR-1). No 1

payments were booked in calendar year 2016 for participation in the pilot program in 2

Planning Year 2016. 3

Procurement of ZRCs to Replace Ludington Unit No. 5 4

Q. Please describe the procurement of ZRCs to replace the capacity of Ludington Unit 5

No. 5. 6

A. In Case No. U-17678-R, Company witness Mark T. Devereaux provided testimony 7

regarding the Compnay’s purchase of ZRCs to replace the capacity of Ludington Unit 8

No. 5 for the balance of Planning Year 2015. In that testimony, Mr. Devereaux describes 9

the cause of the outage that led to the need for the ZRCs, the alternatives considered by 10

the Company, and the measures taken by the Company to purchase the required amount 11

of capacity. Mr. Devereaux reported that of the cost incurred to purchase the replacement 12

ZRCs for the 2015 Planning Year, $1,103,732 was allocated to 2015 calendar year 13

expense and of that amount $603,762 was allocated to DTE Electric. The 2016 calendar 14

year portion of these costs was $1,262,732 and that amount is included in the 15

$10,211,771 of short-term capacity purchase expense shown on line 6, column (g), of 16

Exhibit A-6 (DFR-1). The Company sold DTE Electric its share of the replacement 17

ZRCs at the applicable purchase prices for a total cost of $690,737 for calendar year 18

2016. Such revenue amount is shown on line 8, column (g), of Exhibit A-6 (DFR-1). 19

Conclusion 20

Q. Please summarize your testimony. 21

A. In this testimony, I have presented the basis for recovery of $1,517,972,321 in net P&I 22

and Renewable power supply expense for 2016. My testimony has identified the parties 23

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with whom the Company has long-term supply contracts, the amount of power received 1

from each party, and the amount paid to each party. For those contracts for which 2

Commission approval is required, I have identified the case in which approval was 3

received. I have accounted for the treatment of expense associated with the RRP as 4

approved by the Commission in Case No. U-13843, resulting in the as-booked supply of 5

210,805 MWh of certified renewable energy at no incremental cost to customers, except 6

the contributions customers elected to provide on a voluntary basis. 7

Q. Do you believe that all of the expenses and revenues summarized on Exhibit A-6 8

(DFR-1) were prudently incurred? 9

A. Yes. 10


A. Yes, it does. 12

113




DIRECT TESTIMONY

OF

RAYMOND T. SCAIFE

ON BEHALF OF


March 2017

114

RAYMOND T. SCAIFE DIRECT TESTIMONY

te0317-rts 1


A. My name is Raymond T. Scaife, and my business address is 1945 West Parnall Road, 2




“Company”) as Midcontinent Independent System Operator, Inc. (“MISO”) Settlements 6

Manager of the Electric Transactions & Wholesale Settlements section of the Energy 7

Supply Operations Department. 8

Qualifications 9


A. I received the degree of Bachelor of Business Administration with a Marketing emphasis 11

from Adrian College in 2001. I began my employment with Consumers Energy in 12

December of 2001 in the Real-Time Market Operations. I worked in the Operations 13

Department as Generation Dispatcher and Energy Scheduler from 2001 through 2005. In 14

2005, I participated in the MISO Market as a MISO Market Energy Coordinator. In 15

2007, I became a Technical Analyst with responsibility to provide analysis regarding 16

MISO Settlements to the Operations Superintendent. I then coordinated the Company’s 17

Real-Time Operations entry into the MISO Ancillary Services Market in January of 18

2009. In the fall of 2009, I was hired as the MISO Settlements Manager reporting to the 19

Director of Wholesale Settlements and Support, which is the position I currently hold. 20

As the MISO Settlements Manager, I am responsible for managing the settlement 21

activities related to the MISO Energy and Ancillary Services Market, the MISO 22

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Transmission Market, and the team of analysts employed to support the Company’s 1

MISO Settlement process. 2



A. Yes. I provided testimony in MPSC Case Nos. U-17095-R, U-17317-R, and U-17678-R. 5


A. My testimony will address the settlement of market transactions and transmission 7

expenses incurred with MISO. 8


A. Yes. I am sponsoring the following exhibit: 10

Exhibit A-10 (RTS-1) 2016 – Summary of MISO Market and Tariff 11 Administration Charges/(Credits) Settlement. 12

Q. Was this exhibit prepared by you or under your direction or supervision? 13

A. Yes. 14

Midwest Energy Markets 15

Q. Please describe Exhibit A-10 (RTS-1) titled “2016 – Summary of MISO Market and 16

Tariff Administration Charges/(Credits) Settlement.” 17

A. Exhibit A-10 (RTS-1) provides a summary of MISO Market Charges and Credits that 18

were assessed to the Company from January 1, 2016 through December 31, 2016, along 19

with an accounting Accrual and Adjustments total, System Support Resource Revenue 20

Reclassification, and MISO Market Charges Characterized as Transmission Charges. 21

Q. What is the source of the data from which Exhibit A-10 (RTS-1) is derived? 22

A. The Company has summarized this data from the daily settlement statements that MISO 23

sends the Company for each operating day. 24

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Q. What does the Total Settlement of MISO Energy and Ancillary Services Market 1

represent? 2

A. The Total Settlement of MISO Energy and Ancillary Services Market charges for 2016 3

was $114,438,752 as shown on line 7 of Exhibit A-10 (RTS-1). The Total Settlement of 4

MISO Energy and Ancillary Services Market charges represents the expenses incurred 5

and credits received by the Company associated with procuring or providing energy and 6

ancillary services from or to the MISO Energy Market. It also includes the cost of 7

congestion and transmission losses in moving energy from the Company’s resources to 8

the Company’s distribution system across the transmission system. The Adjusted Total 9

Settlement of MISO Energy and Ancillary Services Market amount of $111,273,031 as 10

shown on line 10 of Exhibit A-10 (RTS-1) and line 16 of Exhibit A-6 (DFR-1), labeled as 11

Net MISO Interchange, is the result of the Company offering its generation into the 12

Market and obtaining energy from the Market to meet its load obligations. 13

MISO Transmission Expense 14

Q. Please describe the MISO transmission settlement. 15

A. The MISO transmission settlements process settles transmission customer’s charges and 16

credits based on use of MISO’s transmission system and mandated, non-competitive 17

Ancillary Services on a monthly calendar basis. The transmission expenses include: 18

Network Integrated Transmission Service expense; costs of other transmission-related 19

purchases; including various MISO transmission-related Schedules (i.e., Schedule 1, 2, 20

10, 10-FERC-METC, and 26); MISO administrative fees; and the Network upgrade 21

charges from MISO’s Transmission Expansion Plan. Charges to transmission customers 22

are calculated based on the MISO tariff approved by the Federal Energy Regulatory 23

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Commission. In 2016, the Company expensed $376,544,039 for Transmission service as 1

shown on line 5 of Exhibit A-6 (DFR-1). In 2016, the Company received $12,085,272 2

for Schedule 2 Reactive service supplied to MISO. 3

Non-MISO Interchange 4

Q. Please describe Non-MISO Interchange Received and Delivered Net Energy $. 5

A. Non-MISO Interchange Received Net Energy $ are the product of bilateral transactions 6

outside of the MISO market where the Company pays a counterparty for energy received, 7

these can be found on line 3 of Exhibit A-6 (DFR-1). The primary cause of these 8

transactions is Ludington Water exchanges between Detroit Edison Company and the 9

Company. The Non-MISO Interchange Delivered Net Energy $ are bilateral transactions 10

outside of the MISO Market where the Company is paid, as seen on line 8 of Exhibit A-6 11

(DFR-1). 12


A. Yes it does. 14

118




DIRECT TESTIMONY

OF

MICHAEL B. SHI

ON BEHALF OF


March 2017

119

MICHAEL B. SHI DIRECT TESTIMONY

te0317-mbs 1


A. My name is Michael B. Shi, and my business address is 1945 West Parnall Road, 2




“Company”) as a Senior Engineer in Resource Planning. 6

Q. Please describe your educational background and business experience. 7

A. I received a Bachelor of Science degree in Industrial Engineering in 2009 and a Master of 8

Science degree in Industrial and Manufacturing Systems Engineering in 2014 from the 9

University of Michigan. I have been employed by Consumers Energy as a Senior 10

Engineer in Resource Planning since April of 2016. In this position, I am responsible for 11

managing the Company’s congestion risk through participation in the Auction Revenue 12

Right (“ARR”) and Financial Transmission Right (“FTR”) processes established by 13

Midcontinent Independent System Operator, Inc. (“MISO”), development of transmission 14

production cost models, and short-term forecasting software. 15


A. The purpose of my testimony is to describe the expenses associated with the Company’s 17

participation in MISO’s FTR and ARR markets. 18


A. Yes, I am sponsoring the following exhibit: 20

Exhibit A-18 (MBS-1) 2016 Expense and Revenue resulting from 21 Congestion, FTR and ARR Transactions. 22

Q. Was this exhibit prepared by you or under your direction or supervision? 23

A. Yes. 24

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Q. Did the Company participate in the MISO FTR and ARR Market in 2016? 1

A. Yes. 2

Q. Are you familiar with the Commission’s August 22, 2006 Order in MPSC Case No. 3

U-14701 regarding FTRs? 4

A. Yes. In that order, the Commission concurred with the Company’s position that the costs 5

and revenues associated with FTRs are to be included in the Company’s Power Supply 6

Cost Recovery (“PSCR”) Plan and reconciliation proceedings at their ultimate settled 7

value. The Commission declined to authorize interim adjustments to the fair value of 8

FTRs as regulatory assets and liabilities for purposes of regulatory reporting to the 9

Commission. 10

Q. Has the Company included its FTR and ARR costs and revenues in this case consistent 11

with the Commission’s Order in MPSC Case No. U-14701? 12

A. Yes. FTR and ARR costs and revenues included in this reconciliation case are based on 13

the ultimate settled value of the FTRs. My testimony reports on the expenses and 14

revenues for all FTRs and ARRs that were settled for each month of 2016; however, the 15

amount requested for recovery includes only those FTRs for which the settlement was 16

booked in 2016. 17

Q. In the 2016 PSCR Plan case, MPSC Case No. U-17918, what was the expense associated 18

with the Company’s participation in the FTR and ARR market? 19

A. The FTR and ARR expense projected for that case was $467,662 as sponsored by 20

Company witness Daniel S. Alfred. See MPSC Case No. U-17918, Exhibit A-1 (DSA-1), 21

page 1, line 21, Schedule 16, Expense. 22

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Q. What was the actual expense the Company incurred as a result of the Company’s 1

participation in the FTR and ARR market in 2016? 2

A. The Company incurred an actual FTR and ARR expense net of congestion charges 3

of -$2,815,136, or net revenue of $2,815,136, as shown in Exhibit A-18 (MBS-1), line 7, 4

column (m). 5

Q. Was any of the expense shown on line 7, column (m) of Exhibit A-18 (MBS-1), incurred 6

in a prior year? 7

A. Yes, for instance, the Company purchased FTRs for January 2016 in the monthly auction 8

that occurred in November 2015. The costs of those purchases were not recovered as part 9

of the 2015 power supply costs but were instead deferred for recovery in the year for 10

which the FTR applied; in this case 2016. 11

Q. Was any of the expense shown on line 7, column (m) of Exhibit A-18 (MBS-1), incurred 12

for FTRs that were applicable in a future year? 13

A. No. 14

Q. Do you believe the Company was prudent in its participation in the FTR and ARR 15

Market in 2016? 16

A. Yes. 17


A. Yes. 19

122




DIRECT TESTIMONY

OF

KEITH G. TROYER

ON BEHALF OF


March 2017

123

KEITH G. TROYER DIRECT TESTIMONY

te0317-kgt 1


A. My name is Keith G. Troyer, and my business address is 1945 West Parnall Road, 2




“Company”). 6

Q. In what capacity are you employed? 7

A. I am a Senior Engineer in the Transactions and Wholesale Settlements Section of the 8


Qualifications 10

Q. Please describe your educational background and business experience. 11

A. I received the degree of Bachelor of Science in Engineering with a specialty in Civil 12

Engineering from Michigan State University in 2008. In 2015, I became a Registered 13

Professional Engineer in the State of Michigan. I am currently pursuing a Master of 14

Business Administration (“MBA”) through Michigan State University’s Executive MBA 15

Program and expect to graduate in March 2018. 16

I joined Consumers Energy in July 2009 as an Electric System Owner at the 17

Battle Creek Service Center. In January 2011, I accepted a position as an Engineer in the 18

Transactions and Resource Planning Section of the Energy Supply Operations 19

Department. In that role, I was responsible for administration and coordination of the 20

Company’s Experimental Advanced Renewable Program (“EARP”), part of the 21

Company’s Renewable Energy (“RE”) Plan. I was involved in the development and 22

implementation of the EARP-Solar expansion in 2011. In June 2013, I began taking on 23

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additional responsibilities associated with the RE Plan, including the calculation of the 1

transfer price associated with RE and capacity and the tracking of RE credits. In 2014, I 2

was also responsible for supervision of the implementation of the EARP-Anaerobic 3

Digestion pilot. In December 2016, I transitioned to a new role where my supervisory 4

and direct responsibilities include administering Power Purchase Agreements (“PPAs”), 5

issuing solicitations for energy and capacity, and managing the Company’s capacity 6

position with the Midcontinent Independent System Operator, Inc. (“MISO”). 7



A. Yes. I provided testimony in: 10

• MPSC Case No. U-17095-R (direct), the Company’s 2013 Power Supply Cost 11 Recovery (“PSCR”) Reconciliation case, regarding 2013 RE Plan expenses 12 recovered through PSCR; 13

• MPSC Case No. U-17631 (direct), the Company’s 2013 Renewable 14 Reconciliation case, regarding 2013 RE Plan expenses recovered through 15 PSCR, RE compliance, and new renewable capacity compliance; 16

• MPSC Case No. U-17317-R (direct), the Company’s 2014 PSCR 17 Reconciliation case, regarding 2014 RE Plan expenses recovered through 18 PSCR; 19

• MPSC Case No. U-17792 (direct and rebuttal), the 2015 biennial review of 20 the Company’s RE Plan, regarding RE Plan expenses recovered through the 21 PSCR, RE compliance, new renewable capacity compliance, and RE 22 programs; 23

• MPSC Case No. U-17803 (direct), the Company’s 2014 Renewable 24 Reconciliation case, regarding 2014 RE Plan expenses recovered through 25 PSCR, RE compliance, and new renewable capacity compliance; 26

• MPSC Case No. U-17678-R (direct and supplemental), the Company’s 2015 27 PSCR Reconciliation Case, regarding 2015 RE Plan expenses recovered 28 through PSCR; 29

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• MPSC Case No. U-17918 (rebuttal), the Company’s 2016 PSCR Plan and 1 five-year forecast, regarding the impacts of net electric metering on energy 2 supply; 3

• MPSC Case No. U-18081 (direct and revised), the Company’s 2015 4 Renewable Reconciliation case, regarding 2015 RE Plan expenses recovered 5 through PSCR, RE compliance, and new renewable capacity compliance; and 6

• MPSC Case No. U-18090 (direct and rebuttal), the Company’s 2016 Public 7 Utilities Regulatory Policy Act case to establish a method and calculation for 8 avoided costs, regarding the Company’s calculation utilizing Transfer Price. 9


A. My testimony will address the RE Transfer Price (“Transfer Price”) included in PSCR 11

expenses. 12


A. Yes. I am sponsoring the following exhibit: 14

Exhibit A-19 (KGT-1) PA 295 Purchased Power and New Build 15 Renewables Total 2016. 16

Q. Was this exhibit created by you or under your direction or supervision? 17

A. Yes. 18

RE Transfer Price 19

Q. What is the Transfer Price? 20

A. The Transfer Price is the price at which the cost of RE is recovered through the 21

Company’s PSCR clause pursuant to MCL 460.1047 and MCL 460.1049 of 2008 Public 22

Act (“Public Act”) 295 (“PA 295”) and as established by the Commission. 23

Q. What is the estimated Transfer Price for 2016? 24

A. The estimated Transfer Price for 2016 is approximately $79.43 per MWh. 25

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te0317-kgt 4

Q. What is the RE Transfer Cost (“Transfer Cost”)? 1

A. The Transfer Cost is the total cost that the Company will transfer to power supply costs, 2

in accordance with MCL 460.1047(2)(b)(iv), associated with renewable generation 3

obtained in accordance with MCL 460.1033. 4

Q. How much renewable generation, for which the Transfer Price applies, was produced in 5

2016? 6

A. A total of approximately 1,500,231 MWhs of Transfer Price-applicable renewable 7

generation was booked in 2016, as shown on Exhibit A-19 (KGT-1) line 23, column (b). 8

Q. Please describe Exhibit A-19 (KGT-1). 9

A. Exhibit A-19 (KGT-1) is the calculation of the total amount of Transfer Price-applicable 10

RE expenses to be recovered through the PSCR mechanism from renewable generation 11

delivered in 2016. Column (a) of Exhibit A-19 (KGT-1) lists all counterparties and 12

Company-owned facilities from which the Company received RE or RE capacity in 2016 13

for which costs were expensed in 2016. Column (b) details the amount of Transfer 14

Price-applicable generation expensed in 2016. Column (c) shows the total Transfer Cost 15

associated with energy production for 2016. Column (d) shows the total Transfer Cost 16

associated with capacity value that is used in determining the total Transfer Cost. 17

Column (e) shows the total Transfer Cost expensed in 2016 for each generator by 18

summing columns (c) and (d). Column (f) represents the energy portion of the Transfer 19

Price for each generator by dividing column (c) by column (b). Column (g) is the total 20

Transfer Price for each unit calculated by dividing the total Transfer Cost in column (e) 21

by the Transfer Price-applicable generation in column (b). 22

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te0317-kgt 5

Q. Two of the counterparties show a negative total PSCR expense in column (e) of Exhibit 1

A-19 (KGT-1). Please explain the reason for these negative values. 2

A. Exhibit A-19 (KGT-1) shows the generation, energy expense, and capacity expense 3

booked in 2016 for facilities that are part of the Company’s RE Plan. The contracts in 4

place with Scenic View Dairy Fennville and Scenic View Dairy Freeport terminated at 5

the end of 2015. New contracts have been entered into with Scenic View Dairy Fennville 6

and Scenic View Dairy Freeport, as part of the Company’s RE Plan, for generation 7

occurring since January 1, 2016 and are shown as Scenic View Dairy-AD and Brook 8

View Dairy-AD, respectively. The amounts shown on lines 12 and 13 of Exhibit A-19 9

(KGT-1), are the booked generation and PSCR expense in 2016 resulting from 10

adjustments to prior periods associated with the contracts in place prior to 2016. The 11

negative total PSCR expense for these facilities shown in column (e) of Exhibit 19 12

(KGT-1) results in a reduction to PSCR expense for 2016. 13

Q. How are the total transfer costs associated with PA 295 PPAs and Company-owned New 14

Build Renewables as shown on Exhibit A-19 (KGT-1) reflected in this PSCR 15

Reconciliation? 16

A. The Transfer Price-applicable generation, total Transfer Cost, and calculated Transfer 17

Price for all of the PA 295 PPAs and the subscribed portion of the Solar Gardens 18

Program is shown on line 18 of Exhibit A-19 (KGT-1). These values are included on line 19

2 in Exhibit A-6 (DFR-1) as PA 295 Purchased Power. The Transfer Price-applicable 20

generation, total Transfer Cost, and calculated Transfer Price of the Company-owned 21

New Build Renewables and the unsubscribed portion of the Solar Gardens Program is 22

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te0317-kgt 6

shown on line 22 of Exhibit A-19 (KGT-1). These values are included on line 13 of 1

Exhibit A-6 (DFR-1). 2

Q. Based on these calculations, what is the Transfer Price? 3

A. As discussed above, the Company calculates the Transfer Price for 2016 to be $79.43 per 4

MWh and is shown on line 23, column (g) of Exhibit A-19 (KGT-1). The Company 5

calculates the total Transfer Cost to be $119,167,367, as shown on line 23, column (e) of 6

Exhibit A-19 (KGT-1). 7


A. Yes, it does. 9

129

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1 JUDGE FELDMAN: Anything further then?

2 MR. GENSCH: No, thank you, your Honor.

3 JUDGE FELDMAN: All right. Who would

4 like to go next?

5 MR. JANISZEWSKI: I'll go next, your

6 Honor.

7 JUDGE FELDMAN: All right.

8 MR. JANISZEWSKI: Thank you. Pursuant to

9 stipulation of the parties, the Attorney General moves

10 for the binding in of the public version of the direct

11 testimony of Sebastian Coppola, consisting of a cover

12 page followed by 19 pages of questions and answers.

13 There is also an Appendix A attached outlining Mr.

14 Coppola's qualifications. There is also a confidential

15 version of Mr. Coppola's testimony that I also move for

16 the binding in at this time. I provided the court

17 reporter with a sealed copy of the confidential version

18 of Mr. Coppola's testimony.

19 And finally, also pursuant to stipulation

20 of the parties, the Attorney General moves for the

21 admission of Mr. Coppola's prefiled Exhibits AG-1 through

22 AG-5. I should note that AG-4 and AG-2 are the

23 confidential exhibits in that set. And that is all of

24 the Attorney General's material in this case.


131

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

2 Janiszewski's request to bind in Mr. Coppola's testimony

3 and admit exhibits?

4 Hearing no objection, the prefiled direct

5 testimony of Mr. Sebastian Coppola, including Appendix A,

6 will be bound into the record, with the public version

7 bound in the public transcript and the confidential

8 version bound in a separate confidential record.

9 Exhibits AG-1 through AG-5 are admitted into evidence,

10 with Exhibits AG-2 and AG-4 being confidential exhibits.


12

13

14

15

16

17

18

19

20

21

22

23

24

25



In the matter of the application of CONSUMERS ENERGY GAS COMPANYfor the Reconciliation of Power Supply Cost Recovery (PSCR) Costs and Revenuesfor the Calendar Year 2016____________________________________/

MPSC Case No. U-17918-R

Direct Testimony

And Exhibits

of Sebastian Coppola

On behalf of

Attorney General Bill Schuette

November 3, 2017

132

U-17918-R S. Coppola – Direct – 2 11/3/17

Qualifications 1

Q. PLEASE STATE YOUR NAME, OCCUPATION, AND ADDRESS. 2

A. My name is Sebastian Coppola. I am an independent business consultant. My office is 3

located at 5928 Southgate Rd., Rochester, Michigan 48306. 4

Q. PLEASE SUMMARIZE YOUR PROFESSIONAL QUALIFICATIONS. 5

A. I am a business consultant specializing in financial and strategic business issues in the 6

fields of energy and utility regulation. I have more than thirty years of experience in public 7

utility and related energy work, both as a consultant and utility company executive. I have 8

testified in several regulatory proceedings before the Michigan Public Service 9

Commission (“MPSC” or “Commission”) and other regulatory jurisdictions. I have 10

prepared and/or filed testimony in general rate case proceedings, revenue decoupling 11

reconciliations, infrastructure replacement mechanisms, gas conservation programs, Gas 12

Cost Recovery (“GCR”) cases and Power Supply Cost Recovery (“PSCR”) cases, among 13

many other regulatory matters. 14

Q. WHAT EXPERIENCE DO YOU HAVE WITH ELECTRIC UTILITIES? 15

A. I have performed rate case analyses and filed testimony in several electric general rate 16

cases addressing issues on revenue requirement, sales level determination, operation and 17

maintenance expenses, cost allocations, cost of capital, cost of service and rate design, and 18

various cost tracking mechanisms. In addition, I have performed analyses of power costs 19

133


and filed testimony in power supply cost recovery mechanisms, including reconciliation 1

of annual power supply costs. 2

In my position as Senior Vice President of Finance at MCN Energy Group (“MCN”), I 3

had responsibility for project financing of independent power generation plants in which 4

MCN was an owner. In this regard, I was intricately involved with and became 5

knowledgeable of PURPA qualified cogeneration plants in Michigan and other states. In 6

addition, I was involved in negotiating the development and financing of power generation 7

and electricity distribution plants in other countries, such as India. 8

Q. PLEASE LIST SOME OF THE MORE RECENT CASES YOU HAVE 9

PARTICIPATED IN BEFORE THE MPSC AND OTHER REGULATORY 10

AGENCIES. 11

A. Here is a partial list of the most recent regulatory cases in which I have participated: 12

o Filed direct and rebuttal testimony on behalf of the Illinois Attorney General for 13 the reconciliation of the rate surcharge for the Qualified Infrastructure Program 14 (Rider QIP) of the Peoples Gas and Coke Company (Peoples Gas) in Docket 15-15 0209. 16

o Filed testimony on behalf of the Michigan Attorney General in DTE Electric 17 Company’s (DTEE) 2017 electric rate case U-18255 on several issues, including 18 revenue, operations and maintenance costs, capital expenditures, cost of capital, 19 rate design, and other items. 20

o Filed testimony on behalf of the Michigan Attorney General in Consumers 21 Energy Company’s (CECo) 2017 electric rate case U-18322 on several issues, 22 including revenue, operations and maintenance costs, capital expenditure 23 programs, cost of capital, and other items. 24

o Filed direct and rebuttal testimony on behalf of the Illinois Attorney General for 25 the re-opening of proceedings in the restructuring of the Peoples Gas’s main 26 replacement program and gas system modernization plan in Docket 16-0376. 27

o Filed testimony on behalf of the Michigan Attorney General in the Upper 28 Michigan Energy Resources Corporation (UMERC) application for a certificate 29

134


of public necessity and convenience to build two power plants in the Upper 1 Peninsula of Michigan in case U-18202. 2

o Filed testimony on behalf of the Michigan Attorney General in SEMCO Energy 3 Gas Company’s (SEMCO) application for a certificate of public necessity and 4 convenience to build a pipeline in the Upper Peninsula of Michigan in case U-5 18202. 6

o Filed testimony on behalf of the Public Counsel Division of the Washington 7 Attorney General in Puget Sound Energy’s 2016 Complaint for Violation of Gas 8 Safety Rules in Docket No. UE-160924. 9

o Filed testimony on behalf of the Michigan Attorney General in DTEE’s 2017 10 PSCR Plan case U-18143. 11

o Filed testimony on behalf of the Michigan Attorney General in CECo’s 2015 12 Power Supply Cost Recovery (PSCR) reconciliation case U-17678-R. 13

o Filed testimony on behalf of the Michigan Attorney General in CECo’s 2016 gas 14 general rate case U-18124 on a several issues, including revenue, operations and 15 maintenance costs, capital expenditures, working capital, cost of capital, and 16 other items. 17

o Filed testimony on behalf of the Illinois Attorney General for the restructuring of 18 the Peoples Gas’s main replacement program in Docket 16-0376. 19

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 20 Company’s (DTE Gas) 2014-2015 GCR Plan reconciliation case U-17332-R. 21

o Filed testimony on behalf of the Michigan Attorney General in the formation of 22 UMERC and the transfer of the Michigan assets of Wisconsin Public Service 23 Corporation and Wisconsin Electric Company to UMERC in Case U-18061. 24

o Filed testimony on behalf of the Michigan Attorney General in CECo’s Court of 25 Appeals Remand Case U-17087 for review of the Automated Meter Infrastructure 26 (AMI) opt-out fees. 27

o Filed testimony on behalf of the Michigan Attorney General in CECo’s 2016 28 electric Rate Case U-17990 on a several issues, including revenue, operations and 29 maintenance costs, capital expenditure programs, cost of capital, rate design and 30 other items. 31

o Filed testimony on behalf of the Michigan Attorney General in Michigan Gas 32 Utilities Corporation’s (MGUC) 2016-2017 Gas Cost Recovery (GCR) Plan case 33 U-17940. 34

o Filed testimony on behalf of the Michigan Attorney General in DTEE’s 2016 35 electric Rate Case U-18014 on several issues, including revenue, revenue 36 decoupling, operations and maintenance costs, capital expenditures, cost of 37 capital, rate design and other items. 38

135


Appendix A elaborates further on my qualifications in the regulated energy field. 1

Prepared Direct Testimony 2

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 3

A. I have been asked by the Michigan Department of Attorney General to make an 4

independent analysis of Consumers Energy Company’s (CECo) PSCR Reconciliation for 5

the year 2016. This testimony presents a report of my analysis. 6

Q. WHAT TOPICS ARE YOU ADDRESSING IN YOUR TESTIMONY? 7

A. I will be addressing two major topics in this case: 8

1. The disallowance of replacement power costs and lost revenue related to outages 9

at certain power plants. 10

2. The removal of costs for major maintenance and overhaul or replacement facilities 11

and equipment incurred by Biomass Merchant Plants (“BMPs”). 12

The absence of a discussion of other matters in my testimony should not be taken as an 13

indication that I agree with those aspects of CECo’s PSCR reconciliation filing. My 14

testimony is, instead, a consequence of focusing on priority issues within the available 15

resources. 16

Q. IS YOUR TESTIMONY ON THESE TOPICS ACCOMPANIED BY EXHIBITS? 17

A. Yes. I have included the following exhibits to accompany this testimony: 18

1. Exhibit AG-1 CECo Responses to Overhaul/Upgrade of Ludington Unit 5 19

2. Exhibit AG-2 Replacement Power Costs – Ludington Unit 5 - CONFIDENTIAL 20

136


exclude these costs from reimbursable O&M costs under MCL 460.6a (7), (8) 1

and (9). 2

The remainder of my testimony provides further details and support to these summary 3

conclusions and recommendations. 4

Power Plant Outages 5

Q. PLEASE BRIEFLY DISCUSS THOSE POWER PLANT OUTAGES THAT 6

WARRANT A POTENTIAL COST DISALLOWANCE. 7

A. According to witness Robert Schram’s direct testimony, the Company had 534 outages in 8

2016 at its power generating units.1 This number is an increase of nearly 16% over the 9

461 outages experienced in 2015. 2 Exhibit A-11 (RCS-1) lists the 2016 outages in 10

summary form. Exhibit A-13 (RCS-3) provides additional details with causes and 11

remedies for 80 of the outages where the generating units had lower availability than the 12

established industry standards (NERC-GADS).3 13

After reviewing the outage reports in Exhibits A-11 (RCS-1) and A-13 (RCS-3), I have 14

determined that there are two outage incidents where the Company failed to exercise 15

proper planning and diligence, resulting in higher power costs to PSCR customers during 16

the year 2016. The two incidents are partially described on pages 4 and 13 of Exhibit A-17

1 Direct testimony of Robert Schram at page 3. 2 U-17678-R, Direct testimony of David Kehoe at page 5. 3 Direct testimony of Robert Schram at page 3.

138


13 (RCS-3). The incremental power costs that I propose to disallow from these two 1

incidents are approximately $3.5 million for 2016. 2

Q. PLEASE DESCRIBE THE FIRST INCIDENT. 3

A. The first outage incident occurred at the Ludington Unit 5 on June 9, 2015 and lasted 4

nearly two years until May 24, 2017. According to the Company, on June 9, 2015, 5

Ludington Unit 5 experienced an unplanned catastrophic thrust bearing failure. The 6

Company decided not to undertake any repairs at that point on the basis that it had planned 7

a major overhaul and upgrade project for the generating unit beginning in April of 2016.4 8

Thus, from June 9, 2015, Ludington Unit 5 was out of commission and had no work done 9

on it until April 5, 2016, at which time the Company began its major overhaul of the unit. 10

Exhibit AG-1 includes the Company response to discovery request AG-CE-61 establishing 11

the start and end dates of the unit’s overhaul and upgrade work. 12

In discovery, the Company was asked to explain why it delayed beginning the overhaul 13

and upgrade work by nearly 10 months, until April 5, 2016, for such a large and critical 14

power generating unit. In its initial response to discovery question AG-CE-46, the 15

Company stated that the primary reason for the delay was spatial constraints and conflicts 16

with the overhaul project going on with a different unit, the Ludington Unit 4.5 In a 17

subsequent discovery response (AG-CE-61), the Company elaborated that as part of the 18

major overhaul and upgrade project at the Ludington facility, it built two maintenance 19

4 Direct testimony of Robert Schram at page 8. 5 See CECo discovery response AG-CE-46c included in Exhibit AG-1.

139


facilities at each end of the power plant and the buildings could only support one overhaul 1

and upgrade at a time. It further stated that the lay-down area near the generating units 2

was significantly limited and could not accommodate the turbine covers and other 3

components of the generating unit.6 4

The Company’s explanation and justification for delaying the start of the overhaul and 5

upgrade of Ludington Unit 5 is not credible or reasonable. The Company has not presented 6

any engineering analysis or assessment of all available options that would have allowed it 7

to undertake the overhaul work of Unit 5 contemporaneously with the overhaul work going 8

on with Unit 4. With its response to AG-CE-61, the Company provided an overhead 9

photograph of the Ludington Power Plant.7 It is apparent from the photograph that 10

sufficient open space existed in the parking lot and land adjoining the plant where turbine 11

covers and temporary work areas could have been staged to undertake the overhaul and 12

upgrade of Unit 5 much earlier than April 5, 2016. It is also not clear why the two 13

temporary work buildings built at each end of the plant could not accommodate work for 14

both Unit 4 and 5. The overhaul of Unit 4 had begun in March 2015 and was well 15

underway by late summer 2015. 16

Page 4 of Exhibit AG-1 shows the Company’s original work plan to overhaul the 17

Ludington Unit 5. The first two lines under the summary sections show that from the start 18

of the outage and beginning of the overhaul of the unit to disassembling of the unit, the 19

Company had planned a period of about seven to eight weeks. It would seem reasonable 20

6 See Exhibit AG-1, 7 Id.

140


then that from the June 9, 2015 failure date the Company could have begun the overhaul 1

and upgrade work on Unit 5 by early August 2015. This would have given the Company 2

approximately two months to revise its work plan, arrange for accelerated delivery of 3

components and labor resources, and begin staging the project. In its response to the 4

discovery requests, the Company did not express any concerns with being unable to obtain 5

components and labor resources to overhaul and upgrade Unit 5 earlier than originally 6

planned. Its only express concern was spatial considerations. 7

Given the critical role that the Ludington Power Plant has in providing power during peak 8

demand periods, the Company should have been highly concerned with the failure of Unit 9

5, and should have been more proactive in its response to get all generating units back on-10

line as soon as possible. With six generating units at the plant, two idle units represent 11

one-third of the total generating capacity being off-line. Without these units generating 12

power during peak demand periods, the Company must buy replacement power in the 13

MISO market at a potentially much higher cost to customers. 14

Q. WHAT IS YOUR CONCLUSION AND RECOMMENDATION? 15

A. My conclusion is that the Company did not act prudently in undertaking all reasonable 16

steps to begin the overhaul and upgrade of the Ludington Unit 5. As stated earlier, the 17

Company could have reasonably started work on Unit 5 within two months of the June 9, 18

2015 failure date. Assuming the overhaul and upgrade project would have started on 19

August 1, 2015, it could have been completed by October 20, 2016 if we allow the same 20

141


Q. PLEASE EXPLAIN THE SECOND POWER OUTAGE INCIDENT AND YOUR 1

FINDINGS. 2

A. On page 13 of Exhibit A-13 (RCS-3), the Company reported that it experienced an 3

extended outage of the Ludington Unit 4 from January 1, 2016 to May 20, 2016 due to 4

testing of the generating unit, after it had completed a major overhaul. The total duration 5

of this outage was 3,367 hours, which represents 140 days that the unit was not operational, 6

resulting in a loss of 1,043,392 MWh of power generation. 7

In discovery, the Company was asked to explain why it was necessary for the Ludington 8

Unit 4 be out of commission for 140 days of testing. The responses to discovery requests 9

AG-CE-53 and AG-CE-67 state that testing of the unit began on April 26, 2016 and ended 10

on May 27, 2016. This is approximately 31 days. The responses also state that the 11

Company and its team of engineering experts determined that 31 days is the appropriate 12

test period when overhauling and upgrading each of the generating units at the Ludington 13

Plant. Exhibit AG-3 includes the discovery responses. 14

With this test period established, it is not clear why the Company required Unit 4 to be out 15

of commission for an additional 109 days. In its response to AG-CE-67, the Company 16

tries to justify the additional outage time as part of the planned extension of the overhaul 17

and upgrade project. This explanation contradicts the clear reasons for the outage shown 18

on page 13 of Exhibit A-13 where it states that “Root Cause” and “Final Root Cause” is 19

“Testing during Unit #4 commissioning”. 20


143


power sales revenue billed from delivering energy. Under MCL 460.6a (7), (8) and (9), 1

and in accordance with the August 2009 Commission order in Case No. U-16048, the 2

BMPs can, together, recover the shortfall in fuel and O&M expenses up to a total amount 3

of $12 million annually, adjusted for inflation since enactment of the applicable sections 4

of the law. The inflation-adjusted maximum amount for 2016 is $13,424,648.13 5

The total shortfall of fuel and O&M expenses for 2016 claimed by the seven BMPs is 6

$18,708,856, which exceeds the maximum allowed recovery amount of $13,424,648 by 7

$5,284,208. 8

Because the total cost shortfall amount exceeds the recoverable maximum amount, the 9

recoverable amount of $13,424,648 is pro-rated to each BMP based on the ratio of each 10

BMP’s cost recovery shortfall amount to the total shortfall amount of the group. Exhibit 11

BMP-1 presents these calculated amounts. 12

Q. PLEASE DESCRIBE YOUR FINDINGS FROM REVIEWING THE REQUEST 13

FOR RECOVERY OF THE COST SHORTFALL AMOUNT OF EACH BMP. 14

A. In reviewing the cost data presented by each BMP, I discovered that some plants are 15

including the cost of major maintenance and major overhaul of plant equipment as O&M 16

expenses, instead of excluding them as capitalized costs. 17

13 Exhibit BMP-1, line 26.

145


This practice could result in a higher recovery of costs than reasonable or prudent from 1

CECo’s PSCR customers, and also results in inequities in the apportionment of cost 2

recovery within the BMP group. 3

Q. PLEASE EXPLAIN. 4

A. For example, in reviewing the Maintenance and Other Variable O&M expenses of 5

$1,036,004 claimed for 2016 by Genesee Power Station Limited Partnership (“Genesee”) 6

on line 10 of Exhibit BMP-4 (KAD-1), I discovered that Genesee included $927,003 for 7

major maintenance. Genesee did not explain what major maintenance was performed, but 8

given the size of the expenditure it is likely that it involved more than routine maintenance 9

of equipment. The major maintenance costs represent 45% of the total maintenance and 10

other variable O&M costs of $2,072,007.14 The major maintenance costs dwarf any of the 11

other expenses included on the list of O&M recovery items. Exhibit AG-1 includes the 12

schedule of detailed O&M costs for 2016 and 2015 provided by the Company in response 13

to discovery. 14

It is also informative to point out that in the 2015 O&M cost recovery filing, Genesee 15

included an even larger amount for major maintenance, of approximately $2.5 million and 16

$2.3 million for a major turbine overhaul. These two amounts represent 86% of the total 17

14 Genesee has requested recovery of 50% of the total maintenance and other variable O&M costs of $2,072,007 which is $1,036,004.

146


O&M costs incurred for the year. 15 These expenditures are not typical, routine O&M 1

expenses that should be included for recovery in this case. 2

Under generally accepted accounting principles, costs for major maintenance and overhaul 3

of facilities that improve or put the facility or equipment in a better operating condition, 4

or extend its useful life or its efficiency should be capitalized and not included as current 5

O&M expenses. From the limited information provided by Genesee, it appears that the 6

large costs for major maintenance and turbine overhaul should have been excluded from 7

recoverable O&M expenses. 8

Q. HAVE OTHER BMPs INCLUDED MAJOR MAINTENANCE COSTS WITH 9

VARIABLE O&M EXPENSES AND REQUESTED RECOVERY OF THESE 10

COSTS? 11

A. Yes. In 2016, Cadillac Renewable Energy (“Cadillac”) included $200,328 of major 12

maintenance costs in O&M expenses to replace and overhaul ash handling equipment, the 13

associated conveyor system, and other equipment. Hilman Power Company (“Hilman”) 14

included $67,134 in 2016 O&M expenses for a new ash mixer and associated support 15

structure. In 2015, Hilman included $169,395 in O&M expenses for a new precipitator to 16

control emissions. 17

In 2016, Viking Energy of McBain (“Viking-McBain”) incurred $225,791 of maintenance 18

costs for the cooling tower, circulators, and associated piping. The 2016 amount is an 19

increase of $206,931 over the amount spent in 2015. It is likely that the higher amount 20

15 Genesee incurred $5,580,859 of maintenance and other variable expense and claimed recovery of 50% of this amount, or $2,790,429.

147


spent in 2016 included major maintenance or the overhaul of the cooling tower, circulators, 1

and associated equipment. 2

Q. HAS THE INCLUSION OF COSTS FOR MAJOR MAINTENANCE AND 3

EQUIPMENT OVERHAUL AFFECTED THE AMOUNT OF O&M COSTS 4

RECOVERED FROM PSCR CUSTOMERS DURING 2016? 5

A. No. Because the amount of permitted recovery of shortfall Fuel and O&M costs is 6

considerably lower than the amount requested by the BMP group by approximately $5.3 7

million, the PSCR customers were not billed for major maintenance and equipment 8

overhaul costs in 2016. However, this could change in the future if one or more of the 9

BMPs were removed from the group. For example, TES Filer City plans to convert its 10

facilities from partially burning bio-mass waste products to burning 100% natural gas.16 11

Consumers Energy, who is part owner of the facility, currently has an application before 12

the Commission requesting approval to amend its PPA with TES Filer City. It is likely 13

that once TES Filer City converts its operation to burn 100% natural gas it would not 14

qualify for reimbursement of the shortfall in fuel and O&M expenses because it would no 15

longer be a biomass, waste wood, burning facility. 16

In 2016, TES Filer City represented approximately $6.4 million, or 34% of the total fuel 17

and O&M expense shortfall of $18.7 million. If this amount were to be removed, the total 18

shortfall expense amount for the remaining BMPs would have been $12.3 million, or $1.1 19

million below the maximum inflation-adjusted amount of $13.4 million for 2016. Under 20

16 Case No. U-18392, CECo application page 2.

148


this scenario, the inclusion of the major maintenance and facilities overhaul costs would 1

have made a difference and PSCR customers would have paid for costs that should not 2

have been included in O&M expenses. 3

Q. DOES THE INCLUSION OF MAJOR MAINTENANCE AND EQUIPMENT 4

OVERHAUL COSTS IN O&M EXPENSE CREATE INEQUITIES IN THE 5

RECOVERY OF COSTS AMONG THE BMP GROUP? 6

A. Yes. Given that the maximum amount of recoverable costs is allocated based on the ratio 7

of each BMP’s requested shortfall of fuel and O&M expenses to the total amount for the 8

group, any improper O&M costs included by a BMP will result in that BMP being assigned 9

a higher percentage of the allowable maximum recovery amount. This inaccurate 10

allocation of recoverable costs results in some BMPs within the group receiving a higher 11

recovery amount and others less. The effect of this skewed allocation is an inequitable 12

distribution of available recovery amounts. 13


A. My conclusion is that costs for major maintenance and overhaul of facilities should not be 15

included in reimbursable O&M expense. Therefore, I recommend that the Commission 16

direct the BMPs to exclude these costs in all future cases from reimbursable O&M costs 17

under MCL 460.6a (7), (8) and (9). 18

149


Prior Year PSCR Cost Over-Recovery 1

Q. PLEASE EXPLAIN WHAT PROBLEM EXISTS WITH THE PRIOR YEAR 2

CARRYOVER BALANCE INCLUDED IN THE 2016 POWER COST 3

RECONCILIATION. 4

A. In Exhibit A-4 (HLP-1), which is the 2016 Power Supply Cost Recovery Reconciliation 5

schedule, the Company shows a prior year over-recovery amount of $12,184,853 on line 6

26. This amount represents the amount proposed by the Company in the rebuttal testimony 7

of witness Stanley Hunley in Case No. U-17678-R. Staff and intervenors proposed several 8

power cost disallowances in that case which are not reflected in the Company’s carryover 9

balance. The case is still pending before the Administrative Law Judge. Once the 10

Commission issues an order in Case U-17678-R, the 2015 PSCR carryover balance needs 11

to be updated to reflect the correct amount. 12

Current Year PSCR Cost Over-Recovery 13

Q. WHAT IS THE OVER-RECOVERY OF PSCR COSTS AT THE END OF 2016 14

INCLUSIVE OF YOUR ADJUSTMENTS? 15

A. In Exhibit A-4 (HLP-1), the Company has reported an over-recovery amount of 16

$2,817,173 for 2016, before interest. 17

My proposed adjustments total to a reduction of $3,529,800 to 2016 power costs before 18

applying the average jurisdictional rate of 99.04% for the year. After applying the 19

jurisdictional rate, the amount of my proposal disallowance is $3,495,914. Therefore, the 20

150


over-recovery amount at the end of 2016 inclusive of my adjustments is $6,313,087 before 1

interest and subject to the correct prior reconciliation balance from Case No. U-17678-R. 2

Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY? 3

A. Yes, it does. However, I reserve the right to amend, revise and supplement my testimony 4

to incorporate new information that may become available. 5

151

Appendix A

Experience and Qualifications of Sebastian Coppola

1

Mr. Sebastian Coppola is an independent energy business consultant and president

of Corporate Analytics, Inc., whose place of business is located at 5928 Southgate

Rd., Rochester, Michigan 48306.

EMPLOYMENT BACKGROUND

Mr. Coppola has been an independent consultant for more than 15 years.

Before that, he spent three years as Senior Vice President and Chief Financial

Officer of SEMCO Energy, Inc. with responsibility for all financial operations,

corporate development and strategic planning for the company’s Michigan and

Alaska regulated and non-regulated operations. During the period at SEMCO

Energy, he had also responsibility for certain storage and pipeline operations as

President and COO of SEMCO Energy Ventures, Inc. Prior to SEMCO, Mr.

Coppola was Senior Vice President of Finance for MCN Energy Group, Inc., the

parent company of Michigan Consolidated Gas Company.

During his 24-year career at MCN and MichCon, he held various

analytical, accounting, managerial and executive positions, including Manager of

Gas Accounting with responsibility for maintaining the accounting records and

preparing financial reports for gas purchases and gas production. In this role, he

had also responsibility for preparing Gas Cost Recovery (GCR) reconciliation

analysis and reports, and supporting preparation of testimony for the cost of gas

reconciliation proceedings before the MPSC. Over the years, Mr. Coppola also

held the positions of Treasurer, Director of Investor Relations, Director of

Accounting Services, Manager of Corporate Finance, Manager of Customer Billing

and Manager of Materials Inventory and Warehousing Accounting. In many of

these positions he interacted with various operating areas of the company and was

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2

intricately involved in construction and operating programs, defining gas

purchasing strategies, rate case analysis, cost of capital studies and other regulatory

proceedings.

ENERGY INDUSTRY AND REGULATORY EXPERIENCE

As a business consultant, Mr. Coppola specializes in financial and strategic

business issues in the fields of energy and utility regulation. He has more than

thirty years of experience in public utility and related energy work, both as a

consultant and utility company executive. He has testified in several regulatory

proceedings before State Public Service Commissions. He has prepared and/or

filed testimony in electric and gas general rate case proceedings, power supply and

gas cost recovery mechanisms, revenue and cost tracking mechanisms/riders and

other regulatory proceedings. As accounting manager and later financial executive

for two regulated gas utilities with operations in Michigan and Alaska, he has been

intricately involved in operating and construction programs, gas cost recovery and

reconciliation cases, gas purchase strategies and rate case filings.

Mr. Coppola has more than 15 years of experience in the area of gas supply

and regulatory proceedings. He has led or participated in the financial operations,

gas supply planning and/or gas cost recovery arrangements of two major gas

utilities in Michigan and in Alaska. He has prepared testimony in multiple electric

and gas general rate cases, Power Supply Cost Recovery (PSCR) and Gas Cost

Recovery (GCR) proceedings, Cast Iron and Pipeline Replacement Programs and

other regulatory cases on behalf of the Michigan Attorney General, Citizens

Against Rate Excess (CARE), the Public Counsel Division of the Washington

Attorney General, the Illinois Attorney General and the Ohio Office of Consumers

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Counsel in electric and gas utility rate cases, including AEP Ohio, Ameren-Illinois

Utilities, Avista, Consumers Energy, Detroit Edison, MichCon (DTE Gas),

Michigan Gas Utilities Corp, PacifiCorp, Peoples Gas, Puget Sound Energy,

SEMCO, Upper Peninsula Power Company and Wisconsin Public Service

Company.

As accounting manager and later financial executive for two regulated gas

utilities, he has been intricately involved in gas purchase strategies and CGR

reconciliation cases. He has had direct responsibility for preparing GCR

reconciliation analysis and reports, and supporting preparation of testimony for the

cost of gas reconciliation proceedings before the Michigan Public Service

Commission (MPSC). He is intricately familiar with the power supply and gas cost

recovery mechanisms, gas supply and pricing issues, and regulatory issues faced

by utilities.

As manager of customer billing, Mr. Coppola developed intricate

knowledge of customer billing and meter reading operations. As manager of

materials inventory and warehousing accounting, he also developed intricate

knowledge of pipeline and materials procurement, warehousing and construction

operations including safety compliance issues. Mr. Coppola has testified

extensively on gas utility pipeline, service lines and inside meters replacement

programs related to at-risk pipes that provide safety issues to customers and the

general public.

In his role as Treasurer and Chairman of the MCN/MichCon Risk

Committee from 1996 through 1998, Mr. Coppola was involved in reviewing and

deciding on the appropriate gas purchase price hedging strategies, including the

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use of gas future contracts, over the counter swaps, fixed price purchases and index

price purchases.

In March 2001, Mr. Coppola testified before the Michigan House Energy

and Technology Subcommittee on Natural Gas Fixed Pricing Mechanisms. Mr.

Coppola has participates in natural gas issue forums sponsored by the American

Gas Association and stays current on various energy supply issues through review

of industry analyst reports and other publications issued by various trade groups.

Specific Regulatory Proceedings And Related Experience:

o Filed direct and rebuttal testimony on behalf of the Illinois Attorney General for the reconciliation of the rate surcharge for the Qualified Infrastructure Program (Rider QIP) of the Peoples Gas and Coke Company’s (Peoples Gas) in Docket 15-0209.

o Filed testimony on behalf of the Michigan Attorney General in DTE Electric Company (DTEE) 2017 electric Rate Case U-18255 on a several issues, including revenue, operations and maintenance costs, capital expenditures, cost of capital, rate design and other items.

o Filed testimony on behalf of the Michigan Attorney General in Consumers Energy Company (CECo) 2017 electric rate Case U-18322 on a several issues, including revenue, operations and maintenance costs, capital expenditure programs, cost of capital and other items.

o Filed direct and rebuttal testimony on behalf of the Illinois Attorney General for the re-opening of proceedings in the restructuring of the Peoples Gas’s main replacement program and gas system modernization plan in Docket 16-0376.

o Filed testimony on behalf of the Michigan Attorney General in the Upper Michigan Energy Resources Corporation (UMERC) application for a certificate of public necessity and convenience to build two power plants in the Upper Peninsula of Michigan in case U-18202.

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o Filed testimony on behalf of the Michigan Attorney General in SEMCO Energy Gas Company (SEMCO) application for a certificate of public necessity and convenience to build a pipeline in the Upper Peninsula of Michigan in case U-18202.

o Filed testimony on behalf of the Public Counsel Division of the Washington Attorney General in Puget Sound Energy’s 2016 Complaint for Violation of Gas Safety Rules in Docket No. UE-160924.

o Filed testimony on behalf of the Michigan Attorney General in DTEE 2017 PSCR Plan case U-18143.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2015 Power Supply Cost Recovery (PSCR) reconciliation case U-17678-R.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2016 gas general rate case U-18124 on a several issues, including revenue, operations and maintenance costs, capital expenditures, working capital, cost of capital and other items.

o Filed testimony on behalf of the Illinois Attorney General for the restructuring of the Peoples Gas’s main replacement program in Docket 16-0376.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas Company (DTE Gas) 2014-2015 GCR Plan reconciliation case U-17332-R.

o Filed testimony on behalf of the Michigan Attorney General in the formation of UMERC and the transfer of Michigan assets of Wisconsin Public Service Corporation and Wisconsin Electric Company to UMERC in Case U-18061.

o Filed testimony on behalf of the Michigan Attorney General in CECo Court of Appeals Remand Case U-17087 for review of the Automated Meter Infrastructure (AMI) opt-out fees.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2016 electric Rate Case U-17990 on a several issues, including revenue, operations and maintenance costs, capital expenditure programs, cost of capital, rate design and other items.

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o Filed testimony on behalf of the Michigan Attorney General in Michigan Gas Utilities Corporation (MGUC) 2016-2017 Gas Cost Recovery (GCR) Plan case U-17940.

o Filed testimony on behalf of the Michigan Attorney General in DTEE 2016 electric Rate Case U-18014 on a several issues, including revenue, revenue decoupling, operations and maintenance costs, capital expenditures, cost of capital, rate design and other items.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO Energy Gas (SEMCO) 2016-2017 GCR Plan case U-17942.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2016-2017 GCR Plan case U-17941.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2015 gas general rate case U-17999 on a several issues, including revenue, operations and maintenance costs, capital expenditures, main replacement program, Revenue Decoupling Mechanism (RDM) program, cost of capital and other items.

o Filed testimony on behalf of the Michigan Attorney General in Consumers Energy Company (CECo) 2016-2017 GCR Plan case U-17943.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2016 Power Supply Cost Recovery (PSCR) Plan case U-17918.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2014-2015 GCR Plan reconciliation case U-17334-R.

o Filed testimony on behalf of the Michigan Attorney General in DTE Electric (DTEE) 2016 PSCR Plan case U-17920.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO 2014-2015 GCR Plan reconciliation case U-17333-R.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2015 gas general rate case U-17882 on a several issues, including revenue, operations and maintenance costs, capital expenditures, main replacement program, infrastructure cost recovery mechanism, cost of capital and other items..

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o Filed testimony on behalf of the Michigan Attorney General in CECo Gas Choice and End-User Transportation tariff changes case U-17900.

o Analyzed the gas rate case filings of MGUC in Case U-17880 and assisted the Michigan Attorney General in settlement of the case.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2014 Power Supply Cost Recovery (PSCR) reconciliation case U-17317-R.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas Company (DTE Gas) 2013-2014 GCR Plan reconciliation case U-17131-R.

o Filed testimony on behalf of the Michigan Attorney General in DTEE 2014 electric Rate Case U-17767 on a several issues, including operations and maintenance costs, capital expenditures, AMI program, cost of capital and other items.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2015-2016 GCR Plan case U-17691.

o Filed testimony on behalf of the Illinois Attorney General in Ameren Illinois Company’s 2015 general rate case on operation and maintenance costs in Docket 15-0142.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2014 electric Rate Case U-17735 on a several issues, including sales, operations and maintenance costs, capital expenditures, cost of capital, AMI program, revenue decoupling and infrastructure cost recovery mechanisms.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2015-2016 GCR Plan case U-17693.

o Filed testimony on behalf of the Michigan Attorney General in MGUC 2015-2016 GCR Plan case U-17690.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2015 PSCR Plan case U-17678.

o Analyzed the electric rate case filings of Northern States Power in Case U-17710 and Wisconsin Public Service Company U-17669, and assisted the Michigan Attorney General in settlement of these cases.

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o Filed testimony on behalf of the Michigan Attorney General in CECo 2013-2014 GCR Plan reconciliation case U-17133-R.

o Filed testimony on behalf of the Michigan Attorney General in MGUC 2013-2014 GCR Plan reconciliation cases U-17130-R.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO Energy Gas (SEMCO) 2013-2014 GCR Plan reconciliation case U-17132-R.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2014 gas general rate case U-17643 on a several issues, including revenue, operations and maintenance costs, capital expenditures, main replacement program, cost of capital and other items..

o Filed testimony on behalf of the Illinois Attorney General in Wisconsin Energy merger with Integrys on the Peoples Gas and Coke Company’s Accelerated Main Replacement Program Docket 14-0496.

o Filed testimony on behalf of Citizens Against Rate Excess in Wisconsin Public Service Company’s 2013 Power Supply Cost Recovery (PSCR) plan reconciliation case U-17092-R.

o Filed testimony on behalf of the Michigan Attorney General in Consumers Energy Company’s (CECo) 2014 Power Supply Cost Recovery (PSCR) plan case U-17317.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2014 OPEB Funding case U-17620.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO 2014-2015 GCR Plan case U-17333.


o Filed testimony on behalf of the Michigan Attorney General in CECo 2014-2015 GCR Plan case U-17334.

o Filed testimony for Citizens Against Rate Excess in Wisconsin Public Service Company’s 2014 Power Supply Cost Recovery (PSCR) plan case U-17299.

o Filed testimony in March 2013 on behalf of the Michigan Attorney General in CECo’s electric Rate Case U-15645 on remand from the

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Michigan Court of Appeals for review of the Automatic Metering Infrastructure (AMI) program.

o Filed testimony for Citizens Against Rate Excess in Upper Peninsula Power Company’s 2012 PSCR plan case U-17298.

o Filed testimony on behalf of the Michigan Attorney General in MGUC 2012-2013 GCR Reconciliation case U-16920-R.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas Company 2012-2013 GCR Reconciliation case U-16921-R.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2012-2013 GCR Reconciliation case U-16924-R.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO 2012-2013 GCR Reconciliation case U-16922-R.

o Filed testimony for Citizens Against Rate Excess in Upper Peninsula Power Company’s 2012 Power Supply Cost Recovery (PSCR) reconciliation case U-16881-R.

o Filed testimony in Puget Sound Energy’s 2013 Power Cost Only Rate Case on behalf of the Public Counsel Division of the Washington Attorney General in Docket No. UE-130167 on the power costs adjustment mechanism.

o Filed testimony in PacifiCorp’s 2013 General Rate Case on behalf of the Public Counsel Division of the Washington Attorney General in Docket No. UE-130043 on power costs, cost allocation factors, O&M expenses and power cost adjustment mechanisms.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO 2013-2014 GCR Plan case U-17132.


o Filed testimony on behalf of the Michigan Attorney General in CECo’s 2012 electric Rate Case U-17087 on a several issues, including cost of service methodology, rate design, operations and maintenance costs, capital expenditures and infrastructure cost recovery mechanism and other revenue/cost trackers.

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o Filed reports on gas procurement and hedging strategies of four gas utilities before the Washington Utilities and Transportation Commission on behalf of the Washington Attorney General – Office of Public Counsel in April 2013.

o Filed testimony on behalf of the Michigan Attorney General in MGUC and SEMCO 2011-2012 GCR Plan reconciliation cases U-16481-R and U-16483-R.

o Filed testimony for Citizens Against Rate Excess in Upper Peninsula Power Company’s 2012 Power Supply Cost Recovery (PSCR) plan case U-17091.

o Filed testimony in MichCon’s 2012 gas Rate Case U-16999 on a several issues, including sales volumes, revenue decoupling mechanism, operations and maintenance costs, capital expenditures and infrastructure cost recovery mechanism.

o Filed testimony on behalf of the Washington Attorney General – Office of Public Counsel on executive and board of directors’ compensation in the 2012 Avista general rate case.

o Filed testimony for Citizens Against Rate Excess in Upper Peninsula Power Company’s 2011 Power Supply Cost Recovery (PSCR) reconciliation case U-16421-R.

o Filed testimony on behalf of the Ohio Office of Consumers Counsel in AEP Ohio’s power supply restructuring case in June 2012.

o Filed testimony on behalf of the Michigan Attorney General in MGUC and SEMCO 2012-2013 GCR Plan cases U-16920 and U-16922.

o Filed testimony for Citizens Against Rate Excess in Upper Peninsula Power Company’s 2012 PSCR plan case U-16881.

o Filed testimony for Citizens Against Rate Excess in Wisconsin Public Service Corporation‘s 2012 PSCR plan case U-16882.

o Filed testimony for the Michigan Attorney General in CECo’s gas business Pilot Revenue Decoupling Mechanism in case U-16860.

o Filed testimony for the Michigan Attorney General in Consumers Energy Gas 2011 Rate Case U-16855 on several issues, including

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sales volumes, operations and maintenance cost, employee benefits, capital expenditures and cost of capital.

o Filed testimony for the Michigan Attorney General in SEMCO and MGUC 2010-2011 GCR Plan reconciliation cases U-16147-R and U-16145-R.

o Filed testimony for the Michigan Attorney General in Consumers Energy 2011 electric Rate Case U-16794 on several issues, including electric sales forecast, revenue decoupling mechanism, operations and maintenance cost, employee benefits, capital expenditures and cost of capital.

o Filed testimony for the Michigan Attorney General in CECo’s electric business Pilot Revenue Decoupling Mechanism in case U-16566.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO and MGUC 2011-2012 GCR Plan cases U-16483 and U-16481.

o Filed testimony for the Michigan Attorney General in Detroit Edison 2010 electric Rate Case U-16472 on several issues, including revenue decoupling mechanism, operations and maintenance cost, executive compensation and benefits, capital expenditures and cost of capital.

o Filed testimony for the Michigan Attorney General in SEMCO 2009-2010 GCR reconciliation case U-15702-R.

o Filed testimony for Michigan Attorney General in MGUC 2009-2010 GCR reconciliation case U-15700-R.

o Filed testimony for Michigan Attorney General, in Consumers Energy Gas 2010 Rate Case U-16418 on several issues, including sales volumes, operations and maintenance costs, capital expenditures and cost of capital.

o Filed testimony for Michigan Attorney General, in SEMCO 2010 Rate Case U-16169 on several issues, including sales volumes, rate design, operations and maintenance cost, executive compensation and benefits, capital expenditures and cost of capital.

o Filed testimony, for Michigan Attorney General in Consumers Energy 2009 electric Rate Case U-16191 on several issues, including sales

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volumes, revenue decoupling mechanism, operations and maintenance cost and capital expenditures.

o Filed testimony for Michigan Attorney General, in MichCon 2009 gas Rate Case U-15985 on several issues, including sales volumes, revenue decoupling mechanism, operations and maintenance cost, capital expenditures and cost of capital.

o Filed testimony for Michigan Attorney General and was cross-examined in Consumers Energy 2009 gas Rate Case U-15986 on several issues, including sales volumes, revenue decoupling mechanism, operations and maintenance cost, capital expenditures and cost of capital.

o Prepared testimony and assisted the Michigan Attorney General in discussions and settlement of SEMCO and MGUC 2010-2011 GCR Plan cases U-16147 and U-16145.

o Prepared testimony and assisted Michigan Attorney General in settlement of SEMCO 2009-2010 GCR case U-15702.

o Prepared testimony and assisted Michigan Attorney General in settlement of MGUC 2009-2010 GCR case U-15700.

o Prepared testimony and assisted the Michigan Attorney General in discussions and settlement of SEMCO 2008-2009 GCR case U-15452 and reconciliation case U-15452-R.

o Prepared testimony and assisted Michigan Attorney General in discussions and settlement of MGUC 2008-2009 GCR reconciliation case U-15450-R.

o Prepared testimony for Michigan Attorney General in SEMCO GCR 2007-2008 Reconciliation Case U-15043-R.

o Prepared testimony for Michigan Attorney General filed in MGUC 2007-2008 GCR Reconciliation Case U-15040-R.

o Participated in drafting of testimony for all aspects of SEMCO rate case filing with the Regulatory Commission of Alaska (RCA) in 2001.

o Filed testimony in 2001 before the (RCA) and was cross-examined on the financing plans for the acquisition of Enstar Corporation and the capital structure of SEMCO.

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o Developed a cost of capital study in support of testimony by company witness in the Saginaw Bay Pipeline Company rate request proceeding in 1989.

o Prepared testimony for company witness on cost of capital and capital structure in MichCon 1988 gas rate case.

o Filed testimony in MichCon gas conservation surcharge case in 1986-87.

o Testified before MPSC ALJ in MichCon customer bill collection complaints in 1983.

o Participated in analysis of uncollectible gas accounts expense for inclusion in rate filings between 1975 and 1988.

o Participated in analysis of allocation of corporate overhead to subsidiaries and use of the “Massachusetts Formula” at MichCon and at SEMCO in 1975 and 2000.

o Prepared support information on GCR and rate case-O&M testimony at MichCon from 1975 to 1988.

o Filed testimony in MichCon financing orders in 1987 and 1988.

o Participated in rate case filing strategy sessions at MichCon and SEMCO from 1975 to 2001.

o Provided Hearing Room assistance and guidance to counsel on financial and policy issues in various cases from 1975 to 2001.

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EDUCATIONAL BACKGROUND

Mr. Coppola did his undergraduate work at Wayne State University, where

he received the Bachelor of Science degree in Accounting in 1974. He later

returned to Wayne State University to obtain his Master of Business

Administration degree with major in Finance in 1980.

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4 JUDGE FELDMAN: Anything further?

5 MR. JANISZEWSKI: No, thank you, your

6 Honor.

7 JUDGE FELDMAN: All right. Thank you.

8 Mr. Waters.

9 MR. WATERS: Does Staff want to go first?

10 JUDGE FELDMAN: Perhaps.

11 MR. SATTLER: I would certainly be

12 willing to go next.

13 JUDGE FELDMAN: All right. Thank you.

14 MR. SATTLER: Thank you. Staff has filed

15 testimony of just one witness and she filed revised

16 testimony on March 15, 2018, the testimony being of

17 Gretchen M. Wagner, and it consists of a cover page and

18 six pages of questions and answers. In connection with

19 her testimony she also filed one exhibit, then marked as

20 Exhibit S-1-R. It's a revised exhibit. And consistent

21 with the parties' agreement, I would move to bind her

22 testimony in the record and admit her exhibit into

23 evidence.


25 for the record if there are any objections to

206

1 Mr. Sattler's request to bind in Ms. Wagner's testimony

2 and admit her exhibit?

3 Hearing no objection, the revised

4 prefiled direct testimony of Gretchen M. Wagner is bound

5 into the record, and Exhibit S-1-R is admitted into

6 evidence.


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* * * *

In the matter of the application of ) CONSUMERS ENERGY COMPANY ) for the Reconciliation of Power Supply ) Case No. U-17918-R Cost Recovery (PSCR) Costs and Revenues ) for the Calendar Year 2016 )

QUALIFICATIONS AND REVISED DIRECT TESTIMONY OF

GRETCHEN M. WAGNER

MICHIGAN PUBLIC SERVICE COMMISSION

March 15, 2018

207

QUALIFICATIONS OF GRETCHEN M. WAGNER CASE NUMBER U-17918-R

PART I

1


A. My name is Gretchen M. Wagner. My business address is 7109 West Saginaw 2

Hwy., Lansing, Michigan 48917. 3


A. I am employed by the Michigan Public Service Commission (MPSC or 5

Commission) as an Auditor in the Act 304 Reconciliations Section of the 6

Regulated Energy Division. 7

Q. Please outline your educational background. 8

A. I earned a Master of Science Degree in Accounting, with a Concentration in 9

Taxation, from Michigan State University. I also earned a Bachelor of Arts 10

Degree in Accounting from Michigan State University. 11

Q. Please describe your professional background. 12

A. In February 2009, I accepted my position with the MPSC. Prior to my 13

employment with the Commission, I was employed by Oakland University as an 14

Internal Auditor and by Iannuzzi and Darling, LLC as a Field Auditor. While in 15

school, I was employed by Maner, Costerisan & Ellis, P.C. as a Tax Intern and 16

also by Charles K. Poor, CPA, P.C. as an Accountant. 17

I have attended the Institute of Public Utilities’ (IPU) two week Annual 18

Regulatory Studies Program at Michigan State University and I have attended 19

various IPU Advanced Studies Sessions. I have also attended MPSC training 20

sessions regarding rate-making issues. 21

Q. Have you obtained any certificates? 22

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PART I

2

A. Yes. I obtained a Tier I Certificate of Continuing Regulatory Education in 1

December 2014, from the Institute of Public Utilities Regulatory Research and 2

Education. 3

Q. Briefly discuss your experience with the MPSC. 4

A. I have served as the lead auditor, case coordinator, and/or performed audit work 5

on numerous cases, including: Power Supply Cost Recovery (PSCR) 6

reconciliations, Gas Cost Recovery (GCR) reconciliations, Times Interest Earned 7

Ratio (TIER) reconciliations, Uncollectible Expense True-up Mechanism 8

(UETM) reconciliations, Enhanced Infrastructure Replacement Program (EIRP) 9

reconciliations, Self-implementation Refund (SIR), Choice Incentive Mechanism 10

(CIM), and General Rate cases. 11

Q. Have you previously filed testimony before the MPSC? 12

A. Yes, I have filed testimony in the following cases: 13

Case Number Company Subject 14

U-15452-R SEMCO Energy GCR (MPSC) 15


U-15981 Wisconsin Electric Rate Case (taxes) 17

U-16146-R MichCon GCR 18


U-16427-R Ontonagon PSCR & TIER 20

U-16447 MichCon SIR 21

U-16482-R MichCon GCR 22


209


PART I

3

U-16484-R SEMCO Energy GCR (BC) 1

U-16830 Wisconsin Electric Rate Case (taxes) 2

U-16921-R DTE Gas Company GCR 3

U-16952 Detroit Edison CIM (Choice Incentive Mechanism) 4

U-16999 MichCon Rate Case (Uncollectible Exp.) 5

U-17097-R Detroit Edison PSCR 6



U-17680-R DTE Electric Company PSCR 9

U-17678-R Consumers Energy Co. PSCR10

210

REVISED DIRECT TESTIMONY OF GRETCHEN M. WAGNER CASE NUMBER U-17918-R

PART II

4


A. The purpose of my testimony is to present the MPSC Staff’s (Staff) position on 2

Consumer Energy’s (Consumers or the Company) cumulative Power Supply Cost 3

Recovery (PSCR) reconciliation for the 12-month period ending December 2016. 4

I will also address the Biomass Merchant Plants’ (BMPs) request for cost 5

recovery for their capped and uncapped actual fuel and variable operation and 6

maintenance (O&M) costs incurred during the time period of January 1, 2016 7

through December 31, 2016. 8

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


Exhibits Title 11

S-1-R Power Supply Cost Recovery Calculation 12

Q. Were these exhibits prepared by you or under your direction? 13

A. Yes. 14

Q. Please explain Exhibit S-1-R. 15

A. Exhibit S-1-R presents Staff’s calculation of the total cumulative PSCR over 16

recovery, with interest. The starting point for Staff’s revised calculation was 17

Consumers Exhibit A-30, filed on March 12, 2018. First, Staff verified the 18

mathematical accuracy of the Company’s exhibit. Staff made very minor layout 19

changes and added the interest calculation section to its Exhibit S-1-R when 20

compared to Exhibit A-30. Exhibit S-1-R consists of two pages and incorporates 21

Staff’s adjustments to the PSCR calculation discussed below. 22

211


PART II

5

Q. In this case, does Staff agree with the capped 2016 actual fuel and variable O&M 1

costs for recovery identified on the revised September 14, 2017, Exhibit BMP-1, 2

line 27, in the amount of $13,424,648? 3

A. Yes, it does. 4

Q. Did Staff make any adjustments to the Company’s filed figures? 5

A. Yes, Staff made two adjustments. 6

Q. Please explain Staff’s first adjustment. 7

A. Staff included the SOx and NOx expenses from BMP-7 (RJT-1), lines 15 and 16 8

in the Purchased, Interchange & Renewable Power costs on line 26 of Exhibit S-9

1-R, in the corresponding months. These costs consist of actual fuel and variable 10

O&M costs not subject to a $1,000,000.00 monthly limit, since these costs 11

resulted from changes in federal or state environmental laws or regulations that 12

were made and implemented after October 6, 2008 (the effective date of PA 286 13

of 2008). 14

Q. Please explain Staff’s second adjustment. 15

A. Staff’s second adjustment is an increase of $1,424,648 to the Purchased, 16

Interchange & Renewable Power costs on line 26 of Exhibit S-1-R, in December, 17

for the BMP inflation adjusted shortfall. The adjustment is the difference 18

between the capped shortfall payments included by the Company in its initial 19

filing and the inflation adjusted capped shortfall pursuant to MCL 460.6a, 20

subsections (7), (8), and (9).1 MCL 460.6a, subsections (7), (8), and (9) discuss 21

1 As interpreted by the Court of Appeals in its May 28, 2015 decision in Docket No. 314361

212


PART II

6

the costs that are recoverable by the BMPs. Capped costs consist of actual fuel 1

and variable O&M costs subject to a $1,000,000.00 monthly limit, which may be 2

adjusted by the Commission. The inflation rate applied to the capped shortfall 3

payments is the percentage change between the average annual CPI in the 2009 4

base year and the PSCR year. 5

Q. What is Staff’s recommended over recovery for Consumers Energy’s 2016 PSCR 6

Reconciliation period? 7

A. Staff recommends the Commission approve an over recovery of $11,766,792, 8

including interest, to be used as the Company’s beginning balance in its 2017 9

PSCR Reconciliation. 10


A. Yes, it does.12

213

214

1 MR. SATTLER: Thank you, your Honor.

2 Nothing further.

3 JUDGE FELDMAN: All right. Mr. Waters.

4 MR. WATERS: Thank you. I move the

5 following testimony be bound in the record and the

6 following exhibits be admitted into evidence. The direct

7 testimony of Thomas A. Schmid, the rebuttal testimony of

8 Thomas A. Schmid, the direct testimony of Kenneth A.

9 Desjardins, the direct testimony of Michael D. Bean, the

10 direct testimony of Doug A. Audette as well as the

11 rebuttal testimony of Doug A. Audette, the direct

12 testimony of Robert Joe Tondu, the direct testimony of

13 Neil R. Taratuta, the direct testimony of Thomas V. Vine

14 as well as the rebuttal testimony of Thomas V. Vine, the

15 direct testimony of Donald Adams, and the rebuttal

16 testimony of Thomas J. Allen.

17 I move that Exhibits BMP-1 through BMP-16

18 be admitted into evidence.

19 For the record the testimony, the direct

20 testimony, the rebuttal testimony, and the exhibits are

21 as prefiled with the Commission.

22 JUDGE FELDMAN: All right. And some of

23 the testimony as initially filed was revised.

24 MR. WATERS: That is correct.

25 JUDGE FELDMAN: And it is the revised

215

1 versions of those --

2 MR. WATERS: -- that is being bound in

3 the record, yes, your Honor.

4 JUDGE FELDMAN: And that is indicated on

5 the cover pages of the few witnesses who filed revised

6 testimony. And likewise I believe that a few of the

7 exhibits were revised, BMP-1 and 2, and then I believe 5

8 and 6 were also revised.

9 MR. WATERS: That is correct.

10 JUDGE FELDMAN: And it's the revised

11 versions being admitted.

12 MR. WATERS: Yes.

13 JUDGE FELDMAN: Let me ask for the record

14 if there are any objections to Mr. Waters' request to

15 bind in the testimony of his witnesses or admit the

16 exhibits?

17 All right. Hearing no objection, the

18 prefiled direct and rebuttal testimony of Thomas A.

19 Schmid will be bound in the record. The prefiled direct

20 testimony of Kenneth A. Desjardins will be bound in the

21 record. The prefiled direct testimony of Michael D. Bean

22 will be bound in the record. The prefiled direct and

23 rebuttal testimony of Doug A. Audette will be bound in

24 the record. The prefiled direct testimony of Robert Joe

25 Tondu will be bound into the record. The prefiled direct

216

1 testimony of Neil R. Taratuta will be bound in the

2 record. The prefiled direct and rebuttal testimony of

3 Thomas V. Vine will be bound in the record. The prefiled

4 direct testimony of Donald Adams will be bound in the

5 record. And the prefiled rebuttal testimony of Thomas J.

6 Allen will be bound in the record. And Exhibits BMP-1

7 through BMP-16 are admitted into evidence.


9

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11

12

13

14

15

16

17

18

19

20

21

22

23

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25

STATE OF MICHIGAN


In the matter of the application of ) CONSUMERS ENERGY COMPANY ) for the Reconciliation of Power Supply ) Cost Recovery (PSCR) Costs and ) Case No. U-17918-R Revenues for the Calendar Year 2016. ) )

DIRECT TESTIMONY

OF

THOMAS A. SCHMID

ON BEHALF OF

CADILLAC RENEWABLE ENERGY, LLC

(REVISED 9-13-2017)

217

1

INTRODUCTION 1

Q. PLEASE STATE YOUR NAME. 2

A. My name is Thomas A. Schmid. 3

4

Q. BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED? 5

A. I am employed by Atlantic Power Corporation as the Plant Manager for Cadillac 6

Renewable Energy, LLC. 7

8

Q. PLEASE DESCRIBE ATLANTIC POWER CORPORATION? 9

A. Atlantic Power Corporation operates and maintains power plants, including biomass 10

plants, and other electric generating assets. Atlantic Power Corporation has a 11

demonstrated record of plant improvement, heat rate efficiency, reliability, availability 12

and safety. 13

14

Q. PLEASE BRIEFLY DESCRIBE THE CADILLAC PLANT. 15

A. Cadillac Renewable Energy owns and operates a merchant plant in Cadillac, Michigan. 16

It consists of electric generating equipment and associated facilities with a capacity of 38 17

MW. 18

19

Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND BUSINESS 20

EXPERIENCE. 21

A. I served in the United States Navy from 1984 through 1988 and was honorably 22

discharged. While in the Navy, I served as a Machinist Mate. I have worked for 25 years 23

218

2

in the electric generation business, 2 years at the McBain Generating Station and 23 years 1

at Cadillac. I was the maintenance manager at the Cadillac plant from 2004 to 2015. I 2

became the Plant Manager of the Cadillac Plant on June 15, 2015. 3

4

Q. PLEASE DESCRIBE YOUR JOB RESPONSIBILITIES. 5

A. As Plant Manager, I am responsible for the safe, environmentally compliant and efficient 6

operation of Cadillac Renewable Energy, LLC. 7

8

Q. WHAT IS YOUR EXPERIENCE AND RESPONSIBILITY FOR FUEL 9

PROCUREMENT? 10

A. I work closely with Cadillac's fuel manager and have final authority regarding the 11

quantities of fuel that Cadillac purchases and the prices that it pays for that fuel. 12

13

Q. PLEASE ELABORATE ON YOUR RESPONSIBILITIES WITH RESPECT TO 14

FUEL PROCUREMENT. 15

A. I am ultimately responsible for all plant activities, including fuel procurement. My 16

responsibilities include overseeing all wood fuel deliveries, ensuring fuel quality, and 17

tracking the volume and cost of wood fuel by supplier. I also oversee the development of 18

new suppliers. 19

20

Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE MICHIGAN PUBLIC 21

SERVICE COMMISSION? 22

219

3

A. Yes. I testified in Consumer's 2015 PSCR reconciliation proceeding, MPSC Case No. U-1

17678-R. 2

3

Q. ON WHOSE BEHALF ARE YOU SUBMITTING YOUR TESTIMONY IN THIS 4

PROCEEDING? 5

A. I am testifying on behalf of Cadillac Renewable Energy, LLC. 6

7

Q. ARE YOU SPONSORING ANY EXHIBITS? 8

A. Yes. I am sponsoring Exhibit BMP-3 (TAS-1) and co-sponsoring Exhibits BMP-1 and 9

BMP-2. 10

11

Q. WERE THESE EXHIBITS PREPARED BY YOU OR UNDER YOUR 12

SUPERVISION? 13

A. BMP-3 was prepared under my supervision. The portions of BMP-1 and BMP-2 relating 14

to Cadillac were also prepared under my supervision. I have reviewed and agree to the 15

remainder of BMP-1 and BMP-2. 16

17



A. The purpose of my testimony is to describe Cadillac Renewable Energy's actual fuel and 20

variable operation and maintenance costs for the period from January 1, 2016 through 21

December 31, 2016 and to demonstrate that those costs were reasonably and prudently 22

incurred. I will also testify as to the amount that Consumers Energy Company paid to 23

220

4

Cadillac Renewable Energy for fuel and variable operation and maintenance costs 1

incurred during that time period. My testimony provides factual support for Cadillac 2

Renewable Energy’s request for recovery of costs under the terms of Public Act 286 of 3

2008, which permits recovery of costs that exceed the amount that a merchant plant is 4

paid under a contract with an eligible utility. 5

6

ELIGIBILITY FOR COST RECOVERY 7

Q. IS THERE A POWER PURCHASE AGREEMENT ("PPA") BETWEEN 8

CADILLAC RENEWABLE ENERGY, LLC AND CONSUMERS ENERGY 9

COMPANY? 10

A. Yes. A complete copy of the agreement, as amended, has been previously provided to 11

the MPSC. My understanding is that it was provided to the parties in both Consumers 12

Energy's 2009 and 2010 PSCR Reconciliation cases, MPSC Case Nos. U-15675-R and 13

U-16045-R. 14

15

Q. HAVE THERE BEEN ANY CHANGES TO THE PPA SINCE IT WAS ENTERED 16

INTO THE RECORD OF THOSE PROCEEDINGS? 17

A. No. 18

19

Q. WAS CADILLAC RENEWABLE ENERGY, LLC'S PPA ENTERED ON OR 20

BEFORE JANUARY 1, 2008? 21

A. Yes. 22

23

221

5

Q. DOES THE CONTRACT HAVE AN INITIAL TERM OF 20 YEARS OR MORE? 1

A. Yes. 2

3

Q. DOES THE PPA PROVIDE FOR CADILLAC RENEWABLE ENERGY, LLC TO 4

SELL ELECTRICITY TO AN ELECTRIC UTILITY WHOSE RATES ARE 5

REGULATED BY THE COMMISSION WITH 1,000,000 OR MORE RETAIL 6

CUSTOMERS IN THIS STATE? 7

A. Yes. 8

9

Q. AT ANY TIME PRIOR TO JANUARY 1, 2008, DID CADILLAC RENEWABLE 10

ENERGY, LLC GENERATE ANY ELECTRICITY IN WHOLE OR IN PART 11

FROM WOOD OR SOLID WOOD WASTES AND SELL THAT ELECTRICITY 12

TO CONSUMERS ENERGY COMPANY? 13

A. Yes. 14

15

Q. DOES CADILLAC RENEWABLE ENERGY, LLC STILL GENERATE 16

ELECTRICITY IN WHOLE OR IN PART FROM WOOD OR SOLID WOOD 17

WASTES AND SELL THAT ELECTRICITY TO CONSUMERS ENERGY 18

COMPANY? 19

A. Yes. 20

21

Q. WITH RESPECT TO ENERGY DELIVERED BETWEEN JANUARY 1, 2016 22

AND DECEMBER 31, 2016, DID CONSUMERS ENERGY COMPANY MAKE 23

222

6

PAYMENTS TO CADILLAC RENEWABLE ENERGY, LLC UNDER THE 1

TERMS OF THE PPA? 2

A. Yes. 3

4

Q. DID PORTIONS OF THE PAYMENTS FROM CONSUMERS ENERGY TO 5

CADILLAC RENEWABLE ENERGY, LLC INCLUDE PAYMENT FOR FUEL 6

AND VARIABLE OPERATION AND MAINTENANCE ("O & M") COSTS? 7

A. Yes. 8

9

Q. DID THE AMOUNT OF CADILLAC RENEWABLE ENERGY'S ACTUAL FUEL 10

AND VARIABLE O & M COSTS EXCEED THE AMOUNT THAT CONSUMERS 11

ENERGY PAID TO CADILLAC RENEWABLE ENERGY, LLC UNDER THE 12

PPA FOR THOSE COSTS? 13

A. Yes. Please see Exhibits BMP-1, BMP-2 and BMP-3 (TAS-1). 14

15

Q. IS CADILLAC RENEWABLE ENERGY, LLC A LANDFILL GAS PLANT, A 16

HYDRO PLANT, OR A MUNICIPAL SOLID WASTE PLANT? 17

A. No. 18

19

Q. IS CADILLAC RENEWABLE ENERGY, LLC ENGAGED IN LITIGATION 20

AGAINST AN ELECTRIC UTILITY SEEKING HIGHER PAYMENTS FOR 21

POWER DELIVERED PURSUANT TO A CONTRACT? 22

A. No. 23

223

7

COST DATA 1

Q. WHAT AMOUNT HAS CADILLAC RENEWABLE ENERGY, LLC SET FORTH 2

ON EXHIBIT BMP-3 (TAS-1) AS ITS ACTUAL FUEL AND VARIABLE 3

OPERATION AND MAINTENANCE COSTS INCURRED FOR SALES OF 4

ELECTRIC GENERATION TO CONSUMERS ENERGY COMPANY DURING 5

2016? 6

A. Cadillac Renewable Energy, LLC has identified $6,395,351 in actual fuel and variable 7

operation and maintenance costs for sales to Consumers Energy Company in 2016. 8

9

Q. DOES THIS AMOUNT INCLUDE ALL OF THE PLANT’S FUEL AND 10

VARIABLE OPERATION AND MAINTENANCE COSTS INCURRED FOR 11

SALES TO CONSUMERS ENERGY COMPANY IN 2016? 12

A. No. For simplicity, Cadillac Renewable Energy, LLC has decided to seek recovery of 13

only certain variable operation and maintenance costs during 2016. As discussed in more 14

detail below, we are seeking recovery for only four variable operation and maintenance 15

cost groups. Cadillac Renewable Energy incurs variable operation and maintenance costs 16

beyond the four groups listed. 17

18

Q. PLEASE STATE THE AMOUNT THAT CONSUMERS ENERGY PAID TO 19

CADILLAC RENEWABLE ENERGY, LLC PURSUANT TO THE PPA 20

BETWEEN CADILLAC AND CONSUMERS FOR FUEL AND VARIABLE 21

OPERATION AND MAINTENANCE COSTS INCURRED DURING 2016. 22

224

8

A. Under the terms of our PPA, Consumers Energy paid our merchant plant a total of 1

$4,064,311 for actual fuel and variable operation and maintenance costs incurred for 2

2016. 3

4

Q. IS THERE A SHORTFALL BETWEEN THE FUEL AND VARIABLE O & M 5

COSTS THAT CADILLAC INCURRED FOR SALES TO CONSUMERS IN 2016 6

AND THE PAYMENTS THAT CADILLAC RECEIVED FROM CONSUMERS 7

FOR THOSE COSTS UNDER ITS PPA? 8

A. Yes, the total shortfall is $2,331,040. 9

10

Q. DO YOU HAVE DOCUMENTATION TO SUPPORT THE COST AND 11

PAYMENT FIGURES THAT YOU HAVE PROVIDED IN RESPONSE TO THE 12

PRIOR FOUR QUESTIONS? 13

A. Yes. These cost figures and Consumers Energy's payments to our merchant plant for 14

actual fuel and variable operation and maintenance costs are detailed on Exhibit BMP-3 15

(TAS-1). 16

17

Q. WHAT AMOUNT IS CADILLAC RENEWABLE ENERGY, LLC SEEKING TO 18

RECOVER IN THIS PROCEEDING? 19

A. As set forth in Exhibit BMP-1, Cadillac Renewable Energy is seeking to recover 20

$1,683,050. This amount could change in the unlikely event that an adjustment is made 21

to the fuel and variable operation and maintenance expense which any other Biomass 22

Merchant Plant is seeking to recover in this proceeding with respect to a month in which 23

225

9

the collective payments to the Biomass Merchant Plants exceed the statutory cap on cost 1

recovery. In the event that the Commission were to make such an adjustment, the capped 2

amount would be reallocated among all of the Biomass Merchant Plants. The result of 3

this reallocation process would be that the amount that Cadillac Renewable Energy is 4

seeking to recover in this proceeding would change in order to accurately reflect its 5

proportionate share of the capped amount. 6

7

Q. THE MPSC's AUGUST 11, 2009 ORDER IN CASE NO. U-16048 ALLOWS THE 8

BMPS TO SUBMIT MONTHLY INVOICES TO CONSUMERS FOR THE 9

AMOUNTS RECOVERABLE UNDER PA 286. THE SAME ORDER REQUIRES 10

CONSUMERS TO MAKE INTERIM MONTHLY PAYMENTS TO THE BMPs 11

TO COVER 80% OF THE INVOICED AMOUNTS. HAS CONSUMERS MADE 12

PARTIAL PAYMENTS TO CADILLAC IN 2016? 13

A. Yes. As reflected in Exhibits BMP-1, BMP-2 and BMP-3, Consumers Energy has paid 14

Cadillac $1,179,555 of the $1,683,050 that Cadillac seeks to recover in this proceeding, 15

leaving a balance due to Cadillac of $503,495. 16

17

Q. ARE YOU SEEKING RECOVERY OF ANY ACTUAL FUEL AND VARIABLE 18

OPERATION AND MAINTENANCE COSTS THAT WERE INCURRED DUE 19

TO CHANGES IN FEDERAL OR STATE ENVIRONMENTAL LAWS OR 20

REGULATIONS THAT WERE IMPLEMENTED AFTER OCTOBER 6, 2008? 21

A. No. 22

23

226

10

PROCUREMENT PROCEDURES 1

Q. PLEASE DESCRIBE THE FUEL OR FUELS THAT CADILLAC RENEWABLE 2

ENERGY, LLC USED TO GENERATE ELECTRICITY DURING THE PERIOD 3

FROM JANUARY 1, 2016 THROUGH DECEMBER 31, 2016. 4

A. Cadillac Renewable Energy used 100% wood waste for fuel to generate electricity in 5

2016. 6

7

Q. PLEASE STATE THE SOURCES AND VOLUMES OF THE FUEL THAT WERE 8

USED DURING 2016. 9

A. Cadillac Renewable Energy used 242,581.36 tons of wood waste from January 1, 2016 10

through December 31, 2016. Of that total, 46.85% was derived from forest waste, 11

41.36% was mill waste, and 11.79% was recycled wood waste such as tub grindings, 12

pallets, stumpage, etc. 13

14

Q. WHAT ARE TUB GRINDINGS? 15

A. Tub grindings are the output of tub grinders, which are machines used to grind or chip 16

wood wastes for mulching, composting or size reduction. 17

18

Q. DOES CADILLAC RENEWABLE ENERGY, LLC HAVE PURCHASE 19

AGREEMENTS WITH ANY FUEL SUPPLIERS? 20

A. No. All fuel is purchased on the spot market at the lowest possible price. 21

22

227

11

Q. PLEASE EXPLAIN WHY YOU HAVE CHOSEN TO PURCHASE ALL OF 1

YOUR FUEL ON THE SPOT MARKET. 2

A. There are two schools of thought regarding the relative advantages and disadvantages of 3

buying on the spot market versus signing long term contracts. Both approaches are 4

reasonable, but we have elected to purchase on the spot market because, with the variety 5

of suppliers in our particular location, it is our best judgment that the spot market will 6

provide our plant with the lowest overall cost. 7

8

Q. WHEN YOU PROCURED THE FUEL THAT WAS CONSUMED DURING 2016, 9

WAS ONE OF YOUR JOB DUTIES TO MINIMIZE THE COST OF FUEL 10

PURCHASED BY CADILLAC RENEWABLE ENERGY, LLC? 11

A. Yes. Cost was a very important consideration. Other important considerations were the 12

reliability, quality and availability of the fuel supply. 13

14

Q. PLEASE DESCRIBE THE STEPS THAT YOU UNDERTOOK TO ACHIEVE 15

THESE OBJECTIVES. 16

A. We worked to minimize the cost of fuel, maintain reliability, quality and availability of 17

the fuel supply for our plant by: 1) building fuel inventory when fuel was available at low 18

prices; 2) maintaining a large number of suppliers; 3) maintaining a prudent fuel 19

inventory going into winter operations; and 4) keeping abreast of changing markets so 20

risks could be avoided and opportunities could be realized. As Plant Manager, and in 21

order to take economic advantage of falling diesel fuel prices, I have implemented a 22

wood fuel pricing formula that lowers the cost that Cadillac will pay for its fuel when 23

228

12

diesel fuel prices are falling and increases the cost that Cadillac will pay for its fuel when 1

diesel fuel prices are rising. 2

3

Q. ARE THERE SEASONAL VARIATIONS IN FUEL COSTS? 4

A. Generally, yes. Normally, costs for wood fuel decrease as summertime availability 5

increases. Prices can go up if inventory levels fall in the winter due to adverse weather. 6

7

Q. ARE THERE REGIONAL DIFFERENCES IN FUEL COSTS? 8

A. Yes. For instance, in areas of the state where there are higher concentrations of low 9

quality species of trees (e.g. Jack Pine), such as in Roscommon, Grayling and Oscoda 10

Counties, the cost of wood fuel is usually below the cost of wood in areas of the state 11

with lower concentrations of low quality species of trees. 12

13

Q. DOES THE DISTANCE BETWEEN THE FUEL SOURCE AND YOUR PLANT 14

HAVE AN IMPACT ON THE FINAL FUEL PRICE? 15

A. Yes, shipping costs are an important component of fuel costs. Generally speaking, fuel 16

becomes more expensive if purchased from a more distant location. 17

18

Q. WHAT WAS YOUR INTENTION IN PROCURING FUEL ON THE SPOT 19

MARKET TO BE USED DURING 2016, AS YOU HAVE DESCRIBED? 20

A. It was our intention to secure a supply of fuel that would be adequate to meet our 21

generating needs, reliable enough to assure our continued performance and sufficiently 22

diversified to ensure the stability of our fuel supply, all within the context of an overall 23

229

13

effort to minimize costs as much as reasonable and practicable. The spot market allows 1

us to adjust pricing quickly in order to take advantage of changing market conditions. 2

3

Q. AT THE TIME YOU PURCHASED YOUR FUEL, WERE YOU ABLE TO 4

OBTAIN THE BEST PRICES THAT WERE AVAILABLE TO YOU? 5

A. Yes. Considering the volumes of fuel, the timing of delivery and the reliability of supply, 6

we selected the lowest prices available to us at that time from more than 40 suppliers. 7

8

Q. IN YOUR OPINION, WERE YOUR COMPANY'S DECISIONS TO PURCHASE 9

FUEL ON THE SPOT MARKET REASONABLE AND PRUDENT BASED ON 10

THE FACTS AND CIRCUMSTANCES KNOWN OR REASONABLY 11

FORESEEABLE AT THE TIME THE DECISIONS WERE MADE? 12

A. Yes. In our location, we were able to use the spot market to achieve the best pricing. 13

14

Q. WHAT FACTORS INFLUENCE THE PRICE OF THE FUELS THAT YOU 15

PROCURE? 16

A. The supply of wood fuel in the marketplace, the plant’s production requirements and the 17

prices offered by our competitors are the main factors influencing the price of fuel. 18

19

Q. IN CONNECTION WITH YOUR FUEL PROCUREMENT DECISIONS FOR 20

2016, DID YOU EXERCISE YOUR BEST JUDGMENT? 21

A. Yes. 22

23

230

14

VARIABLE OPERATION & MAINTENANCE COSTS 1

Q. TURNING TO THE TOPIC OF OPERATION AND MAINTENANCE COSTS, 2

PLEASE DESCRIBE THE VARIABLE OPERATION AND MAINTENANCE 3

COSTS THAT YOU ARE SEEKING TO RECOVER IN THIS PROCEEDING. 4

A. We are seeking to recover the following variable operation and maintenance cost groups: 5

1) Variable Utility and Services, which include water and wastewater disposal costs; 2) 6

Variable Plant Maintenance, includes costs for maintaining all plant equipment that wears 7

in proportion to generation amounts such as the boiler, electrical, fuel and ash systems, 8

steam turbine and generator; 3) Leases and Rentals that vary with plant operations 9

including, costs for equipment such as bulldozers, scaffolding and pumps; 4) Other 10

Variable Operations Expenses, consisting of water treatment chemicals, lubricants, gases, 11

supplies, vehicle maintenance and emissions control costs. 12

13

Q. DOES YOUR PLANT INCUR OTHER VARIABLE OPERATION AND 14

MAINTENANCE COSTS? 15

A. Yes. For simplicity, however, Cadillac Renewable Energy has chosen to seek cost 16

recovery at this time for only those items identified above. 17

18

Q. DID YOU MAKE REASONABLE EFFORTS TO MINIMIZE THE VARIABLE 19

OPERATION AND MAINTENANCE COSTS? 20

A. Yes. 21

22

231

15

Q. PLEASE EXPLAIN THE MEASURES THAT CADILLAC RENEWABLE 1

ENERGY, LLC UNDERTOOK TO CONTROL ITS VARIABLE OPERATION 2

AND MAINTENANCE COSTS. 3

A. The plant developed an ash recycling program which eliminates all costs associated with 4

ash disposal. Urea is purchased in dry form and reconstituted with water at the plant, 5

saving a considerable amount of money. Operators have been given targets of urea 6

consumption on a per MW basis. The plant entered into a fixed price lease agreement for 7

the maintenance of fuel handling equipment. Water costs are reduced by routing what 8

was once waste water into cooling tower makeup water, lowering both raw water 9

purchases and sewer costs. The plant installed reverse osmosis units in series with the 10

demineralizers, which greatly reduce water usage and sewage disposal costs. The 11

installation of variable frequency drives on fan motors reduces the plant’s parasitic loads 12

which in turn lowers fuel consumption. The plant will seek a minimum of three bids for 13

all major contract services to ensure the best possible price and service is obtained. We 14

are continually seeking ways to minimize our costs. 15

16

CONCLUSION 17

Q. IN YOUR OPINION, WERE CADILLAC RENEWABLE ENERGY, LLC'S 18

PURCHASING PRACTICES REASONABLE AND PRUDENT? 19

A. Yes. 20

21

Q. IN YOUR OPINION, WERE CADILLAC RENEWABLE ENERGY, LLC'S 22

ACTUAL FUEL AND VARIABLE OPERATION AND MAINTENANCE COSTS 23

232

16

FOR THE PERIOD FROM JANUARY 1, 2016 THROUGH DECEMBER 31, 2016 1

REASONABLY AND PRUDENTLY INCURRED? 2

A. Yes. 3

4

Q. ARE CADILLAC RENEWABLE ENERGY, LLC’S FUEL AND VARIABLE 5

OPERATION AND MAINTENANCE COST RECORDS AUDITED? 6

A. Yes. Our plant’s 2016 records were audited by KPMG, LLP. No material misstatements 7

were identified in our financial records. The audit included a review of fuel and variable 8

operation and maintenance costs, and revenues. 9

10

Q. IN YOUR OPINION, AS A PERSON WITH EXTENSIVE EXPERIENCE IN THE 11

FIELD OF FUEL PROCUREMENT, DO YOU THINK THAT ANY OF 12

CADILLAC RENEWABLE ENERGY, LLC'S ACTUAL FUEL OR VARIABLE 13

OPERATION AND MAINTENANCE COSTS WERE EXTRAVAGANT, 14

UNNECESSARY, INEFFICIENT OR IMPRUDENT? 15

A. No. 16

17

Q. DOES THAT COMPLETE YOUR DIRECT TESTIMONY IN THIS 18

PROCEEDING? 19

A. Yes. 20

233

STATE OF MICHIGAN



REBUTTAL TESTIMONY

OF

THOMAS A. SCHMID

ON BEHALF OF

CADILLAC RENEWABLE ENERGY, LLC

234

1

INTRODUCTION 1

Q. PLEASE STATE YOUR NAME. 2

A. My name is Thomas A. Schmid. 3

4

Q. ARE YOU THE SAME THOMAS A. SCHMID WHO PREVIOUSLY FILED 5

TESTIMONY IN THIS PROCEEDING? 6

A. Yes. On September 13, 2017, I filed Direct Testimony on behalf of Cadillac Renewable 7

Energy, LLC. ("Cadillac"). 8

9

Q. WHAT IS THE PURPOSE OF YOU REBUTTAL TESTIMONY? 10

A. The purpose of my Rebuttal Testimony is to respond to the Direct Testimony of 11

Sebastian Coppola submitted on behalf of the Attorney General which states that he 12

discovered “that some plants are including the cost of major maintenance and major 13

overhaul of plant equipment as O&M expenses, instead of excluding them as capitalized 14

costs," Coppola Direct Testimony ("CDT") at 14:15-17, specifically as it relates to 15

Cadillac. 16

17

Q. HAVE YOU REVIEWED THE DIRECT TESTIMONY SUBMITTED BY 18

SEBASTIAN COPPOLA ON BEHALF OF THE ATTORNEY GENERAL? 19

A. Yes. 20

21

235

2

Q. HAVE YOU ALSO REVIEWED THE PORTION OF THE REBUTTAL 1

TESTIMONY OF THOMAS ALLEN SUBMITTED ON BEHALF OF THE 2

BIOMASS MERCHANT PLANTS ("BMPs")? 3

A. Yes. 4

5

Q. FOR THE PURPOSE OF AVOIDING REPETITION AND REDUCING THE 6

BURDEN ON THE ALJ AND THE COMMISSION, DO YOU AGREE WITH 7

THAT TESTIMONY AND INCORPORATE IT AS YOUR TESTIMONY ON 8

BEHALF OF CADILLAC IN LIEU OF SEPARATELY RESTATING THE 9

TESTIMONY? 10

A. Yes. 11

12

Q. ARE CADILLAC'S FINANCIALS AUDITED BY INDEPENDENT OUTSIDE 13

ACCOUNTANTS ON AN ANNUAL BASIS? 14

A. Yes. Cadillac's financial statements are audited by KPMG, a nationally and 15

internationally recognized CPA and financial services firm. 16

17

Q. JUST TO BE CLEAR, WERE THE COSTS SUBMITTED BY CADILLAC AS 18

VARIABLE O&M COSTS, INCLUDING THOSE QUESTIONED BY MR. 19

COPPOLA, CHARACTERIZED SPECIFICALLY AS SUCH TO SUPPORT THE 20

REQUEST FOR REIMBURSEMENT AS PART OF THIS RECONCILIATION? 21

A. No. These numbers are taken directly from Cadillac's financial statements. 22

23

236

3

Q. DID CADILLAC ALSO PROVIDE INFORMATION REGARDING ITS 1

VARIABLE O&M COSTS TO THE OTHER BMPs? 2

A. Yes. 3

4

Q. HAVE ANY OF THE OTHER BMPs OBJECTED TO CADILLAC'S 5

CHARACTERIZATION OF THE COSTS DISPUTED BY MR. COPPOLA AS 6

VARIABLE O&M COSTS? 7

A. No. 8

9

Q. DID THE OTHER BMPs SIMILARLY PROVIDE INFORMATION TO 10

CADILLAC THAT INCLUDED THEIR VARIABLE O&M COSTS? 11

A. Yes. 12

13

Q. HAS CADILLAC OBJECTED TO ANY OF THE COSTS THAT MR. COPPOLA 14

DISPUTES AS TO THE OTHER BMPs? 15

A. No. 16

17

Q. ARE YOU FAMILIAR WITH THE PORTION OF MR. COPPOLA'S 18

TESTIMONY IN WHICH HE TAKES ISSUE WITH THE 19

CHARACTERIZATION OF THE O&M COSTS SUBMITTED BY CADILLAC? 20

A. Yes. 21

22

23

237

4

Q. WHAT CHARGES DOES MR. COPPOLA DISPUTE? 1

A. Mr. Coppola notes that Cadillac's 2016 submission lists $200,320 "to replace and 2

overhaul ash handling equipment, the associated conveyor system, and other equipment." 3

CDT at 16:12-14. 4

5

Q. THROUGH DISCOVERY IN THIS PROCEEDING, DID CADILLAC PROVIDE 6

ANY ADDITIONAL DETAIL ON THESE CHARGES? 7

A. Yes. In response to Question 20 of the Attorney General's second discovery requests, a 8

breakdown of the ash handling expenses was provided. 9

10

Q. WHAT EXPENSES ARE INCLUDED IN THIS AMOUNT? 11

A. That amount represents the following work and costs: 12

• Ash surge bin pug mill. Replaced auger housing, two augers, flights, bearings, bull gears

• Overhaul bottom ash conveyor, drag chain, flights, bearings, rollers, and decking

• Purchased new bottom ash trailer • Installed platforms for safe access to

precipitator hoppers

$46,481.00 $18,646.87 $ 8,500.00 $15,200.00

13

Q. MR. COPPOLA NOTES THAT THESE COSTS ARE IDENTIFIED AS HAVING 14

BEEN INCURRED DUE TO "MAJOR MAINTENANCE." WHAT DOES THE 15

TERM "MAJOR MAINTENANCE" REFER TO? 16

A. Cadillac uses the term "major maintenance" to identify projects as to which detailed 17

separate costs are available, as distinguished from smaller routine items like lubrication, 18

bolts, belts, etc. 19

238

5

Q. MR. COPPOLA'S DIRECT TESTIMONY SPECIFICALLY QUESTIONS THE 1

CHARACTERIZATION OF THE COSTS INCURRED TO OVERHAUL THE 2

CONVEYOR. PLEASE EXPLAIN WHAT THESE COSTS REPRESENT. 3

A. The costs were for parts and materials only to maintain the conveyor. 4

5

Q. PLEASE EXPLAIN INCLUSION OF THE COSTS TO INSTALL SAFETY 6

PLATFORMS. 7

A. Cadillac installed two working platforms for safety purposes. The $15,200 was the cost 8

for an outside contractor to engineer, build, and install those two working platforms, 9

which platforms were certified for weight and structure. 10

11

Q. DOES THAT AMOUNT INCLUDE LABOR? 12

A. Yes, but only the labor charges as invoiced by the contractor. No internal labor costs are 13

included. 14

15

Q. WERE THE COSTS OBJECTED TO BY MR. COPPOLA INCURRED TO 16

EXTEND THE USEFUL LIFE OF THE EQUIPMENT OR TO OVERHAUL 17

THE FACILITIES OR IMPROVE THE EFFICIENCY OF THE FACILITY? 18

A. No. 19

20

Q. DOES THIS COMPLETE YOUR REBUTTAL TESTIMONY IN THIS 21

PROCEEDING? 22

A. Yes. 23

239

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of ) CONSUMERS ENERGY COMPANY ) for the Reconciliation of Power Supply ) Cost Recovery (PSCR) Costs and ) Case No. U-17918-R Revenues for the Calendar Year 2016. ) )

DIRECT TESTIMONY

OF

KENNETH A. DESJARDINS

ON BEHALF OF

GENESEE POWER STATION LIMITED PARTNERSHIP

AND

THE BIOMASS MERCHANT PLANTS

(REVISED 9-13-2017)

240

1

INTRODUCTION 1

Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 2

A. My name is Kenneth A. DesJardins and my business address is Genesee Power Station, 3

G5310 N. Dort Hwy, Flint, MI 48505 4

5


A. I am employed by CMS Generation Operating LLC as the Plant General Manager of the 7

Genesee Power Station. 8

9

Q. PLEASE BRIEFLY DESCRIBE THE GENESEE POWER STATION. 10

A. The Genesee Power Station is a merchant plant consisting of electric generating 11

equipment and associated facilities with a capacity of 40 MW. The plant is located in 12

Flint, Michigan and is not owned or operated by an electric utility. The Genesee Power 13

Station is owned by Genesee Power Station Limited Partnership (“GPS”). 14

15

Q. PLEASE DESCRIBE YOUR BUSINESS EXPERIENCE. 16

A. From 1977 through 1985, I worked at Consumers Energy Company's J.C.Weadock Plant 17

as a mechanic, laboratory technician and senior I & C technician. From 1985 through 18

1991, I worked at Consumers' Jackson Equipment Performance Testing Section as an 19

engineering analyst and senior emission test coordinator. From 1991 through 2003, I 20

worked at the D.E. Karn 1 & 2 Plant as a senior production analyst, senior maintenance 21

analyst, operations superintendent and production manager. From 2003 through 2005, I 22

worked at the Karn-Weadock Site as a business manager. From 2005 through 2008, I 23

241

2

worked at the J.R. Whiting Plant as a production manager. From 2008 through 2010, I 1

worked at the Karn-Weadock Site as an Operations Liaison. From 2010 through July 2

2013, I worked at the Karn-Weadock Site as an Outage and Scheduling Manager. On 3

August 1, 2013, I assumed responsibility as Plant Manager at the Genesee Power Station. 4

5


A. I manage all business, operations and maintenance activities at GPS's wood-fired power 7

plant. 8

9



A. I am ultimately responsible for the administration of the exclusive long term fuel supply 12

contract between Genesee Power Station Limited Partnership and Mid-Michigan 13

Recycling, L.C. (“MMR”). MMR procures all of the solid fuels consumed at GPS. 14

15



A. Yes. I testified in Consumers Energy’s 2012 PSCR reconciliation proceeding, MPSC 18

Case No. U-16890-R, its 2013 PSCR reconciliation proceeding, MPSC Case No. U-19

17095-R, its 2014 PSCR reconciliation proceeding, MPSC Case No. U-17317-R, and its 20

2015 PSCR reconciliation proceeding, MPSC Case No. U-17678-R. 21

22

242

3


PROCEEDING? 2

A. The first part of my testimony is on behalf of the Genesee Power Station Limited 3

Partnership. The remainder of my testimony regarding the CPI adjustment, on pages 16 4

through 21, is on behalf of all of the Biomass Merchant Plants (BMPs"). 5

6


A. Yes. I am sponsoring Exhibit BMP-4 and Exhibit BMP-10, and am co-sponsoring 8

Exhibits BMP-1 and BMP-2. 9

10


SUPERVISION? 12

A. Yes as to Exhibits BMP-1, BMP-2, and BMP-4. BMP-10 is a public document prepared 13

by the United States Department of Labor, Bureau of Labor Statistics. 14

15



A. The purpose of my testimony is to describe GPS’s actual fuel and variable operation and 18

maintenance costs for the period from January 1, 2016 to December 31, 2016, and to 19

demonstrate that those costs were reasonably and prudently incurred. I will also testify as 20

to the amount that Consumers Energy Company paid to GPS for fuel and variable 21

operation and maintenance costs incurred during that time period. My testimony 22

provides factual support for GPS’s request for recovery of costs under the terms of Public 23

243

4

Act 286 of 2008, which permits recovery of costs that exceed the amount that a merchant 1

plant is paid for those costs under a contract with an eligible utility. In addition, my 2

testimony will support the Biomass Merchant Plant’s request for a Consumer Price Index 3

adjustment permitted under Public Act 286 of 2008. 4

5


Q. IS THERE A POWER PURCHASE AGREEMENT ("PPA") BETWEEN GPS 7

AND CONSUMERS ENERGY COMPANY? 8




U-16045-R. 12

13



A. No. 16

17

Q. WAS GPS’s PPA ENTERED ON OR BEFORE JANUARY 1, 2008? 18

A. Yes. 19

20


A. Yes. 22

23

244

5

Q. DOES THE PPA PROVIDE FOR GPS TO SELL ELECTRICITY TO AN 1

ELECTRIC UTILITY WHOSE RATES ARE REGULATED BY THE 2

COMMISSION WITH 1,000,000 OR MORE RETAIL CUSTOMERS IN THIS 3

STATE? 4

A. Yes, the PPA is with Consumers Energy Company. 5

6

Q. AT ANY TIME PRIOR TO JANUARY 1, 2008, DID GPS GENERATE ANY 7



COMPANY? 10

A. Yes. 11

12

Q. DOES GPS STILL GENERATE ELECTRICITY IN WHOLE OR IN PART 13



A. Yes. 16

17



PAYMENTS TO GPS UNDER THE TERMS OF THE PPA? 20

A. Yes. 21

22

245

6

Q. DID PORTIONS OF THE PAYMENTS FROM CONSUMERS ENERGY TO GPS 1

INCLUDE PAYMENT FOR FUEL AND VARIABLE OPERATION AND 2

MAINTENANCE ("O & M") COSTS? 3

A. Yes. 4

5

Q. DID THE AMOUNT OF GPS's ACTUAL FUEL AND VARIABLE O & M COSTS 6

EXCEED THE AMOUNT THAT CONSUMERS ENERGY PAID TO GPS UNDER 7

THE PPA FOR THOSE COSTS? 8

A. Yes. Please see Exhibits BMP-1, BMP-2 and BMP-4. 9

10

Q. IS GPS A LANDFILL GAS PLANT, A HYDRO PLANT, OR A MUNICIPAL 11

SOLID WASTE PLANT? 12

A. No. 13

14

Q. IS GPS ENGAGED IN LITIGATION AGAINST AN ELECTRIC UTILITY 15

SEEKING HIGHER PAYMENTS FOR POWER DELIVERED PURSUANT TO A 16

CONTRACT? 17

A. No. 18

19

COST DATA 20

Q. WHAT AMOUNT HAS GPS SET FORTH ON EXHIBIT BMP-4 AS ITS ACTUAL 21

FUEL AND VARIABLE OPERATION AND MAINTENANCE COSTS 22

246

7

INCURRED FOR SALES OF ELECTRIC GENERATION TO CONSUMERS 1

ENERGY COMPANY DURING 2016? 2

A. GPS has identified $5,745,251 in actual fuel and variable operation and maintenance 3

costs for sales to Consumers Energy Company in 2016. 4

5




A. No. For simplicity, however, Genesee has decided to seek recovery of only certain 9

variable operation and maintenance costs during 2016. As discussed in more detail 10

below, Genesee is seeking recovery for only the categories of variable operation and 11

maintenance costs listed below. GPS incurs variable operation and maintenance costs 12

beyond the categories listed below. 13

14

Q. PLEASE STATE THE AMOUNT THAT CONSUMERS ENERGY PAID TO GPS 15

PURSUANT TO THE PPA BETWEEN GPS AND CONSUMERS FOR FUEL AND 16

VARIABLE OPERATION AND MAINTENANCE COSTS INCURRED DURING 17

2016. 18



2016. 21

22

247

8


COSTS THAT GPS INCURRED FOR SALES TO CONSUMERS IN 2016 AND 2

THE PAYMENTS THAT GPS RECEIVED FROM CONSUMERS FOR THOSE 3

COSTS UNDER ITS PPA? 4


6




A. Yes. The actual fuel and variable operation and maintenance costs, and the payments to 10

GPS for actual fuel and variable operation and maintenance costs are detailed on Exhibit 11

BMP-4. 12

13

Q. WHAT AMOUNT IS GPS SEEKING TO RECOVER IN THIS PROCEEDING? 14

A. As set forth in BMP-1, GPS is seeking to recover $1,736,834. This amount could change 15

in the unlikely event that an adjustment is made to the fuel and variable operation and 16

maintenance expense which any other BMP is seeking to recover in this proceeding with 17

respect to a month in which the collective payments to the BMPs exceed the statutory cap 18

on cost recovery. While we do not believe that any adjustment to any other BMP’s costs 19

would be appropriate or required, it is theoretically possible that an adjustment could be 20

made. In that event, the capped amount would be reallocated among all of the BMPs, 21

taking into account the adjustment. The result of this reallocation process would be that 22

248

9

the amount that GPS is seeking to recover in this proceeding would change in order to 1

accurately reflect its proportionate share of the capped amount. 2

3






PARTIAL PAYMENTS TO GPS IN 2016? 9

A. Yes, as reflected in Exhibits BMP-1, BMP-2 and BMP-4 (KAD-1), Consumers Energy 10

has paid GPS $1,050,468 of the $1,736,834 that GPS seeks to recover in this proceeding, 11

leaving a balance due to GPS of $686,366. 12

13

Q. IS GPS SEEKING RECOVERY OF ANY ACTUAL FUEL AND VARIABLE 14




A. No. 18

19

249

10


Q. PLEASE DESCRIBE THE FUEL OR FUELS THAT GPS USED TO GENERATE 2

ELECTRICITY DURING 2016. 3

A. GPS burned a blend of several waste wood materials as its primary fuel, a de minimis 4

(less than 2%) amount of TDF and natural gas for start-ups. 5

6

Q. PLEASE STATE THE SOURCE OF THE FUEL AND THE VOLUMES THAT 7

GPS USED DURING 2016. 8

A. From January 1, 2016 through December 31, 2016, GPS burned 168,212.35 green tons of 9

wood waste which was procured by Mid-Michigan Recycling, L.C. (“MMR”) from 10

multiple sources and used at the Genesee Power Station. The sources of the wood waste 11

included wood from wood recovery yards, municipalities, utility companies, land 12

clearing companies, tree trimming companies, private residences, industrial companies, 13

and construction companies. 14

15

Q. WHAT TYPES OF WASTE WOOD FUEL DID GPS CONSUME? 16

A. Wood waste fuel sources included the following types of material: 17

• Slash and forest residue 18

• Tree-trimming material from utility line clearance operations 19

• Wood waste from land-clearing operations 20

• Branches and brush 21

• Lumber (cut offs) from construction activities 22

• Waste pallet wood material 23

250

11

• Sawdust 1

• Waste plywood 2

• Waste pressed board 3

• Waste oriented strand board 4

• Wood waste from secondary manufacturing 5

6

Q. PLEASE EXPLAIN THE RELATIONSHIP BETWEEN GPS AND MMR 7

SUMMARIZE THE PRINCIPAL TERMS OF GPS’ FUEL SUPPLY 8

AGREEMENT WITH MMR. 9

A. GPS has an exclusive wood waste delivery services agreement with MMR. The fuel 10

supply agreement between MMR and GPS contains the following principal provisions: 11

Term: The term of the agreement expires on December 31, 2021, subject to 12

earlier termination in certain limited circumstances of non-performance by either 13

party. 14

Quantity of Wood: The agreement is an exclusive supply agreement for MMR to 15

supply 100% of GPS’s wood waste requirements for its biomass power plant 16

located in Flint, Michigan. There are supply and scheduling procedures to 17

provide some flexibility to both parties. 18

Specification of Wood Waste: All wood waste supplied under the agreement 19

must conform to specifications related to moisture-content, size and quality with 20

respect to the percentage of non-combustibles. 21

Pricing Arrangements: MMR charges a service fee for each ton of wood waste 22

fuel delivered to GPS that allows for cost recovery of all reasonable expenses 23

251

12

incurred by MMR associated with the identification, collection, loading, 1

processing, sorting, storage, handling, transportation and unloading of wood 2

waste. Such service fee is subject to adjustment based upon a cost recovery and 3

return formula where, in general, higher service fees result in MMR earning lower 4

returns and lower service fees result in MMR earning higher returns. 5

6

Q. IN YOUR OPINION, WAS GPS’s DECISION TO ENTER INTO THE 7

EXCLUSIVE SUPPLY AGREEMENT WITH MMR REASONABLE AND 8

PRUDENT BASED ON THE FACTS AND CIRCUMSTANCES KNOWN OR 9

REASONABLY FORESEEABLE AT THE TIME THE DECISION WAS MADE? 10

A. Yes. Purchasing fuel via long-term contracts, or via the spot market, can both be 11

reasonable procurement practices. The decision to utilize a long-term fuel contract or 12

rely upon the spot market to procure fuel involves the balancing of a variety of risks. 13

Long-term contracts mitigate the risk of fuel supply shortages and can be used to mitigate 14

the risk of price fluctuations. Long-term contracts, however, may lock a buyer into prices 15

that are higher or lower than what the spot market would otherwise provide at any given 16

moment. Utilizing the spot market ensures that the buyer will receive the lowest 17

available price for fuel on a short-term basis that day, however, the buyer may experience 18

dramatic price fluctuations and possible fuel shortages. The decision to utilize long-term 19

contracts or the spot market necessarily involves the balancing of a variety of complex 20

factors including, fuel price level, fuel supply reliability, and fuel price volatility. GPS’s 21

decision to enter into a long-term fuel supply agreement with MMR was reasonable. 22

23

252

13

Q. IS THERE A SPOT MARKET FOR BIOMASS FUEL? 1

A. Not in the same way as there is for natural gas, or other fuel commodities. There are not 2

any nationally published indices for waste wood prices, nor is there a commodities 3

exchange that a buyer can utilize to obtain fuel from a fuel supplier. When a Biomass 4

Merchant Plant (“BMP”) seeks to procure biomass fuel on ‘the spot market’, the BMP 5

will contact area biomass fuel suppliers directly to identify the availability and price for 6

fuel at that time. 7

8

Q. ARE THERE SEASONAL VARIATIONS IN YOUR FUEL COSTS? 9

A. Generally, yes. Normally, costs for wood fuel decrease during the summertime when 10

availability of wood increases. Similarly, costs for wood fuel can go up during the winter 11

due to adverse weather conditions and decreased availability of wood wastes. 12

13


A. Yes. The proximity to wood-based infrastructure industries like sawmills and timber 15

operations in the state’s northern forests have a dramatic impact on costs. In those 16

northern regions, the costs of wood fuel are generally lower than the costs associated with 17

acquiring wood fuel in the urban areas of the southern regions in the state where fewer 18

forests exist. As you can see, on Exhibit BMP-10 (KAD-2), the BMPs are located 19

throughout the state. 20

21

253

14

Q. DOES THE DISTANCE BETWEEN THE FUEL SOURCE AND A BIOMASS-1

FUELED GENERATION PLANT HAVE AN IMPACT ON THE FINAL FUEL 2

PRICE? 3

A. Yes, trucking costs are an important component of fuel costs. Generally speaking, wood 4

fuel becomes more expensive if purchased from a more distant location. 5

6

Q. DO GPS's FUEL COSTS DIFFER FROM OTHER BMP's? 7

A. Yes. GPS must arrange for a diverse supply of multiple types of waste wood from 8

numerous different sources within an urban area. The lack of plentiful fuel supplies of 9

waste wood near the GPS generating plant increases the cost of wood fuel for GPS. 10

11

Q. WHAT MECHANISMS ENSURE THAT THE BMPS’ COSTS, INCLUDING 12

GPS’s COSTS, ARE REASONABLY AND PRUDENTLY INCURRED? 13

A. A major factor ensuring that the BMPs’ costs are reasonably and prudently incurred is 14

that the BMPs are not guaranteed cost recovery. As Exhibit BMP-1 shows, even with the 15

additional $1,000,000 per month capped payment under Public Act 286 of 2008, the 16

BMPs’ actual fuel and variable operation and maintenance costs exceeded the payments 17

that the BMPs received for those costs pursuant to their contracts with Consumers during 18

all twelve months of 2016. Thus, the more the BMPs spend on fuel and variable O&M 19

costs, the more money they could lose on fuel and variable O&M costs. Additionally, the 20

BMPs cannot simply raise their prices to cover their actual costs. The risk of financial 21

loss and the desire for returns on investment are significant incentive mechanisms that 22

ensure that the BMPs work to keep their fuel and operating costs low. 23

254

15

1

Q. WHAT WERE THE EFFECTS DURING 2016 OF GPS HAVING ENTERED 2

INTO THE FUEL SUPPLY AGREEMENT WITH MMR? 3

A. The effects of entering into this agreement were that GPS was able to secure a supply of 4

wood waste fuel that was of adequate quality to meet GPS’s generating needs, reliable 5

enough to assure GPS’s continued performance as required by the terms of the PPA and 6

sufficiently diversified to ensure the stability of supply, all within the context of an 7

overall effort to minimize costs as much as reasonable and practicable. 8

9





A. We are seeking to recover the following variable operation and maintenance costs: 1) 14

water supply and treatment costs; 2) sewer and wastewater disposal costs; 3) ash handling 15

costs; 4) fuel handling costs; 5) emission control costs; 6) water treatment costs; and 7) 16

variable maintenance costs. 17

18



A. Yes. For simplicity, however, Genesee has chosen to seek cost recovery at this time for 21

only those items identified above. 22

23

255

16



A. Yes, to the extent practicable, we made every reasonable effort to control these costs by 3

competitively bidding purchases where possible, and by always looking for lower cost 4

materials, which meet our minimum specifications for the intended use. 5

6

CONCLUSIONS REGARDING COST RECOVERY 7

Q. IN YOUR OPINION, WERE GPS’s ACTUAL FUEL AND VARIABLE 8

OPERATION AND MAINTENANCE COSTS FOR THE PERIOD FROM 9

JANUARY 1, 2016 THROUGH DECEMBER 31, 2016 REASONABLY AND 10

PRUDENTLY INCURRED? 11

A. Yes. 12

13

Q. IN YOUR OPINION, DO YOU THINK THAT ANY OF GPS’s ACTUAL FUEL 14

OR VARIABLE OPERATION AND MAINTENANCE COSTS WERE 15

EXTRAVAGANT, UNNECESSARY, INEFFICIENT OR IMPRUDENT? 16

A. Absolutely not. 17

18

Q. ARE GPS’s FUEL AND VARIABLE OPERATION AND MAINTENANCE COST 19

RECORDS AUDITED? 20

A. Yes. Our plant’s 2016 records were audited by Plante Moran. The audit report indicates 21

that GPS’ financial statements present fairly, in all material respects, the financial 22

position of GPS. 23

256

17

1

CONSUMER PRICE INDEX ADJUSTMENT 2

Q DOES PUBLIC ACT 286 OF 2008 PERMIT AN INFLATIONARY ADJUSTMENT 3

TO THE $1,000,000 PER MONTH LIMIT ON THE AMOUNTS RECOVERABLE 4

BY THE BIOMASS MERCHANT PLANTS? 5

A. Yes. Public Act 286 of 2008 requires an adjustment of the initial $1,000,000 per month 6

limit on the amounts recoverable by the biomass merchant plants if their actual fuel and 7

variable operation and maintenance costs exceed the amount that they are paid under 8

their respective PPAs for those costs by more than $1,000,000 per month. 9

10

Q. DID THE BMPS’ ACTUAL FUEL AND VARIABLE OPERATION AND 11

MAINTENANCE COSTS EXCEED THE AMOUNT THAT THE BMPS WERE 12

PAID BY CONSUMERS ENERGY FOR THOSE COSTS UNDER PPAS BY 13

MORE THAN $1,000,000 IN ANY MONTH DURING 2016? 14

A. Yes. As shown on Exhibit BMP-1, Line 8, the shortfall between the reasonably and 15

prudently incurred actual fuel and variable operation and maintenance costs and 16

Consumers Energy Company's payments for those costs under the PPAs exceeded 17

$1,000,000 in all months of 2016. 18

19

Q. PLEASE EXPLAIN EXHIBIT BMP-1. 20

A. Lines 1-7 of Exhibit BMP-1 show the recoverable shortfall between 1) the reasonably 21

and prudently incurred actual fuel and variable operation and maintenance costs incurred 22

by each Biomass Merchant Plant and 2) the amounts that Consumers Energy paid the 23

257

18

BMPs for those costs for each month from January 1, 2016 through December 31, 2016. 1

The monthly shortfall amounts are derived from Exhibits BMP-3 through BMP-9. Line 8 2

is the summation of lines 1 through 7. 3

4

Line 9 of Exhibit BMP-1 identifies the unadjusted capped amount of Consumers Energy 5

Company’s payments to the Biomass Merchant Plants, as established by Public Act 286 6

of 2008. 7

8

Line 10 shows the percentage of the Biomass Merchant Plants’ aggregate actual fuel and 9

variable operation and maintenance costs that is recoverable under the unadjusted 10

statutory cap. 11

12

Lines 11 through 17 show the capped payments due to each Biomass Merchant Plant by 13

month. The amounts reflected are equal to each Biomass Merchant Plant’s monthly 14

shortfall multiplied times the recoverable percentage. Line 18 is the summation of lines 15

11 through 17. Line 18 shows the total amounts of the capped payments that are due to 16

the Biomass Merchant Plants for calendar year 2016, before application of the statutory 17

CPI adjustment. 18

19

Lines 19 through 26 are calculated in the same manner as lines 1 through 18, except, as 20

explained below, they reflect the application of a Consumer Price Index adjustment for 21

each month of 2016. 22

23

258

19

Q. ARE THE BIOMASS MERCHANT PLANTS REQUESTING THAT THE 1

COMMISSION ADJUST THE MONTHLY LIMIT? 2

A. Yes. The Biomass Merchant Plants request that the Commission adjust the $1,000,000 3

monthly limit at a rate equal to the percentage increase in the annual average United 4

States Consumer Price Index for All Urban Consumers between 2009 and 2016. 5

6

Q. WHAT WAS THE ANNUAL AVERAGE LEVEL OF THE CONSUMER PRICE 7

INDEX FOR ALL URBAN CONSUMERS, AS DEFINED AND REPORTED BY 8

THE UNITED STATED DEPARTMENT OF LABOR, BUREAU OF LABOR 9

STATISTICS, FOR 2009? 10

A. The Consumer Price Index for 2009 was 214.537. See, Exhibit BMP-10. 11

12

Q. WHAT WAS THE ANNUAL AVERAGE LEVEL OF THE CONSUMER PRICE 13

INDEX FOR ALL URBAN CONSUMERS, AS DEFINED AND REPORTED BY 14

THE UNITED STATED DEPARTMENT OF LABOR, BUREAU OF LABOR 15

STATISTICS, FOR 2016? 16

A. The Consumer Price Index for 2016 was 240.007. See, Exhibit BMP-10. 17

18

Q. THUS, WHAT WAS THE PERCENTAGE INCREASE IN THE CONSUMER 19

PRICE INDEX FROM 2009 THROUGH 2016? 20

A. The percentage increase from 2009 through 2016 was 11.87207% (240.007 - 214.537 = 21

25.47 and 25.47/ 214.537 = 0.1187207). 22

23

259

20

Q. WHAT SHOULD THE MONTHLY LIMIT BE FOR 2016 FOR AMOUNTS 1

RECOVERABLE FOR FUEL AND VARIABLE OPERATION AND 2

MAINTENANCE COSTS BY THE BIOMASS MERCHANT PLANTS? 3

A. The monthly limit should be set at $1,118,721 per month. 4

5

Q. DID YOU FOLLOW THE SAME METHODOLOGY IN THIS CASE (U-17918-R) 6

THAT WAS USED IN PREVIOUS RECONCILIATION CASES? 7

A. Yes, the BMPs used the change in the CPI from the base year to the year being 8

reconciled. Specifically, I used the change in the CPI from 2009 to 2016 in my testimony 9

in this case because 2009 is the base year and 2016 is the year being reconciled. This 10

adjustment accounts for all of the inflation that has occurred since 2009. 11

12

Q. IS YOUR PROPOSED ADJUSTMENT CONSISTENT WITH PUBLIC ACT 286 13

OF 2008? 14

A. Yes. Act 286 incorporates a CPI inflation adjustment. In part, Act 286 states that "As 15

used in this subsection [8] , 'United States consumer price index' means the United States 16

consumer price index for all urban consumers as defined and reported by the United 17

States department of labor, bureau of labor statistics." 18

19

AMOUNTS REQUESTED BY BMPs 20

Q. WHAT IS THE TOTAL AMOUNT OF FUEL AND VARIABLE OPERATION 21

AND MAINTENANCE COSTS SUBJECT TO THE MONTHLY LIMIT THAT 22

260

21

THE BMPs ARE REQUESTING FOR THE PERIOD JANUARY 1, 2016 1

THROUGH DECEMBER 31, 2016? 2

A. In total, the Biomass Merchant Plants request that the Commission approve recovery of 3

$13,424,648 in capped payments from Consumers Energy Company for the time period 4

January 1, 2016 through December 31, 2016 as reflected on lines 26 and 27 of Exhibit 5

BMP-1 and on line 8, column E, Exhibit BMP-2. 6

7

Q. PLEASE EXPLAIN EXHIBIT BMP-2. 8

A. Exhibit BMP-2 is the reconciliation of Consumers Energy Company’s actual payments to 9

each BMP for fuel and variable operation and maintenance costs incurred from January 1, 10

2016 through December 31, 2016. Exhibit BMP-2 shows the total recoverable shortfall 11

for each Biomass Merchant Plant, and the capped payment due to each Biomass 12

Merchant Plant for 2016 both before and after the application of the CPI adjustment. The 13

exhibit then shows the total amount of PA 286 payments that Consumers Energy has paid 14

each Biomass Merchant Plant based on estimated costs incurred from January 1, 2016 15

through December 31, 2016. Consumers Energy Company’s total PA 286 payments to 16

the Biomass Merchant Plants equaled $9,600,002 in 2016. The total payments reflect 17

approximately 80% of the BMPs’ submitted shortfall, up to the unadjusted statutory cap, 18

consistent with the remittance procedures approved by the Commission in MPSC Case 19

No. U-16048. The exhibit then reflects the recoverable amount for environmental costs 20

incurred due to changes in state or federal laws implemented after October 6, 2008, the 21

effective date of PA 286 of 2008. Those environmental costs are not subject to the 22

statutory cap. The exhibit then shows the remaining amount that is due to each Biomass 23

261

22

Merchant Plant. The total remaining amount due to each BMP is equal to the capped 1

payment due to the BMP (with the CPI adjustment), plus the amount not subject to the 2

cap, if any, minus Consumers Energy’s actual PA 286 payments to the BMP during 2016. 3

4


PROCEEDING? 6

A. Yes, it does. 7

262

STATE OF MICHIGAN


DIRECT TESTIMONY

OF

MICHAEL D. BEAN

ON BEHALF OF

GRAYLING GENERATING STATION LIMITED PARTNERSHIP

(REVISED 9-13-2017)

263

1

INTRODUCTION 1


A. My name is Michael D. Bean and my business address is One Energy Plaza; EP11-414; 3

Jackson, Mi 49201. 4

5


A. I am employed by CMS Enterprises as the Asset Manager responsible for the Grayling 7

Generating Station plant. 8

9

Q. PLEASE BRIEFLY DESCRIBE THE GRAYLING GENERATING STATION. 10

A. The Grayling Generating Station is a merchant plant consisting of electric generating 11

equipment and associated facilities with a capacity of 38 MW. The plant is located in 12

Grayling Township, Michigan and is not owned or operated by an electric utility. The 13

Grayling Generating Station is owned by the Grayling Generating Station Limited 14

Partnership (“GGS”). 15

16


EXPERIENCE. 18

A. I graduated from the University of Detroit in 1977 with a BS in Finance and in 1983 with 19

a Masters of Business Administration. I began my professional career at American 20

Natural Resources in 1977 in various finance and accounting roles. I participated on the 21

team that built a $2 billion coal gasification plant and then started up the first independent 22

power subsidiary at American Natural Resources. In 1988, I joined CMS Energy as we 23

264

2

started growing the independent power business at CMS. At CMS, I have filled a variety 1

of roles including Director of Accounting, Group Controller, Senior Associate Project 2

Finance, International Asset Manager and Asset Manager. When Phil Lewis retired last 3

year, I also served as the interim General Manager of the Grayling Generating Station LP 4

biomass plant for four months until the new General Manager was hired. 5

6


A. I currently have overall responsibility for the Grayling Generating Station LP biomass 8

power plant. The General Manager of the Grayling Generating Station LP reports to me. 9

10

Q. WITHIN YOUR ORGANIZATION, ARE YOU RESPONSIBLE FOR FUEL 11

PROCUREMENT? 12

A. Yes. AJD procures the fuel for GGS and reports to me and the plant General Manager 13

regarding its fuel procurement activities. 14

15

Q. APPROXIMATELY HOW MANY YEARS HAVE YOU HAD RESPONSIBILITY 16

FOR FUEL PROCUREMENT? 17

A. Five years. 18

19



265

3

A. As Asset Manager, I oversee the administration of the fuel supply agreement with AJD 1

Forest Products. This includes ensuring we have the right amount and type of waste 2

wood material to efficiently operate the boiler at GGS. 3

4




17678-R. 8

9


PROCEEDING? 11

A. I am submitting testimony on behalf of Grayling Generating Station Limited Partnership. 12

13


A. Yes. I am sponsoring Exhibit BMP-5 and co-sponsoring Exhibits BMP-1 and BMP-2. 15

16


SUPERVISION? 18

A. Yes. 19

20

266

4



A. The purpose of my testimony is to describe GGS’s actual fuel and variable operation and 3

maintenance costs for the period from January 1, 2016 to December 31, 2016, and to 4

demonstrate that those costs were reasonably and prudently incurred. I will also testify as 5

to the amount that Consumers Energy Company paid to GGS for fuel and variable 6

operation and maintenance costs incurred during that time period. My testimony 7

provides factual support for GGS’s request for recovery of costs under the terms of 8

Public Act 286 of 2008, which permits recovery of costs that exceed the amount that a 9

merchant plant is paid under contract with an eligible utility for those costs. 10

11


Q. IS THERE A POWER PURCHASE AGREEMENT ("PPA") BETWEEN GGS 13





U-16045-R. 18

19



A. No. 22

23

267

5

Q. WAS GGS’s PPA ENTERED ON OR BEFORE JANUARY 1, 2008? 1

A. Yes. 2

3


A. Yes. 5

6

Q. DOES THE PPA PROVIDE FOR GGS TO SELL ELECTRICITY TO AN 7



STATE? 10

A. Yes, our PPA is with Consumers Energy Company. 11

12

Q. AT ANY TIME PRIOR TO JANUARY 1, 2008, DID GGS GENERATE ANY 13



COMPANY? 16

A. Yes. 17

18

Q. DOES GGS STILL GENERATE ELECTRICITY IN WHOLE OR IN PART 19



A. Yes. 22

23

268

6



PAYMENTS TO GGS UNDER THE TERMS OF THE PPA? 3

A. Yes. 4

5

Q. DID PORTIONS OF THE PAYMENTS FROM CONSUMERS ENERGY TO GGS 6



A. Yes. 9

10

Q. DID THE AMOUNT OF GGS's ACTUAL FUEL AND VARIABLE O & M COSTS 11

EXCEED THE AMOUNT THAT CONSUMERS ENERGY PAID TO GGS 12

UNDER THE PPA FOR THOSE COSTS? 13

A. Yes. Please see Exhibits BMP-1, BMP-2 and BMP-5 (MDB-1). 14

15

Q. IS GGS A LANDFILL GAS PLANT, A HYDRO PLANT, OR A MUNICIPAL 16


A. No. 18

19

Q. IS GGS ENGAGED IN LITIGATION AGAINST AN ELECTRIC UTILITY 20


CONTRACT? 22

A. No. 23

269

7

COST DATA 1

Q. WHAT AMOUNT HAS GGS SET FORTH ON EXHIBIT BMP-5 AS ITS 2

ACTUAL FUEL AND VARIABLE OPERATION AND MAINTENANCE COSTS 3

INCURRED FOR SALES OF ELECTRIC GENERATION TO CONSUMERS 4

ENERGY COMPANY DURING 2016? 5

A. GGS has identified $5,244,195 in actual fuel and variable operation and maintenance 6

costs for sales to Consumers Energy Company in 2016. 7

8




A. No. For simplicity, however, Grayling Generating Station has decided to seek recovery 12

of only certain variable operation and maintenance costs during 2016. As discussed in 13

more detail below, we are seeking recovery for only the categories of variable operation 14

and maintenance costs listed below. Grayling Generating Station incurs variable 15

operation and maintenance costs beyond the categories listed below. 16

17

Q. PLEASE STATE THE AMOUNT THAT CONSUMERS ENERGY PAID TO GGS 18

PURSUANT TO THE PPA BETWEEN GGS AND CONSUMERS FOR FUEL 19

AND VARIABLE OPERATION AND MAINTENANCE COSTS INCURRED 20

DURING 2016. 21

270

8



2016. 3

4


COSTS THAT GGS INCURRED FOR SALES TO CONSUMERS IN 2016 AND 6

THE PAYMENTS THAT GGS RECEIVED FROM CONSUMERS FOR THOSE 7



10





our merchant plant for actual fuel and variable operating and maintenance costs, are 15

detailed on Exhibit BMP-5. 16

17

Q. WHAT AMOUNT IS GGS SEEKING TO RECOVER IN THIS PROCEEDING? 18

A. As set forth in Exhibit BMP-1, GGS is seeking to recover $1,069,360. This amount 19

could change in the unlikely event that an adjustment is made to the fuel and variable 20

operation and maintenance expense which any other BMP is seeking to recover in this 21

proceeding with respect to a month in which the collective payments to the BMPs exceed 22

the statutory cap on cost recovery. While we do not believe that any adjustment to any 23

271

9

other BMP’s costs would be appropriate or required, it is theoretically possible that an 1

adjustment could be made. In that event, the capped amount would be reallocated among 2

all of the BMPs, taking into account the adjustment. The result of this reallocation 3

process would be that the amount that GGS is seeking to recover in this proceeding 4

would change in order to accurately reflect its proportionate share of the capped amount. 5

6





TO COVER 80% OF THE INVOICED AMOUNTS. DID CONSUMERS MAKE 11

PARTIAL PAYMENTS TO GGS IN 2016? 12

A. Yes, as reflected in Exhibits BMP-1, BMP-2 and BMP-5 (MDB-1), Consumers Energy 13

has paid GGS $828,067 of the $1,069,360 that GGS seeks to recover in this proceeding, 14

leaving a balance due to GGS of $241,293. 15

16

Q. IS GGS SEEKING RECOVERY OF ANY ACTUAL FUEL AND VARIABLE 17




A. No. 21

22

272

10


Q. PLEASE DESCRIBE THE FUEL OR FUELS THAT GGS USED TO GENERATE 2

ELECTRICITY DURING 2016. 3

A. GGS used waste wood (consisting of bark, chips, sawdust and mill shavings), and tire 4

derived fuel (tire chips or “TDF”). 5

6

Q. WITH RESPECT TO EACH OF THE FUELS THAT YOU HAVE LISTED, 7

PLEASE SPECIFY THE VOLUMES OF EACH TYPE OF FUEL THAT WERE 8

USED DURING 2016. 9

A. GGS used 236,752 tons of waste wood and 3,299 tons of TDF from January 1, 2016 10

through December 31, 2016. 11

12

Q. DOES GGS HAVE FUEL SUPPLY PURCHASE AGREEMENTS WITH ANY 13

FUEL SUPPLIERS? 14

A. Yes. GGS has a long-term fuel supply agreement with AJD Forest Products. A letter of 15

intent was executed with AJD around 1987. A definitive wood fuel supply agreement 16

was executed in October 1990. AJD signed an amended long-term fuel supply agreement 17

with GGS on January 1, 1995. AJD has continued to be the exclusive supplier of wood 18

fuel to the project since that time. GGS does not have a fuel supply agreement for TDF. 19

GGS purchases TDF on the spot market. 20

21

Q. PLEASE EXPLAIN WHY GGS USES BOTH A FUEL SUPPLY AGREEMENT 22

AS WELL AS SPOT MARKET PURCHASES. 23

273

11

A. Purchasing fuel via long-term contracts, or via the spot market, can both be reasonable 1

procurement practices. The decision to utilize a long-term fuel contract or rely upon the 2

spot market to procure fuel involves the balancing of a variety of risks. Long-term 3

contracts mitigate the risk of fuel supply shortages and can be used to mitigate the risk of 4

price fluctuations. Long-term contracts, however, may lock a buyer into prices that are 5

higher or lower than what the spot market would otherwise provide at any given moment. 6

Utilizing the spot market ensures that the buyer will receive the lowest available price for 7

fuel on a short-term basis that day, however, the buyer may experience dramatic price 8

fluctuations and possible fuel shortages. The decision to utilize long-term contracts or 9

the spot market necessarily involves the balancing of a variety of complex factors 10

including, fuel price level, fuel supply reliability, and fuel price volatility. Given the fuel 11

supply options available to GGS, the most cost effective way to obtain a reliable supply 12

of fuel was to purchase our wood through a long-term contract and our supply of TDF on 13

the spot market. 14

15

Q. PLEASE SUMMARIZE THE PRINCIPAL TERMS OF GGS’s FUEL SUPPLY 16

AGREEMENT WITH AJD. 17

A. This agreement requires the supplier to provide various types of waste wood at the 18

“lowest Rates possible” plus a small service fee. Based on price and moisture content, 19

the supplier can qualify for a bonus. 20

21

Q. WHY DID GGS DECIDE TO CONTRACT WITH ONLY ONE WOOD 22

SUPPLIER INSTEAD OF MULTIPLE SUPPLIERS? 23

274

12

A. In order for the plant to be financed, the lenders required a wood supplier with experience 1

in the supply of waste wood. AJD fit that requirement. By contracting with AJD, GGS is 2

in effect contracting with multiple suppliers since AJD buys on GGS’s behalf from many 3

different suppliers. Our contract with AJD has incentives to keep the costs low. 4

5

Q. WHAT WERE THE EFFECTS DURING 2016 OF HAVING ENTERED INTO 6

THE FUEL SUPPLY AGREEMENT? 7

A. The effects of entering into this agreement were that GGS was able to secure a supply of 8

wood fuel that was adequate to meet our generating needs, and reliable enough to assure 9

our continued performance, all within the context of an overall effort to minimize costs as 10

much as reasonable and practicable. 11

12

Q. WHAT WERE THE EFFECTS IN 2016 OF PURCHASING GGS’s SUPPLY OF 13

TDF ON THE SPOT MARKET? 14

A. Supplementing our wood fuel with TDF enables us to diversify our fuel supply and take 15

advantage of opportunities to secure TDF at favorable prices. This provides a high btu 16

fuel to supplement the wood fuel when the wood is wet. 17

18

Q. WHEN YOU WERE PROCURING THE FUEL THAT WAS CONSUMED 19

DURING 2016, WAS ONE OF YOUR JOB DUTIES TO MINIMIZE THE COST 20

OF FUEL PURCHASED BY GGS? 21

A. Yes. Cost was a very important consideration. Another important consideration was the 22

reliability of the fuel supply. GGS and AJD regularly evaluate new sources of wood fuel 23

275

13

based on delivered price, moisture content (which affects plant efficiency), reliability of 1

the supplier, and ability to meet fuel specifications and permit requirements. We also 2

periodically evaluated non-wood sources of fuel, which led to the facility burning a small 3

percentage of tire-derived fuel. Fuel purchasing decisions are made based on minimizing 4

net fuel costs, while securing a reliable supply of fuel and meeting permit restrictions. 5

6


THESE OBJECTIVES. 8

A. GGS routinely consults with AJD about fuel quantity, quality and prices. 9

10

Q WAS PURCHASING FUEL PURSUANT TO YOUR FUEL SUPPLY 11

AGREEMENT WITH AJD THE BEST FUEL SUPPLY OPTION REASONABLY 12

AVAILABLE TO GGS IN 2016? 13

A. Yes. 14

15

Q. IN CONNECTION WITH YOUR FUEL PROCUREMENT DECISIONS, DID 16

YOU EXERCISE YOUR BEST JUDGMENT? 17

A. Yes. 18

19

Q. IN YOUR OPINION, WAS GGS’s DECISION TO ENTER INTO THE FUEL 20

SUPPLY AGREEMENT WITH AJD REASONABLE AND PRUDENT BASED ON 21

THE FACTS AND CIRCUMSTANCES KNOWN OR REASONABLY 22

FORESEEABLE AT THE TIME? 23

276

14

A. Yes. 1


A. AJD is the best option for fuel supply to GGS for several reasons: (1) competitively 3

priced fuel, (2) immediate proximity to the GGS site, (3) experience in supplying waste 4

wood to power plants, especially Dow Corning's previous wood-fired cogeneration 5

facility in Midland, (4) sizable internal generation of waste wood from their sawmill and 6

logging operations provides a reliable source of fuel, (5) for the wood fuel business, AJD 7

is a sizable company with decent financial strength providing stability and (6) great 8

relationships and connections in the Michigan lumbering industry. 9

10

Q. IN YOUR OPINION, WAS GGS’s DECISION TO ACQUIRE TDF ON THE SPOT 11

MARKET REASONABLE AND PRUDENT? 12

A. Yes. Supplementing our supply of wood fuel with TDF enabled us to diversify our fuel 13

supply, and purchasing TDF on the spot market ensures that we pay the lowest possible 14

price at that moment in time. 15

16

277

15








maintenance costs. 8

9



A. Yes. For simplicity, however, Grayling Generating Station has chosen to seek cost 12

recovery during 2016 for only those items identified above. 13

14



A. Yes, to the extent practicable, we made every reasonable effort to control these costs. 17

18

Q. PLEASE EXPLAIN THE MEASURES THAT GGS UNDERTOOK TO 19

CONTROL ITS VARIABLE OPERATION AND MAINTENANCE COSTS. 20

A. Our plant has purchasing policies that require us to competitively bid any large 21

purchases. GGS is always looking for lower cost materials. 22

23

278

16

CONCLUSION 1

Q. IN YOUR OPINION, WERE GGS’s PURCHASING PRACTICES REASONABLE 2

AND PRUDENT? 3

A. Yes, definitely. 4

5

Q. IN YOUR OPINION, WERE GGS’s ACTUAL FUEL AND VARIABLE 6




A. Yes. 10

11

Q. ARE GGS’s RECORDS WITH RESPECT TO FUEL AND VARIABLE 12

OPERATION AND MAINTENANCE COSTS AUDITED? 13

A. Yes. Our plant’s 2016 records were audited by Plante & Moran, PLLC. The audit 14

included a review of fuel and variable operation and maintenance costs, and revenues. 15

16


FIELD OF FUEL PROCUREMENT, DO YOU THINK THAT ANY OF GGS’s 18

ACTUAL FUEL OR VARIABLE OPERATION AND MAINTENANCE COSTS 19

WERE EXTRAVAGANT, UNNECESSARY, INEFFICIENT OR IMPRUDENT? 20


22

279

17


PROCEEDING? 2

A. Yes, it does. 3

280

STATE OF MICHIGAN


DIRECT TESTIMONY

OF

DOUG A. AUDETTE

ON BEHALF OF

HILLMAN POWER COMPANY, LLC

(REVISED 9-13-2017)

281

1

INTRODUCTION 1


A. My name is Doug A. Audette and my business address is 750 Progress Street, Hillman, 3

MI 49746. 4

5


A. I am employed by Fortistar Biomass Group as the Plant Manager of Hillman Power 7

Company, LLC. 8

9

Q. PLEASE BRIEFLY DESCRIBE THE HILLMAN POWER COMPANY. 10

A. The Hillman Power Company, LLC owns and operates a merchant plant consisting of 11

electric generating equipment and associated facilities with a capacity of 19 MW. The 12

plant is located in Hillman, Michigan and is not owned or operated by an electric utility. 13

14


EXPERIENCE. 16

A. I graduated from Remer, Minnesota high school in 1980. I served in the United States 17

Marine Corps from 1980 through 1988, at which time I was honorably discharged. From 18

1988 through 1996, I worked as an oil refinery Equipment Operator and Lead Operator 19

for Koch Industries. I joined Northern States Power in 1996, where I held several jobs of 20

increasing responsibility and importance. These jobs included plant attendant, operator, 21

lead operator, and Instrumentation and Control Tech. I then moved into supervision via 22

the company’s leadership pipeline and held several supervisor positions in operations and 23

282

2

maintenance departments at 400MW and 600MW electric generating plants. After that, 1

I became the Plant Superintendent at an RDF plant in Red Wing MN. I then joined 2

Evergreen Energy and served as Plant Manager for a 37 MW biomass plant, and was 3

promoted to Director of Production for four plants in the St. Paul, Minnesota area. I 4

have been employed at Hillman since July 2015 and, as I indicated at the outset of my 5

testimony, am currently the Plant Manager of that facility. 6

7


A. As Plant Manager, I am ultimately responsible for all business, operations and 9

maintenance, and fuel procurement activities at the Hillman Power Company. 10

11

Q. PLEASE ELABORATE ON YOUR RESPONSIBILITIES AS PLANT MANAGER 12

AT THE HILLMAN POWER PLANT. 13

A. I am currently the person within my organization who has overall responsibility for the 14

operation of the Hillman biomass plant. This includes ensuring that the facility has an 15

adequate supply of fuel to operate the boilers reliably and efficiently. 16

17

Q. WHO WAS RESPONSIBLE FOR HILLMAN'S FUEL PROCUREMENT IN 2016? 18

A. I became primarily responsible for Hillman's fuel procurement as of the beginning of 19

2016. 20

21

Q. HAVE YOU REVIEWED HILLMAN'S 2016 FUEL PROCUREMENT 22

ACTIVITIES? 23

283

3

A. Yes, I have personally reviewed Hillman's 2016 fuel procurement business records and 1

activities and, as explained below, found its costs and activities to be reasonable and 2

prudent. 3

4




17678-R. 8

9


PROCEEDING? 11

A. My testimony is on behalf of Hillman Power Company, LLC. 12

13


A Yes. I am sponsoring Exhibit BMP-6 (DAA-1) and co-sponsoring Exhibits BMP-1 and 15

BMP-2. 16

17


SUPERVISION? 19

A. Yes. 20

21



284

4

A. The purpose of my testimony is to describe Hillman Power Company's actual fuel and 1

variable operation and maintenance costs for the period from January 1, 2016 to 2

December 31, 2016, and to demonstrate that those costs were reasonably and prudently 3


Hillman Power Company for fuel and variable operation and maintenance costs incurred 5

during that time period. My testimony provides factual support for Hillman Power 6

Company’s request to recover costs under the terms of Public Act 286 of 2008, which 7

permits recovery of costs that exceed the amount that a merchant plant is paid under 8

contract with an eligible utility for those costs. 9

10


Q. IS THERE A POWER PURCHASE AGREEMENT ("PPA") BETWEEN 12

HILLMAN POWER COMPANY AND CONSUMERS ENERGY COMPANY? 13




U-16045-R. 17

18



A. No. 21

22

285

5

Q. WAS HILLMAN POWER COMPANY’S PPA ENTERED ON OR BEFORE 1

JANUARY 1, 2008? 2

A. Yes. 3

4


A. Yes. 6

7

Q. DOES THE PPA PROVIDE FOR HILLMAN POWER COMPANY TO SELL 8

ELECTRICITY TO AN ELECTRIC UTILITY WHOSE RATES ARE 9



A. Yes, Hillman Power Company’s PPA is with Consumers Energy Company. 12

13

Q. AT ANY TIME PRIOR TO JANUARY 1, 2008, DID HILLMAN POWER 14

COMPANY, LLC GENERATE ANY ELECTRICITY IN WHOLE OR IN PART 15



A. Yes. 18

19

286

6

Q. DOES HILLMAN POWER COMPANY STILL GENERATE ELECTRICITY IN 1

WHOLE OR IN PART FROM WOOD OR SOLID WOOD WASTES AND SELL 2

THAT ELECTRICITY TO CONSUMERS ENERGY COMPANY? 3

A. Yes. 4

5



PAYMENTS TO HILLMAN POWER COMPANY UNDER THE TERMS OF THE 8

PPA? 9

A. Yes. 10

11


HILLMAN POWER COMPANY INCLUDE PAYMENT FOR FUEL AND 13

VARIABLE OPERATION AND MAINTENANCE ("O & M") COSTS? 14

A. Yes. 15

16

Q. DID THE AMOUNT OF HILLMAN POWER COMPANY'S ACTUAL FUEL AND 17

VARIABLE O & M COSTS EXCEED THE AMOUNT THAT CONSUMERS 18

ENERGY PAID TO HILLMAN POWER COMPANY UNDER THE PPA FOR 19

THOSE COSTS? 20

A. Yes. Please see Exhibits BMP-1, BMP-2 and BMP-6 (DAA-1). 21

22

287

7

Q. IS HILLMAN POWER COMPANY A LANDFILL GAS PLANT, A HYDRO 1

PLANT, OR A MUNICIPAL SOLID WASTE PLANT? 2

A. No. 3

4

Q. IS HILLMAN POWER COMPANY ENGAGED IN LITIGATION AGAINST AN 5

ELECTRIC UTILITY SEEKING HIGHER PAYMENTS FOR POWER 6

DELIVERED PURSUANT TO A CONTRACT? 7

A. No. 8

9

COST DATA 10

Q. WHAT AMOUNT HAS HILLMAN POWER COMPANY SET FORTH ON 11

EXHIBIT BMP-6 AS ITS ACTUAL FUEL AND VARIABLE OPERATION AND 12

MAINTENANCE COSTS INCURRED FOR SALES OF ELECTRIC 13

GENERATION TO CONSUMERS ENERGY COMPANY DURING 2016? 14

A. Hillman Power Company has identified $5,788,436 in actual fuel and variable operation 15

and maintenance costs for sales to Consumers Energy Company in 2016. 16

17




A. No. For simplicity, however, Hillman Power Company, LLC has decided to seek 21

recovery of only certain variable operation and maintenance costs during 2016. As 22

discussed in more detail below, we are seeking recovery for only those categories of 23

288

8

variable operation and maintenance costs identified below. Hillman incurs variable 1

operation and maintenance costs beyond the categories listed below. 2

3


HILLMAN POWER COMPANY PURSUANT TO THE PPA BETWEEN 5

HILLMAN AND CONSUMERS FOR FUEL AND VARIABLE OPERATION AND 6

MAINTENANCE COSTS INCURRED DURING 2016. 7



2016. 10

11


COSTS THAT HILLMAN INCURRED FOR SALES TO CONSUMERS IN 2016 13

AND THE PAYMENTS THAT HILLMAN RECEIVED FROM CONSUMERS 14

FOR THOSE COSTS UNDER ITS PPA? 15


17




A. Yes. The cost figures and Consumers Energy's payments to Hillman Power Company 21

for actual fuel and variable operating and maintenance costs are detailed on Exhibit 22

BMP-6 (DAA-1). 23

289

9

Q. WHAT AMOUNT IS HILLMAN POWER COMPANY, LLC SEEKING TO 1

RECOVER IN THIS PROCEEDING. 2

A. As set forth in Exhibit BMP-1, Hillman Power Company is seeking to recover 3


to the fuel and variable operation and maintenance expense which any other BMP is 5

seeking to recover in this proceeding with respect to a month in which the collective 6

payments to the BMPs exceed the statutory cap on cost recovery. While we do not 7

believe that any adjustment to any other BMP’s costs would be appropriate or required, it 8

is theoretically possible that an adjustment could be made. In that event, the capped 9

amount would be reallocated among all of the BMPs, taking into account the adjustment. 10

The result of this reallocation process would be that the amount that Hillman Power 11

Company is seeking to recover in this proceeding would change in order to accurately 12

reflect its proportionate share of the capped amount. 13

14






PARTIAL PAYMENTS TO HILLMAN IN 2016? 20

A. Yes, as reflected in Exhibits BMP-1, BMP-2 and BMP-6 (DAA-1), Consumers Energy 21

has paid Hillman $936,234 of the $1,365,022 that Hillman seeks to recover in this 22

proceeding, leaving a balance due to Hillman of $428,788. 23

290

10

Q. IS HILLMAN POWER COMPANY SEEKING TO RECOVER ANY ACTUAL 1

FUEL AND VARIABLE OPERATION AND MAINTENANCE COSTS THAT 2

WERE INCURRED DUE TO CHANGES IN FEDERAL OR STATE 3

ENVIRONMENTAL LAWS OR REGULATIONS THAT WERE 4

IMPLEMENTED AFTER OCTOBER 6, 2008? 5

A. No. 6

7


Q. PLEASE DESCRIBE THE FUELS THAT HILLMAN POWER COMPANY USED 9

TO GENERATE ELECTRICITY DURING 2016. 10

A. The plant used waste wood (consisting of bark, chips, sawdust and mill shavings) and tire 11

derived fuel (TDF - ground up tires) during that time period. 12

13


PLEASE STATE THE SOURCE OF THE FUEL AND THE VOLUMES THAT 15

WERE USED DURING 2016. 16

A. The waste wood is derived from sawmills and forest operations. TDF is purchased from 17

Environmental Rubber Recycling. From January 1, 2016 through December 31, 2016, 18

the plant used 78,725 tons of waste wood from sawmills, 98,184 tons of waste wood from 19

forest operations, and 9,131 tons of TDF. 20

21

22

291

11

Q. DID HILLMAN POWER COMPANY HAVE FUEL SUPPLY AGREEMENTS 1

WITH ANY FUEL SUPPLIERS IN 2016? 2

A. In 2016, Hillman purchased much of its waste wood fuel and TDF under fuel contracts. 3

Small quantities were purchased in the spot market to take advantage of prices that were 4

sometimes lower than the prices in the fuel contracts. 5

6

Q. PLEASE EXPLAIN WHY YOU HAVE CHOSEN TO PURCHASE ALL OF 7

YOUR FUEL ON THE SPOT MARKET. 8

A. There are two schools of thought regarding the relative advantages and disadvantages of 9

buying on the spot market versus signing long term contracts. Both approaches are 10

reasonable. 11

12

Q. WHY DOES HILLMAN POWER COMPANY BURN BOTH WASTE WOOD 13

AND TDF? 14

A. TDF is produced by chipping rubber tires and removing the metal strips with a magnet. 15

TDF provides a reliable fuel source that burns hotter than waste wood. Burning TDF, 16

within environmental constraints, permits the plant to operate more efficiently than the 17

plant would operate without burning TDF. 18

19

20

21

22

292

12

Q. WHAT WERE THE EFFECTS OF PURCHASING FUEL IN THE SPOT 1

MARKET AS YOU HAVE DESCRIBED? 2

A. Hillman Power Company was able to meet its generating needs, assure its continued 3

performance and the stability of its fuel supply, all within the context of an overall effort 4

to minimize costs as much as reasonable and practicable. 5

6


DURING 2016, WAS ONE OF HILLMAN'S OBJECTIVES TO MINIMIZE THE 8

COST OF THE FUEL IT PURCHASED? 9

A. Yes. Cost was and is a very important consideration. Other important considerations 10

were the reliability and quality of the fuel supply. 11

12


THESE OBJECTIVES. 14

A. We continually reviewed the performance of all of our actual and potential suppliers, to 15

determine if they provide appropriate pricing and performance for waste wood fuel and 16

TDF. We facilitated and encouraged suppliers to buy private stumpage which was more 17

cost effective. We have certified the facility for the federal Biomass Crop Assistance 18

Program which increased our fuel vendor base, increasing competition. This maintains a 19

competitive environment at the lowest possible price. 20

293

13

Q. AT THE TIME HILLMAN POWER COMPANY ENTERED INTO THE FUEL 1

SUPPLY AGREEMENTS WITH ITS FUEL SUPPLIERS, WERE THOSE 2

PRICES THE BEST PRICES THAT WERE REASONABLY AVAILABLE? 3

A. Yes, considering the volumes of fuel, the timing of delivery and the reliability of supply, 4

we selected the lowest prices available to us at that time. 5

6

Q. WERE HILLMAN POWER COMPANY’S FUEL SUPPLY PURCHASES THE 7

BEST OPTION REASONABLY AVAILABLE TO HILLMAN POWER 8

COMPANY IN 2016? 9

A. Yes. 10

11


HILLMAN EXERCISE ITS BEST JUDGMENT? 13

A. Yes. 14

15

Q. IN YOUR OPINION, WERE THE DECISIONS TO ENTER INTO THESE 16

SUPPLY AGREEMENTS REASONABLE AND PRUDENT BASED ON THE 17

FACTS AND CIRCUMSTANCES KNOWN OR REASONABLY FORESEEABLE 18

AT THE TIME THE DECISIONS WERE MADE? 19

A. Yes. 20

21

294

14


A. Hillman Power Company purchases its fuel from a mix of suppliers that compete for the 2

business. This assures that the plant has a reliable supply of fuel at the lowest possible 3

prices. 4

5


A. Generally, yes. Normally, costs for wood fuel decrease as summertime availability 7

increases. Prices can go up if inventory levels fall in the winter due to adverse weather. 8

9


A. Yes. Fuel costs differ widely by region due to variability in land ownership (e.g. private, 11

state, federal), forest type, forest management objectives and practices, conflicting uses 12

(e.g. wildlife habitat, recreation) the level of logging activity, the type and number of 13

waste wood generators, and market competition, such as mulch processors and fiberboard 14

manufacturers. 15

16





21

22

23

295

15






water and sewer costs; 2) ash handling costs; 3) fuel handling costs; 4) emission control 6

costs; and 5) water treatment costs. 7

8



A. Yes. For simplicity, however, Hillman Power Company has chosen to seek cost recovery 11

during 2016 for only those items identified above. 12

13




17

Q. PLEASE EXPLAIN THE MEASURES THAT HILLMAN POWER COMPANY 18

UNDERTOOK TO CONTROL ITS VARIABLE OPERATION AND 19

MAINTENANCE COSTS. 20

A. Through the use of predictive and preventative maintenance programs, Hillman Power 21

Company ensures that equipment is operated at peak efficiencies and within original 22

equipment manufacturers recommendations. Applications of maintenance programs such 23

296

16

as these are considered prudent industry practices that keep variable operation and 1

maintenance costs to a minimum. 2

3

CONCLUSION 4

Q. IN YOUR OPINION, WERE HILLMAN POWER COMPANY'S PURCHASING 5

PRACTICES REASONABLE AND PRUDENT? 6


8

Q. IN YOUR OPINION, WERE HILLMAN POWER COMPANY'S ACTUAL FUEL 9

AND VARIABLE OPERATION AND MAINTENANCE COSTS FOR 2016 10


A. Yes. 12

13

Q. ARE HILLMAN POWER COMPANY’S RECORDS WITH RESPECT TO FUEL 14

AND VARIABLE OPERATION AND MAINTENANCE COSTS AUDITED? 15

A. Yes. Our plant’s 2016 records were audited by Rehmann. The audit found no material 16

issues in our financial statements. The audit performed by Rehmann included a review of 17

fuel and variable operation and maintenance costs, and Hillman Power Company’s 18

revenues. 19

20

21

22

297

17


FIELD OF FUEL PROCUREMENT, DO YOU THINK THAT ANY OF 2

HILLMAN POWER COMPANY'S ACTUAL FUEL OR VARIABLE 3

OPERATION AND MAINTENANCE COSTS WERE EXTRAVAGANT, 4

UNNECESSARY, INEFFICIENT OR IMPRUDENT? 5


7


PROCEEDING? 9

A. Yes, it does. 10

298

STATE OF MICHIGAN


REBUTTAL TESTIMONY

OF

DOUG A. AUDETTE

ON BEHALF OF

HILLMAN POWER COMPANY, LLC

299

1

INTRODUCTION 1


A. My name is Doug A. Audette and my business address is 750 Progress Street, Hillman, 3

MI 49746. 4

5

Q. ARE YOU THE SAME DOUG A. AUDETTE WHO PREVIOUSLY FILED 6


A. Yes. On September 13, 2017, I filed Direct Testimony on behalf of Hillman Power 8

Company, LLC ("Hillman"). 9

10

Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY? 11





costs," Coppola Direct Testimony ("CDT") at 14:15-17, specifically as it relates to 16

Hillman. 17

18



A. Yes. 21

22

300

2


TESTIMONY OF THOMAS ALLEN SUBMITTED ON BEHALF OF THE 2

BIOMASS MERCHANT PLANTS ("BMPs")? 3

A. Yes. 4

5

Q. FOR PURPOSES OF AVOIDING REPETITION AND REDUCING THE 6

BURDEN ON THE ALJ AND THE COMMISSION, DO YOU AGREE WITH 7

THAT TESTIMONY AND INCORPORATE IT AS YOUR TESTIMONY ON 8

BEHALF OF HILLMAN IN LIEU OF SEPARATELY RESTATING THAT 9

TESTIMONY? 10

A. Yes. 11

12

Q. ARE HILLMAN'S FINANCIALS AUDITED BY INDEPENDENT OUTSIDE 13

ACCOUNTANTS ON AN ANNUAL BASIS? 14

A. Yes. Hillman's financial statements are audited by Rehmann, which is a CPA, business 15

consulting, and financial services firm with 17 offices in Michigan, Ohio, and Florida. 16

17

Q. JUST TO BE CLEAR, WERE THE COSTS SUBMITTED BY HILLMAN AS 18




A. No. These numbers are taken directly from Hillman's financial statements. 22

301

3

Q. DID HILLMAN ALSO PROVIDE INFORMATION REGARDING ITS 1


A. Yes. 3

4

Q. HAVE ANY OF THE OTHER BMPs OBJECTED TO HILLMAN'S 5



A. No. 8

9

Q. DID THE OTHER BMPs SIMILARLY PROVIDE INFORMATION TO 10

HILLMAN THAT INCLUDED THEIR VARIABLE O&M COSTS? 11

A. Yes. 12

13

Q. HAS HILLMAN OBJECTED TO ANY OF THE COSTS THAT MR. COPPOLA 14


A. No. 16

17



CHARACTERIZATION OF THE O&M COSTS SUBMITTED BY HILLMAN? 20

A. Yes. 21

22

302

4

Q. WHAT AMOUNTS SUBMITTED BY HILLMAN DOES MR. COPPOLA 1

DISPUTE? 2

A. Mr. Coppola characterizes $67,134 submitted for a new ash mixer and associated support 3

structure as "major maintenance costs" that he contends should have been capitalized. 4

CDT at 16:14-16. 5

6

Q. WOULD YOU PLEASE EXPLAIN WHAT IS INCLUDED IN THIS ENTRY? 7

A. Yes. The ash mixer is a component of the ash system. The mixer was replaced with one 8

that was built by a third party vendor. The $67,000 was incurred solely for parts and 9

outside labor costs. 10

11

Q. DOES MR. COPPOLA'S TESTIMONY REFERENCE ANY OTHER HILLMAN 12

O&M COSTS? 13

A. Yes. Mr. Coppola's testimony curiously also states, with no additional explanation, that 14

"in 2015, Hillman included $169,395 in O&M expenses for a new precipitator to control 15

omissions." CDT at 16:16-17. 16

17

Q. WOULD THIS 2015 EXPENDITURE HAVE ANY EFFECT WHATSOEVER ON 18

THIS 2016 RATE RECOVERY PROCEEDING? 19

A. No. 20

21

Q. WOULD YOU PLEASE NONETHELESS EXPLAIN THIS CHARGE? 22

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5

A. Sure. These costs were related to repair and replacement of certain parts of the 1

precipitator. The repairs were necessary to comply with our environmental permit. 2

3


EXTEND THE USEFUL LIFE OF THE EQUIPMENT OR TO OVERHAUL THE 5

FACILITIES OR IMPROVE THE EFFICIENCY OF THE FACILITY? 6

A. No. 7

8


PROCEEDING? 10

A. Yes. 11

12

304

STATE OF MICHIGAN



DIRECT TESTIMONY

OF

ROBERT JOE TONDU

ON BEHALF OF

TES FILER CITY STATION LIMITED PARTNERSHIP

(REVISED 9-13-2017)

305

1

I. INTRODUCTION 1


A. My name is Robert Joe Tondu. My business address is Tondu Corporation, 11777 Katy 3

Freeway, Suite 120, Houston, TX 77079. 4

5

Q. BY WHOM ARE YOU EMPLOYED AND WHAT IS YOUR POSITION? 6

A. I am the sole owner and president of Tondu Corporation formally known as Tondu 7

Energy Systems, Inc. Tondu Corporation is engaged in the business of investing and 8

cogeneration and alternative energy development. Tondu Corporation was the original 9

developer of the T.E.S. Filer City Station project and, through affiliates, is an owner and 10

one of the two general partners of the T.E.S. Filer City Station Limited Partnership. 11

(“TES”) 12

13

Q. WOULD YOU PLEASE STATE YOUR EDUCATIONAL BACKGROUND? 14

A. I am a native of Manistee County, Michigan. I graduated from Grand Valley State 15

College in Allendale, Michigan in 1973 with a BS Degree in Geology. I received a 16

Master's Degree in Geology from the University of Texas at Austin in 1976 and have also 17

completed numerous short courses in various business-related subjects. 18

19

Q. WHAT IS YOUR BUSINESS EXPERIENCE? 20

A. In 1975, I joined Getty Oil Company as a staff geologist working in their development 21

section. I left Getty Oil Company in 1978 and became an independent geologist. Since 22

306

2

1979, I have been engaged in oil and gas exploration and development and energy-related 1

activities including cogeneration and alternative energy development. 2

3

Q. PLEASE BRIEFLY DESCRIBE THE PLANT. 4

A. TES Filer City Station is a merchant plant consisting of electric generating equipment 5

and associated facilities with a nameplate capacity rating of 72.54 MW. The plant is 6

located in Filer City, Michigan, and is not owned or operated by an electric utility. 7

8

Q. ARE YOU FAMILIAR WITH, AND ULTIMATELY RESPONSIBLE FOR, FUEL 9

PROCUREMENT? 10

A. Yes. As the representative of one of the two General Partners of TES, I have final 11

approval, in conjunction with the other General Partner, of all fuel procurement for the 12

TES Filer City Station power plant. With the representative of the other general partner, 13

I approve the TES budgets and all fuel contracts. 14

15



A. Yes, I testified in both MPSC Case No. U-8562 and MPSC Case No. U-13917. I also 18

testified in Consumers Energy’s 2009 PSCR reconciliation proceeding, MPSC Case No. 19

U-15675-R, Consumers Energy’s 2010 PSCR reconciliation proceeding, MPSC Case No. 20




307

3


U-17317-R and Consumers Energy’s 2015 PSCR reconciliation proceeding, MPSC Case 2

No. U-17678-R. 3

4


PROCEEDING? 6

A. My testimony is on behalf of TES. 7

8


A. Yes. I am sponsoring Exhibits BMP-7 (RJT-1), BMP-11 (RJT-4), BMP-12 (RJT-5), 10

BMP-13 (RJT-6), BMP-14 (RJT-7), BMP-15 (RJT-8) and BMP-16 (RJT-9) and I am co-11

sponsoring Exhibits BMP-1 and BMP-2. 12

13


SUPERVISION? 15

A. Yes, as to Exhibit BMP-1, BMP-2 and BMP-7 (RJT-1). Exhibits BMP-11 (RJT-4), 16

BMP-12 (RJT-5), BMP-13 (RJT-6), BMP-14 (RJT-7), BMP-15 (RJT-8) and BMP-16 17

(RJT-9) are public documents, prepared by the United States government. 18

19

II. PURPOSE OF TESTIMONY 20


A. The purpose of my testimony is to describe TES Filer City Station's actual fuel and 22


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4

December 31, 2016, and to demonstrate that those costs were reasonably and prudently 1


TES for fuel and variable operation and maintenance costs incurred during that time 3

period. Furthermore, I will testify as to the amount of CSAPR allowance costs incurred 4

in 2016 that are not subject to the monthly cap on cost recovery under Public Act 286 of 5

2008. My testimony provides factual support for TES’s request for recovery of certain 6

costs under the terms of Public Act 286 of 2008. 7

8

III. ELIGIBILITY FOR COST RECOVERY 9

Q. IS THERE A POWER PURCHASE AGREEMENT ("PPA") BETWEEN TES 10



the MPSC. It was provided to the parties in both Consumers Energy's 2009 and 2010 13

PSCR Reconciliation cases, MPSC Case Nos. U-15675-R and U-16045-R. 14

15

Q. WAS TES’s PPA ENTERED ON OR BEFORE JANUARY 1, 2008? 16

A. Yes, TES entered into the current PPA with Consumers Energy in July of 1986. 17

18

Q. WERE THERE ANY CHANGES TO THE PPA IN 2016? 19

A. No. 20

21


A. Yes. 23

309

5

Q. DOES THE PPA PROVIDE FOR TES TO SELL ELECTRICITY TO AN 1



STATE? 4


6

Q. AT ANY TIME PRIOR TO JANUARY 1, 2008, DID TES GENERATE ANY 7



COMPANY? 10

A. Yes. 11

12

Q. DOES TES STILL GENERATE ELECTRICITY IN WHOLE OR IN PART 13



A. Yes. 16

17



PAYMENTS TO TES UNDER THE TERMS OF THE PPA? 20

A. Yes. 21

22

310

6

Q. DID PORTIONS OF THE PAYMENTS FROM CONSUMERS ENERGY TO TES 1



A. Yes. 4

5

Q. DID THE AMOUNT OF TES’s ACTUAL FUEL AND VARIABLE O & M COSTS 6

EXCEED THE AMOUNT THAT CONSUMERS ENERGY PAID TO TES UNDER 7

THE PPA FOR THOSE COSTS? 8

A. Yes. Please see Exhibits BMP-1, BMP-2 and BMP-7 (RJT-1). 9

10

Q. IS TES A LANDFILL GAS PLANT, A HYDRO PLANT, OR A MUNICIPAL 11


A. No. 13

14

Q. IS TES ENGAGED IN LITIGATION AGAINST AN ELECTRIC UTILITY 15


CONTRACT? 17

A. No. 18

19

311

7

IV. COST DATA 1

Q. WHAT WERE TES'S ACTUAL FUEL AND VARIABLE OPERATION AND 2



A. As set forth in Exhibit BMP-7 (RJT-1), TES has identified $21,348,150 in actual fuel and 5

variable operation and maintenance costs for sales to Consumers Energy Company in 6

2016. 7

8




A. No. For simplicity, TES has decided to seek recovery of only certain variable operation 12

and maintenance costs during 2016. As discussed in more detail below, we are seeking 13

recovery for only the categories of variable operation and maintenance costs listed below. 14

TES incurs variable operation and maintenance costs beyond the categories listed below. 15

16

Q. PLEASE STATE THE AMOUNT THAT CONSUMERS ENERGY PAID TO TES 17

PURSUANT TO THE PPA BETWEEN TES AND CONSUMERS FOR FUEL AND 18


2016. 20

A. Under the terms of our PPA, Consumers Energy paid TES a total of $14,979,948 for 21

actual fuel and variable operation and maintenance costs incurred for 2016. 22

23

312

8


COSTS THAT TES INCURRED FOR SALES TO CONSUMERS IN 2016 AND 2

THE PAYMENTS THAT TES RECEIVED FROM CONSUMERS FOR THOSE 3



6





TES for actual fuel and variable operation and maintenance costs, are detailed on Exhibit 11

BMP-7 (RJT-1). 12

13

Q. WHAT AMOUNT IS TES SEEKING TO RECOVER IN THIS PROCEEDING 14

FOR CAPPED FUEL AND VARIABLE OPERATIONS AND MAINTENANCE 15

COSTS? 16

A. As set forth on line 23 of Exhibit BMP-1, TES is seeking to recover capped payments of 17


to the fuel and variable operation and maintenance expense which any other Biomass 19

Merchant Plant is seeking to recover in this proceeding with respect to a month in which 20

the collective payments to the Biomass Merchant Plants exceed the statutory cap on cost 21

recovery. In the event that the Commission were to make such an adjustment, the capped 22

amount would be reallocated among all of the Biomass Merchant Plants. The result of 23

313

9

this reallocation process would be that the amount that TES is seeking to recover in this 1

proceeding would change in order to accurately reflect its proportionate share of the 2

capped amount. 3

4


BMPs TO SUBMIT MONTHLY INVOICES TO CONSUMERS FOR THE 6




PARTIAL PAYMENTS TO TES IN 2016? 10

A. Yes, as reflected in Exhibits BMP-1, BMP-2 and BMP-7 (RJT-1), Consumers Energy has 11

paid TES $3,542,440 of the $4,522,105 of capped fuel and variable O & M costs that 12

TES seeks to recover in this proceeding, leaving a balance due to TES for capped fuel 13

and variable O & M costs of $979,665. 14

15

Q. IS TES ALSO SEEKING RECOVERY OF ANY UNCAPPED ACTUAL FUEL 16

AND VARIABLE OPERATION AND MAINTENANCE COSTS THAT WERE 17

INCURRED DUE TO CHANGES IN FEDERAL OR STATE ENVIRONMENTAL 18

LAWS OR REGULATIONS THAT WERE IMPLEMENTED AFTER OCTOBER 19

6, 2008? 20

A. Yes. TES is seeking to recover $233,000 in CSAPR seasonal and annual NOx allowance 21

costs that were incurred in 2016 pursuant to the Cross State Air Pollution Rule, 40 CFR 22

97 Subparts AAAAA to DDDDD ("CSAPR"). The CSAPR allowance costs are 23

314

10

identified on Exhibit BMP-7 (RJT-1). Thus, as reflected in Exhibit BMP-2, the 1

remaining balance of both capped and uncapped fuel and variable O & M costs that TES 2

claims is $1,212,665. 3

4

V. PROCUREMENT PROCEDURES 5

Q. PLEASE DESCRIBE THE FUEL OR FUELS THAT TES USED TO GENERATE 6

ELECTRICITY DURING THE PERIOD FROM JANUARY 1, 2016 THROUGH 7

DECEMBER 31, 2016. 8

A. TES used a variety of fuels to produce electricity during this period including waste 9

wood, bituminous coal, sub-bituminous coal, and Tire Derived Fuel (“TDF”). TES 10

burned a small amount of petroleum coke in 2016 but, because of environmental 11

concerns, ceased using that fuel as of January 2016. 12

13

Q. DOES TES HAVE FUEL SUPPLY AGREEMENTS WITH ANY FUEL 14

SUPPLIERS? 15

A. Yes. TES has a long standing contractual agreement with Packaging Company of 16

America (“PCA”) for the supply of bark, tree branches, and other wood waste from the 17

PCA facility. PCA is a paper mill located adjacent to TES. TES also has fuel supply 18

agreements with two suppliers for coal. TES purchases TDF on the spot market. 19

20

Q. PLEASE EXPLAIN WHY TES USES BOTH FUEL SUPPLY AGREEMENTS AS 21

WELL AS SPOT MARKET PURCHASES. 22

315

11

A. Purchasing fuel via multi-year contracts, or via the spot market, can both be reasonable 1

procurement practices. The decision to utilize a multi-year fuel contract or rely upon the 2

spot market to procure fuel involves the balancing of a variety of risks. Multi-year 3

contracts mitigate the risk of fuel supply shortages and can be used to mitigate the risk of 4

price fluctuations. Multi-year contracts, however, may lock a buyer into prices that are 5

higher or lower than what the spot market would otherwise provide at any given moment. 6

Utilizing the spot market ensures that the buyer will receive the lowest available price for 7

fuel on a short-term basis that day, however, the buyer may experience dramatic price 8

fluctuations and possible fuel shortages. The decision to utilize multi-year contracts or 9

the spot market necessarily involves the balancing of a variety of complex factors, 10

including fuel price level, fuel supply reliability, and fuel price volatility. Given the fuel 11

supply options available to TES, the most cost effective way to obtain a reliable supply of 12

fuel was to purchase our coal, and wood through multi-year contracts and our supply of 13

TDF on the spot market. 14

15

Q. PLEASE DESCRIBE THE PROCESS THAT WAS USED TO ENTER INTO 16

TES’s COAL AND FUEL SUPPLY AGREEMENTS. 17

A. A competitive bid process was used for the purchase of coal and other fuels. Multiple 18

factors were considered in the process including commodity price, sulfur content, ash 19

content, transloading and blending costs and, ultimately, cost per MMBTU delivered to 20

TES. 21

22

23

316

12

Q. PLEASE SUMMARIZE THE PRINCIPAL TERMS OF YOUR COAL AND FUEL 1

SUPPLY AGREEMENTS. 2

A. The principal terms of each contract are similar in that each contains contractual volume 3

commitments, conditions concerning delivery timing, fuel quality parameters including 4

rejection limits, fixed pricing for each year of the contract, plus termination dates for each 5

contract. 6

7

Q. WHEN YOU ENTERED INTO THESE SUPPLY AGREEMENTS, DID YOU 8

CONSIDER OTHER AVAILABLE ALTERNATIVE SUPPLIERS? 9

A. Yes. 10

11

Q. PLEASE EXPLAIN WHAT ALTERNATIVES YOU CONSIDERED AND WHY 12

YOU CHOSE TO REJECT THEM. 13

A. In addition to the successful bidders for the majority of our fuel supply, various 14

alternative suppliers were asked to bid on the TES fuel supply. Bidders are rejected when 15

the delivered cost of fuel is higher than other available alternatives or when the quality of 16

proposed fuel does not meet TES’s fuel supply needs. 17

18

Q. WHAT WERE THE EFFECTS OF ENTERING INTO THE FUEL SUPPLY 19

AGREEMENTS THAT YOU HAVE DESCRIBED? 20

A. The effects of entering into these agreements were that TES was able to secure a supply 21

of fuel that was adequate to meet its generating needs, reliable enough to assure its 22

continued operation, and to the extent practicable, sufficiently diversified to ensure the 23

317

13

stability of its fuel supply, all within the context of an overall effort to minimize costs as 1

much as practicable. 2

3

Q. DURING THE PERIOD FROM JANUARY 1, 2016 THROUGH DECEMBER 31, 4

2016, WAS ONE OF YOUR OVERSIGHT RESPONSIBILITIES TO ENSURE 5

THE COST OF FUEL PURCHASED BY TES WAS MINIMIZED? 6

A. Yes. Cost was a very important consideration. Additional important considerations were 7

the reliability of the fuel supply, the costs of trans-loading and blending, as well as ash 8

disposal and sulfur scrubbing cost considerations. 9

10

Q. PLEASE DESCRIBE THE STEPS THAT HAVE BEEN TAKEN AT THE TES 11

PLANT TO ACHIEVE THESE OBJECTIVES. 12

A. Among other things, I have had the TES plant management and staff develop a 13

computerized fuel cost program that generates a projected delivered cost of coal. This 14

program also considers terminaling and transportation costs as well as various fuel 15

surcharges, sulfur content and ash content, allowing TES to consider all of the various 16

fuels offered by the various suppliers, all to optimize the overall delivered cost of the 17

final fuel blend. 18

19

Q. ARE THERE OTHER EXAMPLES OF HOW TES SEEKS TO MINIMIZE ITS 20

FUEL COSTS WHILE MAINTAINING A RELIABLE FUEL SUPPLY AND 21

ADDRESSING THE OTHER CONSIDERATIONS THAT YOU HAVE 22

MENTIONED? 23

318

14

A. Yes. TDF is the lowest cost fuel that TES consumes, so we maximize its consistent with 1

environmental constraints. 2

3


A. Generally, yes. 5

6


A. Yes. 8

9



A. Yes, shipping costs are an important component of fuel cost, so, generally speaking, fuel 12


14

Q. AT THE TIME YOU ENTERED INTO THE FUEL SUPPLY AGREEMENTS 15

WITH YOUR VARIOUS FUEL SUPPLIERS, WERE THOSE PRICES THE BEST 16

PRICES THAT WERE REASONABLY AVAILABLE TO YOU? 17

A. Yes. 18

19

Q DID PURCHASING FUEL PURSUANT TO THE FUEL SUPPLY AGREEMENTS 20

PROVIDE THE BEST PRICES REASONABLY AVAILABLE TO TES FILER 21

CITY STATION IN 2016? 22

A. Yes. 23

319

15



A. Yes. 3

4

Q. IN YOUR OPINION, WERE TES’s DECISIONS TO ENTER INTO THESE FUEL 5

SUPPLY AGREEMENTS REASONABLE AND PRUDENT BASED ON THE 6

FACTS AND CIRCUMSTANCES KNOWN OR REASONABLY FORESEEABLE 7

AT THE TIMES WHEN THE DECISIONS WERE MADE? 8

A. Yes. 9

10


A. The process that TES uses to procure its fuel results in the optimum overall cost for that 12

fuel from operational and commercial perspectives. After a competitive bid process, TES 13

executed multiple contracts for coal in 2016 to benefit from reliable contracted fuel 14

pricing. 15

16

17

320

16

VI. O&M COSTS 1







maintenance costs. As previously noted, TES actually incurs additional variable 8

operation and maintenance costs beyond the categories listed above, but those additional 9

costs are not listed on Exhibit BMP-7 (RJT-1). 10

11




15

Q. PLEASE EXPLAIN THE MEASURES THAT TES UNDERTOOK TO CONTROL 16

ITS VARIABLE OPERATION AND MAINTENANCE COSTS. 17

A. Generally, our cost-control measures include employee incentives, competitive bidding, 18

proactive and preventative maintenance programs, and innovative initiatives to minimize 19

costs. By way of example: 20

1) TES gives its operations staff financial incentives to minimize costs overall and 21

to use the most economical fuel blends available to produce electricity; 22

321

17

2) TES’s purchasing policy requires most major purchases to be competitively bid; 1

and 2

3) TES uses a computerized maintenance tracking program that identifies proactive 3

and preventative maintenance that can be performed on plant systems and equipment. 4

Maintaining plant equipment through planned maintenance is always less expensive than 5

repairing equipment when it unexpectedly breaks or fails. 6

7

VII. CSAPR ALLOWANCE COSTS 8

Q. TURNING TO THE ISSUE OF AIR POLLUTION ALLOWANCE COSTS, YOU 9

PREVIOUSLY INDICATED THAT TES IS SEEKING TO RECOVER COSTS 10

THAT IT INCURRED PURSUANT TO THE CROSS STATE AIR POLLUTION 11

RULE. PLEASE DESCRIBE THESE COSTS. 12

A. In 2016, TES incurred $106,000 for CSAPR seasonal NOx allowances costs and 13

$127,000 for CSAPR annual NOx allowances costs related to plant emissions, all 14

pursuant to the Cross State Air Pollution Rule, 40 CFR 97 Subparts AAAAA to DDDDD 15

("CSAPR"). CSAPR is a federal market-based cap-and-trade program that applies to 16

power plants in multiple states. The allowance expenses are identified on Exhibit BMP-7 17

(RJT-1). 18

19

Q. WHAT CSAPR REQUIREMENTS WAS TES REQUIRED TO SATISFY IN 2016? 20

A. CSAPR requires that a source of air pollution must hold a number of allowances adequate 21

to cover its actual emissions. In 2016, CSAPR required TES to purchase CSAPR 22

322

18

seasonal NOx allowances. The specific condition in CSAPR that required it to do so is in 1

40 CFR Part 97, Subpart BBBBB, §97.506, and states as follows: 2

"(c) NOX emissions requirements—(1) CSAPR NOX Ozone Season Group 1 3 emissions limitation. (i) As of the allowance transfer deadline for a control period 4 in a given year, the owners and operators of each CSAPR NOX Ozone Season 5 Group 1 source and each CSAPR NOX Ozone Season Group 1 unit at the source 6 shall hold, in the source's compliance account, CSAPR NOX Ozone Season 7 Group 1 allowances available for deduction for such control period under 8 §97.524(a) in an amount not less than the tons of total NOX emissions for such 9 control period from all CSAPR NOX Ozone Season Group 1 units at the source. 10 11 (ii) If total NOX emissions during a control period in a given year from the 12 CSAPR NOX Ozone Season Group 1 units at a CSAPR NOX Ozone Season 13 Group 1 source are in excess of the CSAPR NOX Ozone Season Group 1 14 emissions limitation set forth in paragraph (c)(1)(i) of this section, then: 15 16 (A) The owners and operators of the source and each CSAPR NOX Ozone Season 17 Group 1 unit at the source shall hold the CSAPR NOX Ozone Season Group 1 18 allowances required for deduction under §97.524(d); and 19 20 (B) The owners and operators of the source and each CSAPR NOX Ozone Season 21 Group 1 unit at the source shall pay any fine, penalty, or assessment or comply 22 with any other remedy imposed, for the same violations, under the Clean Air Act, 23 and each ton of such excess emissions and each day of such control period shall 24 constitute a separate violation of this subpart and the Clean Air Act." (TR NOx 25 Annual Trading Program requirements (40 CFR Part 97, Subpart BBBBB, 26 §97.506(c)). 27

28

In 2016, TES incurred $106,000 for CSAPR seasonal NOx allowances costs pursuant 29

to the Cross State Air Pollution Rule, 30

CSAPR also required TES to purchase CSAPR annual NOx allowances. The specific 31

condition in CSAPR that required it to do so is in 40 CFR Part 97, Subpart AAAAA, 32

§97.406, and states as follows: 33

(c) NOX emissions requirements—(1) CSAPR NOX Annual emissions limitation. 34 (i) As of the allowance transfer deadline for a control period in a given year, the 35 owners and operators of each CSAPR NOX Annual source and each CSAPR 36 NOX Annual unit at the source shall hold, in the source's compliance account, 37 CSAPR NOX Annual allowances available for deduction for such control period 38

323

19

under §97.424(a) in an amount not less than the tons of total NOX emissions for 1 such control period from all CSAPR NOX Annual units at the source. 2 3 (ii) If total NOX emissions during a control period in a given year from the 4 CSAPR NOX Annual units at a CSAPR NOX Annual source are in excess of the 5 CSAPR NOX Annual emissions limitation set forth in paragraph (c)(1)(i) of this 6 section, then: 7 8 (A) The owners and operators of the source and each CSAPR NOX Annual unit at 9 the source shall hold the CSAPR NOX Annual allowances required for deduction 10 under §97.424(d); and 11 12 (B) The owners and operators of the source and each CSAPR NOX Annual unit at 13 the source shall pay any fine, penalty, or assessment or comply with any other 14 remedy imposed, for the same violations, under the Clean Air Act, and each ton 15 of such excess emissions and each day of such control period shall constitute a 16 separate violation of this subpart and the Clean Air Act." (40 CFR Part 97, 17 Subpart AAAAA, §97.406(c)) 18

19

The CSAPR annual NOx allowance costs that TES incurred in 2016 and is 20

seeking to recover were the costs for its 2015 annual NOx allowances. The deadline for 21

purchasing those allowances was March 1, 2016 and, as permitted by the U.S. EPA, TES 22

did not purchase those allowances until February 11, 2016 through February 16, 2016. In 23

my testimony last year in U-17678-R, page 18 lines 26-28, I indicated that TES would be 24

seeking to recover the costs for its 2015 annual NOx allowances in Consumers' 2016 25

PSCR reconciliation case, and TES is now seeking to do so. In 2016, TES incurred 26

$127,000 for CSAPR annual NOx allowances costs related to plant emissions in 2015. 27

TES will seek to recover its NOx annual allowance costs for the 2016 compliance period 28

in Consumers' 2017 PSCR reconciliation case. 29

The CSAPR regulations also require emission sources to hold and/or acquire 30

annual SO2 allowances. As in 2015, TES was allocated sufficient annual SO2 allowances 31

and it incurred no annual SO2 allowance costs in 2016. 32

324

20

Q. WHAT ARE ALLOWANCES? 1

A. They are limited authorizations to emit a certain amount of air pollutants per year. The 2

need for allowances arises in direct proportion to the generator’s level of operation and 3

each allowance represents the right to emit one ton of pollutants. The number of CSAPR 4

allowances allocated to each generator is determined by the EPA. Generally, my 5

understanding is that they are based upon the source's previous emissions, adjusted 6

downward slightly to accommodate the overall goal of reducing emissions from power 7

plants. If any additional allowances are needed to cover actual emissions, they are 8

purchased by that generator in the open market. 9

10

Q: WHAT WERE TES's TOTAL CSAPR NOx SEASONAL ALLOWANCE 11

REQUIREMENTS? 12

A: The TES plant emitted 548 tons of NOx from its Units 1 and 2 during the 2016 Ozone 13

Season. Thus, the TES plant was required to hold 548 CSAPR NOx seasonal allowances 14

between (i) the number of allowances allocated to TES by the EPA and (ii) TES's 15

purchase of additional CSAPR NOx seasonal allowances in the market. 16

17

Q. HOW MANY CSAPR 2016 SEASONAL NOx ALLOWANCES DID THE EPA 18

ALLOCATE TO TES? 19

A. The U.S. EPA initially allocated 210 CSAPR seasonal NOx allowances to TES for the 20

2016 NOx ozone season. See, https://www.epa.gov/csapr/cross-state-air-pollution-rule-21

csapr-allowance-allocations-and-templates. The U.S. EPA then subsequently granted 4 22

325

https://www.epa.gov/csapr/cross-state-air-pollution-rule-csapr-allowance-allocations-and-templates

https://www.epa.gov/csapr/cross-state-air-pollution-rule-csapr-allowance-allocations-and-templates

21

additional CSAPR seasonal NOx allowances to TES for the 2016 NOx ozone season. 1

Thus, the total 2016 CSAPR seasonal NOx allowances that were granted to TES was 214. 2

3

Q. DID TES NEED TO PURCHASE ADDITIONAL CSAPR ALLOWANCES 4

BEYOND THOSE ALLOCATED BY THE EPA? 5

A. Yes. Because the plant's actual NOx seasonal emissions exceeded the EPA allocated 6

allowances for the 2016 compliance period, TES was required to purchase additional 7

CSAPR allowances in the open market. 8

9

Q. HOW MANY ADDITIONAL CSAPR SEASONAL NOx ALLOWANCES DID TES 10

PURCHASE? 11

A. TES purchased 400 additional CSAPR seasonal NOx allowances beyond those allocated 12

to it by the EPA. 13

14

Q: DID TES PURCHASE MORE ALLOWANCES THAN IT NEEDED FOR THE 15

2016 NOx OZONE SEASON? 16

A: Yes. 17

18

Q: IF SO, HOW MANY EXTRA? 19

A: TES needed to purchase a minimum of 334 CSAPR seasonal NOx allowances in 2016, 20

and actually purchased 400 allowances on November 28, 2016. 21

22

326

22

Q: HOW DID TES DETERMINE THE NUMBER OF CSAPR SEASONAL NOx 1

ALLOWANCES THAT IT NEEDED TO HOLD IN 2016? 2

A: It was based on actual NOx emissions from both of TES's boilers during the Ozone Season 3

(May through September), plus a prudent margin to account for corrections and 4

reconciliations as suggested by the EPA. 5

6

Q: IS THERE A DOCUMENT IN WHICH THE EPA SUGGESTED A PRUDENT 7

MARGIN TO ACCOUNT FOR CORRECTIONS AND RECONCILIATIONS? 8

A: Yes. See attached exhibit BMP-11 (RJT-4). In that EPA document, the EPA states that it: 9

"…recommends that compliance accounts hold more allowances than 10 are needed to cover emissions in case, after the allowance transfer 11 deadline, NOx or SO2 emissions are discovered to be greater than 12 what was originally reported or accounting or other types of errors 13 were made." 14

15

Q: WHY DOES THE EPA RECOMMEND HOLDING MORE ALLOWANCES 16

THAN ARE NEEDED TO COVER EMISSIONS? 17

A: In Exhibit BMP-11 (RJT-4), the EPA recommends holding more allowances than are 18

needed to cover emissions in order "To avoid costly excess emissions penalties--$3,818 a 19

ton for Acid Rain affected sources, and a 2 for 1 allowance surrender for sources subject 20

to CSAPR…." 21

22

Q: WHY WAS IT PRUDENT FOR TES TO PURCHASE MORE ALLOWANCES 23

THAN IT ACTUALLY NEEDED? 24

A: Because there are penalties for not holding sufficient allowances to cover actual 25

emissions. For the CSAPR ozone season program, 40 CFR 97.524(d) provides that if an 26

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23

emission source does not hold sufficient allowances to cover actual emissions, the EPA 1

will then deduct two allowances per each ton of excess emissions as a penalty. 2

3

Q: WERE THERE ANY OTHER REASONS FOR BUYING MORE ALLOWANCES 4

THAN WERE REQUIRED TO COVER ACTUAL EMISSIONS? 5

A: Yes. The determination of NOx emissions is accomplished through the use of continuous 6

emissions monitoring systems (CEMS) operated and maintained in accordance with 40 7

CFR Part 75. While TES diligently maintains the monitoring equipment and attempts to 8

follow all of the EPA’s related guidance and reporting instructions, internal or external 9

EPA audits of the data submitted under 40 CFR Part 75 could result in a need to revise 10

previously reported NOx emissions after the deadline for acquiring allowances. By 11

maintaining a reasonable margin of allowances above the reported NOx emissions for a 12

given compliance period, TES is able to minimize the likelihood that any necessary data 13

revisions would result in its failure to hold a sufficient number of allowances to cover 14

emissions. Thus, having some extra allowances in our account gives TES the ability to 15

use those allowances to cover any shortfall caused by compliance deductions, which 16

helps to avoid costly and unpredictable EPA penalties. 17

18

Q: BY WHAT MECHANISM DID TES FIND OUT HOW MANY ALLOWANCES IT 19

ACTUALLY NEEDED IN 2016? 20

A: By October 30, 2016, TES was required to submit the Part 75 Electronic Data Report 21

(EDR) for the 3rd quarter of 2016, with the report including an accounting of the NOx 22

emissions for the 2016 ozone season. The preceding level of NOx emissions was then 23

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24

compared to the facility’s initial 2016 CSAPR seasonal NOx allocation from the EPA to 1

arrive at the needed allowance purchases. 2

3

Q: WHAT ARE THE BEGINNING AND ENDING DATES OF THE CSAPR 4

SEASONAL NOx ALLOWANCE PERIOD? 5

A: May 1st through September 30th of each calendar year, starting in 2015 and each calendar 6

year thereafter. 7

8

Q: WHAT IS THE DEADLINE FOR PURCHASING ALLOWANCES TO COVER 9

THAT PERIOD? 10

A: Allowances for a given NOx ozone season compliance period must be held in a facility’s 11

compliance account by no later than midnight on November 30th following each ozone 12

season compliance period. 13

14

Q: WHEN DO YOU FIND OUT HOW MANY OF THOSE ALLOWANCES WERE 15

USED AND HOW MANY ARE LEFT OVER? 16

A: The EPA typically completes allowance deductions for a given ozone season compliance 17

period in February of the following calendar year. For the 2016 CSAPR NOx ozone 18

season compliance period, the EPA completed allowance deductions on February 2, 19

2017. 20

21

Q: DOES CSAPR INCLUDE ANY ANNUAL, AS OPPOSED TO SEASONAL, NOx 22

EMISSION REQUIREMENTS? 23

329

25

A: Yes. 1

2

Q: WHAT ARE THE BEGINNING AND ENDING DATES OF THE CSAPR 3

ANNUAL NOx ALLOWANCE PERIOD? 4

A: January 1st through December 31st of each calendar year, starting in 2015 and each 5

calendar year thereafter. 6

7

Q: WHAT WAS THE DEADLINE FOR PURCHASING ALLOWANCES TO COVER 8

THAT PERIOD? 9

A: For the 2015 CSAPR NOx annual compliance period, TES was required to purchase its 10

annual NOx allowances (i.e., the amount that exceeded the EPA allocation) by no later 11

than midnight on March 1, 2016. 12

13

Q: DID TES PURCHASE ANY CSAPR NOx ANNUAL ALLOWANCES IN 2016? 14

A: Yes, TES incurred costs in 2016 in accordance with the CSAPR compliance deadline, 15

requiring that a facility hold its allowances by no later than midnight on March 1st 16

following each annual compliance period. These allowances were purchased between 17

February 11, 2016 and February 16, 2016. 18

19

Q. HOW MANY ADDITIONAL CSAPR ANNUAL NOx ALLOWANCES DID TES 20

PURCHASE? 21

A. TES emitted 1,615 tons of NOx during the 2015 CSAPR annual NOx compliance period. 22

The U.S. EPA initially granted TES 500 CSAPR NOx annual allowances for that 23

330

26

compliance period. TES purchased 1,200 additional CSAPR annual NOx allowances 1

beyond those allocated to it by the EPA. 2

3

Q: DID TES PURCHASE MORE ALLOWANCES THAN IT NEEDED FOR THE 4

2015 NOx ANNUAL COMPLIANCE PERIOD? 5

A: Yes. 6

7

Q: IF SO, HOW MANY EXTRA? 8

A: In 2016, TES needed to purchase a minimum of 1,105 CSAPR NOx annual allowances 9

for the 2015 compliance period. TES actually purchased 1,200 allowances in February 10

2016. In addition, on February 12, 2016, TES was granted 10 additional 2015 CSAPR 11

annual NOx allowances. 12

13

Q. WAS IT REASONABLE AND PRUDENT FOR TES TO PURCHASE MORE 14

ALLOWANCES THAN IT NEEDED FOR THE 2015 NOx ANNUAL 15

COMPLIANCE PERIOD? 16

A. Yes. Please see my earlier testimony regarding the reasonableness and prudence of 17

purchasing more seasonal allowances than a facility may need. 18

19

Q: DURING 2016, WAS THE TES FACILITY REQUIRED TO PURCHASE ANY 20

CSAPR SO2 ALLOWANCES? 21

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27

A: No, the EPA allocated sufficient CSAPR SO2 allowances to TES to cover the plant's 1

actual 2015 SO2 emissions. Accordingly, TES was not required to purchase any 2

additional allowances in the market. 3

4

Q: WHEN DO YOU FIND OUT HOW MANY OF THOSE SO2 ALLOWANCES 5

WERE USED AND HOW MANY ARE LEFT OVER? 6

A: The EPA typically completes allowance deductions for a given annual compliance period 7

in May of the following calendar year. For the 2015 CSAPR annual NOx and SO2 8

compliance periods, the EPA completed its allowance deductions on May 5, 2016. 9

10

Q. ARE CSAPR NOx ALLOWANCES A FUEL OR VARIABLE OPERATION AND 11

MAINTENANCE COST? 12

A. Yes. In at least three cases, the MPSC has held that allowances costs are fuel costs 13

(MPSC Case Nos. U-10335 (p. 67), U-13937 (p. 9) and U-15415 (p. 11)). Additionally, 14

the need for allowances arises as a result of the operation of the generator’s facility and 15

varies according to its electrical output. 16

17

Q. EXHIBIT BMP-7 (RJT-1) INDICATES THAT THE CSAPR NOx ALLOWANCE 18

COSTS ARE NOT SUBJECT TO THE MONTHLY CAP UNDER MCL 460.6a. 19

WHY ARE THE CSAPR ALLOWANCE COSTS NOT SUBJECT TO THE CAP? 20

A. Section 6a(7) of 2008 PA 286, MCL 460.6a(7), allows TES to “recover the amount, if 21

any, by which the merchant plant's reasonably and prudently incurred actual fuel and 22

variable operation and maintenance costs exceed the amount that the merchant plant is 23

332

28

paid under the contract for those costs.” Section 6a(8) of 2008 PA 286, MCL 460.6a(8), 1

further provides that: "the $1,000,000.00 limit specified in this subsection, as adjusted, 2

shall not apply with respect to actual fuel and variable operation and maintenance costs 3

that are incurred due to changes in federal or state environmental laws or regulations that 4

are implemented after the effective date of the amendatory act that added this subsection 5

[October 6, 2008]." TES incurred its CSAPR allowance costs due to changes in federal 6

or state environmental laws or regulations that were implemented after October 6, 2008. 7

8

Q. WHAT WAS THE CHANGE IN FEDERAL OR STATE ENVIRONMENTAL 9

LAWS OR REGULATIONS THAT WAS IMPLEMENTED AFTER OCTOBER 6, 10

2008 THAT CAUSED TES TO INCUR THESE CSAPR ALLOWANCE COSTS? 11

A. The change was the new Cross State Air Pollution Rule ("CSAPR") which was proposed 12

after October 6, 2008, noticed after October 6, 2008, promulgated after October 6, 2008, 13

revised after October 6, 2008, and implemented after October 6, 2008. 14

15


A. CSAPR was originally proposed on July 6, 2010 and notice of the proposed rule was 17

published in the Federal Register on August 2, 2010, (75 FR 45210). See, Exhibit BMP-18

12 (RJT-5). The CSAPR regulations were promulgated by the U.S. Environmental 19

Protection Agency on August 8, 2011 (76 FR 48208). See, Exhibit BMP-13 (RJT-6). 20

The purpose of the CSAPR regulations was to limit the interstate transport of emissions 21

of nitrogen oxides (NOx) and sulfur dioxide (SO2) and the CSAPR regulations specify 22

333

29

both seasonal and annual allowance requirements for NOx and annual allowance 1

requirements for SO2. 2

A proposed revision to the CSAPR regulations was published on October 14, 2011 (76 3

FR 63817, et seq.) and a supplemental rule adopted on December 27, 2011 (76 FR 80760, 4

et seq.). See, Exhibits BMP-14 and BMP-15 (RJT-7 & 8). This supplemental rule 5

required five additional states to make seasonal NOx reductions under CSAPR (Iowa, 6

Michigan, Missouri, Oklahoma and Wisconsin). CSAPR was implemented on January 1, 7

2015. CSAPR is codified in the Code of Federal Regulations at 40 CFR 97 Subparts 8

AAAAA to DDDDD. http://www.ecfr.gov/cgi-bin/text-9

idx?tpl=/ecfrbrowse/Title40/40cfr97_main_02.tpl 10

11

Q. WHEN WAS TES REQUIRED TO COMPLY WITH THE NEW CSAPR RULE? 12

A. TES was required to comply with the new CSAPR regulations beginning on January 1, 13

2015. Compliance with CSAPR’s Phase 1 emissions budgets was initially proposed for 14

2012, but subsequently delayed until 2015. (79 FR 71663, et seq.) BMP-16 (RJT-9) . 15

The EPA's website clearly states that "CSAPR implementation began on January 1, 16

2015.” See, https://www.epa.gov/csapr/cross-state-air-pollution-rule-csapr-basics 17

18

Q. DID TES EVER INCUR CSAPR ALLOWANCE COSTS PRIOR TO 2016? 19

A. No. 20

21

22

23

334

http://www.ecfr.gov/cgi-bin/text-idx?tpl=/ecfrbrowse/Title40/40cfr97_main_02.tpl

http://www.ecfr.gov/cgi-bin/text-idx?tpl=/ecfrbrowse/Title40/40cfr97_main_02.tpl

30

Q. WHY DIDN’T TES PURCHASE CSAPR ALLOWANCES BEFORE 2016? 1

A. The CSAPR requirements were not promulgated until 2011 and were not implemented 2

until 2015. Accordingly, TES was not subject to any CSAPR regulations until 2015, and 3

was not required to purchase any CSAPR allowances until the new requirements were 4

implemented in 2015. 5

6

Q. ARE THERE ANY DOCUMENTS THAT CONFIRM THE FACT THAT THE 7

CSAPR RULES WERE NOT PROMULGATED UNTIL 2011 AND WERE NOT 8

MADE EFFECTIVE UNTIL 2016? 9

A. Yes. See Exhibits BMP-11 (RJT-4), BMP-12 (RJT-5), BMP-13 (RJT-6), BMP-14 (RJT-10

7), BMP-15 (RJT-8) and BMP-16 (RJT-9), all discussed above. 11

12

VIII. CSAPR NOx ALLOWANCE PROCUREMENT PROCEDURES 13

Q. PLEASE DESCRIBE THE PROCESS THAT WAS USED BY TES TO 14

PURCHASE THE CSAPR NOx ALLOWANCES. 15

A. TES utilized CMS Energy Company’s wholly owned subsidiary, CMS Energy Resource 16

Management Company (“CMS ERM Co”) as its agent to acquire CSAPR NOx 17

allowances. CMS ERM Co agreed to arrange for TES’s acquisition of the necessary 18

CSAPR NOx allowances when it arranged for other non-regulated entities to obtain their 19

allowances. 20

21

335

31

Q. WHEN YOU DECIDED TO UTILIZE CMS ERM CO TO PROCURE THE 1

CSAPR NOx ALLOWANCES, DID YOU CONSIDER OTHER AVAILABLE 2

ALTERNATIVES? 3

A. Yes. 4

5

Q. PLEASE EXPLAIN WHAT ALTERNATIVES YOU CONSIDERED AND WHY 6

YOU CHOSE TO REJECT THEM. 7

A. TES considered retaining a different agent or directing one of our staff members to 8

become familiar with the procedure for acquiring CSAPR allowances directly. CMS 9

ERM Co, however, offered to perform the function at no cost to TES as part of CMS 10

ERM Co's efforts to procure CSAPR NOx allowances for other affiliated non-regulated 11

power plants. By combining the purchases of TES’s CSAPR NOx allowances with the 12

purchase of CSAPR NOx allowances for other independent power plants, all the power 13

plants gained an economy of scale that lowered the costs for all of the participating power 14

plants in the pool. Since there were no added costs to utilize CMS ERM Co as TES’s 15

agent, and since TES would not have to incur the expense of acquiring or developing in-16

house expertise, obtaining TES’s CSAPR NOx allowances in this manner constituted the 17

lowest possible cost approach for obtaining the necessary allowances. Additionally, 18

since some of the CSAPR NOx allowance costs had to be paid out of CMS Energy 19

Company’s gross operating income, and thereby reduce its profitability, TES was 20

confident that there were strong financial incentives for CMS ERM Co to minimize the 21

allowance costs to the benefit of all of the power plants in the pool. 22

23

336

32

Q. WHAT WERE THE BENEFITS OF USING CMS ERM CO TO ACQUIRE THE 1

CSAPR ALLOWANCES? 2

A. TES was able to utilize the expertise of CMS ERM Co’s personnel to secure CSAPR 3

NOx allowances adequate to meet TES's generating needs to comply with the applicable 4

regulations, while minimizing both the allowance costs and the transaction costs to secure 5

the allowances as much as practicable. CMS ERM Co is able to aggregate the emission 6

allowance needs of several of CMS Energy Company's non-regulated entities to achieve 7

better economies of scale for the benefit of all entities involved. Better economies of 8

scale will often improve prices. 9

10

Q. DID TES MAKE REASONABLE EFFORTS TO MINIMIZE ITS CSAPR 11

ALLOWANCE COSTS? 12

A. Yes, to the extent practicable, we made every reasonable effort to control these costs. We 13

used CMS ERM Co’s buying power to acquire our CSAPR NOx allowances, and CMS 14

ERM Co did not add any fees or transaction costs for its service. 15

16

Q. AT THE TIME TES PURCHASED THE CSAPR ALLOWANCES, WERE THOSE 17

PRICES THE BEST PRICES THAT WERE REASONABLY AVAILABLE TO 18

TES? 19

A. Yes. I instructed CMS ERM Co to arrange for the lowest cost CSAPR NOx allowances 20

available at the time. Additionally, CMS ERM Co was purchasing CSAPR NOx 21

allowances for other affiliated non-regulated entities at the same time it was buying 22

CSAPR NOx allowances for TES. Since some of the CSAPR NOx allowance costs had to 23

337

33

be paid out of CMS Energy Company’s gross operating income, thereby reducing the 1

profitability of CMS Energy Company, we were confident that there were strong 2

financial incentives for CMS ERM Co to minimize the allowance costs to the benefit of 3

all of the power plants in the pool. 4

5

Q. IN CONNECTION WITH YOUR CSAPR ALLOWANCE PROCUREMENT 6

DECISIONS, DID YOU EXERCISE YOUR BEST JUDGMENT? 7

A. Yes. 8

9

Q. IN YOUR OPINION, WERE TES’s DECISIONS TO PURCHASE CSAPR 10

ALLOWANCES THROUGH CMS ENERGY’S SUBSIDIARY, CMS ERM CO, 11

REASONABLE AND PRUDENT BASED ON THE FACTS AND 12

CIRCUMSTANCES KNOWN OR REASONABLY FORESEEABLE AT THE 13

TIME WHEN THE DECISIONS WERE MADE? 14

A. Yes. 15

16

Q. IN YOUR OPINION, WERE TES’s CSAPR ALLOWANCE PURCHASES 17

REASONABLE AND PRUDENT? 18

A. Yes. By using a CMS ERM Co staff member experienced in allowance procurement, by 19

aggregating our allowances into a larger buying pool with other power plants, and by 20

recognizing that CMS Energy Company affiliates were bearing the financial cost of some 21

of these allowances for their own internal use, we believe that we achieved the lowest 22

338

34

possible cost for these allowances. Our decision to use CMS ERM Co to procure the 1

necessary CSAPR allowances was reasonable and prudent. 2

3

XI. CONCLUSION 4

Q. IN YOUR OPINION, WERE TES’s PURCHASING PRACTICES REASONABLE 5

AND PRUDENT? 6

A. Yes. 7

8

Q. IN YOUR OPINION, WERE TES’s ACTUAL FUEL AND VARIABLE 9




A. Yes. 13

14

Q. ARE TES’s RECORDS WITH RESPECT TO FUEL AND VARIABLE 15

OPERATION AND MAINTENANCE COSTS AUDITED? 16

A. Yes. Our plant’s 2016 records were audited by Hungerford, Aldrin, Nichols & Carter, 17

PC. 18

19


FIELD OF FUEL PROCUREMENT, DO YOU THINK THAT ANY OF TES’s 21


WERE EXTRAVAGANT, UNNECESSARY, OR IMPRUDENT? 23

339

35


2


PROCEEDING? 4

A. Yes, it does. 5

340

STATE OF MICHIGAN



DIRECT TESTIMONY

OF

NEIL R. TARATUTA

ON BEHALF OF

VIKING ENERGY OF LINCOLN, LLC

(REVISED 9-13-2017)

341

1

INTRODUCTION 1


A. My name is Neil R. Taratuta and my business address is 509 W. State St., Lincoln, 3

Michigan. 4

5


A. I am employed by Viking Energy of Lincoln, LLC an ENGIE NA company, as Plant 7

Manager for the Lincoln Power Station ("Viking Energy of Lincoln"). 8

9

Q. PLEASE BRIEFLY DESCRIBE YOUR PLANT. 10

A. The Lincoln Power Station is a merchant plant consisting of electric generating 11

equipment and associated facilities with a nameplate capacity of 16 MW. With our good 12

management practices and experience with the equipment, we are able to achieve an 13

actual capacity of 18 MWe (megawatt electric) at the plant. Our plant is located in 14

Lincoln, Michigan and is not owned or operated by an electric utility. 15

16


EXPERIENCE. 18

A. I hold a Bachelor of Science degree in Electrical Engineering Technology from Lake 19

Superior State University. Since 1990, I have held positions of increasing responsibility 20

at the Lincoln Power Station. From 1990 to 2005, I was the Unit Supervisor. From 2005 21

to 2008, I was the Operations Supervisor at the plant. In 2008, I was promoted to Plant 22

Manager. 23

342

2


A. I am responsible for the operation and maintenance of the Lincoln Power Station. 2

3

Q. WITHIN YOUR ORGANIZATION, ARE YOU THE PERSON WHO IS MOST 4

RESPONSIBLE FOR FUEL PROCUREMENT? 5

A. No. Procurement of fuel is the responsibility of the Regional Fuels Manager, Don 6

Adams. My responsibility regarding fuel procurement is primarily from the time when 7

the fuel is delivered to the site. This includes weighing delivered loads, unloading and 8

storing fuel, and transferring fuel to the power plant. Additionally, fuel procurement is 9

within the plant budget for which I am responsible in its entirety. 10

11





16045-R, its 2011 PSCR reconciliation proceeding, MPSC Case No. U-16432-R, its 2012 16

PSCR reconciliation proceeding, MPSC Case No. U-16890-R, its 2013 PSCR 17

reconciliation proceeding, MPSC Case No. U-17095-R, its 2014 PSCR reconciliation 18

proceeding, MPSC Case No. U-17317-R, and its 2015 reconciliation proceeding, MPSC 19

Case No. U-17678-R. 20

21


PROCEEDING? 23

343

3

A. My testimony is on behalf of Viking Energy of Lincoln. 1

2


A. Yes. I am sponsoring Exhibit BMP-8 (NRT-1) and co-sponsoring Exhibits BMP-1 and 4

BMP-2. 5

6


SUPERVISION? 8

A. Yes. 9

10



A. The purpose of my testimony is to describe Lincoln Power Station's actual fuel and 13


December 31, 2016 and to demonstrate that the variable operation and maintenance costs 15

were reasonably and prudently incurred. My colleague, Mr. Donald Adams will testify 16

that the fuel costs were reasonably and prudently incurred. I will also testify as to the 17

amount that Consumers Energy Company paid to Lincoln Power Station for fuel and 18

variable operation and maintenance costs incurred during the foregoing time period. My 19

testimony provides factual support for Viking Energy of Lincoln’s request for recovery of 20

costs under the terms of Public Act 286 of 2008, which permits recovery of costs that 21

exceed the amount that a merchant plant is paid under contract with an eligible utility for 22

those costs. 23

344

4


Q. IS THERE A POWER PURCHASE AGREEMENT ("PPA") BETWEEN VIKING 2

ENERGY OF LINCOLN AND CONSUMERS ENERGY COMPANY? 3




U-16045-R. 7

8



A. No. 11

12

Q. WAS THE LINCOLN PLANT’S PPA ENTERED ON OR BEFORE JANUARY 1, 13

2008? 14

A. Yes. 15

16


A. Yes. 18

19

Q. DOES THE PPA PROVIDE FOR THE LINCOLN PLANT TO SELL 20




345

5


Q. AT ANY TIME PRIOR TO JANUARY 1, 2008, DID THE LINCOLN PLANT 2

GENERATE ANY ELECTRICITY IN WHOLE OR IN PART FROM WOOD OR 3

SOLID WOOD WASTES AND SELL THAT ELECTRICITY TO CONSUMERS 4

ENERGY COMPANY? 5

A. Yes. 6

7

Q. DOES THE LINCOLN PLANT STILL GENERATE ELECTRICITY IN WHOLE 8

OR IN PART FROM WOOD OR SOLID WOOD WASTES AND SELL THAT 9

ELECTRICITY TO CONSUMERS ENERGY COMPANY? 10

A. Yes. 11

12



PAYMENTS TO VIKING ENERGY OF LINCOLN UNDER THE TERMS OF 15

THE PPA? 16

A. Yes. 17

18


VIKING ENERGY OF LINCOLN INCLUDE PAYMENT FOR FUEL AND 20


A. Yes. 22

23

346

6

Q. DID THE AMOUNT OF VIKING ENERGY OF LINCOLN'S ACTUAL FUEL 1

AND VARIABLE O & M COSTS EXCEED THE AMOUNT THAT CONSUMERS 2

ENERGY PAID TO VIKING ENERGY OF LINCOLN UNDER THE PPA FOR 3

THOSE COSTS? 4

A. Yes. Please see Exhibits BMP-1, BMP-2 and BMP-8 (NRT-1). 5

6

Q. IS THE LINCOLN PLANT A LANDFILL GAS PLANT, A HYDRO PLANT, OR 7

A MUNICIPAL SOLID WASTE PLANT? 8

A. No. 9

10

Q. IS VIKING ENERGY OF LINCOLN ENGAGED IN LITIGATION AGAINST AN 11



A. No. 14

15

COST DATA 16

Q. WHAT AMOUNT HAS THE LINCOLN PLANT SET FORTH ON EXHIBIT 17

BMP-8 AS ITS ACTUAL FUEL AND VARIABLE OPERATION AND 18



A. Viking Energy of Lincoln has identified $5,954,464 in actual fuel and variable operation 21


23

347

7




A. Yes, as discussed in more detail below, Lincoln is seeking recovery for those categories 4

of variable operation and maintenance costs identified in Exhibit BMP-8 (NRT-1). 5

6


VIKING ENERGY OF LINCOLN PURSUANT TO THE PPA BETWEEN 8

VIKING ENERGY OF LINCOLN AND CONSUMERS FOR FUEL AND 9


2016. 11



2016. 14

15

Q. WAS THERE A SHORTFALL BETWEEN THE FUEL AND VARIABLE O & M 16

COSTS THAT VIKING ENERGY OF LINCOLN INCURRED FOR SALES TO 17

CONSUMERS IN 2016 AND THE PAYMENTS THAT VIKING ENERGY OF 18

LINCOLN RECEIVED FROM CONSUMERS FOR THOSE COSTS UNDER ITS 19

PPA? 20

A. Yes, that shortfall was $1,671,381. 21

22

348

8





Viking Energy of Lincoln for actual fuel and variable operation and maintenance costs 5

are detailed on Exhibit BMP-8 (NRT-1). 6

7

Q. WHAT AMOUNT IS VIKING ENERGY OF LINCOLN SEEKING TO 8

RECOVER IN THIS PROCEEDING. 9

A. As set forth in Exhibit BMP-1, Viking Energy of Lincoln is seeking to recover 10








The result of this reallocation process would be that the amount that Viking Energy of 18

Lincoln is seeking to recover in this proceeding would change in order to accurately 19

reflect its proportionate share of the capped amount. 20

21



349

9




PARTIAL PAYMENTS TO LINCOLN IN 2016? 4

A. Yes, Consumers Energy has paid Lincoln $839,321 of the $1,208,912 of capped fuel and 5

variable O & M costs that Lincoln seeks to recover in this proceeding, leaving a balance 6

due to Lincoln of $369,591, as reflected in Exhibits BMP-1, BMP-2 and BMP-8 (NRT-7

1). 8

9

Q. IS VIKING ENERGY OF LINCOLN SEEKING RECOVERY OF ANY ACTUAL 10

FUEL AND VARIABLE OPERATION AND MAINTENANCE COSTS THAT 11

WERE INCURRED DUE TO CHANGES IN FEDERAL OR STATE 12

ENVIRONMENTAL LAWS OR REGULATIONS THAT WERE 13

IMPLEMENTED AFTER OCTOBER 6, 2008? 14

A. No. 15

16


Q. PLEASE DESCRIBE THE FUEL OR FUELS THAT THE LINCOLN PLANT 18

USED TO GENERATE ELECTRICITY DURING 2016. 19

A. The Lincoln Plant used chipped waste wood, including chipped creosote treated railroad 20

ties, and tire derived fuel (“TDF”), to generate electricity from January 1, 2016 through 21

December 31, 2016. 22

350

10


PLEASE STATE THE VOLUMES THAT WERE USED DURING 2016. 2

A. The volumes of fuels used were as follows: 3

• Chipped Waste Wood 178,206 Tons 4

• Tire Derived Fuel 11,524 Tons 5

6





A. Lincoln is seeking to recover those variable operation and maintenance costs identified in 11

BMP-8. Those costs include, among others: 1) water supply costs; 2) sewer and 12

wastewater disposal costs; 3) ash handling costs; 4) fuel handling costs; 5) emission 13

control costs; and 6) water treatment costs. 14

15




19

Q. PLEASE EXPLAIN THE MEASURES THAT THE LINCOLN PLANT 20



351

11

A. We utilize a variety of measures to control our variable costs. Purchases are 1

competitively bid where practicable in accordance with written company policies and 2

procedures. Markets are monitored to determine prevailing prices. Equipment is 3

shutdown when not in use. Additionally, equipment is maintained in accordance with a 4

preventive and predictive maintenance program that ensures the equipment is operating at 5

its peak efficiency. Unnecessary repairs or modifications are not made. 6

7

CONCLUSION 8

Q. IN YOUR OPINION, WERE THE LINCOLN PLANT'S PURCHASING 9



12

Q. ARE THE LINCOLN PLANT'S RECORDS WITH RESPECT TO FUEL AND 13

VARIABLE OPERATION AND MAINTENANCE COSTS AUDITED? 14

A. Yes. Our plant’s 2016 records were subject to an internal audit performed by our parent 15

company, Engie NA. No issues were identified relating to purchasing of materials or 16

services for Lincoln Power Station. The audit included a review of fuel and variable 17


19

Q. IN YOUR OPINION, WERE THE LINCOLN PLANT'S ACTUAL FUEL AND 20

VARIABLE OPERATION AND MAINTENANCE COSTS FOR 2016 21


A. Yes. 23

352

12

Q. IN YOUR OPINION, DO YOU THINK THAT ANY OF YOUR MERCHANT 1

PLANT'S ACTUAL FUEL OR VARIABLE OPERATION AND MAINTENANCE 2

COSTS WERE EXTRAVAGANT, UNNECESSARY, INEFFICIENT OR 3

IMPRUDENT? 4


6


PROCEEDING? 8

A. Yes, it does. 9

353

STATE OF MICHIGAN



DIRECT TESTIMONY

OF

THOMAS V. VINE

ON BEHALF OF

VIKING ENERGY OF MCBAIN, LLC

(REVISED 9-13-2017)

354

1

INTRODUCTION 1


A. My name is Thomas V. Vine and my business address is 6751 W. Gerwoude Drive, 3

McBain, Michigan. 4

5


A. I am employed by Viking Energy of McBain, LLC, an ENGIE NA company, as Plant 7

Manager for the McBain Power Station. 8

9

Q. PLEASE BRIEFLY DESCRIBE YOUR PLANT. 10

A. The McBain Power Station is a merchant plant consisting of electric generating 11

equipment and associated facilities with a nameplate capacity of approximately 16 MW. 12

With our good management practices and experience with the equipment, we are able to 13

achieve an actual capacity of 18 MWe (megawatt electric) at the plant. Our plant is 14

located in McBain, Michigan and is not owned or operated by an electric utility. 15

16


EXPERIENCE. 18

A. I have held the position of Plant Manager at Viking Energy of McBain from July 2008 19

until the present. Between 2005 and 2008, I was the Maintenance Manager for the 20

University of Iowa Power Plant. From 1981 to 2005, I worked in the commercial nuclear 21

power field holding various positions including Manager, Engineering Programs; 22

Supervisor, Radwaste; Project Engineer, Spent Fuel Storage; and Principal Engineer. 23

355

2

I hold Bachelor of Science degrees from Temple University in Architecture and Civil 1

Engineering & Construction Technology. I have also completed graduate courses in 2

Engineering at the Pennsylvania State University. 3

4


A. I am responsible for the operation and maintenance of the McBain Power Station. 6

7



A. No. Procurement of fuel is the responsibility of the Regional Fuels Manager, Don 10

Adams. Although Mr. Adams is my direct report, my responsibility regarding fuel 11

procurement is primarily from the time when the fuel is delivered to the site. This 12

includes weighing delivered loads, unloading and storing fuel, and transferring fuel to the 13

power plant. Additionally, fuel procurement is within the plant budget for which I am 14

responsible in its entirety. 15

16







reconciliation proceeding, MPSC Case No. U-17095-R, its 2014 PSCR reconciliation 23

356

3

proceeding, MPSC Case No. U-17317-R, its 2015 PSCR reconciliation proceeding, 1

MPSC Case No. U-17678-R, and MPSC Case No. U-18090, Consumers' avoided cost 2

PURPA proceeding. 3

4


PROCEEDING? 6

A. My testimony is on behalf of Viking Energy of McBain. 7

8


A. Yes. I am sponsoring Exhibit BMP-9 (TVV-1) and co-sponsoring Exhibits BMP-1 and 10

BMP-2. 11

12


SUPERVISION? 14

A. Yes. 15

16



A. The purpose of my testimony is to describe McBain Power Station's actual fuel and 19


December 31, 2016 and to demonstrate that the variable operation and maintenance costs 21

were reasonably and prudently incurred. My colleague, Mr. Donald Adams, will testify 22

that the fuel costs were reasonably and prudently incurred. I will also testify as to the 23

357

4

amount that Consumers Energy Company paid to McBain Power Station for fuel and 1

variable operation and maintenance costs incurred during the foregoing time period. My 2

testimony provides factual support for Viking Energy of McBain’s request for recovery 3

of certain costs under the terms of Public Act 286 of 2008, which permits recovery of 4

costs that exceed the amount that a merchant plant is paid under contract with an eligible 5

utility for those costs. 6

7


Q. IS THERE A POWER PURCHASE AGREEMENT ("PPA") BETWEEN VIKING 9

ENERGY OF MCBAIN AND CONSUMERS ENERGY COMPANY? 10


the MPSC. It was provided to the parties in both Consumers Energy's 2009 and 2010 12

PSCR Reconciliation cases, MPSC Case Nos. U-15675-R and U-16045-R. 13

14



A. No. 17

18

Q. WAS VIKING ENERGY OF MCBAIN'S PPA ENTERED ON OR BEFORE 19

JANUARY 1, 2008? 20

A. Yes. 21

22

23

358

5


A. Yes. 2

3

Q. DOES THE PPA PROVIDE FOR THE MCBAIN PLANT TO SELL 4





9

Q. AT ANY TIME PRIOR TO JANUARY 1, 2008, DID THE MCBAIN PLANT 10

GENERATE ANY ELECTRICITY IN WHOLE OR IN PART FROM WOOD OR 11

SOLID WOOD WASTES AND SELL THAT ELECTRICITY TO CONSUMERS 12

ENERGY COMPANY? 13

A. Yes. 14

15

Q. DOES THE MCBAIN PLANT STILL GENERATE ELECTRICITY IN WHOLE 16

OR IN PART FROM WOOD OR SOLID WOOD WASTES AND SELL THAT 17

ELECTRICITY TO CONSUMERS ENERGY COMPANY? 18

A. Yes. 19

20



359

6

PAYMENTS TO VIKING ENERGY OF MCBAIN UNDER THE TERMS OF THE 1

PPA? 2

A. Yes. 3

4


VIKING ENERGY OF MCBAIN INCLUDE PAYMENT FOR FUEL AND 6


A. Yes. Please see Exhibits BMP-1, BMP-2 and BMP-9 (TVV-1). 8

9

Q. DID THE AMOUNT OF VIKING MCBAIN'S ACTUAL FUEL AND VARIABLE 10

O & M COSTS EXCEED THE AMOUNT THAT CONSUMERS ENERGY PAID 11

TO VIKING ENERGY OF MCBAIN UNDER THE PPA FOR THOSE COSTS? 12

A. Yes. Please see Exhibits BMP-1, BMP-2 and BMP-9 (TVV-1). 13

14

Q. IS THE MCBAIN PLANT A LANDFILL GAS PLANT, A HYDRO PLANT, OR A 15

MUNICIPAL SOLID WASTE PLANT? 16

A. No. 17

18

Q. IS VIKING ENERGY OF MCBAIN ENGAGED IN LITIGATION AGAINST AN 19



A. No. 22

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7

COST DATA 1

Q. WHAT AMOUNT HAS VIKING ENERGY OF MCBAIN SET FORTH ON 2

EXHIBIT BMP-9 AS ITS ACTUAL FUEL AND VARIABLE OPERATION AND 3

MAINTENANCE COSTS FOR 2016? 4

A. Viking Energy of McBain has identified $6,794,710 in actual fuel and variable operation 5


7




A. Yes, as discussed in more detail below, McBain is seeking recovery for those categories 11

of variable operation and maintenance costs identified in Exhibit BMP-9 (TVV-1). 12

13


VIKING ENERGY OF MCBAIN PURSUANT TO THE PPA BETWEEN VIKING 15

ENERGY OF MCBAIN AND CONSUMERS FOR FUEL AND VARIABLE 16

OPERATION AND MAINTENANCE COSTS INCURRED DURING 2016. 17



2016. 20

21

Q. WAS THERE A SHORTFALL BETWEEN THE FUEL AND VARIABLE O & M 22

COSTS THAT VIKING ENERGY OF MCBAIN INCURRED FOR SALE TO 23

361

8

CONSUMERS AND THE PAYMENTS THAT VIKING ENERGY OF MCBAIN 1

RECEIVED FROM CONSUMERS FOR THOSE COSTS UNDER ITS PPA? 2

A. Yes, the shortfall was $2,508,696. 3

4




A. Yes. The actual fuel and variable operation and maintenance costs are detailed on 8

Exhibit BMP-9 (TVV-1). 9

10

Q. WHAT AMOUNT IS VIKING ENERGY OF MCBAIN SEEKING TO RECOVER 11

IN THIS PROCEEDING. 12

A. As set forth in Exhibit BMP-1, Viking Energy of McBain is seeking to recover 13








The result of this reallocation process would be that the amount that Viking Energy of 21

McBain is seeking to recover in this proceeding would change in order to accurately 22

reflect its proportionate share of the capped amount.23

362

CORRECTED 9






PARTIAL PAYMENTS TO VIKING ENERGY OF MCBAIN IN 2016? 6

A. Yes, as reflected in Exhibits BMP-1, BMP-2 and BMP-9 (TVV-1), Consumers Energy 7

paid Viking Energy of McBain $1,223,917 of the $1,839,365 that Viking Energy of 8

McBain seeks to recover in this proceeding, leaving a balance due to Viking Energy of 9

McBain of $615,448. 10

11

Q. ARE YOU SEEKING RECOVERY OF ANY ACTUAL FUEL AND VARIABLE 12




A. No. 16

17


Q. PLEASE DESCRIBE THE FUEL OR FUELS THAT THE MCBAIN PLANT 19

USED TO GENERATE ELECTRICITY DURING 2016. 20

A. The McBain plant used chipped waste wood and tire derived fuel (“TDF”), to generate 21

electricity from January 1, 2016 through December 31, 2016. 22

23

363

10


PLEASE STATE THE VOLUMES THAT WERE USED DURING 2016. 2

A. The volumes of fuels used were as follows: 3

• Chipped Waste Wood 127,595 Tons 4

• Creosote Treated Wood 33,799 Tons 5

• Tire Derived Fuel 12,042 Tons 6

The, the total volume of fuel used in 2016 was 161,394 Tons. 7

8





A. We are seeking to recover those variable operation and maintenance costs identified in 13

BMP-9 (TVV-1). Those costs include, among others: 1) water supply costs; 2) sewer 14

and wastewater disposal costs; 3) ash handling costs; 4) fuel handling costs; 5) emission 15

control costs; and 6) water treatment costs. 16

17

Q. DID THE MCBAIN PLANT MINIMIZE THE FUEL AND VARIABLE 18


A. Yes, we made every reasonable effort to control these costs. Viking Energy has gone to 20

extraordinary measures to obtain its fuel at the lowest available cost. During 2016, 21

Viking Energy of McBain embarked on an innovative fuel procurement strategy to 22

provide fuel to the facility at costs substantially below other available options. This 23

364

11

involved the procurement of whole used railroad ties, shipping those to the plant in whole 1

form and processing them into usable boiler fuel. The on-site processing included the 2

removal of all metals such as tie plates, spikes, bolts and other miscellaneous metal parts 3

and sizing the wood to meet the boiler's fuel specifications. The processing was 4

accomplished using two highly specialized pieces of grinding equipment that first shred 5

the ties into pieces 1' to 2' long and removed metal parts in the process. The second 6

grinder was a hammer mill that sized the primary shreds into 2" to 3" fuel chips that 7

could be efficiently fed to the boiler for combustion. All costs to process this material 8

into fuel at the Viking Energy of McBain site, including the cost of operating, 9

maintaining and leasing the grinding equipment are captured as fuel costs for recovery 10

under PA 286. These reasonable and prudently incurred costs replaced costs which would 11

have been included in the price per ton paid for traditionally procured wood fuel, and this 12

was done at a lower cost than other available options. The cost savings were garnered by 13

first shipping the ties whole, which resulted in much lower transportation costs and, 14

second, by processing the ties into boiler fuel on site, eliminating the transportation cost 15

for the chipped fuel and utilizing in-house labor to perform these operations. 16

17

Q. PLEASE EXPLAIN OTHER MEASURES THAT THE MCBAIN PLANT 18



A. We utilize a variety of measures to control our variable costs. Purchases are 21

competitively bid where practicable in accordance with written company policies and 22

procedures. Markets are monitored to determine prevailing prices. Equipment is 23

365

12

shutdown when not in use. Additionally, equipment is maintained in accordance with a 1

preventive and predictive maintenance program that ensures the equipment is operating at 2

its peak efficiency. Unnecessary repairs or modifications are not made. 3

4

CONCLUSION 5

Q. IN YOUR OPINION, WERE THE MCBAIN PLANT'S PURCHASING 6



9

Q. IN YOUR OPINION, WERE THE MCBAIN PLANT'S ACTUAL FUEL AND 10

VARIABLE OPERATION AND MAINTENANCE COSTS FOR THE PERIOD 11

FROM JANUARY 1, 2016 THROUGH DECEMBER 31, 2016 REASONABLY 12

AND PRUDENTLY INCURRED? 13

A. Yes. 14

15

Q. ARE THE MCBAIN PLANT’S RECORDS WITH RESPECT TO FUEL AND 16

VARIABLE OPERATION AND MAINTENANCE COSTS AUDITED? 17

A. Yes. Our plant’s 2016 records were subject to an internal audit performed by our parent 18

company, Engie NA. No issues were identified relating to purchasing of materials or 19

services for McBain Power Station. The audit included a review of fuel and variable 20


22

366

13

Q. IN YOUR OPINION, DO YOU THINK THAT ANY OF THE MCBAIN PLANT'S 1


WERE EXTRAVAGANT, UNNECESSARY, INEFFICIENT OR IMPRUDENT? 3


5


PROCEEDING? 7

A. Yes, it does. 8

367

STATE OF MICHIGAN



REBUTTAL TESTIMONY

OF

THOMAS V. VINE

ON BEHALF OF

VIKING ENERGY OF MCBAIN, LLC

368

1

INTRODUCTION 1


A. My name is Thomas V. Vine and my business address is 6751 W. Gerwoude Drive, 3

McBain, Michigan. 4

5

Q. ARE YOU THE SAME THOMAS V. VINE WHO PREVIOUSLY FILED 6


A. Yes. On September 13, 2017, I filed Direct Testimony on behalf of Viking Energy of 8

McBain, LLC. 9

10






costs," Coppola Direct Testimony ("CDT") at 14:15-17, and specifically his assertion that 16

McBain included "major maintenance" costs within its Variable O&M expenses. 17

18



A. Yes. 21

22

369

2


TESTIMONY OF THOMAS ALLEN SUBMITTED ON BEHALF OF THE FOUR 2

BIOMASS MERCHANT PLANTS SUBMITTING REBUTTAL TESTIMONY? 3

A. Yes. 4

5

Q. FOR THE PURPOSES OF AVOIDING REPETITION AND REDUCING THE 6

BURDEN ON THE ALJ AND COMMISSION, DO YOU AGREE WITH THAT 7

TESTIMONY AND INCORPORATE IT AS YOUR TESTIMONY ON BEHALF 8

OF MCBAIN IN LIEU OF SEPARATELY RESTATING THE TESTIMONY? 9

A. Yes. 10

11

Q. ARE MCBAIN'S FINANCIALS AUDITED ON AN ANNUAL BASIS? 12

A. McBain's financial statements are audited annually by Viking Energy's parent company, 13

Engie NA and are periodically audited by an independent outside accounting firm. 14

15

Q. JUST TO BE CLEAR, WERE THE COSTS SUBMITTED BY MCBAIN AS 16




A. No. These numbers are taken directly from McBain's financial statements. 20

21

Q. DID MCBAIN ALSO PROVIDE INFORMATION REGARDING ITS VARIABLE 22

O&M COSTS TO THE OTHER BMPs? 23

370

3

A. Yes. 1

2

Q. HAVE ANY OF THE OTHER BMPs OBJECTED TO MCBAIN'S 3



A. No. 6

7

Q. DID THE OTHER BMPs SIMILARLY PROVIDE INFORMATION TO MCBAIN 8

THAT INCLUDED THEIR VARIABLE O&M COSTS? 9

A. Yes. 10

11

Q. HAS MCBAIN OBJECTED TO ANY OF THE COSTS THAT MR. COPPOLA 12


A. No. 14

15



CHARACTERIZATION OF THE O&M COSTS SUBMITTED BY MCBAIN? 18

A. Yes. 19

20

Q. WHAT CHARGES DOES MR. COPPOLA DISPUTE? 21

A. Mr. Coppola states that McBain "incurred $225,791 of maintenance costs for the cooling 22

tower, circulators, and associated piping." CDT at 16:18-19. 23

371

4

Q. DID MCBAIN INCUR $225,791 IN MAINTENANCE COSTS FOR THE 1

COOLING TOWER, CIRCULARS, AND ASSOCIATED PIPING IN 2016? 2

A. No. There was an error in McBain's discovery response. The amount for maintenance of 3

the cooling tower, circulators, and associating piping was transposed with the amount 4

incurred with respect to the steam turbine generator, which was reported on the next line. 5

The actual costs associated with the cooling tower, circulators, and piping was actually 6

$10,809. 7

8

Q. GIVEN THAT, WAS THE $225,791 INCURRED IN 2016 FOR MAINTENANCE 9

COSTS ASSOCIATED WITH THE STEAM TURBINE GENERATOR? 10

A. Yes 11

12

Q. EVEN THOUGH MR. COPPOLA DID NOT ADDRESS THE STEAM TURBINE 13

GENERATOR DUE TO THE ERROR, COULD YOU PLEASE EXPLAIN WHAT 14

MAINTENANCE WAS DONE ON THE STEAM TURBINE GENERATOR IN 15

2016 THAT COST $225,791? 16

A. Certainly. In 2016, it was determined that the generator rotor had degraded to a point that 17

it either had to be repaired or replaced. We considered performing a rewind of the rotor, 18

but determined that doing so would cost in excess of $750,000 and result in an outage of 19

a minimum of 40 days. McBain instead elected to swap out the McBain generator rotor 20

and replace it with the generator rotor from Engie NA's Northumberland plant, which had 21

been mothballed pending a decision regarding the disposition of that plant. The scope of 22

work included reviewing and testing the Northumberland rotor, removing both the 23

372

5

McBain and Northumberland rotors, and reinstalling the Northumberland rotor at the 1

McBain facility. Since the rotor was borrowed at no cost and no refurbishment or 2

overhaul was required for either rotor, the cost of the swap was necessarily an O&M 3

expense; but McBain realized a significant cost savings. 4

5

Q. WERE ANY INTERNAL LABOR COSTS INCLUDED IN THE $225,791 6

EXPENDITURE? 7

A. No, the $225,791 amount included only outside labor costs. It did not include any 8

internal labor costs. 9

10

Q. CAN YOU PLEASE ADDRESS MR. COPPOLA'S CONCLUSION THAT "IT IS 11

LIKELY THAT THE HIGHER AMOUNT SPENT IN 2016 INCLUDED MAJOR 12

MAINTENANCE OR THE OVERHAUL" OF EQUIPMENT AS THAT 13

CONCLUSION MIGHT RELATE TO THE COSTS INCURRED WITH 14

RESPECT TO THE GENERATOR ROTOR? 15

A. As stated above, by 2016, the generator rotor had degraded during its use related to the 16

operating hours and output of the plant and had to be repaired or replaced. In 2015, the 17

generator rotor was still functioning. I know of no direct relationship between the 18

amount of a cost and whether it is a capital or O&M cost. 19

20


EXTEND THE USEFUL LIFE OF THE EQUIPMENT OR TO OVERHAUL THE 22

FACILITIES OR IMPROVE THE EFFICIENCY OF THE FACILITY? 23

373

6

A. No. 1

2


PROCEEDING? 4

A. Yes. 5

374

STATE OF MICHIGAN


DIRECT TESTIMONY

OF

DONALD ADAMS

ON BEHALF OF

VIKING ENERGY OF MCBAIN, LLC. AND

VIKING ENERGY OF LINCOLN, LLC.

375

1

INTRODUCTION 1


A. My name is Donald Adams and my business address is 6751 W. Gerwoude Drive, 3

McBain, MI 49657. 4

5


A. I am employed an ENGIE NA company, as a Regional Fuel Manager for Viking Energy. 7

8


EXPERIENCE. 10

A. I am a high school graduate, with one year of college in Mechanical Engineering. My 11

business experience includes five years of service in the United States Navy as a second 12

class Boiler Technician. I have been employed with Viking Energy for more than 25 13

years in positions of increasing responsibility. My duties with Viking Energy have 14

included Operation Supervisor (on site fuel representative), Production Support 15

Supervisor, Plant Manager and Regional Fuel Manager. 16

17


A. As Regional Fuel Manager, my duties include contract negotiations and administration, 19

fuel inventory control, and fuel quality assurance. 20

21

376

2



A. Yes. 3

4

Q. APPROXIMATELY HOW MANY YEARS HAVE YOU HAD PRIMARY 5

RESPONSIBILITY FOR FUEL PROCUREMENT? 6

A. I have been involved in procurement generally for 23 years, and I have been responsible 7

for fuel purchasing for 10 years. 8

9



A. My direct responsibilities regarding negotiations and administration include acting as the 12

primary contact between the supplier and the plant site to determine the volume and 13

pricing of material. If a new supplier is required, the site will notify me of any fuel needs 14

such as quantity needs, timeframe and any other special provisions. I also maintain a 15

historical tracking file on all suppliers. This file includes daily deliveries of each 16

individual supplier along with weekly pricing. With regards to fuel quality issues, I will 17

complete an assessment of fuels delivered and apply any necessary cost adjustments. 18

19

377

3

Q. PRIOR TO WORKING WITH YOUR CURRENT EMPLOYER, DID YOU EVER 1

HAVE ANY RESPONSIBILITIES RELATED TO FUEL PROCUREMENT? 2

A. Yes, while in the United States Navy, I was directly responsible for ordering and 3

maintaining boiler fuel inventories for USS Raleigh LPD-1. I was not responsible for the 4

contract negotiation of this fuel. 5

6







reconciliation proceeding, MPSC Case No. U-17095-R, and its 2014 PSCR reconciliation 13

proceeding, MPSC Case No. U-17317-R. 14

15


PROCEEDING? 17

A. My testimony is on behalf of both Viking Energy of McBain, LLC and Viking Energy of 18

Lincoln, LLC ("Viking Energy"). 19

20


A No. 22

23

378

4



A. The purpose of my testimony is to describe Viking Energy's fuel procurement practices 3

and to provide factual support to demonstrate that Viking Energy’s costs were reasonably 4

and prudently incurred. 5

6

FUEL PROCUREMENT PROCEDURES 7

Q. PLEASE DESCRIBE THE FUEL OR FUELS THAT VIKING ENERGY USED 8

TO GENERATE ELECTRICITY DURING 2016. 9

A. Both Viking Energy of McBain and Viking Energy of Lincoln used waste wood to 10

generate electricity from January 1, 2016 through December 31, 2016, including waste 11

wood from forestry operations, mill waste, and hogged demolition. Hogged demolition is 12

shredded or tub grinded construction and demolition wood material. Viking Energy of 13

Lincoln also used creosote treated railroad ties. Both plants also used tire derived fuel 14

(“TDF”). 15

16

Q. DOES VIKING ENERGY HAVE FUEL SUPPLY AGREEMENTS WITH ANY 17

FUEL SUPPLIERS? 18

A. Yes. 19

20

Q. PLEASE DESCRIBE THE PROCESS THAT WAS USED TO ENTER INTO 21

THESE FUEL SUPPLY AGREEMENTS. 22

379

5

A. Once a contact has been established with a potential supplier, we will issue that new 1

supplier a package consisting of our terms and conditions, insurance requirements, and 2

fuel specifications. Once the terms and conditions have been signed, we will issue a fuel 3

supply agreement identifying the price per ton and any other special conditions. 4

5

Q. PLEASE SUMMARIZE THE PRINCIPAL TERMS OF YOUR FUEL SUPPLY 6

AGREEMENTS, INCLUDING THE PRICE OF THE FUEL AND THE 7

DURATION OF THE AGREEMENT. 8

A. Our contracts are “at will” contracts. All of our suppliers are given 12 month quota 9

contracts in which Viking Energy will guarantee to receive X number of tons of energy 10

chips and the supplier guarantees to deliver this amount. With this guaranteed receive 11

and deliver contract, the supplier is also guaranteed a firm base price for the term of the 12

contract. All tonnage is averaged over a rolling three-week period. If the three-week 13

average falls below the guaranteed delivery average without prior approval, the fuel 14

supply agreement becomes void. 15

16

Q. WHEN YOU ENTERED INTO THESE SUPPLY AGREEMENTS, DID YOU 17

CONSIDER OTHER AVAILABLE ALTERNATIVE SUPPLIERS? 18

A. Yes. 19

20

Q. WHAT WERE THE EFFECTS OF ENTERING INTO THE FUEL SUPPLY 21

AGREEMENTS THAT YOU HAVE DESCRIBED? 22

380

6

A. The effects of entering into these agreements were that Viking Energy was able to secure 1

a supply of fuel that was adequate to meet its generating needs, reliable enough to assure 2

its continued performance, and sufficiently diversified to ensure the stability of its fuel 3

supply, all within the context of an overall effort to minimize costs as much as reasonable 4

and practicable. 5

6


DURING 2016, WAS ONE OF YOUR JOB DUTIES TO MINIMIZE THE COST 8

OF FUEL PURCHASED BY YOUR MERCHANT PLANT? 9

A. Yes. Cost was always a very important consideration. Another important consideration 10

was the reliability of the fuel supply. 11

12

Q. WHAT STEPS DID YOU TAKE TO ACHIEVE THESE OBJECTIVES? 13

A. I tracked pricing and reliability on a weekly basis to determine who could deliver the 14

most reliable, lowest cost fuel. 15

16

Q. AT THE TIME YOU ENTERED THE FUEL SUPPLY AGREEMENTS WITH 17

YOUR FUEL SUPPLIERS, WERE THOSE PRICES THE BEST PRICES THAT 18

WERE REASONABLY AVAILABLE TO YOU? 19

A. Yes, considering the volumes of fuel, the timing of delivery and the reliability of supply, 20

we selected the lowest prices available to us at that time. 21

22

381

7

Q DID PURCHASING FUEL PURSUANT TO YOUR FUEL SUPPLY 1

AGREEMENTS PROVIDE VIKING ENERGY WITH THE BEST FUEL 2

PRICING OPTIONS REASONABLY AVAILABLE TO VIKING ENERGY OF 3

LINCOLN AND VIKING ENERGY OF MCBAIN IN 2016? 4

A. Yes. 5

6

Q. IN YOUR OPINION, WERE VIKING ENERGY'S DECISIONS TO ENTER INTO 7

THESE FUEL SUPPLY AGREEMENTS REASONABLE AND PRUDENT BASED 8

ON THE FACTS AND CIRCUMSTANCES KNOWN OR REASONABLY 9

FORESEEABLE AT THE TIME WHEN THE DECISIONS WERE MADE? 10

A. Yes. 11

12


A. We entered into agreements based on known market conditions and reliable data 14

concerning the actual historical performance of suppliers. 15

16

Q. WERE THERE SEASONAL VARIATIONS IN YOUR FUEL COSTS? 17

A. No. With all of our suppliers signing an annual contract in 2016, seasonal cost variations 18

did not occur. 19

20


A. Yes. Regional differences can occur depending on fuel market demand within any given 22

region. Fiberboard and lumber markets can shift without much warning. This generally 23

382

8

results in an unpredicted increase in wood fiber costs. When this occurs, fuel may have 1

to be purchased outside a typical geographic area resulting in higher prices due to 2

increased transportation costs. 3

4





9



A. Yes. 12

13

Q. IN YOUR OPINION, WERE VIKING ENERGY'S PURCHASING PRACTICES 14

REASONABLE AND PRUDENT? 15


17


FIELD OF FUEL PROCUREMENT, DO YOU THINK THAT ANY OF VIKING 19

ENERGY’S ACTUAL FUEL COSTS WERE EXTRAVAGANT, UNNECESSARY, 20

INEFFICIENT OR IMPRUDENT? 21


23

383

9


PROCEEDING? 2

A. Yes, it does. 3

384

STATE OF MICHIGAN


REBUTTAL TESTIMONY

OF

THOMAS J. ALLEN

ON BEHALF OF

GENESEE POWER STATION LIMITED PARTNERSHIP

AND

CADILLAC RENEWABLE ENERGY, LLC, HILLMAN POWER COMPANY, LLC

AND VIKING ENERGY OF MCBAIN, LLC

385

1

INTRODUCTION 1


A. My name is Thomas J. Allen and my business address is One Energy Plaza, 11-415 3


5


A. I am presently the Commercial Director for North American Operations at CMS 7

Enterprises Company, a subsidiary of CMS Energy. I started my career at CMS as a 8

Senior Financial Analyst in October 1988. In this capacity, I was significantly involved 9

in the development of the Genesee project, which is partially owned by CMS. I am 10

currently the Asset Manager for Genesee Power Station Limited Partnership ("Genesee"). 11

12


EXPERIENCE. 14

A. I have a Bachelor of Science in Accounting from the University of Michigan. Prior to 15

my employment with CMS, I was a Senior Financial Analyst and Senior Accountant for 16

Coastal Power Production Company, responsible for financial analysis and project 17

accounting. I have participated in the development and financing of a number of electric 18

energy projects. I have also been responsible for the oversight of loan payoffs for a 19

number of other projects. I have traveled extensively throughout the United States and 20

South America to evaluate, model, manage, and work on dozens of other development 21

and investment opportunities for CMS. 22

23

386

2


A. I am generally responsible for providing asset management services and general business 2

support for several of CMS's domestic power projects, including Genesee. My 3

responsibilities also include serving as the alternate CMS representative on the 4

management committees of some of these projects. 5

6



A. No. 9

10

Q. ON WHOSE BEHALF ARE YOU SUBMITTING YOUR REBUTTAL 11


A. The first part of my testimony, through page 12, line 9, applies to Genesee and the three 13

other Biomass Merchant Plants submitting Rebuttal Testimony, Viking Energy of 14

McBain LLC, Hillman Power Co., LLC, and Cadillac Renewable Energy, LLC, 15

("BMPs") whose representatives have reviewed my rebuttal testimony and incorporated it 16

by reference in their Rebuttal Testimony. We are doing this in order to avoid repetition 17

and reduce the burden on the ALJ and Commission. The second part of my testimony, 18

beginning on page 12, line 11, is submitted specifically on behalf of Genesee. 19

20

Q. WHAT IS THE BASIS OF YOUR KNOWLEDGE WITH RESPECT TO 21

GENESEE AND THE OTHER BMPs WITH REGARD TO THE SUBJECT 22

MATTER OF YOUR REBUTTAL TESTIMONY? 23

387

3

A. As stated above, I have a degree in accounting and over 30 years of experience in the 1

management and financial oversight of numerous domestic power projects. I am 2

personally familiar with the proceedings before the MPSC in which the MPSC approved 3

the rates and charges that underlie this cost recovery proceeding and which set the 4

parameters for the Fuel and Variable O&M costs at issue. Additionally, I personally 5

participated in the audits which the MPSC Staff undertook in 2011 with regard to the 6

TES Filer City Station, Grayling and Cadillac projects, which audits were performed by 7

MPSC Staff auditor Jay Gerken. 8

9

Q. HAVE YOU REVIEWED THE DIRECT AND REBUTTAL TESTIMONY 10

SUBMITTED ON BEHALF OF THE BMPs SUBMITTED IN THIS 11

PROCEEDING? 12

A. Yes. 13

14






costs," Coppola Direct Testimony ("CDT") at 14:15-17, and specifically his assertion that 20

Genesee’s inclusion of "large costs for major maintenance and turbine overhaul should 21

have been excluded from recoverable O&M expenses." CDT at 16:6-7. 22

23

388

4

Q. HAVE YOU REVIEWED MR. COPPOLA'S TESTIMONY? 1

A. Yes I have, as it relates to Genesee and the other BMPs. 2

3

Q. DOES MR. COPPOLA ASSERT THAT PSCR CUSTOMERS WERE BILLED 4

THE COSTS THAT HE QUESTIONS? 5

A. No. In fact, he specifically states that "[b]ecause the amount of permitted recovery of 6

shortfall Fuel and O&M costs is considerably lower than the amount requested by the 7

BMP group by approximately $5.3 million, the PSCR customers were not billed for 8

major maintenance and equipment overhaul costs in 2016." CDT at 17:6-9. 9

10

Q. IS MR. COPPOLA RECOMMENDING THAT THE AMOUNT TO BE 11

RECOVERED BY THE BMPs FOR 2016 VARIABLE O&M COSTS BE 12

REDUCED? 13

A. No. Mr. Coppola acknowledges that the major maintenance and equipment overhaul 14

costs will not reduce the amount recoverable in this reconciliation because the BMPs 15

incurred Fuel and Variable O&M costs well in excess of the monthly cap. CDT at 17:3-16

9. 17

18

Q. SINCE MR. COPPOLA IS NOT OBJECTING TO THE AMOUNT OF 19

RECOVERY REQUESTED BY THE BMPs FOR 2016, WHAT RELIEF IS HE 20

REQUESTING? 21

389

5

A. Mr. Coppola asks that "the Commission direct the BMPs to exclude these costs in all 1

future cases from reimbursable O&M costs under MCL 460.6a (7), (8) and (9)." CDT at 2

18:16-18. 3

4

Q. DOES MR. COPPOLA IDENTIFY WHAT HE MEANS BY "THESE COSTS" AS 5

THEY RELATE TO ANY FUTURE YEAR? 6

A. No. The Fuel and Variable O&M costs that are submitted for reimbursement by the 7

BMPs will necessarily vary from year to year. There is no way to take particular 2016 8

costs, referred to by Mr. Coppola as "these costs", and exclude them in "future years" 9

since such future costs have not yet been incurred or submitted to Consumers Energy 10

Company ("Consumers") for cost recovery. Evaluation of what constitutes a variable 11

O&M cost is very fact-specific and requires knowledge and consideration of the specific 12

cost being claimed in the particular situation in any given year. 13

14

Q. DOES MR. COPPOLA GIVE ANY OTHER REASON WHY HE THINKS THAT 15

THE COMMISSION SHOULD BE CONCERNED ABOUT THE COSTS HE 16

IDENTIFIED SINCE THE BMPs' VARIABLE O&M COSTS FAR EXCEED 17

WHAT WOULD BE RECOVERABLE UNDER THE CAP? 18

A. Mr. Coppola speculates that fuel and O&M costs might exceed the cap in future years if 19

one or more of the BMPs were removed from the group. CDT at 17:6-10. 20

21

Q. DOES MR. COPPOLA GIVE ANY SPECIFIC EXAMPLE AS TO WHY HE 22

THINKS THIS MAY BE A CONCERN? 23

390

6

A. He states that Consumers Energy, which he identifies as a part owner of TES Filer City, 1

has submitted an application requesting approval to amend its PPA with TES Filer City 2

and that TES Filer City plans to convert its facilities to burn 100% natural gas, thereby 3

making it ineligible to recover any cost shortfall under Act 286 in future years. He 4

speculates that because TES Filer represented 34% of the total BMPs' 2016 fuel and 5

O&M expense shortfall, the total shortfall for the remaining BMPs might fall below the 6

maximum inflation-adjusted amount if the Commission grants Consumers' application. 7

8

Q. WHAT IS YOUR REACTION TO MR. COPPOLA'S EXAMPLE? 9

A. First, Mr. Coppola is incorrect in asserting that Consumers is a part owner of the facility. 10

The Owner is T.E.S. Filer City Station Limited Partnership, of which an affiliate of 11

Consumers is a part owner. In addition, his concerns about what TES Filer City might do 12

in the future have no impact on the costs which the BMPs seek to recover for 2016, 13

which is the only year properly under consideration in this proceeding. Mr. Coppola has 14

no information other than pure speculation what the remaining BMPs' total Fuel and 15

Variable O&M shortfall will be in 2017 or any other year. As noted above, the BMPs' 16

maintenance costs naturally vary from year to year as maintenance is typically 17

undertaken on plant equipment on a rotating or as needed basis. 18

19

Q. ARE YOU AWARE OF ANY STATUTORY AUTHORITY FOR THE 20

COMMISSION TO MAKE A DETERMINATION REGARDING COSTS THAT 21

MAY BE INCURRED IN FUTURE YEARS? 22

391

7

A. No. My understanding is that the Act provides for review of fuel and variable operation 1

and maintenance costs on an annual basis, subject to a monthly cap. MCL 460.6a (7), 2

and (8). 3

4

Q. DO YOU HAVE ANY OTHER CONCERNS WITH MR. COPPOLA'S 5

TESTIMONY AS IT RELATES TO THE BMPs? 6

A. Yes. Mr. Coppola's testimony ignores the fact that the variable O&M costs submitted by 7

the BMPs, including Genesee, are taken directly from each BMP's financial statements, 8

which, with the exception of Lincoln and McBain, are audited annually by qualified 9

independent auditing firms after review and testing of the company's records in 10

accordance with Generally Accepted Accounting Principles ("GAAP"). Lincoln and 11

McBain's financial statements are audited internally by its parent company and are 12

periodically by an independent outside accounting firm. 13

14

Q. IS MR. COPPOLA A CPA? 15

A. Not to my knowledge. He states that he is "a business consultant specializing in financial 16

and strategic business issues in the fields of energy and utility regulation." CDT at 2:6. 17

His Appendix A summary of Experience and Qualifications indicates that he has a BS in 18

accounting and an MBA from Wayne State University. 19

20

Q. JUST TO BE CLEAR, WERE THE COSTS SUBMITTED BY GENESEE AND 21

OTHER BMPs AS VARIABLE O&M COSTS, INCLUDING THOSE 22

QUESTIONED BY MR. COPPOLA, CHARACTERIZED SPECIFICALLY AS 23

392

8

SUCH TO SUPPORT THE REQUESTS FOR REIMBURSEMENT AS PART OF 1

THIS RECONCILIATION? 2

A. No. These numbers are taken directly from the financial statements of Genesee and the 3

other BMPs. 4

5

Q. ARE THE AMOUNTS INCLUDED AS VARIABLE O&M COSTS TAKEN 6

DIRECTLY FROM THE FINANCIAL STATEMENTS THE AMOUNTS THAT 7

THE BMPs USE IN THE ORDINARY COURSE OF BUSINESS? 8

A. Yes. 9

10

Q. WHY IS IT APPROPRIATE FOR THE BMPS TO CHARACTERIZE 11

EXPENDITURES AS THEY DO? 12

A. Because their accountants have advised them that the way that the costs are currently 13

characterized comports with GAAP. If the BMPs were to capitalize costs that are not 14

properly capital costs in accordance with GAAP, the accountants would not certify their 15

audited financial statements. 16

17

Q. DOES MR. COPPOLA STATE THAT HE IS CONFIDENT IN HIS OPINIONS AS 18

TO THE CHARACTERIZATION OF THESE COSTS TO A REASONABLE 19

DEGREE OF PROFESSIONAL CERTAINTY? 20

A. No. Mr. Coppola states in various places in his testimony that based on "limited 21

information" it is "likely" that certain expenditures may have involved more than routine 22

393

9

maintenance. As previously indicated, the characterization of costs is fact-specific and 1

cannot be made on limited information as Mr. Coppola indicated he did. 2

3

Q. ADDRESSING MR. COPPOLA'S STATEMENT THAT HE HAD "LIMITED 4

INFORMATION," DID THE ATTORNEY GENERAL SUBMIT DISCOVERY 5

REQUESTS TO THE BMPs IN THIS PROCEEDING AND DID THE BMPs 6

RESPOND TO THOSE REQUESTS? 7

A. Yes. The Attorney General submitted two sets of written discovery to the BMPs, and the 8

BMPs fully responded to both sets of discovery. 9

10

Q. DID THE ATTORNEY GENERAL'S DISCOVERY REQUESTS INCLUDE 11

QUESTIONS AS TO THE COSTS CHALLENGED BY MR. COPPOLA IN HIS 12

TESTIMONY? 13

A. Yes. 14

15

Q. BEFORE ADDRESSING SPECIFIC COSTS, CAN YOU IDENTIFY WHAT MR. 16

COPPOLA RELIES UPON TO SUPPORT HIS CONTENTION THAT THE 17

IDENTIFIED COSTS ARE "LIKELY" NOT ROUTINE MAINTENANCE? 18

A. Mr. Coppola appears to rely on (a) the dollar amount of the identified expenditures; and 19

(b) the relative expenditures for variable O&M costs in 2016 as compared to 2015. CDT 20

at 15:4-16:8. 21

22

394

10

Q. DOES THE DOLLAR AMOUNT DETERMINE WHETHER AN EXPENDITURE 1

IS A CAPITAL COST AS OPPOSED TO ROUTINE MAINTENANCE 2

EXPENSE? 3

A. No. Under GAAP, the dollar amount does not determine whether an expenditure is a 4

capital cost as opposed to an expense. The characterization of every accounting entry 5

under GAAP is fact-specific, and Mr. Coppola offers no facts whatsoever to support his 6

conclusion. 7

8

Q. AS A GENERAL RULE, ARE LARGER COSTS REQUIRED TO BE 9

CAPITALIZED? 10

A. No. If the costs do not improve or put the facility in a better operating condition or 11

extend useful life, then under GAAP the costs cannot be capitalized. 12

13

Q. CAN YOU PLEASE EXPOUND UPON WHAT IT MEANS FOR A COST TO BE 14

INCURRED TO EXTEND THE USEFUL LIFE OF EQUIPMENT AND WHY 15

THAT IS RELEVANT? 16

A. The term over which a capitalized piece of equipment can be depreciated is determined 17

by its useful life. Depending on the machinery, the useful life of a piece of electric 18

generating equipment can typically be 30 or 40 years. Costs incurred to maintain a piece 19

of equipment so that it can be used for its full useful life, even if significant, do not, by 20

definition, extend the useful life of the equipment. Rather, those maintenance costs 21

simply ensure that the equipment can be used for its entire useful life. 22

395

11

Q. PLEASE ADDRESS MR. COPPOLA'S SUGGESTION THAT THE FACT THAT 1

VARIABLE O&M COSTS INCURRED FROM YEAR TO YEAR VARY IS AN 2

INDICATION THAT COSTS MAY NOT HAVE BEEN PROPERLY 3

CHARACTERIZED AS O&M EXPENSES AS OPPOSED TO CAPITAL 4

EXPENDITURES. 5

A. It is no surprise that variable O&M costs vary from year to year. Typically, the plants 6

will perform routine maintenance on a rotating basis so that not all maintenance costs are 7

incurred in the same year. The hope would be to try to spread maintenance costs as 8

evenly as possible from year to year, but given that different pieces of equipment are 9

being maintained in different years, that is not always be possible. 10

11

Q. WHY MIGHT MAINTENANCE COSTS VARY, PERHAPS SIGNIFICANTLY, 12

FROM YEAR TO YEAR? 13

A. Maintenance costs can vary from year to year depending on the utilization rate of the 14

equipment, the life cycle plan for scheduled maintenance, the emergence of any 15

unplanned maintenance, and maintenance to repair equipment breakdowns. 16

17

Q. MR. COPPOLA ALSO EXPRESSED CONCERN IN HIS TESTIMONY THAT IF 18

CERTAIN BMPs HAVE INCLUDED AS VARIABLE O&M COSTS 19

EXPENDITURES THAT SHOULD HAVE BEEN EXCLUDED AS CAPITAL 20

COSTS, THOSE BMPs WILL RECEIVE A DISPROPORTIONATE AMOUNT 21

OF THE SHORTFALL TO THE DISADVANTAGE OF THE OTHER BMPs. 22

ARE THERE ANY SAFEGUARDS IN PLACE TO MITIGATE THIS? 23

396

12

A. Yes. First, as mentioned above, each of the BMPs has taken the claimed variable O&M 1

costs directly from their financial statements, and have not specifically characterized 2

those amounts for purposes of maximizing recovery in this proceeding. In addition, the 3

costs for each BMP are submitted to Consumers and each of the BMPs has a chance to 4

review and potentially challenge any costs submitted by any of the other BMPs. 5

6

Q. HAVE ANY OF THE BMPs CHALLENGED THE CHARACTERIZATION OF 7

THE COSTS IDENTIFIED BY MR. COPPOLA? 8

A. Not to my knowledge. 9

10

Q. IN HIS TESTIMONY, DID MR. COPPOLA IDENTIFY ANY PARTICULAR 11

COSTS SUBMITTED BY GENESEE THAT HE CLAIMS WERE NOT 12

PROPERLY CHARACTERIZED? 13

A. Yes. In his testimony he questioned an entry titled "Major Maintenance" in the amount 14

of $927,003. The $927,003 amount was contained in a discovery response. It was not 15

included as such in Genesee's cost recovery request. 16

17

Q. WAS THE $927,003 APPLIED TOWARD THE SHORTFALL? 18

A. No. Although Mr. Coppola incorrectly references Exhibit AG-1, instead of Exhibit AG-19

5, only 50% of that $927,003 variable maintenance cost set forth was included in 20

Genesee's cost recovery request. 21

22

Q. WHY WERE ONLY 50% OF THE COSTS INCLUDED? 23

397

13

A. The 50% reduction represents an effort to be very conservative with the requested 1

reimbursement amount. Since Genesee's costs are not always broken down minutely, a 2

50% multiplier is applied to ensure the reasonableness of the requested reimbursement 3

amount as a variable O&M cost. 4

5

Q. WHAT ARE MR. COPPOLA SPECIFIC OBJECTIONS TO THIS ENTRY? 6

A. Mr. Coppola initially states that "given the size of the expenditure it is likely that it7

involved more than routine maintenance of equipment." CDT at 15: 9-10. 8

9

Q. IS THIS IS A VALID OBSERVATION? 10

A. No. Aside from the fact that Mr. Coppola acknowledges that he is merely speculating, as 11

set forth above, there is no basis for distinguishing between maintenance and capital costs 12

based on the amount of the expenditure, and certainly nothing in GAAP that would make 13

this distinction on that basis. 14

15

Q. DOES MR. COPPOLA GIVE ANY OTHER REASON WHY HE IS 16

QUESTIONING THIS EXPENDITURE? 17

A. Yes. He notes that this line item represents 45% of the total variable O&M costs 18

identified by Genesee. 19

20

Q. DOES THIS HAVE ANY SIGNIFICANCE UNDER GAAP? 21

A. No. 22

398

14

Q. MR. COPPOLA ALSO QUESTIONS GENESEE'S 2015 TURBINE OVERHAUL 1

AND FURTHER STATES IT IS "INFORMATIVE" TO POINT OUT THAT IN 2

GENESEE'S 2015 COST REIMBURSEMENT FILING GENESEE HAD AN 3

EVEN LARGER AMOUNT FOR MAJOR MAINTENANCE. ARE EITHER OF 4

THESE COMMENTS INFORMATIVE AS TO THE PROPER 5

CHARACTERIZATION OF EXPENDITURES IN 2016? 6

A. No, not at all. First, this is the cost recovery proceeding for 2016 expenditures, and 7

Genesee's 2015 costs are irrelevant to this proceeding. Second, as stated, the amount of 8

an expenditure alone is not an indicator of the correct accounting treatment of any 9

expenditure. 10

11

Q. DOES MR. COPPOLA GIVE ANY OTHER FACTS OR BASIS FOR HIS 12

STATEMENT THAT "THESE EXPENDITURES ARE NOT TYPICAL, 13

ROUTINE O&M EXPENSES THAT SHOULD BE INCLUDED FOR RECOVERY 14

IN THIS CASE." CDT AT 16:1-2. 15

A. No. It is just a statement with no citation. He merely states that from the "limited 16

information" he had, these "large" costs should have been excluded. 17

18

Q. IS THERE ANY SIGNIFICANCE TO THE FACT THAT THESE COSTS WERE 19

LISTED UNDER THE HEADING "MAJOR MAINTENANCE"? 20

A. No, the title is intended to indicate that the maintenance relates to major systems, not 21

major maintenance of equipment. Genesee's bond financing and loan requires it to have a 22

399

15

maintenance forecast for planned work on major systems and the title of 'major 1

maintenance' corresponds to that forecast. 2

3

Q. CAN YOU EXPLAIN WHAT MAINTENANCE THIS ENTRY RELATES TO? 4

A. Yes. In 1996, when the plant was built, Genesee placed a number of equipment systems 5

into operation as a functioning single unit power facility. As this was considered long 6

lived equipment, a 40 year depreciation schedule was established. This equipment has 7

been used over time to generate electric energy. In order to keep it running for its 40 year 8

useful life, the equipment has to be inspected, serviced, and maintained. These costs 9

were incurred to enable these equipment systems to generate electric energy for the 10

useful life of the plant, not to extend its useful life. 11

12

Q. TYPICALLY, WHEN DOES GENESEE PERFORM MAINTENANCE ON 13

MAJOR SYSTEMS THAT ARE SCHEDULED FOR ROUTINE 14

MAINTENANCE? 15

A. Every year there is a spring and fall outage during which time maintenance is performed 16

on major systems, which major systems are then not available to generate power during 17

that time. 18

19

Q. IN YOUR TESTIMONY ABOVE, YOU INDICATED THAT THE AMOUNT OF 20

VARIABLE O&M COSTS SUBMITTED BY THE BMPs WERE TAKEN 21

DIRECTLY FROM THE FINANCIAL STATEMENTS USED BY THE BMPs IN 22

400

16

THE ORDINARY COURSE OF THEIR BUSINESS. IS THIS TRUE AS TO THE 1

PARTICULAR ENTRY THAT MR. COPPOLA DISPUTES AS TO GENESEE? 2

A. Yes. 3

4

Q. DID GENESEE SPECIFICALLY CHARACTERIZE THE COSTS RELATING 5

TO THE MAINTENANCE OF THE EQUIPMENT AS VARIABLE O&M COSTS 6

SPECIFICALLY FOR PURPOSES OF THIS COST RECOVERY 7

PROCEEDING? 8

A. No. 9

10

Q. IN ITS FINANCIAL STATEMENTS, DOES GENESEE CHARACTERIZE SOME 11

COSTS AS CAPITAL COSTS? 12

A. Yes. After an examination of the specific facts related to a particular expenditure, and 13

when required to do so by GAAP, Genesee has and does characterize expenditures as 14

capital costs. 15

16

Q. YOU ALSO MENTIONED THAT TYPICALLY THE BMPs' FINANCIALS, ARE 17

AUDITED ANNUALLY BY INDEPENDENT OUTSIDE ACCOUNTING FIRMS 18

IN ACCORDANCE WITH GAAP. WHAT ACCOUNTING FIRM AUDITED 19

GENESEE'S FINANCIALS FOR 2016? 20

A. Plante and Moran. 21

22

401

17

Q. ARE THE AUDITORS AT PLANTE AND MORAN CERTIFIED PUBLIC 1

ACCOUNTANTS? 2

A. Yes. Plante and Moran is a nationally recognized certified public accounting and 3

business advisory firm. 4

5

Q. IN ADDITION TO THE REVIEW BY PLANTE AND MORAN, ARE GENESEE'S 6

FINANCIALS PREPARED OR REVIEWED BY ANY OTHER ACCOUNTANTS? 7

A. Yes. The costs are first determined by plant level accounting personnel. Thereafter, they 8

are subject to review by qualified home office technical staff accountants who oversee 9

preparation of monthly financial statements. Ultimately, the financial statements are 10

submitted to Plante and Moran for annual audit. 11

12

Q. DID ALL OF THESE PROFESSIONALS WITH KNOWLEDGE OF THE 13

SPECIFIC FACTS UNDERLYING THE EXPENDITURES MAKING UP THE 14

$927,003 CONCLUDE THAT THEY WERE VARIABLE O&M COSTS AND NOT 15

CAPITAL COSTS? 16

A. Yes. 17

18

Q. DID GENESEE ALSO PROVIDE INFORMATION REGARDING ITS 19


A. Yes. 21

22

402

18

Q. HAVE ANY OF THE OTHER BMPs RAISED ANY CONCERNS AS TO THE 1

VARIABLE O&M COSTS CLAIMED BY GENESEE? 2

A. No. 3

4


PROCEEDING? 6

A. Yes. 7

403

404

1 JUDGE FELDMAN: Anything further,

2 Mr. Waters?

3 MR. WATERS: No, your Honor. Thank you

4 very much.

5 JUDGE FELDMAN: Anything further from

6 anybody else?

7 MR. GENSCH: No, your Honor.

8 JUDGE FELDMAN: All right. Thank you

9 very much. If you can find the time in your schedule to

10 file a complete set of your exhibits in the e-docket,

11 obviously with the appropriate filing for the

12 confidential exhibits, I believe that would be a big

13 help. I appreciate all your efforts to settle this case.

14 And of course if for some reason you need additional time

15 as we bump against the briefing schedule we currently

16 have in place, just let me know.

17 And wishing you all that spring will come

18 soon, if there's nothing further from anybody, we're

19 adjourned.

20 (At 9:14 a.m., the record was closed.)

21 - - -

22

23

24

25

405

1

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-17918-R, before Sharon L. Feldman,

7 Administrative Law Judge with MAHS, at the Michigan

8 Public Service Commission, Lansing, Michigan, on

9 Thursday, April 19, 2018; and do further certify that the

10 foregoing transcript, consisting of Volume 2, Pages

11 11-405, is a true and correct transcript of my stenotype

12 notes.

13

14

15 _______________________________

16 Marie T. Schroeder, CSR-2183 Notary Public, Oakland County

17 33231 Grand River Avenue Farmington, Michigan 48336

18 [email protected]

19

20 Dated: April 20, 2018

21

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