lauren d. donofrio @dteenergy

April 14, 2020 Lisa Felice Executive Secretary Michigan Public Service Commission 7109 West Saginaw Highway Lansing, MI 48917 RE: In the matter of the application of DTE GAS COMPANY for authority to increase

its rates, amend its rate schedules and rules governing the distribution and supply of natural gas, and for miscellaneous accounting authority

MPSC Case No. U-20642 Dear Ms. Felice:

Attached for electronic filing in the above captioned matter is DTE Gas Company’s Rebuttal Testimony of Witnesses, Jaison J. Busby, Robert J. Lee, Shoshannah M. Lenski, Habeeb J. Maroun, and Rajan M. Telang, and Rebuttal Testimony and Exhibits of Witnesses, Andrew D. Dewey, Mark C. Johnson, Tamara Johnson, Henry N. Campbell, George Chapel, Michael S. Cooper, Henry J. Decker, Philip W. Dennis, Alida D. Sandberg, Edward J. Solomon, Theresa M. Uzenski, and Dr. Bente Villadsen. Also attached is the Proof of Service.

Please note that the Exhibit A-23, Schedules M2, M7, M8, M9, M10 and M11 contain

confidential material. The confidential material is being filed under seal and is being supplied to the individuals who have properly executed a non-disclosure certificate pursuant to the Protective Order.

Very truly yours,

Lauren D. Donofrio LDD/lah Attachments cc: Service List

Lauren D. Donofrio (313) 235-4017 [email protected]

DTE Gas Company One Energy Plaza, 1635 WCB Detroit, MI 48226-1279

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the application of )DTE GAS COMPANY for authority to )to increase its rates, amend its rate )schedules and rules governing the ) Case No. U-20642distribution and supply of natural gas, )and for miscellaneous accounting authority )

)

REBUTTAL TESTIMONY

OF

RAJAN M. TELANG

DTE GAS COMPANYREBUTTAL TESTIMONY OF RAJAN M. TELANG

LineNo.

RMT-2-Rebuttal

Q1. Please state your full name, title, business address and by whom you are1

employed?2

A1. My name is Rajan M. Telang. My business address is One Energy Plaza, Detroit,3

Michigan 48226. I am employed by DTE Energy Corporate Services, LLC a4

subsidiary of DTE Energy as Director, Regulatory Affairs.5

6

Q2. Did you file direct testimony in this proceeding on behalf of DTE Gas7

Company (DTE Gas or Company)?8

A2. Yes.9

10

Q3. What is the purpose of your rebuttal testimony?11

A3. The purpose of my rebuttal testimony is to rebut the following positions:12

Michigan Public Service Commission (Commission or MPSC) Staff13

Witness Mr. Rueckert relative to uncollectible expense and discuss a14

proposed Uncollectible Expense True-up Mechanism (UETM).15

Attorney General (AG) Witness Mr. Coppola’s recommendation that16

inflation cost increases are not warranted.17

Attorney General Witness Mr. Coppola and MPSC Staff Witness Ms.18

McMillan-Sepkoski relative to their proposed disallowance of financial-19

related capitalized incentive compensation.20

Michigan Power Limited Partnership and Verso Corporation (MPLP-21

Verso) Witness Mr. Phillips’ recommendation that the Infrastructure22

Recovery Mechanism (IRM) be eliminated.23

MPSC Staff Witness Mr. Todd’s suggestion that rates not become effective24

for up to thirty-days after an Order is issued in this case.25

R. M. TELANGLine U-20642No.

RMT-3-Rebuttal

1

The absence of a discussion of other matters in my rebuttal testimony should not2

be taken as an indication that I agree with other aspects of any Staff or intervenor3

testimony.4

5

Q4. Are you sponsoring any exhibits in this proceeding?6

A4. No, I am not.7

8

Uncollectible Expense9

Q5. On page 6 of her direct testimony, Staff Witness Rueckert recommends10

“[T]hat cash basis accounting of gross write offs less recoveries to gas service11

revenue is preferable for Uncollectible Accounts Expense projections because12

it presents a more accurate picture of the actual cash flows the Company13

receives annually”. Do you agree?14

A5. No. As supported by Company Witness Ms. Uzenski in her rebuttal testimony, the15

Company determines uncollectible accounts expense based on an accrual method.16

The Company’s revenue requirement, and therefore rates, is calculated to recover17

the Company’s expenses expected based on accounting, not cash flow.1 The18

estimation of future expenses should therefore be consistent with the practice used19

to record the actual expenses thereby ensuring recovery of the Company’s prudent20

and reasonable costs. Further, use of a three-year historical average of uncollectible21

expense was approved by the Commission in DTE Gas’s prior two rate cases, Case22

Nos. U-18999 and U-17999.23

24

1 This statement is not meant to imply that cash flow is not an important consideration in the financialhealth of the company or that it should be ignored as a part of the regulatory process.


RMT-4-Rebuttal

Q6. Are there any other reasons that the Commission should not reduce the1

Company’s uncollectible expense projection by $6.5 million as Staff suggests?2

A6. Yes. The Commission should not reduce the Company’s uncollectible expense, as3

Staff suggests, because it has become apparent that the Company’s projected4

uncollectible expense will be far higher than the prior three-year historical average5

uncollectible expense of $33.7 million. As supported by Company Witness Ms.6

Johnson, the Company’s forecasted uncollectible expense could increase to more7

than $65 million during the projected test year, due to the 2020 COVID-198

pandemic and the associated economic impacts. The Company has implemented a9

suspension on service shutoffs for all residential customers and an expansion of the10

winter protection program for senior customers. In addition, DTE Gas expects11

numerous customers will experience some form of economic hardship from job12

loss, reduced work hours, and/or unpaid sick time due to business closures resulting13

from emergency public health and safety measures ordered by Federal, State and14

local governments, for example Executive Orders 2020-04 and 2020-21.15

16

As discussed by Witness T. Johnson, similar to the 2008/2009 economic recession,17

these circumstances are likely to increase DTE Gas’s uncollectible expense from18

the current $33.7 million three-year average historic levels. If we experience an19

increase similar to that of the 2008/2009 recession, then uncollectible expenses20

could increase from 2019 actual uncollectible expense of $38 million to more than21

$65 million during the projected test year. Over 500,000 customers in our service22

territory are classified as low income. In addition, we also have a significant number23

of customers classified as working poor. These populations of customers24

consistently struggle making timely payments. The current pandemic creates added25


RMT-5-Rebuttal

pressures as their resources decline. Customers with otherwise strong payment1

histories experiencing job elimination or reduced hours may also find it difficult to2

pay their bills. In addition, we anticipate that small and medium sized businesses,3

as they are mandated to close, will also experience additional hardship.4

Approximately 20% of these small and medium sized customers are currently past5

due in the amount of approximately $15 million, and we expect this to grow.6

7

Q7. Did DTE Gas experience an increase in uncollectible expense associated with8

a previous widespread economic hardship?9

A7. Yes. As supported by Witness Tamara Johnson and noted in Figure 1 later in my10

testimony, DTE Gas experienced an 80% increase in uncollectible expense from11

$70 million in 2007 to $126 million in 2008 during the 2008 recession, and it took12

two years to recover to pre-recession levels. It is important to recognize that this13

increase happened without a moratorium on service shut-offs. However, during the14

current pandemic, the Company has worked with the Commission and other15

Michigan utilities to implement a temporary suspension on service shutoffs for all16

residential customers as well and an expansion of the winter protection program for17

senior customers. These actions, while necessary to protect the health and safety18

of our customers, are nevertheless expected to exacerbate the level of uncollectible19

expense as explained by Witness T. Johnson.20

21

Q8. If the Commission does not reduce the Company’s projected uncollectible22

expense, as suggested by Staff, is the Company’s previously filed uncollectible23

expense projection adequate given the current economic situation you just24

discussed?25


RMT-6-Rebuttal

A8. No. As mentioned previously, the most recent forecasted uncollectible expense1

could increase to more than $65 million for the test year ending September 30, 20212

and will be higher than the Company’s three-year historic previously filed amount3

of $33.7 million and likewise higher than Staff’s recommendation of $27 million.4

Therefore, neither DTE Gas’s proposed method nor Staff’s method for projecting5

uncollectible expense adequately reflects current conditions and the associated6

impact on DTE Gas’s financial situation.7

8

Q9. What does the Company propose to address this situation?9

A9. The Company is proposing an Uncollectible Expense True-up Mechanism (UETM)10

to ensure that DTE Gas is not severely harmed by the expected increase in11

uncollectible expense while also providing a mechanism to safeguard DTE Gas’s12

customers if uncollectible expense returns to levels less than what is included in13

rates. The UETM would be an annual reconciliation procedure that would allow the14

Company to recover its actual uncollectible expense while sparing the Commission15

the need to determine the proper allowance for uncollectible expense in this16

proceeding, which cannot be accurately predicted under current circumstances. In17

the past, this mechanism was useful protecting DTE Gas and its customers during18

uncertain economic times.19

20

Q10. What is the precedent for using this mechanism?21

A10. The Commission approved a UETM in prior DTE Gas rate cases, Case Nos. U-22

13898 and U-15985, both of which were affirmed on appeal. In its April 28, 200523

Order approving the UETM in Case No. U-13898, the Commission found that24

“MichCon’s present and likely-to-occur projected uncollectible expense level is25


RMT-7-Rebuttal

uncharacteristic as regards the known and measurable change standard, and highly1

unusual. Thus, it is appropriate to consider an increased cost level for purposes of2

this proceeding only. The Commission is persuaded that the UETM, as clarified by3

the Staff, should be implemented.” Although the underlying uncollectible expense4

drivers in the current proceeding are not identical to those in Case No. U-13898,5

they are certainly “uncharacteristic” and “unusual” relative to the known and6

measurable standard, and therefore approval of an UETM in this proceeding is7

warranted.8

As Figure 1 below illustrates, the UETM utilized during the 2004/2005 economic9

slowdown and natural gas price escalations and the 2008 recession performed as10

was designed. It protected both DTE Gas and its customers during years of11

unprecedented uncollectible expense volatility. DTE Gas was not harmed by over12

300% increases in uncollectible expense levels (2002 was the historical test year13

for Case No U-13898) and customers were not harmed when it returned to pre-14

recession levels. In addition, DTE Gas did not have to file rate cases every year due15

to uncollectible expense.16

17


RMT-8-Rebuttal

1

Figure 1 Annual Uncollectible Expense History2

3

Q11. How would the UETM operate?4

A11. By April 30 of each calendar year, the Company would submit a report to the5

Commission comparing its actual uncollectible expense with the uncollectible6

expense allowance approved in this proceeding. Ninety percent of the difference7

between these amounts would represent the amount to be collected or refunded to8

the Company’s customers over a subsequent 12-month period through a temporary9

surcharge or credit. The UETM surcharge or credit would be allocated to the10

respective rate schedules based on the allocation of uncollectible expense adopted11

in the cost of service and rate design in this case. DTE Gas proposes using the prior12

year’s actual sales and transportation volumes by rate schedule to calculate the13

surcharge for each rate to minimize yearly over or under-recoveries. See Table 114

below for an illustrative and simplified example of the determination of the annual15


RMT-9-Rebuttal

UETM. The calculation methodology and level of data provided would be1

consistent with DTE Gas’s prior UETM Reconciliation cases approved by the2

Commission.3

4

Table 1 - Illustrative UETM Examples – Undercollection /5(Overcollection)6

7

DescriptionExample #1

Amount($000s)

Example #2Amount($000s)

Year 1 Actual Uncollectible Expense $60,000 $30,000

Uncollectible Expense in Base Rates 34,000 34,000

Difference $26,000 ($4,000)

Amount Subjected to True-Up x 90% x 90%

Year 1 (Over)/Under Collection $23,400 ($3,600)

8

Witness Uzenski further discusses the accounting treatment for the UETM in her9

rebuttal testimony in this case.10

11

Q12. Why would only 90% of the difference be subject to collection or refund?12

A12. While the actual level of uncollectible expense is largely beyond the Company’s13

control, DTE Gas proposes that the Company remain at risk for 10% of its14

uncollectible expense to provide a further incentive to minimize its actual expense.15

16

Q13. Will there be any carrying charges on the differences between the actual17

uncollectible expense and the amount of uncollectible expense included in base18

rates?19

A13. Yes. DTE Gas will maintain a monthly total balance for UETM accrual amounts,20

balances and collections. Carrying charge expense or revenue will be calculated21


RMT-10-Rebuttal

on the total simple monthly balance of these three components using DTE Gas’s1

average short-term borrowing rate. Interest will be compounded annually on2

December 31.3

4

Q14. Would the UETM operate symmetrically?5

A14. Yes. The UETM would operate symmetrically. If uncollectible expense is higher6

or lower than the base amount, DTE Gas would be at risk for 10% of the difference7

between the uncollectible expense amount approved in this proceeding and the8

actual uncollectible expense and would refund or surcharge 90% of the difference.9

Therefore, customers would receive the benefit of a credit if the economy improves10

and actual uncollectible expense decreases before the Company files its next rate11

case. As discussed previously, the carrying charge for the UETM would be12

symmetrical using the company’s average short-term borrowing rate for both any13

under-recovery or over-recovery. Application of such a true-up mechanism would14

have the added benefit that it should alleviate the Staff’s concerns about over-15

collection in uncollectible expense by the Company, as expressed in Ms. Rueckert’s16

testimony.17

18

Q15. Why is the Company proposing to use prior year’s actual sales and19

transportation volumes in the annual UETM reconciliation rather than20

projected sales and volumes?21

A15. As a result of expected declining consumption per customer due to Energy Waste22

Reduction (EWR), using the projected delivery volumes in this proceeding would23

result in an under-collection of the amount to be recovered via the UETM surcharge24

in the year of recovery, resulting in a large roll-over of the under-collected25


RMT-11-Rebuttal

surcharge amount to the following year. To better approximate the actual delivery1

volumes over which DTE Gas will collect the UETM surcharge, the Company2

proposes using the prior year’s actual volumes for each rate class as reported in3

DTE Gas’s Annual Report of Natural Gas Utilities, DTE Gas’s P-522, pages 305C,4

306C, 312 and 313. Aggregate volumes from pages 312 and 313 will be allocated5

to their proper rate classes to calculate surcharges. Volumes from Rate 2A I and II6

are provided in total but will be separated for calculation of surcharges. Unbilled7

volumes will not be included in the surcharge calculation. Any over or under8

collection due to differences in the actual sales and transportation volumes billed9

during the period that the surcharge is in effect would be rolled over as the10

beginning balance into the following year’s UETM surcharge.11

12

Q16. How would the UETM annual reconciliation be implemented by the13

Commission?14

A16. The Company would submit an application that included the specific details15

described above by April 30 of each year. This application would be noticed with16

an opportunity for a hearing. It is assumed that the elements of the application17

would be narrow in scope and that a prompt hearing and Commission order could18

ensue to facilitate timely implementation of the UETM credit or surcharge. The19

Company would anticipate that the reconciliation would follow the form and20

process of that used to reconcile the UETM approved in the U-13898 and U-1598521

final rate orders.22

23

Q17. How does the Company plan to address the initial 2020 UETM period?24


RMT-12-Rebuttal

A17. It is expected that the Commission will issue an Order establishing new base rates1

in this proceeding in September 2020 or earlier. Therefore, the initial period for2

the UETM will be less than a full calendar year. Consistent with the Commission’s3

order in U-13898, the Company proposes that this initial period’s uncollectible4

expense over or under recovery be prorated based on a comparison of sales and5

transportation revenue for the portion of the year following the implementation of6

new rates pursuant to the Order to the total sales and transportation revenue for the7

calendar year.8

9

Q18. How long does the Company propose that the UETM would be in effect?10

A18. The Company proposes that the UETM remain in effect until the Commission11

issues a final order in DTE Gas’s next rate case. This would allow the parties and12

the Commission an opportunity to assess the effectiveness of the UETM and the13

level of uncollectible expense in DTE Gas’s base rates to determine if any changes14

to either are appropriate.15

16

Inflation17

Q19. Do you agree with AG Witness Mr. Coppola recommendation that projected18

inflation cost increases are not warranted in this case?19

A19. No, I do not agree with Witness Coppola’s recommendation that inflation cost20

increases are not warranted in this case.21

22

Q20. Has the Company presented evidence that there is inflationary pressure in this23

case?24


RMT-13-Rebuttal

A20. Yes. Company Witnesses Cooper and Uzenski both presented evidence in support1

of inflation in their respective direct testimonies.2

3

Q21. What support does Company Witness Cooper provide in support of inflation?4

A21. In Company Witness Cooper’s Direct Testimony as stated in Section Labor Cost5

Escalation, Answer 45, with regard to represented employees, “[b]ased on existing6

Collective Bargaining Agreements, the Company is obligated to increase pay rates7

by approximately 3% annually through the term of the contracts. In addition to8

scheduled pay rate increases, the agreements also provide for progression increases9

for those employees that have not yet achieved the maximum pay rate for their10

positions.”11

12

Q22. What support does Company Witness Uzenski provide in support of inflation?13

A22. Company Witness Uzenski supports the composite rate of inflation for 2019, 2020,14

and 2021. To arrive at the composite rate utilized in this case, Witness Uzenski15

assumes a contract labor inflation rate of 3%, as much of the workforce is16

represented by unions and has wages that will increase at that rate as specified in17

collective bargaining agreements. Company Witness Uzenski uses the consumer18

price index (CPI)-Urban forecast published by IHS Markit for non-labor costs. The19

calculation of the blended rate is provided in Company Witness Uzenski’s Exhibit20

A-13, Schedule C12.21

22

Q23. Should the Commission accept AG Witness Coppola’s recommendation to23

remove inflation from these forecasts?24


RMT-14-Rebuttal

A23. No. As described by Company Witnesses Cooper and Uzenski, and as has been1

supported in previous rate case decisions, the Company has experienced and will2

continue to experience inflationary pressures. Thus, the Company’s projection of3

future O&M expenditures is reasonable.4

5

Q24. On page 106 of his direct testimony Witness Coppola states that the inflation6

rates used by the Company in its direct case are now out of date, and the rates7

contained in Exhibit AG-4 are generally lower than the rates used by the8

Company. Should the AG’s inflation numbers be substituted for those used9

by the Company?10

A24. No, the Company’s projected O&M expenditures were developed at a point in time.11

Selectively choosing cost elements that have decreased since that point in time12

without acknowledging those items that may have increased over the same period13

would not be appropriate.14

15

Incentive Compensation16

Q25. Staff Witness McMillan-Sepkoski states on page 9 of her direct testimony that17

“Since the Commission has consistently disallowed the revenue requirement18

of the financial portion of Incentive Compensation, Staff recommends19

excluding the capitalized portion for 2018 going forward, which net of20

accumulated depreciation, is a $9,898,000 reduction to test year rate base”.21

AG Witness Coppola, on page 129 of his direct testimony, also recommends22

disallowing capitalized incentive costs related to financial measures for 201823

through the end of the projected test year. Do you agree?24


RMT-15-Rebuttal

A25. No. The Company disagrees with MPSC Staff and the AG’s proposals to disallow1

financial-related capitalized incentive compensation from the projected test year as2

well as for time periods that are historical (2018) or will be past (2019, and most of3

2020) by the time an order is issued in this case. DTE Gas also disagrees that these4

capitalized amounts were previously disallowed from rate base. The Commission’s5

September 13, 2018 order in Case No. U-18999 was specific that incentive6

compensation expense tied to financial measures be disallowed. The Commission7

did not disallow any capitalized incentive costs. Therefore, Staff Witness8

McMillan-Sepkoski and AG Witness Coppola’s recommendations should be9

rejected because it is a departure from past rate-making treatment and will result in10

a plant balance that does not reflect the full capitalized cost incurred by DTE Gas.11

12

Q26. What would be the immediate impact to DTE Gas if the Commission adopted13

Staff and the Attorney General’s recommendations to retroactively disallow14

the previously capitalized portion of incentive compensation related to15

financial measures?16

A26. If the Commission were to retroactively disallow previously capitalized incentive17

compensation related to financial measures as proposed by Staff and the Attorney18

General, the Company would have to write off $3.1 million of capitalized19

incentives from 2018, $3.2 million from 2019 and $2.4 million from January to20

September 2020. As described previously, the Company disagrees with the Staff21

and Attorney General’s proposal. However, if the Commission agrees with the22

disallowance of capitalized incentive compensation related to financial measures,23

then the Company requests the change be made on a prospective basis; specifically,24

the date on which rates approved in this case become effective. The use of that25


RMT-16-Rebuttal

effective date will avoid a significant write-off related to costs that had previously1

been incurred and approved for inclusion in rates as reasonable and prudent by the2

Commission in prior cases.3

4

Infrastructure Recovery Mechanism5

Q27. On page 22 of his direct testimony, MPLP-Verso Witness Phillips recommends6

that the “IRM be eliminated or certainly not increased. If it is not eliminated,7

it should be maintained at its current level as recently authorized in Case No.8

U-18999”. Do you agree?9

A27. No. The Commission has consistently approved the use of the Company’s IRM in10

the past three DTE Gas rate cases – Case Nos. U-18999, U-17999, and U-16999.11

Specifically, the merits of the IRM and the very same considerations raised by12

MPLP-Verso Witness Phillips in this case were already fully litigated and the IRM13

ultimately approved by the Commission in those previous DTE Gas rate cases.14

MPLP-Verso Witness Phillips has not raised any new issues that the Commission15

has not previously considered nor shown that circumstances have changed so that16

the Commission’s prior findings are no longer applicable. Therefore MPLP-Verso17

Witness Phillips recommendations regarding the IRM should be rejected.18

19

Further, the Company’s proposed IRM capital expenditures in the MRP, MMO,20

MAC MMO and PI programs, and the contemporaneous cost recovery of those21

expenditures through the proposed IRM surcharge, is of critical importance. As22

supported by Company Witness Mr. Dewey in his direct testimony, the IRM23

programs are necessary to assure the safety of DTE Gas’s customers and the public24

and to allow the Company to provide reliable utility service. The IRM expenditures25


RMT-17-Rebuttal

proposed in this case continue supporting DTE Gas’s and the Commission’s goal of1

safe and reliable service. The proposed IRM expenditures are necessary to achieve2

the Main Renewal targets in the Commission’s September 13, 2018 order in Case3

No. U-18999.4

5

Rate Implementation6

Q28. On page 21 of his direct testimony, Staff Witness Todd states “In order for the7

Company to have adequate time to update their billing system with the new8

rates, Staff recommends that the effective date be set seven calendar days after9

the date the Order is issued”. Does the Company agree with this10

recommendation?11

A28. No. While the Company recognizes that Staff Witness Todd’s proposal would12

provide DTE Gas time to update the billing system, a full seven-day period is not13

necessary. Absent extenuating circumstances or major unexpected changes in14

billing, DTE Gas can update its billing system for new base rates in a much shorter15

time period, and fully contemplated the time required to accurately implement new16

rates when determining the date on which the rate case was filed in 2019 to ensure17

it was adequate. DTE Gas creates test scenarios for rates and tests them prior18

issuance of an order. As long as only rates change, not the structure of those rates,19

our testing allows us to implement new rates quickly.20

21

Further, depending on the timing of the Commission’s order in this case, delaying22

the effective date for new base rates by seven days may unintentionally result in23

new base rates becoming effective after the start of the projected test year, which24

would result in financial harm to the Company. Therefore, the Company proposes25


RMT-18-Rebuttal

that new base rates become effective October 1, 2020, which is the start of the1

projected test year. Aligning the effective date with the start of the projected test2

year would also be consistent with the Commission’s September 13, 2018 Order in3

its last rate case, Case No. U-18999, and the Commission’s September 26, 20194

order in Consumers Energy’s last gas rate case, Case No. U-20322.5

6

Q29. On pages 21– 22 of his direct testimony, Staff Witness Todd suggests, as an7

alternate proposal, that the rates approved by the Commission’s final Order8

in this case not become effective until as much as 30 days after that Order is9

issued. Does the Company agree with this suggestion?10

A29. No. Rate case proceedings are required by statute (2016 Public Act 341) to be11

litigated within a ten-month period. Staff Witness Todd’s suggestion that there be12

as much as a 30-day delay from the time a final Order is issued in this proceeding13

would unnecessarily delay the implementation of rates beyond the period described14

in the statute or require that the initial final Order be issued earlier than otherwise15

necessary. The latter would further shorten an already compressed time table for16

rate cases. If adopted, Staff’s proposal to delay the date for making rates effective17

by as much as 30 days would effectively make what is intended to be a ten-month18

case an eleven-month case. Additionally, the Company has chosen its test year to19

receive rate relief in ten-months from its filing date. Not receiving that relief at the20

start of the projected test year would result in financial harm to the Company.21

22

Q30. Does Staff Witness Todd offer any explanation why a delay in the effective23

date for rates is necessary?24


RMT-19-Rebuttal

A30. Yes, Staff Witness Todd explains that the delay would provide parties with more1

time to verify the rates before they become effective. According to Staff Witness2

Todd’s proposal, the delay would be 21 days if no errors were found, and up to 303

days if corrections are necessary.4

5

Q31. If additional time is necessary to validate rates contained in a final Order prior6

to those rates becoming effective, what remedial action should the Commission7

take to address any errors found after the Order issuance?8

A31. The Company is not opposed to a means to address errors found after the issuance9

of the final Order. However, DTE Gas recommends, consistent with past practice,10

that new base rates reflecting the Commission’s final Order become effective on11

October 1, 2020, the start of the projected test year, and any errors found would be12

corrected as soon as possible.13

14

Q32. Does this conclude your rebuttal testimony?15

A32. Yes, it does.16

STATE OF MICHIGAN



)

REBUTTAL TESTIMONY

OF

JAISON J BUSBY

DTE GAS COMPANYREBUTTAL TESTIMONY OF JAISON BUSBY

LineNo.

JJB-1-Rebuttal

Please state your full name, title, business address and by whom you are1

employed?2

A1. My name is Jaison J Busby. My business address is One Energy Plaza, Detroit,3

Michigan 48226. I am employed by DTE Energy Corporate Services, LLC, as4

Director – Information Officer within the Information Technology Services (ITS)5

organization.6

7

What is your education?8

A2. I graduated from Oakland University with a Bachelor’s degree, in Management9

Information Systems in 1999 and University of Phoenix with a Master’s Degree in10

Business Administration (MBA), Technical Management in 2004.11

12

What work experience do you have?13

A3. I have worked for DTE Energy or one of its regulated utilities for over 5 years in14

various Information Technology (IT) positions. I am currently the IT Director of15

Power Supply and Energy Gas for the LLC. As the IT Director of Power Supply16

and Energy Gas, I am responsible for the teams that support Nuclear, Fossil17

Generation, Generation Optimization, Fuel Supply, Renewables and Energy Gas18

business units to operate, secure, deliver and plan information technology solutions.19

My portfolio also supports the success of individual business units by delivering20

new application capabilities, monitoring and maintaining the health of the systems.21

Prior to my current position, I was the Business Relationship Manager for the22

J. BUSBYLine U-20642No.

JJB-2-Rebuttal

Employee Experience Group, Manager of IT Network Engineering Group and the1

Customer IT Operations Group.2

3

Have you previously sponsored testimony before the Michigan Public Service4

Commission (MPSC)?5

A4. No.6

7

Did you file direct testimony in this proceeding on behalf of DTE Gas?8

A5. No.9

10

Purpose of Testimony11

What is the purpose of your rebuttal testimony?12

A6. The purpose of my rebuttal testimony is to:13

o Refute Staff Witness Joy H. Wang’s proposed total capital disallowance of14

$614,547, with $85,897 in the bridge year and $528,650 in the test year.15

My testimony will support the four DTE Gas IT projects, specifically Field16

Sketch 2020, Field Sketch 2021, EGMS Enhancements and Predictive17

Dialer/Nice(vendor) Enhancements.18

o Refute Attorney General (AG) Witness Coppola’s proposed removal of19

$8.9 million in capital expenditures for the Clicksoft Field Management20

System (Clicksoft) and $3.5 million in capital expenditures for the21

Electronic Gas Management System (EGMS). My rebuttal testimony will22


JJB-3-Rebuttal

demonstrate that the requested recovery is required for prudent and1

necessary projects to support Gas Operations and Gas Dispatch services.2

3

Are you sponsoring any exhibits in this proceeding?4

A7. No.5

6

Staff’s Proposed Disallowances7

What is Staff proposing?8

A8. Staff witness Wang is proposing a total capital disallowance of $614,547, with9

$85,897 in the bridge year and $528,650 in the test year, for the four DTE Gas IT10

projects.11

12

What is Witness Wang’s basis for the disallowance of the Company’s proposed13

total capital expenditure of $614,547, with $85,897 in the bridge year and14

$528,650 in the test year for the Four DTE Gas IT projects?15

A9. On page 25 of her testimony, Witness Wang states that there is no adequate16

explanation for the four Gas IT projects nor is information available to determine17

the reasonableness and prudency of these projects (Field Sketch 2020, Field Sketch18

2021, EGMS Enhancements and Predictive Dialer/Nice Enhancements).19

20

In Witness Wang’s testimony she asserts that DTE Gas does not adequately21

explain the purpose of the four IT projects and in all four cases a synopsis only22

details that “enhancements” will be made. How do you define Enhancements?23


JJB-4-Rebuttal

A10. An enhancement is a term used at DTE to define a change to an existing application1

or system in production to add new features or capabilities. Examples of new2

features and capabilities can include changes required by internal end users to make3

an application or system more user friendly or can include external factors such as4

a software vendor upgrading their software, which would require DTE to take5

action to upgrade the DTE environment. Features and new capabilities targeted for6

the four projects are explained in detail in testimony below beginning with Q13.7

8

Do you agree with Witness Wang’s recommendation for disallowance of9

capital expenditure for $614,547, with $85,897 in the bridge year and $528,65010

in the test year for the Four DTE Gas IT Projects?11

A11. No. I do not. DTE Gas requires the capital expenditure of $614,547, with $85,89712

in the bridge year and $528,650 in the test year for the Four DTE Gas IT Projects13

(Field Sketch 2020, Field Sketch 2021, EGMS Enhancements and Predictive14

Dialer/Nice Enhancements) to add new features and capabilities required by the15

business.16

17

Field Sketch 202018

Q12. What Field Sketch 2020 enhancements (requirements) will the capital19

expenditures include in this case fund?20

A12. The following are the specific requirements for the Field Sketch 2020 project21

included in this case:22


JJB-5-Rebuttal

Provide the ability for gas employees to view electric facility data as well as1

hazmat and brownfield locations, which was not previously available. By2

accessing this data, gas employees will be able to identify that this is a possible3

safety concern and take appropriate action. Having this data visible also assists4

in assigning jobs, which will ensure proper protective gear is used on the job5

site.6

Implement and upgrade the search capability to include the compatible unit gas7

library. This will increase the efficiency of identifying correct assets that are8

being constructed and installed.9

Upgrade MIMS (Mobile Information Management System) application with10

annotation functionality. Implementing this functionality would enable gas11

employees to view the GIS (Geographic Information System) maps with12

improved symbology and text labeling.13

Include snap capability feature. This functionality will allow improved14

placement of assets (compatible units) on the map for viewing and improve the15

final mapping of the asset.16

Implement new bookmark feature to allow end user to save work for historical17

viewing abilities as well as in the event they are called to another job site. This18

capability will improve mapping cycle time and eliminate cost associated with19

re-work.20

Allow the ability to search by GPS coordinates in addition to address. This will21

allow gas employees to enter a latitude and longitude coordinate if they have it22


JJB-6-Rebuttal

and search for a location. Increases efficiency by adding an additional search1

tool.2

Implement ESRI (Environmental Systems Research Institute) corrections3

process converting from manual to electronic submissions. This capability4

within MIMS will allow the employee to identify changes needed in the maps5

that they have identified while in the field on a job. They will have the ability6

to submit without going to another system. The correction will automatically7

be sent to the new electronic correction process site.8

Improve sketch efficiency and upgrade the application to display a directional9

arrow indicator icon (north arrow/compass). Employees will use this to provide10

proper dimensions and locations of the assets.11

Upgrade to include a visual feature within the application to notify an end user12

that application is still processing or syncing to corporate systems. This visual13

notification will assist the employee in knowing the syncing status and prevent14

them from trying to execute the syncing function multiple times manually15

resulting in the application freezing and impacting employee productivity.16

17

Field Sketch 202118

Q13. What Field Sketch 2021 requirements will the capital expenditures included in19

this case fund?20

A13. The following are the specific requirements for the Field Sketch 2021 project21



JJB-7-Rebuttal

Incorporate MIMS (Mobile Information Management System) software tool1

to capture barcode data into the application. This software tool will enable2

DTE to automatically place barcode data into the system and reduce the3

amount of manual data entry by field employees.4

Update MIMS Field Sketch application to ensure compatibility with field5

hardware devices so the application and devices remain operable. This will6

minimize the impact to field employee productivity, preventing hardware7

devices from being removed from service for repair.8

9

EGMS Enhancements10

Q14. What EGMS enhancements will the capital expenditures included in this case11

fund?12

A14. The following are the specific requirements for the EGMS Enhancements Project13


Incorporate new and upgraded existing TIPS (The Intelligent Plant System)15

reporting to increase efficiency and reduce manual efforts.16

Upgrade QPTM (Quorum Pipeline Transaction Management) report to improve17

dependability and reduce the risk of revenue loss for the external customer.18

Enhance screen feature to track monthly scheduled quantities between DTE Gas19

and interconnecting pipelines to reconcile month end business, while archiving20

historical information.21

22

23


JJB-8-Rebuttal

Predictive Dialer/Nice Enhancements:1

Q15. What are the required changes included in the Predictive Dialer/Nice2

Enhancements project included in this case?3

A15. The following are the specific requirements for Predictive Dialer project funded:4

Enable Supervisor to view the Agent dialer screen in real time. Real time5

feedback in the moment to provide more useful coaching than a6

monthly/weekly review where erroneous behavior may not be recalled.7

Enable Supervisor to view saved screens and replay of agent’s movements for8

all calls. Interface new dialer application with internal systems to improve9

reliability and customer experience. This will improve monthly/weekly10

coaching where coaching can be applied to behavior in the system that may be11

causing problems.12

Incorporate new reporting features to increase efficiencies and reduce manual13

labor. This will enable the team to accurately track their progress, set realistic14

goals, and better focus their efforts on where improvements need to be made.15

Enable Supervisor to set and record random recordings of sessions that can be16

played back. Application feature to be able to ID key words and phrases to17

increase management oversight efficiency. Automated call monitoring allows18

for 100% of contacts to be checked, by checking every call we can improve19

overall agent quality and improve the customer experience. Automating the20

process of collecting and analyzing data will give the analyst more time to21

coach employees on their performance.22


JJB-9-Rebuttal

Create campaign(s) by location specific code (for example, R198, R740,1

W870, etc.) station (Ids) (for example, Lynch, Allen Road, Muskegon, Grand2

Rapids, etc.) and TMS (TIPS Management System) code, meter location and3

zip code and other items as needed. This will improve the agility and speed of4

admins by giving them configurable items based on a variety of factors and5

what they are calling customers about.6

Q16. What should the Commission approve?7

A16. The Commission should approve the total capital of $614,547, with $85,897 in the8

bridge year and $528,650 in the test year, for the Four DTE Gas IT projects,9

specifically Field Sketch 2020, Field Sketch 2021, EGMS Enhancements and10

Predictive Dialer/Nice Enhancements. The implementation of the enhancements11

to existing programs is reasonable and prudent and necessary for the Company to12

meet end user requirements.13

14

AG’s Proposed Disallowances15

ClickSoft Field Service Management16

Q17. What is the AG’s witness proposing?17

A17. Mr. Coppola states that the forecasted capital expenditures for the ClickSoft Field18

Service Management system of $8.9 million should be removed from this rate case.19

20What is Witness Coppola’s reasoning for his suggested removal?21

A18. On page 47 of his testimony, Witness Coppola claims that there is neither clear22

explanation of why this current system needs to be replaced if it was installed in23


JJB-10-Rebuttal

2014 and five years after how it is end of life nor were there any quantifiable1

financial benefits or cost savings identified to support the project.2

3

Do you agree with Witness Coppola’s recommendation to remove the capital4

expenditure of $8.9 million for this project?5

A19. No. I do not. Please see explanation below.6

7

When was the current version of the Field Service Management (Service Suite)8

implemented?9

A20. The system was originally implemented in 2007 with an in-service date of April 7,10

2007 and was owned by a vendor called Advantex. In 2014, ABB (vendor) bought11

the Advantex software and rebranded it as Service Suite and offered a patch12

upgrade, which DTE implemented. The 2014 patch upgrade included screen and13

feature changes, but the base functionalities stayed the same as those implemented14

in 2007, more than a decade ago.15

16

Why does the current system need to be replaced?17

A21. ABB, the vendor of the current system (Service Suite), has indicated that, effective18

December 2019, they would no longer support the product. It has been deemed end19

of life, not by DTE but by the vendor. This poses many risks to DTE such as the20

vendor will no longer provide enhancements or defect remediations to this product21

and will no longer invest in ensuring its stability. ABB will also no longer provide22

critical security updates to ensure the software remains safe from new cyber threats.23


JJB-11-Rebuttal

This increases the risk of security vulnerabilities to DTE’s infrastructure, which is1

an unacceptable risk.2

3

Are there any other concerns if Service Suite is not replaced?4

A22. Today, Service Suite is a shared platform used by both Electric Field Operations5

(EFO) and DTE Gas Field Operations (GFO). EFO is implementing Clicksoft by6

the end of 2020. If DTE Gas Operations does not follow, then DTE Gas will incur7

the full cost of maintaining Service Suite, which is $1,289,445 per year rather than8

the current bill down cost of $258,280 per year for DTE Gas as a shared cost.9

10

What are the financial and cost saving benefits of Clicksoft Field Service11

Management system?12

A23. DTE is implementing ClickSoft for operational functionality purposes and to13

mitigate risk given the end of life status of Service Suite. Please refer to Q21-Q2214

for additional detail regarding why the system needs to be replaced and concerns if15

it is not.16

17

What should the Commission approve instead or what is appropriate?18

A24. The Commission should approve $8.9 million of capital expenditures for the19

Clicksoft Field Service Management system.20

21

Electronic Gas Management System (EGMS)22

What is the AG proposing?23

J. BusbyLine U-20642No.

JJB-12-Rebuttal

A25. Mr. Coppola states that the forecasted capital expenditures for Electronic Gas1

Management system (EGMS) of $3.5 million should be removed from this rate2

case.3

4

What was Witness Coppola’s reasoning for the suggested removal?5

A26. On page 47 of his testimony, Witness Coppola claims that there is neither clear6

explanation of how DTE Gas has been using the system since it has been7

unsupported for so long and why the upgrade and addition of servers is necessary8

nor were there any quantifiable financial and non-financial benefits identified to9

support the investment of $3.5 million for this project.10

11

Do you agree with Witness Coppola’s recommendation to remove the capital12

expenditure of $3.5 million for this project?13

A27. No. I do not. Please see Q28 for additional detail.14

15

Explain how DTE Gas has been using the system since it has been unsupported16

for so long and why the upgrade is necessary?17

A28. Security threats (i.e. code, application and hardware backdoors) by malicious actors18

are increasing and getting more sophisticated every day. As system hardware and19

software ages and we add new features and capabilities, it is important that we20

proactively upgrade the system to remain current with industry standards.21

22


JJB-13-Rebuttal

To mitigate security risk to date on the EGMS system, DTE Gas utilizes standard1

continuous monitoring and software/hardware patching processes. Continuous2

monitoring of the DTE infrastructure ensures malicious activity is proactively3

identified and blocked, while implementing vendor software/hardware patches4

addresses any known security vulnerabilities.5

6

In addition to the security threats and vulnerability risk, there are other benefits7

associated with the upgrade which include:8

The DTE Gas Nominations business has moved from a passive nominations9

system to an active nominations system. Our current version of software10

limits active nomination support whereas our targeted upgraded version of11

software includes features such as capacity analysis, automated12

confirmations, and improved customer reporting in support of an active13

nominations system.14

DTE Gas interconnects with many FERC regulated pipelines. It has become15

necessary that DTE Gas adapt some of the FERC guidelines to monitor our16

system capacity and enable timely interactions between DTE Gas and our17

customers. The upgraded software is FERC compliant and will allow DTE18

Gas to monitor capacity throughout the day, giving the Company more19

reliable insight into capacity constraints on our gas system and will assist20

DTE Gas in managing those constraints when necessary.21

22


JJB-14-Rebuttal

Explain the quantifiable financial and non-financial benefits identified to1

support the investment of $3.5 million for this project?2

A29. Please see Q28 above for a list of benefits associated with executing this project.3

4

What should the Commission approve instead or what is appropriate?5

A30. The Commission should approve the $3.5 million in capital expenditures for the6

Electronic Gas Management system (EGMS).7

8

Does this conclude your rebuttal testimony?9


STATE OF MICHIGAN



)

REBUTTAL TESTIMONY

OF

HENRY N. CAMPBELL

DTE GAS COMPANYREBUTTAL TESTIMONY OF HENRY N. CAMPBELL

LineNo.

HNC-1-Rebuttal


employed?2

A1. My name is Henry (Hank) N. Campbell. My business address is One Energy Plaza,3

Detroit, Michigan 48226. I am employed by DTE Energy Corporate Services,4

(LLC).5

6

Q2. Did you file direct testimony in this proceeding on behalf of DTE Gas?7

A2. Yes.8

9



A3. The purpose of my testimony is to rebut the following:12

Staff’s recommendation to reduce Merchant Fees in the projected test13

period.14

Attorney General’s recommendation that non-residential merchant fees be15

disallowed in the projected test period.16

Attorney General’s assertion that the $75,000 limit for non-residential17

customers is not a significant O&M reduction18

19

Q4. Are you sponsoring any exhibits via this testimony?20

A4. Yes.21

Exhibit Schedule Description22

A-24 N1 U-20561 MECNRDCSDE-1.6c Witness Clinton.23

A-24 N2 U-20642 TMS-13.1 response24

A-24 N3 U-20642 TMS-6.2 response25

H. N. CAMPBELLLine U-20642No.

HNC-1-Rebuttal

Merchant Fees1

Q5. Please explain the calculation of Merchant Fees in the projected test period.2

A5. As stated in my testimony Pg. 14 Line 11-16 the projected test period provides a 3-3

year compound average growth rate (CAGR). Residential customers have increased4

by 17.5% whereas non-residential have increased by 51.4%. These rates have been5

applied to the to the 2018 historical expense.6

7

Q6. Do you agree with AG’s witness Coppola recommendation (Pg 114, Line 1-4)8

that limiting non-residential customers with an annual bill of $75,000 does not9

go far enough to reduce O&M expense?10

A6. No. As shown in AG’s exhibit AG-45, Pg. 4, implementing the $75,000 cap would11

reduce Merchant Fees by $2.4M. This further reduces fees ~20% while still12

allowing small commercial and industrial customers to benefit from this payment13

option.14

15

Q7. Do you agree with the recommendation that no-cost payment by credit and16

debit card be limited to residential customers, as supported in the testimony17

of both Staff Witness Theresa McMillan-Sepkoski (, line 1-3) and18

Attorney General Witness Coppola (Page 114, Lines 13 through 15)?19

A7. No, I do not, for reasons I discuss further in my testimony.20

21

Q8. Does the Company control the amount of the transaction fees?22

A8. No, the Company does not control the transaction fees. Financial institutions and23

credit card companies drive the transaction fees customers incur when paying with24

credit or debit cards. The fee for each credit card transaction type is determined by25


HNC-1-Rebuttal

both the kind of card used, the way it is processed, and the time it takes the merchant1

to batch the transactions for processing. These fees are passed on to the company2

that processes the payment.3

4

Q9. Does the Company promote the use of debit and credit cards over any other5

method of payment as asserted by Staff Witness McMillan-Sepkoski (Pg. 34,6

line 8-12)?7

A9. No. The Company promotes all payment methods which are available to a customer8

to pay their bill, including cash, check, money order, mail or in person at any9

authorized pay agent or bill payment kiosk.10

11

Q10. Why should no-cost payment by credit and debit card be provided to both12

residential and small commercial and industrial customers?13

A10. The Company believes that it is essential to allow small commercial and industrial14

customers to pay by credit and debit cards. Non-residential customers indicated that15

utilizing a credit card provided their business with an extra 30-day float, which was16

critical to maintaining a positive cash flow (Exhibit A-24 Schedule N1 U-2056117

MECNRDCSDE-1.6c Witness Clinton). Furthermore, the focus group study18

referenced by Witness Clinton also indicated that imposing fees for paying by credit19

card would result in the following:20

Increase in cost resulting from loss of credit card rewards from bank21

Loss of flexibility in terms of payment timing22

Increase in bill-processing time and associated labor costs23

Reduced efficiency in terms of recordkeeping24

25


HNC-1-Rebuttal

Given the current economic climate impact of the 2020 Pandemic, small1

commercial and industrial customers will already face financial challenges and the2

inability to pay by credit and debit cards will compound an already tremulous3

situation. The Company believes it is necessary to allow small commercial and4

industrial customers the ability to pay by credit card without fees for such payment5

types in general, and especially now.6

7

Q11. Do you agree with Staff that the projected test period only include residential8

merchant fees?9

A11. No. For reasons stated above, the projected test period should include both10

residential and non-residential customers (small commercial and industrial11

Assuming the $75,000 cap).12

13

Q12. What is Staff’s calculation for non-residential merchant fees in the projected14

test period?15

A12. The non-residential amount of $6.66 million for non-residential customers is based16

on Staff’s 34% calculation correction (Exhibit A-24 N2 U-20642 TMS-13.117

response).18

19

Q13. Do you agree with Staff’s calculation of allocating 34% of Merchant Fees to20

DTE Gas?21

A13. Yes, I do. In my direct testimony (Page 5, lines 23-24), I supported allocating 35%22

of Merchant Fees to DTE Gas. However, as stated in Exhibit A-24 N3 U-2064223

TMS-6.2 response, the 65% / 35% split for Merchant Fees between DTE Electric24

and DTE Gas, was done outside the annual cost driver cycle. The Company25


HNC-1-Rebuttal

recognizes that there can be annual variances and going forward will update the1

allocation using percent of customers annually.2

3


A14. Yes it does.5

STATE OF MICHIGAN



)

REBUTTAL TESTIMONY

OF

GEORGE H. CHAPEL

DTE GAS COMPANYREBUTTAL TESTIMONY OF GEORGE H. CHAPEL

LineNo.

GHC-1-Rebuttal


employed?2

A1. My name is George H. Chapel. My business address is DTE Gas Company (DTE3

Gas or Company), One Energy Plaza, Detroit, Michigan 48226. I am employed by4

DTE Gas as Manager, Market Forecasting.5

6

Q2. Did you file direct testimony in this proceeding on behalf of DTE Gas?7

A2. Yes.8

9



A3. The purpose of my rebuttal testimony is to address the testimony of Staff Witness12

Ausum and Attorney General (AG) Witness Coppola in regard to the Company’s13

sales volumes in the projected test year. In addition, I will discuss the significant14

impact the recent pandemic will likely have on the Company’s sales forecast to15

rebut the positions taken by the Staff and AG in the projected test year.16

17


A4. Yes. I am sponsoring the following exhibits:19


A-25 O1 Expected Recession Impacts on Projected Test Year21

Sales22

23

Q5. Was this exhibit prepared by you or under your direction?24

A5. Yes, it was.25

G. H. CHAPELLine U-20642No.

GHC-2-Rebuttal

1

Rebuttal to Staff Witness Ausum2

Q6. Did you review the testimony and exhibits of Staff Witness Ausum?3

A6. Yes, I did.4

5

Q7. Do you agree with the conclusions that Witness Ausum recommended?6

A7. I agree with his conclusions regarding the customer count forecast and the inclusion7

of adjustments such as heating value and EWR in determining projected test year8

volumes. I do not, however, agree with how he applies these factors in determining9

the projected test year volumes.10

11

Q8. How does Mr. Ausum apply these factors to determine the projected test year12

heating volumes?13

A8. Mr. Ausum used calendar year 2018 normalized volumes as a starting point. He14

then applied a factor of 0.9907 to account for changes in heating value from15

calendar 2018 to the projected test year. Further, he applied a factor of 0.99 x 0.9916

x 0.9925 (or 0.97275) to account for expected EWR reductions from calendar 201817

to the projected test year. His recommendation is a forecast of projected test year18

volumes for GCR/GCC/Aggregate customers to be 157,427 MMcf, 2,472 MMcf19

higher than the Company proposed in its initial filing.20

21

Q9. Is Mr. Ausum correct in his proposal to use a calendar year, in this case 2018,22

as a basis for forecasting volumes?23

A9. No, he is not. Using a calendar year as the basis for a forecast is problematic.24

Calendar 2018 sales are defined as billed sales from January 2018 to December25


GHC-3-Rebuttal

2018 plus unbilled sales for December 2018 minus December 2017 unbilled sales.1

Because the December 2017 and 2018 unbilled sales are estimates, and because2

December is a deep winter month with a large amount of heat sales, those estimates3

may be off by volumes in the magnitude of a Bcf or more. This volume uncertainty4

makes using a calendar year as a basis for forecasting unwise. To note, both5

Michigan Gas Utilities and SEMCO Energy (two utilities regulated by the MPSC)6

also use non-calendar year data as bases for their gas demand forecasts.7

8

For reasons explained in the Company’s direct testimony, the Company uses sales9

billing data from the period 24-months ended July 2019 as a basis for all of its10

forecasting applications. This amount of data allows the Company to analyze11

sufficient customer consumption over two full winter periods of recent customer12

activity and to develop the Company’s three-factor (i.e. non-linear) usage factors.13

The three-factor approach to forecasting recognizes that customer behavior in14

relation to weather changes over the course of the year. This method allows the15

Company to more accurately project demand on a monthly basis assuring that the16

proper amount of supply is procured for the Company’s GCR and GCC customers.17

This forecast methodology is used for all of the Company’s forecast applications –18

rate case forecasts, GCR Plan forecasts, EWR Plan forecasts, and the Company’s19

financial planning forecasts and has been used by the Company for at least the last20

ten years. In addition, this methodology has been adopted in the prior two rate case21

orders - Case Nos. U-17999 and U-18999.22

23

Q10. What are unbilled sales?24


GHC-4-Rebuttal

A10. Unbilled sales are sales volumes that have been consumed within a month but have1

not yet been billed at the time that that month’s books are closed. The Company’s2

customers’ meters are read throughout the course of a month. (In an ideal situation,3

all meters would be read on the last day of the month making unbilled estimates4

unnecessary, but that is not practical.) Consider, for instance, a customer whose5

meter is read on or about the 5th day of each month. That customer’s bill will reflect6

consumption from the 5th day of the prior month through the 5th day of the billing7

month. All of that customer’s consumption from the 6th through the end of the8

billing month will be considered unbilled for that month. That is, the customer has9

consumed gas during that period, but will not be billed for that consumption (i.e.10

unbilled) until the following month. These unbilled estimates are based largely on11

the heating degree days (HDDs) that occur through the month.12

13

Q11. Can you give an example of how using calendar year data distorts annual14

sales?15

A11. Yes. Calendar year sales are defined as January through December billed sales plus16

December unbilled sales minus the prior December’s unbilled sales. The two17

unbilled estimates can be a sizable volume; over the past four years, December18

unbilled sales were 13 to 18 Bcf for GCR/GCC demand, or 8-12% of the19

Company’s annual GCR/GCC sales. The variations in these estimates can swing20

calendar volumes by several Bcf, depending in which calendar year those unbilled21

sales actually occurred.22

23


GHC-5-Rebuttal

Q12. If the Commission were to determine the Company should use a one-year1

period rather than the preferred 2-year period, is January – December 20182

the right 12-month period to use?3

A12. No, it is not. While the Company believes a 24-month period is a better and more4

accurate basis for forecasting volumes, if it must use a 12-month period, the 12-5

months sales ended August 2019 is a better period to use to normalize annual6

demand.7

8

Q13. If the Commission were to choose to use a 12-month sales timeframe versus9

your recommended 24-month timeframe, why is your recommendation for 12-10

months sales ended in August the best time frame to consider?11

A13. The period 12-months ended August provides the period when unbilled estimates12

can least likely distort annual demand. Over the past four years, August unbilled13

sales were 1.5 to 2.5 Bcf for GCR/GCC demand, or 1-2% of the Company’s annual14

GCR/GCC sales. Further, as unbilled sales variations are largely driven by HDDs,15

and since August generally has few (if any) HDDs, unbilled variations in August16

are quite low. In fact, August unbilled sales are so negligible from year to year,17

that 12 months of billed sales ended August is ample to sufficiently calculate18

normalized annual demand.19

20

Q14. Should the Commission adopt Mr. Ausum’s projected test year volumes as a21

basis for setting rates in this case?22

A14. No, it should not. The Commission should adopt the Company’s forecasted test23

year volumes of 154,955 MMcf that I included in my direct testimony in the24

Company’s initial filing. The Company’s forecast methodology is a highly detailed25


GHC-6-Rebuttal

analysis that incorporates the many nuances at play across its very diverse service1

territory. It is a build-up approach of first projecting customer growth/decline by2

each of the Company’s seven forecast areas and then applying two years of demand3

usage factors by each of those areas. Normal weather specific to each region is4

then applied to the usage factors and customer counts in those regions to determine5

a forecast specific to each region. This is necessary in assessing the demand over6

the Company’s far-reaching service territory in order that all the Company’s7

customers are served. Using a simplified single “calendar year” approach will not8

serve the Company’s forecast requirements, and thus will not serve the Company’s9

customers.10

11

Q15. Are there any factors that Staff did not consider at the time they developed12

their forecast analysis that would deem its recommendation not reasonable?13

A15. Yes. The impact of the current pandemic on the economy will be significant and is14

expected to have broad sweeping impacts throughout the DTE Gas service territory.15

In the relatively short period of time since the crisis started and the Governor began16

issuing executive orders, the first of which was released on March 10 where a17

Declaration of a State of Emergency was issued after two cases of coronavirus were18

confirmed in Michigan, we are already experiencing significant negative economic19

impacts, including the closing of businesses by executive order.20

21

A return to work and business as usual is still quite uncertain. Given the continued22

extensions of the stay home orders, the limited availability of widespread testing,23

and the absence of treatments or a vaccine to the virus, the return to work scenario24


GHC-7-Rebuttal

is expected to play out over several months at the earliest to prevent the1

continuation of further outbreaks.2

3

Q16. What impacts on the Company’s projected test year volumes do you expect4

from the current health crisis?5

A16. I expect a significant and prolonged economic downturn, similar to the economic6

downturn we experienced in 2009-10. During difficult economic times, residential7

and small commercial customers increase their focus on controlling their energy8

costs as a direct means within their control to help balance their budgets and control9

costs. Over the past three months, the U.S. economy has experienced over 1610

million jobless claims, with Michigan seeing nearly one million over the same time11

period. These levels are much higher than the peak experienced during the 2009-12

10 recession. Given Michigan’s continued dependency on the auto industry and13

the likelihood of fallout to the region’s residents, we are likely to see similar14

increased foreclosure rates, higher unemployment rates, and greater levels of small15

business bankruptcies.16

17

See Exhibit A-25, page 1 of 2. This exhibit describes the potential effect of the18

expected recession on both normalized residential and commercial GS-1 demand19

based on what the Company experienced during the 2009-10 recession period.20

During the 2009-10 recession period, the Company observed that average21

individual residential and commercial GS-1 natural gas usage per customer fell to22

92.0 Dth per customer and 411.4 Dth per customer, respectively. During difficult23

economic times, it is observed that customers attempt to lower their expenses as24

much as possible, including utility bills. This results in customers lowering their25


GHC-8-Rebuttal

thermostats in the winter, initiating energy efficiency projects (no matter how1

small), and generally paying more attention to how much energy is being2

consumed. Utilizing this residential and commercial GS-1 usage per customer3

reduction figure from the 2009-10 recession period and applying them to the4

Company’s filed heating value of 1.060 MMBtu per Mcf results in 86.8 Dth per5

customer for residential and 388.1 Dth per customer for commercial GS-1. The6

Company, in its initial filing, expected Rate A (i.e. Residential single home)7

demand to be 109,416 MMcf for the projected test year and commercial GS-18

demand to be 39,054 MMcf. Assuming that its residential and GS-1 customers9

behave similar to what was observed during the 2009-10 recession period, and fully10

return to their normalized consumption characteristics observed then, the volumes11

for those two classes would decrease to 103,940 MMcf and 34,645 MMcf,12

respectively. Overall forecasted sales would decline to 145,071 MMcf. This is what13

the Company refers to as a “Full Effect” recession scenario.14

15

Q17. Are there any known differences between the 2009-10 recession period and the16

current, expected recession period?17

A17. Yes. The cost of natural gas is much lower today and is expected to remain so into18

the projected test year. During 2009-10, the per unit cost that customers paid was19

approximately $10 per Mcf (GCR rate plus distribution rate). The present estimated20

per unit cost is approximately $5 per Mcf.21

22

Q18. Does the Company believe this difference in the cost of natural gas between23

the two time periods will influence customer usage?24


GHC-9-Rebuttal

A18. Yes, the Company believes this lower per unit cost may mitigate the full return to1

2009-10 customer behavior.2

3

Q19. What impact on the projected test year volumes does the Company expect4

when taking into account the difference in the cost of natural gas between5

2009-10 and now?6

A19. Although I believe there is a possibility that projected test year volumes may7

experience a “Full Effect” recession scenario, there could be a different scenario8

based on the lower cost of natural gas. Since the cost of natural gas is9

approximately 50% lower than the 2009-10 recession period, the Company10

estimates that the effect of the expected recession on customer usage may be only11

50% of that experienced in the 2009-10 recession period. The Company refers to12

this scenario as the “Half Effect” scenario. See Exhibit A-25, page 2 of 2. This13

exhibit provides a “Half Effect” forecast of the effects of the expected recession on14

both normalized residential and commercial GS-1 demand. Under this scenario15

recession assumptions, residential and commercial GS-1 volumes are expected to16

decrease to 106,678 MMcf and 36,849 MMcf, respectively. I arrived at these17

volumes by applying 50% to the difference between the original projected test year18

use per customer and the use per customer during the 2009-10 recession period.19

20

Q20. Were the volumetric reductions seen during the 2009-10 period impacted by21

the Company’s EWR (previously called Energy Optimization (EO)) program?22

A20. No, they were not. Since the Company filed for an EO program in 2009 and that23

program did not begin until after an order was issued by the Commission in June24

2009 and it took time to implement the various programs, the EO program would25


GHC-10-Rebuttal

have had little to no effect on the volumetric reductions seen during the 2009-101

period.2

3

Q21. With the new recession assumption in place, what is the effect on the total4

projected test year volumes with the expected coming recession?5

A21. Incorporating the “Half Effect” forecasted volumes for Residential Rate A of6

106,678 MMcf and for GS-1 of 36,849 MMcf results in all GCR, GCC, and7

Aggregate customer load for the projected test year to be 150,013 as identified on8

Exhibit A-25.9

10

Q22. What does this analysis tell you about the Company’s sales forecast that it has11

recommended for setting rates in this proceeding?12

A22. If there was any doubt regarding the reasonableness of the level of sales that DTE13

Gas has used as the basis for setting rates in this case, they should be put to rest. In14

light of the present pandemic and economic impact and the expected recession to15

follow, DTE Gas could make the case for a lower sales level for the projected test16

year. The Staff’s proposed level of sales should not be adopted, and the17

Commission should accept nothing greater than the 154,955 MMcf that the18

Company projected in its initial filing.19

20

Rebuttal to Attorney General Witness Coppola21

Q23. Did you review the testimony and exhibits of AG Witness Coppola?22

A23. Yes, I did.23

24


GHC-11-Rebuttal

Q24. Do you agree with the conclusions that Witness Coppola reached and his1

recommendations?2

A24. No, I do not. Witness Coppola relies on straight-line historical trends of calendar3

year normalized volumes to determine his projected test year volumes. He notes4

that calendar-year normalized demand has grown over the past three years and he5

uses that trend to project demand forward to determine his recommendation for6

projected test year demand.7

8

9

Q25. Is this the correct way to forecast company demand?10

A25. No, it is not. Principally, using calendar year normalized data as a basis for a11

forecast has the aforementioned unbilled estimation issues, especially when trying12

to establish trends. Trends cannot be accurately established using normalized13

calendar year data because the variances associated with unbilled estimates can14

overestimate the percentage increases and decreases. As these trends extend further15

and further into the future, these estimation errors become more evident.16

17

Q26. Does Mr. Coppola make any such forecast estimation that emphasizes this18

point?19

A26. He does. His forecast estimation for GS-1, in particular, illustrates this point. In20

Exhibit AG-32, line 11, he forecasts demand for GS-1 load for the projected test21

year to be 42.2 Bcf, or 470.5 Mcf per customer. Over the past five years, per22

customer demand for GS-1 customers has never been this high. For the 36-month23

period ended August 2019, GS-1 customers have averaged just 452.5 Mcf per24


GHC-12-Rebuttal

customer, or 40.5 Bcf. With a recession looming (as discussed earlier), it is more1

likely that volumes will trend to lower levels than to higher.2

3

Q27. Does Mr. Coppola make an adjustment to sales due to system average heating4

value?5

A27. No, he does not. He claims that no adjustment is necessary because he claims that6

the heating value of calendar 2019 (the basis year for his forecast) was 1.0607

MMBtu per Mcf. Further, he claims that this information was provided to him via8

the Company’s response to AGDG-1.24a.9

10

Q28. Did the Company’s response to AGDG-1.24a indicate that the heating value11

of calendar 2019 was 1.060 MMBtu per Mcf?12

A28. No, it did not.13

14

Q29. What did the Company’s response to AGDG-1.24a indicate?15

A29. The Company’s response to AGDG-1.24a made a reference to an attachment that16

identified the heating value of supply that the Company received from the NEXUS17

Pipeline from November 2018 to December 2019. (The discovery question had18

asked for NEXUS’ heating value through January 2020, but as that response was19

developed during January 2020, information for the full month of January 202020

was not yet available.)21

22

Q30. Did this response indicate what the system-wide heating value was for the23

Company for calendar 2019?24


GHC-13-Rebuttal

A30. No, it did not. Discovery question AGDG1-24a only asked for heating value1

information on gas delivered by NEXUS to DTE Gas. The Company provided the2

requested information.3

4

Q31. Did Mr. Coppola correctly interpret the information provided in the response5

to AGDG-1.24a?6

A31. No, he did not. He claimed the 12-month average for system average heating value7

for the Company was 1.060 MMBtu per Mcf and as such, no adjustment due to8

heating value would be necessary. The 12-month average NEXUS heating value9

provided in the response to AGDG-1.24a was 1.059 MMBtu per Mcf. More10

importantly, however, is that NEXUS is only a portion of the gas that the Company11

receives at its interconnects.12

13

Q32. What was the total system-wide heating value of gas on the Company’s system14

for calendar 2019?15

A32. The Company’s system-wide heating value for calendar 2019 was 1.057 MMBtu16

per Mcf. As a result, any 2019 calendar volumes used as a basis for projecting sales17

into the projected test year should be reduced by a factor of 0.997 (i.e. 1.057 /18

1.060).19

20

Q33. Should Mr. Coppola’s sales recommendations be adopted?21

A33. No. As discussed above, the Company does not support Mr. Coppola’s22

recommendations because he uses straight-line historical trends of calendar year23

normalized volumes to determine his projected test year volumes, which does not24

consider variances associated with unbilled estimates. Further, Mr. Coppola has25


GHC-14-Rebuttal

not considered the impact of the total system-wide heating value of gas on the1

Company’s system in his projections.2

3


A34. Yes, it does.5

STATE OF MICHIGAN



)

REBUTTAL TESTIMONY

OF

MICHAEL S. COOPER

DTE GAS COMPANYREBUTTAL TESTIMONY OF MICHAEL S. COOPER

LineNo.

MSC-1-Rebuttal


employed?2

A1. My name is Michael S. Cooper. My business address is DTE Energy Company,3

One Energy Plaza, Detroit, Michigan 48226. I am employed by DTE Energy4

Corporate Services, LLC (DTE LLC).5

6


Company?8

A2. Yes.9

10



A3. My testimony will rebut the testimony of several witnesses, including:13

Michigan Public Service Commission Staff (Staff) Mr. Welke’s use of14

selected 2019 actual Employee Benefits expense as a basis for determining15

the level of selected Employee Benefits expense for the projected test year,16

Attorney General (AG) Witness Coppola’s use of actual 2019 Active17

Medical expense escalated through the end of the projected test year based18

on the historical five-year average of increases in the Company’s Active19

Medical expense,20

Witness Coppola’s proposal to exclude the costs of the Supplemental21

Severance Plan,22

Witness Coppola’s proposed exclusion of expenses related to the Wellness23

Plan,24

M. S. COOPERLine U-20642No.

MSC-2-Rebuttal

Staff Witness Ms. McMillan-Sepkoski’s proposals to exclude incentive1

compensation expense related to financial measures and Restricted Stock,2

and,3

Witness Mr. Coppola’s proposal to exclude incentive compensation4

expense related to financial measures and half of the operating measures.5

6

The absence of a discussion of other matters in my testimony should not be7

regarded as an indication that I agree with other aspects of the Staff’s and8

Intervenor’s testimony. The narrow focus of my testimony is instead a consequence9

of a focus on priority issues in recognition of the available resources.10

11




A-26 P1 Staff’s Employee Benefits Expense15

A-26 P2 Revised Employee Benefits Expense16

A-26 P3 Historical Active Healthcare Expense17

A-26 P4 Constant Dollar Active Healthcare Expense18

A-26 P5 Total Compensation Comparison19

A-26 P6 Operating Measures Results: 2016-201920

21

Q5. Were these exhibits prepared by you or under your direction?22

A5. Yes, they were.23

24


MSC-3-Rebuttal

Employee Benefits Expense1

Q6. What was Staff Witness Welke’s proposal regarding Employee Benefits2

expense?3

A6. Witness Welke has proposed that the Company’s projected Employee Benefits4

expense be reduced by $7.197 million, before adjustments for the portion of5

Employee Benefits expense Capitalized, Transferred and allocated to separate6

surcharge programs, and a reduction of $7.486 million after those adjustments.7

8

Q7. Do you agree with Witness Welke’s proposed adjustment?9

A7. Only in part. Of Witness Welke’s total proposed reduction in Employee Benefits10

expense of $7.197 million, $4.148 million relates to the Company’s projected11

pension expense, which will be eliminated if the Commission adopts the12

Company’s proposal to defer Pension costs to a Regulatory Asset, as supported by13

both the Staff Witness Mr. Putnam and AG Witness Coppola. The remaining14

difference of $3.049 million relates primarily to Witness Welke’s use of 2019 actual15

Employee Benefits expense for specific expense categories rather than the16

Company’s actual Employee Benefits expense for 2018, as used by the Company.17

While I agree with Witness Welke’s $4.148 million adjustment related to Pension18

expense, under the assumption that the Commission adopts the Company’s19

proposal to defer Pension expense, I disagree with Witness Welke’s $3.049 million20

adjustment related to the use of selected actual 2019 Employee Benefits.21

22

Q8. Have you prepared a comparison of Witness Welke’s Employee Benefits23

expense projections to the Company’s?24


MSC-4-Rebuttal

A8. Yes. Exhibit A-26, Schedule P1 reflects a detailed comparison of the Employee1

Benefits expense determined by Witness Welke with the Company’s projection,2

per Exhibit A-13, Schedule C5-9. This Exhibit reflects the actual Employee3

Benefits expense for 2018 and 2019 in columns (b) and (c), respectively. Columns4

(d) through (g) of this Exhibit shows the adjustments made by Witness Welke to5

determine the total Employee Benefits expense for the projected test year. For6

some expense categories Witness Welke adopted the Company’s projections,7

which were based on actual 2018 Employee Benefits as either adjusted for specific8

projections or escalated for increases through the end of the projected test year. For9

other categories, Witness Welke used 2019 actual Employee Benefits expense and10

escalated those expenses for specific escalation factors reflected on the bottom of11

Exhibit A-26, Schedule P1.12

13

Q9. How did Witness Welke determine the Projected Post-Retirement Benefits14

expense reflected on line 2 through 6 of Exhibit A-26, Schedule P1?15

A9. For Pension and Other Post-Employment Benefits (“OPEB”), Witness Welke16

adopted the Company’s proposal to defer any Pension and OPEB expense to either17

a Regulatory Asset or Liability, depending on whether such expense was positive18

or negative. Accordingly, Witness Welke’s projection for Pension and OPEB19

expense is zero for the projected test period. For the New Hire VEBA and20

Employee Savings Plan expense components Witness Welke used actual 201821

expenses with an annual escalation of 30% and 8%, respectively. This projection22

is consistent with the Company’s proposal.23

24


MSC-5-Rebuttal

Q10. How did Witness Welke derive the Active Healthcare expense components for1

the projected test year?2

A10. For Medical, Dental and Vision and Life insurance expenses, Witness Welke relied3

upon the actual 2019 expense and then adjusted these amounts for the Company’s4

annual escalation factors applicable to 2020 and 2021. For Benefit Plan5

Administration Fees Witness Welke used the 2019 expense that was escalated for6

the Staff’s projected annual increases in price level changes as measured by the7

Consumer Price Index (“CPI).8

9

Q11. How did Witness Welke determine the level of Other Employee Benefits10

expense for the projected test year?11

A11. Witness Welke adopted the Company’s projections for Accrued Vacation,12

Supplemental Severance Plan, Wellness Plan, Affordable Care Act, Supplemental13

Savings Plan and Deferred Compensation Plan expenses, which were all either14

based on actual 2018 expense and escalated for expected price level changes or15

were based on specific projections. For Disability, General Benefit and Retirement16

Administration fees, Witness Welke based his projections on actual 2019 expenses17

and in the instance of Disability, escalated by the Company’s 3.0% annual labor18

escalation assumption and the remainder were escalated by the Staff’s CPI19

assumptions.20

21

Q12. Have you prepared an update of the Company’s Employee Benefits expense22

for the projected test year?23

A12. Yes. Exhibit A-26, Schedule P2 reflects an update of the Company’s projected24

Employee Benefits expense for the 12 months ending September 30, 2021 that25


MSC-6-Rebuttal

eliminates the Pension expense, consistent with Witness Welke’s proposal. This1

Exhibit shows total Employee Benefits expense of $42.073 million, which is $3.0492

million higher than the level projected by Witness Welke, due to the Company’s3

consistent use of the 2018 historical test year. The Company’s projected Employee4

Benefits expense after adjustment for the impact of the adjustments for the portion5

capitalized, transferred and allocated to separate surcharges is $38.055 million,6

compared to Witness Welke’s projection on a comparable basis of $34.487 million,7

for a total difference of $3.568 million. The adjustments for the costs capitalized,8

transferred are discussed by Company Witness Ms. Uzenski.9

10

Q13. Do you agree that Witness Welke’s use of 2019 Employee Benefits expense for11

determining Employee Benefits expense for the projected test year?12

A13. No. While generally it can be tempting to use the most recent information as the13

starting point for the determination of expenses to be incurred in future years,14

Witness Welke seems to have selectively used 2019 actual Employee Benefits15

expense, as a base for the projection of future Employee Benefits expense, while16

the remainder of the Staff’s Operations and Maintenance expense (O&M) is based17

on the Company’s 2018 historical test year. There is no legitimate basis to pick and18

choose those expenses that were lower in 2019 relative to the Company’s escalated19

2019 projections, which were based on 2018 actual expense, while ignoring actual20

expense levels in 2019 that were higher than the Company’s 2019 expense21

projections based on 2018 actual expense.22

23

Q14. Are there any 2019 actual Employee Benefits expense levels that were higher24

than the Company projections for 2019?25


MSC-7-Rebuttal

A14. Yes. Both the actual 2019 New Hire VEBA Plan and Employee Savings Plan1

expense were higher than the Company’s 2019 projections of these expenses.2

Whereas Witness Welke has adopted the Company’s projections for these two3

categories, if the same approach had been used for the New Hire VEBA and4

Employee Savings Plan as for Active Healthcare expense, the New Hire VEBA and5

Employee Savings plan expense would have been $0.278 million and $0.1576

million higher than proposed by Witness Welke. This results in Witness Welke’s7

projected Employee Benefit expense being understated by a total of $0.435 million8

due to the inconsistent historical period used as the starting point in determining9

the projected test year expenses.10

11

Q15. Are there any issues beyond the lack of consistency with using 2019 actual12

Employee Benefits expense as the starting point in determining Employee13

Benefits for the projected test year?14

A15. Yes. One of the 2019 actual expense categories used by Witness Welke in his15

determination of Employee Benefits expense for the projected test year was Active16

Healthcare Expense. While for certain Employee Benefits expense categories the17

most recent information is likely the most useful in predicting future expenses, such18

as Employee Savings Plan expense, the most recent Active Healthcare experience19

is not be useful in projecting future Active Healthcare expense20

21

Q16. Why is the most recent Active Healthcare experience not be useful in22

projecting future Active Healthcare expense?23

A16. Unlike Employee Savings Plan expense which increase at a steady trajectory24

reflecting increases in eligible employees and the applicable earnings base, Active25


MSC-8-Rebuttal

Healthcare expenses are subject to a diverse set of variables that are largely beyond1

the Company’s control. Specifically, the Company’s historical active healthcare2

expense can change based on the actual mix of medical care provided and the3

number of plan participants receiving medical care, as more fully described below.4

Accordingly, any single year’s experience is unlikely to be a reliable predicate for5

expected expense in future years because although Active Healthcare expenses6

have a predictable long-term trend, that doesn’t imply there isn’t a high degree of7

year-to-year variability within that trend.8

9

Q17. Is there any evidence that the Company has experienced high year-to-year10

variability in its Active Healthcare expense?11

A17. Yes. Exhibit A-26, Schedule P3 reflects the Company’s actual annual Active12

Healthcare costs, before adjustment for the portion capitalized, and Active13

Healthcare expense for each of the years 2014 through 2019. This Exhibit14

demonstrates that the Company’s annual rate of change in its overall Active15

Healthcare expenses has varied from an actual annual reduction in 2016 of 9.3% to16

an actual annual increase in 2017 of 28.3%.17

18

Q18. What is the source of the year-to-year variability in the Company’s Active19

Healthcare expense?20

A18. The Company is self-insured for most of its healthcare costs and accordingly is21

subject to the actual costs incurred by those covered by the benefit plans in any22

given year. The Company’s annual healthcare costs are highly dependent on the23

level and mix of employee and dependents usage of medical related services and24

prices paid for healthcare in each year. Accordingly, year-to-year variations in the25


MSC-9-Rebuttal

Company’s healthcare costs can be impacted by the degree to which its employees1

and/or dependents receive a disproportionately high or low level of high cost2

medical procedures (i.e., premature births, heart attacks, etc.) as well as a3

disproportionately high or low level of moderate cost medical procedures (i.e., x-4

rays, MRI’s, out-patient surgeries, etc.) While over the long run the choice to be5

self-insured for these costs is less expensive than the use of third-party insurance,6

it often creates significant variability in Active Healthcare expenses between years.7

Even for those plan participants enrolled in Health Maintenance Organizations8

(HMOs) or other managed care providers that provide fully insured coverage, the9

annual premiums for these organizations are experience rated, and thus premiums10

reflect the Company’s actual claims, albeit with some smoothing among years.11

In addition, as a result of the Company’s increased capital expenditure levels over12

the last few years, the portion of Active Healthcare costs that are capitalized has13

impacted the annual changes in Active Healthcare expense. Consequently, the14

9.3% reduction in Active Healthcare expense in 2016 would have been a 5.1%15

increase if the portion of Active Healthcare costs capitalized in 2016 was the same16

as the portion capitalized in 2015.17

18

Q19. Has the Staff been consistent in its use of the most recent Active Healthcare19

expense in prior DTE Gas rate cases?20

A19. No. In Case No. U-18999, the Company’s most recent rate case, the Company used21

a 2016 historical test year, which reflected a 9.3% reduction in actual annual Active22

Healthcare expense relative to the prior year. Although the Company provided its23

actual 2017 Active Healthcare expense, which reflected a 28.3% increase in its24

actual Active Healthcare expense in response to a Staff audit request, the Staff did25


MSC-10-Rebuttal

not propose the Commission adopt the 2017 actual Active Healthcare expense in1

its Testimony and Exhibits filed on March 22, 2018 in that case. As a result, DTE2

Gas Company’s Active Healthcare expense included in the revenue requirement3

adopted by the Commission in its Order in Case No. U-18999 was based on the4

Company’s actual 2016 Active Healthcare expense.5

6

Q20. Is there a method of normalizing the Company’s historical Active Healthcare7

expense to confirm the reasonableness of using the Company’s actual 20188

Active Healthcare expense as a basis for determining Active Healthcare9

expense for the projected test year?10

A20. Yes. In recognition of the intractable variability in the Company’s actual Active11

Healthcare expense, a method of confirming the reasonableness of the selection of12

a single year’s actual Active Healthcare expense in determining the Active13

Healthcare expense for the projected test year, would be to determine the average14

of constant dollar Active Healthcare expense as the starting point in the projection.15

This allows the normalization of actual experience through the elimination of the16

impact of price level changes.17

18

Q21. Have you quantified a constant dollar average of the Company’s Active19

Healthcare expense that demonstrates that reasonableness of the use of 201820

as the basis for projecting future Active Healthcare expense?21

A21. Yes. Exhibit A-26, Schedule P4 reflects the Company’s actual Medical, Dental22

and Vision components of the actual Active Healthcare expense for the years 201423

through 2019, as reflected on Exhibit A-26, Schedule P3, and then adjusts the24

historical actual expense for each of the years for the impact of the actual percent25


MSC-11-Rebuttal

increase in medical trends, as reported by PwC on page 3 of Exhibit A-13, Schedule1

C5.9.2. (The Life Insurance and Benefit Plan Administration Fees have been2

excluded from this analysis because these items are subject to separate escalation3

factors.) Adjusting the Company’s actual Active Healthcare expense for the overall4

increases in medical costs experienced by a broad sample of employers enables the5

separation of the Company’s year-to-year variability that is driven by changes in6

utilization by the Company’s employees and their dependents from changes to7

healthcare inflation. This Exhibit shows that a five-year average of the Company’s8

actual Active Healthcare expense related to Medical, Dental and Vision on a9

constant dollar basis is $18.602 million, which is $1.781 million higher than the10

Company’s actual 2019 Active Healthcare expense used by Witness Welke and11

demonstrates that the Company’s use of 2018 actual Active Healthcare expense of12

$18.015 million is a reasonable, albeit conservative, basis for projecting Active13

Healthcare expense for the projected test year.14

15

Q22. Are there any other factors that Witness Welke may not have been aware of16

when the Staff developed its recommendations?17

A22. Yes. The rapid expansion of the Covid-19 virus pandemic, which was viewed by18

many as merely a potential threat as recently as February 2020, became the basis19

for the declaration of a National Emergency by President Trump on March 13, 202020

and was followed by similar Executive actions by Governor Whitmer just days21

later. The result of the spread of the Covid-19 virus combined with governmental22

mandates in response to the virus will lead to substantial increases in the23

Company’s Active Health care expenses in 2020, arising both from increased self-24

insurance expenses and substantial risk mitigation measures, but will also lead to25


MSC-12-Rebuttal

higher HMO premiums as the impact of higher healthcare costs and waived1

deductibles and co-pays for Covid-19 testing and treatment are reflected in the2

Company’s future experience rated premiums. Moreover, in the absence of the3

rapid development of a safe and effective vaccine for Covid-19, the risk of future4

waves of infection must be considered. While it is premature to attempt to quantify5

the impacts on the Company’s future Active Healthcare expense of the Covid-196

pandemic, there can be little doubt that they are significant and recurring.7

Accordingly, the Company’s projections of Active Healthcare expenses are a8

conservative measure of the Active Healthcare expense the Company will incur9

during the projected test year.10

11

Q23. Did Witness Coppola make an adjustment to the Company’s projected12

Medical expense?13

A23. Yes. Witness Coppola used the Company’s actual 2019 Medical expense with14

escalation for historical changes in actual Medical expense, as the basis for15

adjusting the Company’s projection of Medical expense for the projected test year16

(Coppola Direct, p. 109). Specifically, Witness Coppola used the 2019 actual17

Medical expense of $15.647 million, as reflected on Exhibit AG-43, and then18

escalated this amount by an annual escalation factor of 3.34%, the five-year average19

of the Company’s actual annual increase in Medical expense, to compute the20

Medical expense for the projected test year of $16.592 million. When compared to21

the Company forecast of Medical expense for the projected test year of $19.27022

million, Witness Coppola’s proposal results in a $2.678 million reduction in the23

Company’s Medical expense.24

25


MSC-13-Rebuttal

Q24. Do you agree with Witness Coppola’s proposal?1

A24. No. Similar to Witness Welke, Witness Coppola’s selective use of the Company’s2

actual 2019 Medical expense as a basis for projecting future Medical expense is3

inconsistent with Witness Coppola’s adoption of 2018 actual expense levels as a4

basis for determining expenses through the end of the projected test year for5

virtually all other categories of O&M expense. Further, Witness Coppola’s6

proposal to update for 2019 actual expense levels is also inconsistent with his7

recommendations in Case No. U-18999, where the Company provided in response8

to an AG Discovery request the Company’s actual 2017 Active Healthcare expense,9

but Witness Coppola made no adjustment to his proposed revenue requirement to10

reflect the higher 2017 expense level. Moreover, the problem with the use of a11

single year’s actual experience in light of the year-to-year variability in Active12

Healthcare expense, as described above in reference to Witness Welke’s proposed13

use of 2019 actual Active Healthcare expense, is equally applicable to Witness14

Coppola’s use of 2019 actual Medical expense.15

16

Q25. Do you agree with Witness Coppola’s use of a five-year average of the17

Company’s actual increase in Medical expense to determine the Company’s18

Medical expense for the projected test year?19

A25. No. A simple average of the Company’s actual Medical expenses is a poor20

reflection of the likely increase in the Company’s future Medical expense. For21

example, the use of a single component of Active Healthcare expense ignores that22

expenses of the Company’s healthcare providers aren’t always consistently23

reported within the categories of Active Healthcare expense. Specifically, prior to24

2017, certain administrative costs billed by one of the Company’s insurance carriers25


MSC-14-Rebuttal

were embedded in its Medical billings, whereas in 2017 that carrier began to1

separately bill for its administrative costs that the Company began to report as2

Benefit Plan Administration Fees in 2017 rather than Medical expense. That shift3

in expense is reflected as an expense reduction in Witness Coppola’s singular focus4

on Medical expense. Further, the use of annual changes in Medical expense over a5

five-year period ignores the impact of changes in the Company’s construction6

activity. As the Company has dramatically increased its capital expenditures over7

the last few years, the proportion of Medical costs that are capitalized has increased,8

which has led to reductions in the rate of change in the Company’s Medical9

expense. Indeed, although the Company’s Medical expense have increased at an10

average annual rate of 3.3%, between 2014 and 2019, as computed by Witness11

Coppola, the Company’s total medical costs before the impact of the portion12

capitalized has increased at an average annual rate of 5.0% over the same five-year13

period, as shown on line 3 of Exhibit A-26, Schedule P3. Accordingly, historical14

increases in the Company’s actual Medical expense are an unreliable measure to15

determine projected increases in Medical expense.16

17

Q26. Did Witness Coppola propose any adjustments to the Company’s Active18

Healthcare expense in Case No. U-18999 related to the expected rate of19

increase in Active Healthcare expense?20

A26. No. Witness Coppola apparently adopted the Company’s projected Active21

Healthcare expense trend rates as provided by Aon.22

23


MSC-15-Rebuttal

Supplemental Severance Plan1

Q27. What was Witness Coppola’s adjustment related to the Company’s2

Supplemental Severance Plan?3

A27. Witness Coppola proposes that $0.871 million of Supplemental Severance Plan4

expense for the projected test year be completely eliminated (Coppola Direct, p.5

111).6

7

Q28. What is the basis for Witness Coppola’s proposed elimination of the8

Supplemental Severance Plan expense?9

A28. Witness Coppola claims that because this plan was implemented as a result of DTE10

Energy’s combination with MCN Energy Group, Inc (“MCN”), the costs of this11

plan should be assigned to DTE Energy as a cost of the combination and should not12

be reflected in the revenue requirements of DTE Gas (Coppola Direct, p. 111).13

14

Q29. Do you agree with Witness Coppola’s proposal?15

A29. No. Witness Coppola disputes the propriety of including the Supplemental16

Severance Plan expense without any assessment of the reasonableness of the17

benefits provided under the plan. As I described in my Direct Testimony, this plan18

is designed to address the differences in the full benefit eligibility retirement ages19

between the DTE Traditional Pension and the MCN Traditional Pension Plan.20

Witness Coppola has made no assertion that the full benefit eligibility ages under21

the DTE Traditional Pension Plan are unreasonable, he merely avers that the cost22

of aligning the full benefit eligibility for former MCN employees should be23

attributed to the merger with MCN.24


MSC-16-Rebuttal

Even if one believes the Supplemental Severance Plan expense is a cost arising1

from the merger of DTE Energy and MCN, the cost savings achieved through the2

combination that have flowed through to customers through lower revenue3

requirements is significant. In 2004 alone, DTE Gas Company’s annual merger4

related savings were estimated to be almost $48 million and these savings were5

reflected in the revenue requirement adopted by the Commission in its order in Case6

No. U-13898. The cost savings made possible from the combination of DTE7

Energy and MCN have been reflected in the revenue requirements adopted by the8

Commission in all of DTE Gas Company rate cases subsequent to Case No. U-9

13898. Therefore, even if one accepts the irrelevant premise that these costs relate10

to the combination of DTE Energy with MCN, the DTE Gas’s customers have11

receive substantial savings that dwarf the costs of the Supplemental Severance Plan.12

13

Q30. Is this the first rate case filing by the Company that has included the14

Supplemental Severance Plan expense?15

A30. No. As observed by Witness Coppola, the Supplemental Severance Plan was16

adopted in 2016. Accordingly, the Company included projected Supplemental17

Severance Plan expense in its proposed revenue requirement in its 2017 rate case18

filing in Case No. U-18999. No party in that proceeding objected to the inclusion19

of that expense in the Company’s revenue requirement. Similarly, in DTE20

Electric’s most recent rate case filing in Case No. U-20561 a Supplemental21

Severance Plan expense was included in the Company’s proposed revenue22

requirement, which was also unopposed. While Witness Coppola proposed a23

similar adjustment in DTE Electric’s 2018 filing in Case No. U-20162, the24

Commission did not adopt his proposal.25


MSC-17-Rebuttal

1

Wellness Plan2

Q31. What adjustment did Witness Coppola propose related to the Company’s3

Wellness Plan?4

A31. Witness Coppola proposes the elimination of $0.934 million related to the5

incremental expense due to the enhancements of the Company’s Wellness Plan.6

7

Q32. What is the basis of Witness Coppola’s proposed elimination of the Wellness8

Plan expense?9

A32. Witness Coppola asserts, in apparent reliance on information provided in Case No.10

U-20561, that the Company’s focus on diabetes prevention, obesity, hypertension11

and cardiovascular management programs are provided through the Company’s12

healthcare providers, such as Blue Cross and Blue Shield, and therefore the13

Company’s Wellness Plan is duplicative of other programs available to employees14

(Coppola Direct, p. 110).15

16

Q33. Do you agree with Witness Coppola’s conclusion?17

A33. No. First, the programs Witness Coppola describes as being offered by healthcare18

providers such as Blue Cross and Blue Shield are optional services that are only19

available at an additional cost to the Company, which the Company has opted not20

to participate in due to the higher cost relative to alternatives. Moreover, not every21

employee is enrolled in Blue Cross and Blue Shield plans. Therefore, the Wellness22

Plan being implemented by the Company is not duplicative of services the23

Company is already receiving from others. Second, Witness Coppola has ignored24

that another focus of the Company’s Wellness Plan is an increased emphasis on25


MSC-18-Rebuttal

injury prevention. Third, Witness Coppola has also apparently ignored that an1

overarching objective of the Company’s Wellness Plan is to create an overall2

culture of health and well-being within the Company, which will ultimately be more3

effective in improving the overall health and productivity of the Company’s4

employees than specific target initiates.5

6

Q34. Is there an impact on the Company’s projected Active Healthcare expense of7

the Company’s Wellness Plan?8

A34. Yes. The healthcare trend rates provided by Aon were reduced by 0.50% in 20209

and 1.00% in 2021 for the expected impact of the Company’s Wellness Plan, which10

reduced the Company’s projected Active Healthcare expense by $0.231 million. If11

the Commission adopts a revenue requirement that excludes the increased Wellness12

Plan expense, as advocated by Witness Coppola, then the Company’s projected13

Active Healthcare expense should be increased by $0.231 million.14

15

Incentive Compensation Expense16

Q35. What is Staff Witness McMillan-Sepkoski’s proposal regarding the treatment17

of incentive compensation expense included within O&M?18

A35. Witness McMillan-Sepkoski proposes the exclusion of $8.052 million of incentive19

compensation expense related to financial measures and the exclusion of $0.97020

million of expense related to Restricted Stock (McMillan-Sepkoski Direct, p.10).21

22

Q36. Do you agree with Witness McMillan-Sepkoski’s recommendation?23

A36. No. Witness McMillan-Sepkoski’s proposed exclusion of $8.052 million of24

incentive compensation expense related to the financial measures is apparently25


MSC-19-Rebuttal

premised exclusively on the Commission’s traditional practice. Specifically,1

Witness McMillan-Sepkoski describes the Commission policy as being the2

exclusion of the incentive compensation expense related to financial performance3

measures “on the basis that shareholders specifically benefit from financial4

performance measures such as return on equity and cash flow” (McMillan-5

Sepkoski Direct, p. 8).6

However, Witness McMillan-Sepkoski‘s proposed exclusion of incentive7

compensation expense related to the financial measures is made without regard to8

any determination of the overall reasonableness of the Company’s compensation9

policies and practices. As I demonstrated in Exhibit A-19, Schedule I2, the10

Company’s total cash compensation for its employees is, on average, 0.4% less than11

the Market Median for comparable positions, and in the absence of incentive12

compensation plans would be 12.1% less than the competitive market measures.13

14

Q37. Have you prepared other comparisons of the Company’s total compensation15

relative to external reference points?16

A37. Yes. In response to a series of Staff audit requests in this case and Case No. U-17

20561, the pending DTE Electric rate case, the Company provided various analyses18

of total compensation for 2018 for both DTE Gas and DTE Electric. One of the19

analyses provided for DTE Electric compared the total compensation, inclusive of20

all labor, including incentive compensation, benefits and labor related taxes to the21

average total compensation within the Utility sector as compiled by the Bureau of22

Labor Statistics (“BLS”), within the United States Department of Labor. The23

Company also prepared a similar analysis for DTE Gas, which is included on24

Exhibit A-26, Schedule P5.25


MSC-20-Rebuttal

1

Q38. What are the components of total compensation included on Exhibit A-26,2

Schedule P5?3

A38. Consistent with the format provided in the Staff’s audit request in Case No. U-4

20561, I have summarized the Company’s total compensation on a cost per hour5

worked for DTE Gas and the portion of costs allocated to DTE Gas from DTE6

Energy Corporate Services, LLC differentiated by cost component and between7

Union and Non-Union employee classifications. Wages include all Regular time8

payroll costs. Supplemental Pay includes all Overtime wages as well as normalized9

2018 Incentive Compensation costs, various payments made under the Company’s10

separate recognition programs, which apply primarily to the Company’s Union11

employees, and other lump sum payments. Accordingly, the amount of Total Pay12

is an all-inclusive measure of total compensation costs incurred by the Company in13

2018, without regard to whether these costs were capitalized or expensed.14

15

The remainder of the costs included in Exhibit A-26, Schedule P5 reflect the16

Benefit costs, inclusive of Insurance (which includes Active Healthcare, Life17

insurance and Disability costs) and Retirement Costs (which primarily consists of18

the Service Costs related to both Pension and OPEB as well as Employee Savings19

Plan and New Hire VEBA). Legally Required costs relate primarily to the20

Company’s portion of payroll taxes, such as Social Security and Medicare plus21

Unemployment taxes.22

23


MSC-21-Rebuttal

The comparative BLS data reflects Total Compensation and identified components1

for the Fourth Quarter of 2018 for the Utilities sector within private industry, as2

released by the BLS on March 19, 2019.3

4

Q39. What conclusion do you draw from the information on Exhibit A-26, Schedule5

P5?6

A39. The information on Exhibit A-26, Schedule P5 shows that on an all-inclusive basis7

of total wages and wage related costs, including normalized incentive8

compensation, the Company’s average hourly rate for 2018 for all hours worked9

was $58.77/hour worked compared to $61.87/hour worked as reported by the BLS10

for the Utility sector, which represents a difference of 5%. This analysis confirms11

that the Company’s total compensation practices result in compensation that is in12

line with the external benchmarks.13

14

Q40. Why is the overall reasonableness of the Company’s compensation practices15

relevant to Witness McMillan-Seposki’s proposal to exclude the incentive16

compensation expense related to the financial measures?17

A40. The relevance of the reasonableness of the Company’s total compensation is that18

absent a demonstration that the Company’s total compensation is not excessive,19

there is no legitimate basis for the disallowance of a portion of that compensation,20

irrespective of the method used in determining the compensation. As the21

Commission stated in its Order in Case No. U-10150, Michigan Consolidated Gas22

Company’s “…future approval of an incentive bonus like this requires a showing23

that it will not result in excessive costs and the benefits to the utility’s ratepayers24

will be commensurate with the costs (Case No. U-10150 Order, p. 58). The analysis25


MSC-22-Rebuttal

on Exhibit A-19, Schedule I7 demonstrates that benefits of the Company’s1

incentive compensation programs exceed the costs and the comparison of the2

Company’s total compensation to the market shows that the incentive3

compensation programs do not result in excessive cost.4

5

Q41. What is Witness McMillan’s proposal regarding the issue of Restricted Stock?6

A41. Witness McMillan-Sepkoski also proposes that $0.970 million of Restricted Stock7

expense, which is a component of the Company’s Long-Term Incentive Plan8

(LTIP) be excluded from the Company’s revenue requirement.9

10

Q42. What is Restricted Stock?11

A42. The Company’s LTIP consists of two separate components; Performance Shares12

and Restricted Stock. Performance Shares are granted annually with the ultimate13

number of shares distributed dependent on the Company’s financial performance14

over the ensuing three years, based on the measures detailed on Exhibit A-19,15

Schedule I6. Because the value to the recipients is contingent on the Company’s16

achievement of long-term financial objectives, the costs of the Performance Shares17

are considered to be a component of incentive compensation. In contrast,18

Restricted Stock are granted annually to encourage continued employment of19

certain key executives for which the value is not dependent on the Company’s20

achievement of any financial objectives.21

22

Q43. Do you agree with Witness McMillan-Sepkoski’s proposed exclusion of the23

LTIP expense related to Restricted Stock?24


MSC-23-Rebuttal

A43. No. First, this exclusion is improper for the same reason that the exclusion of the1

incentive compensation expense related to the financial measures is improper;2

Restricted Stock is merely another component of the Company’s total3

compensation practices that have been determined to be reasonable relative to the4

market. Second, Restricted Stock expense is not dependent on either the Company’s5

achievement of its financial objectives or DTE Energy’s future stock price, since6

the expense is recognized based on the value of DTE Energy’s stock price at the7

date of grant, due to the Company’s use of equity accounting for the grants.8

9

Q44. What support does Witness McMillan-Sepkoski rely upon in concluding the10

Restricted Stock expense should be excluded from the Company’s revenue11

requirement?12

A44. Witness McMillan-Sepkoski cites the Company’s LTIP employee plan description13

booklet included as Exhibit S-14.6 that the LTIP is “a reward to employees for14

assisting the Company in reaching its financial performance goals.” (McMillan-15

Sepkoski, p. 11). Witness McMillan-Sepkoski apparently infers from this phrase16

that this means the Restricted Stock is related to financial measures and therefore,17

consistent with the Commission’s traditional practice for excluding incentive18

compensation expense related to financial measures, should be disallowed.19

20

Q45. Do you agree with Witness McMillan-Sepkoski’s inference?21

A45. No. The LTIP employee plan description booklet referenced by Witness22

McMillan-Sepkoski and included in Exhibit S-14.6 addresses features of the23

Performance Shares, which relate to the Company’s future financial performance,24

rather than Restricted Stock, which are not related to the Company’s future25


MSC-24-Rebuttal

financial performance. Accordingly, Witness McMillan-Sepkoski’s conclusion1

that the Restricted Stock expense is related to future financial performance is2

inaccurate.3

4

Q46. What is Witness Coppola’s proposal regarding the Company’s incentive5

compensation expense?6

A46. Witness Coppola proposes the exclusion of all incentive compensation expense7

related to the financial measures ($8.1 million) and an exclusion of 50% of the8

incentive compensation expense related to operating measures ($2.8 million), for9

total disallowance of incentive compensation expense of $10.9 million.10

11

Q47. What is the stated basis for Witness Coppola’s proposal to exclude all incentive12

compensation expense related to financial measures from the Company’s13

revenue requirement?14

A47. The apparent basis for Witness Coppola’s exclusion of incentive compensation15

expense related to financial measures is his claim that the plans are too heavily16

skewed toward financial measures that he contends only directly benefit17

shareholders (Coppola Direct, p. 122).18

19

Q48. Do you agree that financial measures disproportionately benefit shareholders20

rather than customers?21

A48. No. Witness Coppola summarily concludes that the earnings and cash flow related22

measures have no direct relationship to customer benefits. Specifically, Witness23

Coppola opines that the achievement of earnings and cash flow goals “are in place24

to maximize profits and increase cash flow to pay dividends to shareholders”25


MSC-25-Rebuttal

(Coppola Direct, p. 122). This conclusion ignores the customer benefits related to1

the maintenance of the Company’s current debt ratings and the related avoided2

increased interest costs and the operating and capital cost savings enabled by an3

organizational emphasis on operating efficiencies that produce improved earnings4

and cash flow. As described in my Direct testimony, the achievement of the5

Company’s earnings goals is largely made possible through improved operating6

efficiencies that enable the Company to reduce its costs.7

8

Q49. What is the basis for Witness Coppola’s proposal to exclude 50% of the9

incentive compensation expense related to Operating measures?10

A49. Witness Coppola relies on his analysis of the operating performance levels achieved11

for the years 2016 through 2019 to conclude that approximately 50% of these12

measures achieved performance levels that were less than Target for both AIP and13

REP for all employees.14

15

Q50. Do you agree with Witness Coppola’s analysis of the Company’s historical16

performance relative to Target for the operating measures?17

A50. No. Witness Coppola’s analysis of the proportion of measures that were less than18

Target fails to recognize that while certain measures may produce results that are19

less than Target, other measures can produce results that are greater than Target.20

Moreover, even for those measures in which actual performance was less than21

Target can still generate payouts if the actual performance was higher than the22

Threshold level.23

In sum, Witness Coppola’s exclusive reliance on the achievement of Target24

performance levels fails to recognize the gradients of performance between25


MSC-26-Rebuttal

Threshold and Maximum performance levels, as I explained in my Direct1

Testimony relative to the weighted performance during the years 2016 through2

2018.3

4

Q51. Have you prepared an updated analysis of operating measure performance5

that reflects the results for 2019 that recognizes the gradients of performance?6

A51. Yes. Exhibit A-26, Schedule P6, reflects an update to my Exhibit A-19, Schedule7

I1 that includes the actual 2019 results. In spite of the continuation of the8

Company’s practice to generally increase the performance levels in the Target9

setting process and certain specific operating challenges, the weighted results for10

the years 2016 through 2019 show that the Company achieved 90.2% and 79.2 %11

for the AIP and REP, respectively, of its operating Targets, for an overall average12

of 84.7%. This demonstrates that a more rigorous analysis of the Company’s actual13

operating performance relative to Targets is much closer to 100% than opined by14

Witness Coppola.15

16



STATE OF MICHIGAN


In the matter of the application of )

DTE GAS COMPANY for authority to )

to increase its rates, amend its rate )

schedules and rules governing the ) Case No. U-20642

distribution and supply of natural gas, )

and for miscellaneous accounting authority )

)

REBUTTAL TESTIMONY

OF

HENRY J. DECKER

DTE GAS COMPANY

REBUTTAL TESTIMONY OF HENRY J. DECKER

Line

No.

HJD-1-Rebuttal

Q1. Please state your full name, title, business address and by whom you are 1

employed?2

A1. My name is Henry J. Decker and I am currently employed at DTE Gas Company 3

(DTE Gas or Company). My business address is One Energy Plaza, Detroit, 4

Michigan 48226 5

6

Q2. Did you file direct testimony in this proceeding on behalf of DTE Gas 7

Company? 8

A2. Yes. 9

10

Purpose of Testimony 11

Q3. What is the purpose of your rebuttal testimony? 12

A3. The purpose of my rebuttal testimony is to address the testimony of: 13

• Staff Witnesses Krause, Revere, and Creisher; 14

• Attorney General (AG) Witness Coppola; 15

• Retail Energy Supply Association (RESA) Witness Rittimann; and 16

• Citizens Utility Board of Michigan (CUBM) Witness Veerapaneni 17

18

Q4. Are you sponsoring any exhibits in this proceeding? 19

A4. Yes. I am sponsoring the following exhibits: 20

Exhibit Schedule Description 21

A-30 T1 New Customer Attachments 10 Year Surcharge 22

A-30 T2 New Customer Attachments 20 Year Surcharge 23

A-30 T3 Fuel Savings 10 Year Surcharge 24

A-30 T4 Fuel Savings 20 Year Surcharge 25

H. J. DECKER

Line U-20642

No.

HJD-2-Rebuttal

1

Q5. Were these exhibits prepared by you or under your direction? 2

A5. Yes, they were. 3

4

SECTION 1: MPSC STAFF REBUTTAL 5

End-Use Transportation (EUT) IRM Surcharge Cap 6

Q6. Staff Witness Krause recommends increasing the EUT IRM cap from 50% of 7

the customer charge to the full customer charge this rate case with the intent 8

of recommending the cap be lifted in the Company’s next general rate case. 9

Do you support Staff’s recommendation? 10

A6. No. Lifting the IRM caps for the EUT rate classes places significant cost burden 11

on the EUT rate classes, especially the largest EUT customers. For example, in this 12

general rate case, the IRM for XXLT customers are projected to be $1 million per 13

customer during calendar year 2022. Lifting the cap, as proposed by Staff, would 14

result in substantial increases possibly doubling the IRM charge to the Company’s 15

largest commercial and industrial customers beyond 2022. The Company is 16

concerned that lifting and eventually eliminating the IRM cap on the EUT rate 17

classes will motivate the Company’s largest customers to seek alternatives to taking 18

natural gas service from the Company including bypassing to interstate pipeline 19

companies, relocating production to facilities outside of the Company’s service 20

territory, or limiting investments in their Michigan based production operations. It 21

should also be noted that most of the capital expenditures for the Company’s IRM 22

program are spent on renewing distribution mains, primarily benefitting residential 23

and commercial customers and not necessarily the largest EUT customers served 24

from transmission and high-pressure distribution. 25

H. J. DECKER

Line U-20642

No.

HJD-3-Rebuttal

1

Contiguous Customer Charge for the EUT Rate Schedules 2

Q7. Do you agree with Staff Witness Revere’s proposal requiring the Company to 3

include a proposal in its next rate case for the calculation and implementation 4

of contiguous customer charges? 5

A7. No, the Company recommends calculating monthly customer charges based on the 6

economical breakeven threshold, absent a contiguous customer charge, for the 7

School, Large Volume General Service and EUT rate classes and maintaining the 8

contiguous facilities provision and a single monthly customer charge in this general 9

rate case and future rate cases using the same methodology approved by the 10

Commission for decades. 11

12

Q8. Why should the Commission continue to approve the Company’s monthly 13

customer charge calculation based on the long-standing economical breakeven 14

methodology and reject the Staff’s proposed contiguous monthly customer 15

charge? 16

A8. There are numerous reasons: 17

1) A single monthly customer charge applied to contiguous facilities has been 18

consistently approved by the Commission since at least the 1970’s and 1980’s 19

for the Company’s school (includes colleges and universities), and commercial 20

and industrial rates (Rate schedules 6, 7, 8, 9, and 10 that predated EUT service). 21

2) A single monthly customer charge applied to contiguous facilities and the 22

economic breakeven calculations have been consistently approved by the 23

Commission since the 1990’s for EUT rate schedules ST and LT and since 2005 24

and 2010 for EUT rate schedules XLT and XXLT respectively. 25

H. J. DECKER

Line U-20642

No.

HJD-4-Rebuttal

3) The economical breakeven thresholds between rates GS-1 and S, rates GS-1 and 1

GS-2, rates GS-1 and ST, rates ST and LT, rates LT and XLT, rates XLT and 2

XXLT will no longer have precise breakeven points based on volume for 3

customers with contiguous facilities. 4

4) The contiguous customer charge would add another level of complexity to 5

customer invoices and a significantly higher level of complexity to the 6

Company’s rate schedules. 7

5) Under the Consumers Energy methodology, every meter is established as an 8

account and every account receives a bill. The Company’s 571 EUT customers 9

would go from processing 571 invoices and payments to more than 3,500 10

invoices each month; 35,000 more invoices annually. It is difficult to understand 11

how migrating to the Staff’s contiguous customer charge proposal based on 12

Consumers Energy’s methodology would be acceptable as seen from the eyes of 13

the Company’s School, GS-2 and EUT customers. 14

6) Under the Consumers Energy methodology, for example, if an EUT customer 15

has an excess load balancing charged against the contiguous facility, each meter 16

and account are invoiced a pro rata share of the excess storage charge; whereas 17

the Company has a simple one-line charge applied on the single contiguous 18

account. The Staff’s proposed change creates significant increases in data entry 19

requirements for customers and their energy managers. 20

7) The added complexity of invoices will result in customers, their energy 21

managers, and the Company expending more resources conducting payment 22

processing, accounting, monthly balancing, and invoice and rate analysis. 23

8) The Staff’s contiguous customer charge will change the economic breakeven 24

threshold for the smallest ST customers, like school systems, with contiguous 25

H. J. DECKER

Line U-20642

No.

HJD-5-Rebuttal

facilities potentially inducing them to de-contract from their current economic 1

benefit received under EUT service and having to switch to the school or general 2

service rates. 3

9) Schools, community college, and university customers will be most impacted by 4

the contiguous customer charge proposed by Staff. 5

10) The Staff’s contiguous customer charge may result in similarly sized customer 6

campuses and business complexes being on different rates only because one has 7

more or fewer buildings on their campus or complex even though the volume 8

consumed by each customer is the same. 9

11) Customers and customer’s energy managers have not complained about the lack 10

of not having a contiguous customer charge in the Company’s EUT rates. 11

12

Q9. Does Staff Witness Revere err in his direct testimony (starting on line 6, page 13

7) where he states “Instead, the Company should calculate the contiguous 14

customer charges for each rate schedule based on the same method currently 15

used for Rates A, A1, GS-1, and Schools, which only includes the direct costs 16

associated with a customer’s existence as a customer?” 17

A9. Since the contiguous facility provision in the Company’s Rate Book includes the 18

School rate, I presume Witness Revere intended to reference only Rates A, A1, and 19

GS-1. 20

21

Q10. Staff Witness Revere references the application and approval of contiguous 22

customer charges in Consumers Energy’s Case No. U-20322. What did you 23

discover from Consumers Energy’s contiguous customer charge testimony? 24

H. J. DECKER

Line U-20642

No.

HJD-6-Rebuttal

A10. The Commission last approved contiguous customer charges in Consumers 1

Energy’s Case No. U-20322. However, Consumers Energy originally requested the 2

Commission to approve contiguous customer charges in Case No. U-18124. In Case 3

No. U-18124, Consumers Energy Witness Rachael L. Dziewiatkowski testified 4

(page 20, lines 9 through 17 of her testimony): 5

The Company is proposing to establish a contiguous customer charge for 6

both General Service and Transportation rate classes. The Company 7

believes that a contiguous charge will help recover costs that are more 8

appropriately recovered from each customer who takes service on 9

contiguous accounts. Currently, contiguous customers avoid all 10

customer charges and are able to pay the same distribution charge as the 11

“Master” account, which can be significantly lower than what they 12

would normally pay on their appropriate sales rate. Because some 13

contiguous customers combine hundreds of accounts, that may on 14

average have a very low annual usage, the “Master” accounts are 15

essentially subsidizing the contiguous accounts. 16

17

Q11. How does Consumers Energy and the Company differ in the application of 18

contiguous facilities? 19

A11. What clearly stands out as a differing element between Consumers Energy and the 20

Company is that the Company has never applied the use of “Master” account or 21

“Master” meter in association with contiguous facilities. The Company has simply 22

associated the contiguous facility in its entirety as the account; there is no Master 23

account vs. contiguous account or Master meter vs. contiguous meter status related 24

to contiguous facilities in the Company’s gas rate book, and there never has been. 25

The Company’s long-standing approved contiguous facilities provision 26

methodology evolved differently than Consumers Energy and therefore Consumers 27

Energy’s methodology should not be mistaken to be applicable to the Company’s 28

tariffs or desirable for the Company’s customers. The Commission should find the 29

H. J. DECKER

Line U-20642

No.

HJD-7-Rebuttal

Company’s contiguous facilities methodology preferable when compared to 1

Consumers Energy’s contiguous facilities methodology. 2

3

Q12. What other differences have you observed between Consumers Energy’s and 4

the Company’s contiguous facility provision. 5

A12. Consumers Energy, in their general rate case No. U-18124, represents that 6

contiguous customers avoid all customer charges and Master accounts essentially 7

subsidize the contiguous accounts. The Company does not view its long-standing 8

approved monthly charge calculation and contiguous facilities provision in this 9

manner and, as shown in Company Witness Maroun’s testimony, fully attests that 10

the EUT rate schedules appropriately allocate cost to the EUT customers in a manner 11

consistently approved by the Commission. 12

13

Q13. Do you have any last comments pertaining to the Staff’s contiguous customer 14

charge proposal? 15

A13. Yes. With the currently evolving coronavirus pandemic and recessionary effects 16

potentially lasting well into 2021 and 2022 for many market segments, the Company 17

and the Commission should maintain stability and minimize disruptions for our 18

Michigan businesses and schools. The contiguous customer charge proposed by 19

Staff is not a necessity, it is not desired by customers, and should not considered for 20

development in the Company’s next general rate case. 21

22

Customer Attachment Program Changes 23

Q14. What is Staff Witness Creisher’s position with respect to the Company’s 24

proposal to extend the maximum length of the Fixed Monthly Surcharge Period 25

H. J. DECKER

Line U-20642

No.

HJD-8-Rebuttal

(“surcharge period”) associated with the Customer Attachment Program from 1

10 years to 20 years? 2

A14. Witness Creisher disagrees with the Company’s proposal stating that the change 3

significantly impacts a customer’s energy savings over the 20-year period. Witness 4

Creisher also cited one set of conditions that would result in the customer incurring 5

an increase in costs over the 20-year period. 6

7

Q15. Does the Company agree with Witness Creisher’s position? 8

A15. No, we do not. In her testimony, Witness Creisher overlooked several relevant facts 9

and circumstances that support the Company’s proposal to lengthen the maximum 10

surcharge period. 11

12

Q16. What additional information should be considered in making this 13

determination? 14

A16. The Company is proposing a maximum surcharge period of 20 years, but the actual 15

length of the surcharge will be determined on a project-by-project basis. Each 16

project is different in terms of total costs, anticipated usage, and associated off-17

setting revenue. In determining the most appropriate length of the surcharge period, 18

the Company will consider the amount of the monthly surcharge based on different 19

payback scenarios, homeowner affordability issues, and input offered by the 20

homeowners. A “one size fits all” approach will not be used, and the resulting cost 21

savings will vary from project to project. 22

23

Q17. What other information should be considered? 24

H. J. DECKER

Line U-20642

No.

HJD-9-Rebuttal

A17. As part of the communication process with potential customers, the Company urges 1

all homeowners to make an informed decision and provides the information and 2

tools needed to do so. Not only do representatives of the Company speak personally 3

with the homeowners, but they also encourage them to perform their own personal 4

analysis by using the cost calculator located on the Company website at “Switching 5

to Natural Gas1. This calculator allows the homeowner to input their own actual 6

propane usage and price information. Armed with the personalized results of this 7

calculation, each homeowner is well positioned to make an intelligent fact-based 8

decision. 9

10

Q18. Witness Creisher cited the results of a calculation she relied upon in 11

formulating her response to the Company’s proposal. In her example, the 12

homeowner would incur more costs than savings using a 20-year surcharge 13

period. Does the Company believe this should be the only analysis considered? 14

A18. No, we do not. As previously stated, each project is unique and should be considered 15

on a stand-alone basis. To illustrate this concept, I will highlight two hypothetical 16

customer attachments as depicted in Exhibits A-30, Schedule T1 New Customer 17

Attachments 10 Year Surcharge and A-30, Schedule T2 New Customer Attachments 18

20 Year Surcharge. The assumptions underlying Exhibit A-30, Schedule T1 New 19

Customer Attachments 10 Year Surcharge are as follows: 20

a. The homeowner uses 1,125 gallons of propane annually, which is the 21

equivalent of 100 Mcf. 22

b. The propane costs $1.81 per gallon (the same price utilized by Witness 23

Creisher in her testimony). 24

1 https://newlook.dteenergy.com/wps/wcm/connect/dte-web/home/service-request/common/natural-

gas/switching-to-natural-gas

https://newlook.dteenergy.com/wps/wcm/connect/dte-web/home/service-request/common/natural-gas/switching-to-natural-gas








H. J. DECKER

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No.

HJD-10-Rebuttal

c. The project requires 2,500 feet of main to serve 10 homeowners (250 feet each) 1

and 1,500 feet of service line (150 feet each) priced out using the Company’s 2

current approved Generic costs. 3

d. The attachment rate is 60% in Year 1, 10% in Year 2, and 10% Year 3. No 4

additional attachments occur after Year 3. 5

e. The surcharge is recovered over a 10-year period. 6

f. Exhibit A-30, Schedule T3 uses the exact same assumptions, except the 7

surcharge is recovered over a 20-year period. 8

9

As depicted in Exhibit A-30, Schedule T1 New Customer Attachments 10 Year 10

Surcharge, if a 10-year recovery period is utilized the homeowner will pay a monthly 11

surcharge of $88.25. Utilizing a 20-year recovery period results in a monthly 12

surcharge of $60.02, as shown on Exhibit A-30 Schedule T2. 13

14

Q19. How much savings is realized by the homeowner under the 10-year and 20-year 15

surcharge payback scenarios? 16

A19. As shown on Exhibit A-30, Schedule T3 Fuel Savings 10 Year Surcharge and 17

Exhibit A-30, Schedule T4 Fuel Savings 20 Year Surcharge, the homeowner would 18

save only $202 annually based on a 10-year payback, versus an annual savings of 19

$538 using a 20-year payback period. Total 20-year cost savings to the homeowner 20

paying the 10-year surcharge would approximate $14,630 ($202 x 10 years while 21

the surcharge is in effect, plus $1,261 x 10 years after termination of the surcharge). 22

In contrast, the total 20-year cost savings to the homeowner paying the 20-year 23

surcharge would approximate $10,760 during the same 20-year period ($538 x 20 24

years). While the homeowner paying the 10-year surcharge would realize greater 25

H. J. DECKER

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No.

HJD-11-Rebuttal

overall savings than the homeowner paying the 20-year surcharge, it’s critical to 1

note that the 20-year surcharge still yields significant savings while also affording 2

the homeowner a more economical monthly payment. 3

4

Q20. Should other noneconomical factors be considered when determining whether 5

to lengthen the surcharge period? 6

A20. Yes. Unlike propane, natural gas provides constant, reliable service with no fears 7

of interruption or supply shortages. Additionally, natural gas provides peace of mind 8

to customers who are concerned about volatile pricing and potential shortages such 9

as what was experienced during the Polar Vortex. 10

11

Q21. Do you believe there are other facts that may not have been considered by 12

Witness Creisher during the development of her testimony? 13

A21. Yes, given the timing of the rebuttal, it’s likely that the COVID-19 health crisis was 14

not considered. The pandemic has created financial uncertainty among all sectors 15

of the Michigan economy; thus, it’s more important than ever that the Company 16

offer economical options to homeowners. 17

18

SECTION 2: ATTORNEY GENERAL REBUTTAL 19

EUT Volume Projection 20

Q22. AG Witness Coppola proposes increasing the Company’s EUT projected 21

volumes by 6.1 Bcf. Do you agree with the AG’s proposed increase to the EUT 22

volumes? 23

A22. No. The Company stands by its EUT forecast methodology and projected year 24

volume projections. 25

H. J. DECKER

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No.

HJD-12-Rebuttal

1

Q23. How do the Company’s and the AG’s EUT volumes for the projected test year 2

differ? 3

A23. Witness Coppola forecasted higher EUT volumes in three areas; 1) he increases 4

power generation consumption by 5.6 Bcf, 2) he erred in increasing EUT volumes 5

by 0.3 Bcf attributed to a chemical plant return to service, and 3) he rejects that EUT 6

volumes are reduced through EUT customer participation in the Commission 7

approved Energy Waste Reduction program. 8

9

Q24. Why are Witness Coppola’s power generation volumes for the projected year 10

higher than the Company’s power generation volume projection? 11

A24. Witness Coppola used the average consumption for the Company’s power 12

generation customers for the five-year period 2015 through 2019; whereas the 13

Company’s projection uses average consumption for the Company’s power 14

generation customers for the five-year period 2014 through 2018 ending with the 15

historical test year. 16

17

Q25. Why did the Company select the 5-year period ending with the 2018 historical 18

test year as the basis to calculate the power generation average consumption 19

used in its projected year forecast? 20

A25. The use of the average 5-year period ending with historical test year was extensively 21

litigated and approved by the Commission in the Company’s last general rate case 22

U-18999. In this case, Witness Coppola supports the use of the 5-year average 23

methodology; however, he chose a 5-year period unavailable to the Company at the 24

time it filed this case. 25

H. J. DECKER

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No.

HJD-13-Rebuttal

1

Q26. Are there factors the AG did not consider when they developed their forecast 2

analysis? 3

A26. Yes, there are. Witness Coppola’s 5-year forecast period includes the 2019 year 4

when power generation volumes were higher due to a period of very low gas prices 5

while dropping the 2014 year when gas prices were higher, and the summer cooling 6

degree days were 24% lower than that in 2019. Although summer temperatures are 7

one factor that drive gas-fired peaking plants to operate, it is not the only reason. 8

As provided in my direct testimony, there are numerous elements that determine 9

when the gas-fired peaking power plants served by the Company operate including 10

temperatures, gas prices, electric system maintenance, voltage support, base power 11

plant outages, combined with unit performance and being selected to run by the 12

system operator. 13

14

Q27. What other factors did the AG not consider at the time they developed their 15

EUT volume analysis? 16

A27. Witness Coppola does not include the dramatic effects of the Coronavirus health 17

crisis that immediately altered commercial building occupation and shuttered 18

industrial production. Electric generation requirements have dropped precipitously 19

and the Company’s affiliate, DTE Electric, has ceased operating older coal fired 20

units that also use significant volumes for natural gas co-firing. These coal and gas 21

fired plants have stopped operating even though DTE Electric’s Fermi II is currently 22

in a planned outage. Historically, the gas-fired power generation peaker plants 23

would have significant run-hours during a Fermi outage and more when combined 24

with current historically low gas prices. They are not. Recessionary uncertainties 25

H. J. DECKER

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No.

HJD-14-Rebuttal

potentially lasting well into 2020, 2021 and beyond will no doubt result in significant 1

retraction of the Company’s sales volumes to power generation as all commercial 2

and industrial market segments significantly decline for an unknown duration. The 3

EUT power generation volumes most certainly will not be higher than the 4

Company’s forecast during the projected year and will not increase as the AG has 5

proposed. 6

7

Q28. How did Witness Coppola err when he increased the EUT volumes by 288 8

MMcf attributed to a chemical plant return to service? 9

A28. Witness Coppola introduced a Company discovery response into his testimony as 10

Exhibit AG-38. He incorrectly interpreted the Company’s discovery response to 11

mean that the Company did not include a chemical plant’s volumes in the 12

Company’s projected test year EUT volumes. Witness Coppola then made an 13

incorrect increase in his EUT volume forecast by 288 MMcf which is the volume 14

consumed by the chemical plant during 2019. In actuality, the aforementioned 15

facility was purchased by another company which continued operating the chemical 16

plant. The Company actually forecasted an increase in gas consumption by 17

including 333 MMcf for this chemical plant facility in its projected year EUT 18

volumes. No additional volumes should be added to the Company’s EUT forecast 19

attributed to the Witness Coppola’s mis-understanding of the discovery request 20

related to his Exhibit AG-38. 21

22

Q29. What basis does AG Witness S. Coppola use to propose increasing the EUT 23

volumes by 401 MMcf for the energy waste reduction (EWR) initiative? 24

H. J. DECKER

Line U-20642

No.

HJD-15-Rebuttal

A29. Witness Coppola completely rejects the Company’s Commission approved EWR 1

program as it has been applied to the Company’s rate ST and LT EUT volume 2

forecast. He does not provide an alternative EWR calculation or volume projection. 3

4

Q30. Does the Commission provide oversight of the Company’s EWR programs? 5

A30. Yes, it does. The Company files the results of its EWR program with the 6

Commission annually where the Commission performs an exhaustive review and 7

audit of the Company’s EWR programs, including the C&I EWR program. The 8

EWR program for EUT customers achieved 405 MMcf of energy waste reduction 9

measures during 2017, 614 MMcf during 2018, and 520 MMcf during 2019. The 10

Company’s 1% factor applied to the rate ST and rate LT volumes, amounting to 401 11

MMcf, is well supported based on recent program measures. The AG’s proposed 12

disallowance of the Company’s Commission approved EWR program volume 13

forecast, without supporting evidence or an alternative consideration, is 14

disconcerting. 15

16

Appliance Repair Service Revenue 17

Q31. AG Witness Coppola has recommended using a 3-year average to calculate 18

revenues and expenses of the company’s Appliance Repair Service. Do you 19

agree with AG Witness Coppola’s recommendation? 20

A31. No. Adopting the historical test period revenues and costs for the Appliance Repair 21

Service is consistent with prior rate case orders, specifically U-16999 settlement, as 22

well as the Commission’s orders in Case Nos. U-17999 and U-18999. The 23

Appliance Repair Service is also subject to intense competition in the marketplace 24

from independent contractors and other repair service companies. Customer count, 25

H. J. DECKER

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No.

HJD-16-Rebuttal

pricing and costs are highly uncertain going forward. In addition, the Appliance 1

Repair Service is an optional cost from a customer perspective and are therefore 2

subject to economic conditions that the customers are currently facing and would 3

not be accurately reflected in a 3-year average. 4

5

Other Considerations 6

Q32. Are there any other factors that AG Witness Coppola was unable to consider 7

at the time he developed his EUT projected volume forecast and Appliance 8

Repair Service analysis? 9

A32. Yes, there are. The ongoing Coronavirus health crisis has dramatically, and in a 10

short period of time, altered many views of the economic environment. At the time 11

of this writing, the communities in DTE Gas’ service territory have already been 12

severely impacted with many businesses closing, and others reducing operations. 13

Mr. Chapel outlines the Company’s estimated impacts of this economic downturn 14

on residential and GS-1 customers likening it to what occurred in 2009-2010. 15

Although it’s difficult to extrapolate the exact impact of the health crisis on 16

forecasted volumes for all utility customer segments and Appliance Repair Service 17

revenues for the projected test year, it is anticipated that the volumes and revenues 18

will be lower than what the Company filed in this case. 19

20

SECTION 3: RESA REBUTTAL – CUSTOMER USAGE INFORMATION 21

End-Use Transportation 22

Q33. What tariff provision does the Retail Energy Supply Association (RESA) 23

propose for the Company’s gas rate book? 24

H. J. DECKER

Line U-20642

No.

HJD-17-Rebuttal

A33. RESA proposes the Commission direct the Company to add a provision requiring 1

the Company provide EUT customers, or their designated agents, with accurate 2

individual customer usage data no later than the 6 business days after the conclusion 3

of the month. RESA recommends inserting this language in Sections E2 and E16.2 4

of the Company’s gas rate book. 5

6

Q34. Does the Company agree with RESA’s proposed tariff change to Section E16.2 7

in the Company’s gas rate book? 8

A34. No. Section 16.2 is applicable to Off-System Customers, not the Company’s EUT 9

customers. There are currently only two Off-System Customers requiring usage 10

data, and the Company communicates with these two customers daily. The 11

customers have not voiced concerns about the data provided by the Company; 12

therefore, the 6th business day accurate usage provision proposed by RESA is 13

completely unnecessary. 14

15

Q35. Does the Company agree with RESA’s proposed tariff change to Section E2 in 16

the Company’s gas rate book? 17

A35. No. The Company also desires accurate consumption information early in the 18

month for its internal accounting and reporting purposes. The Company’s 3rd 19

business day meter read accuracy target is greater than 98%. During the past 27 20

months, the Company has attained an average 3rd business day meter read accuracy 21

of 97.9%. Given the Company reads more than 3,500 EUT meters monthly, 22

RESA’s proposed tariff change would only be addressing 70 EUT meter issues on 23

average after the 3rd business day. RESA’s claim that “each month there typically 24

are accuracy issues with one out of every dozen transportation customer accounts” 25

H. J. DECKER

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No.

HJD-18-Rebuttal

(RESA Witness Rittimann testimony, page 5, lines 11-12) is not supported by the 1

Company’s meter read tracking process. 2

3

Q36. Does the missing meter read or consumption data available on the third 4

business day improve in accuracy prior to the Company invoicing EUT 5

customers? 6

A36. Yes, it does. According to the Company’s major account billing team, the missing 7

meter read and consumption data improves each day with a majority of the EUT 8

meter read discrepancies solved by the 5th business day. The Company invoices 9

EUT customers on the 10th business day and the preliminary meter reads and 10

consumption data are typically only a couple meter discrepancies short of 100% 11

documented by that time. 12

13

Q37. RESA claims they do not receive usage data after the Day 6 report, is this 14

correct? 15

A37. No, RESA is incorrect. The Company does not send usage data to EUT customers 16

or their suppliers; rather, customers and their authorized agents log into the 17

Company’s eNominator site and generate usage reports themselves. The 18

Preliminary EUT Meter Consumption reports they generate are available beyond the 19

6th business day. EUT customers and their authorized agents have access to the 20

most current (updated daily) preliminary meter and consumption information 21

available by accessing the Preliminary EUT Meter Consumption report 24 hours a 22

day seven days a week, including the 4th through the 10th business day. In fact, 23

customers and their authorized agents suppliers can access the Preliminary EUT 24

Meter Consumption report any time prior to the 4th work day of the following month. 25

H. J. DECKER

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No.

HJD-19-Rebuttal

After the 4th work day of the following month, the Preliminary EUT Meter 1

Consumption report begins a new reporting cycle for the then current bill cycle. 2

3

Q38. What are the primary reasons for meter read and consumption inaccuracies? 4

A38. The Company agrees with RESA that discrepancies are typically due to a meter 5

instrument or meter problem; and sometimes, especially during holidays, it can be 6

challenging to gain access to the customer premise to read the meter. A meter failure 7

or meter instrument failure repair can take time to coordinate; however, most other 8

meter issues are resolved within 24-48 hours of the customer or agent contacting the 9

Company’s account manager or the assigned billing analyst. 10

11

Q39. Starting on page 6, line 18, RESA Witness Rittimann describes issues related 12

to obtaining accurate customer usage data and impacts on customers. Do you 13

agree with his claims? 14

A39. No. RESA, in their testimony, implies that 1) customers are at risk for unauthorized 15

use penalties and excess storage penalties and 2) the Company does not always 16

provide timely confirmation of storage transfers between customers. Witness 17

Rittimann goes on to describe concerns that inaccurate data from the Company may 18

result in the supplier misinforming the customer and impeding their ability to 19

provide the best pricing to the customer. I am confounded by RESA’s claims. The 20

Company always works with customers and their gas suppliers when metering issues 21

arise, working with all parties involved to insure the meter or meter instrument is 22

repaired as quickly as possible and penalties are not charged to the customer for 23

meter problems. The Company will not assess penalty (or will waive a penalty) if 24

it is determined the matter was related to a meter failure or an error created by the 25

H. J. DECKER

Line U-20642

No.

HJD-20-Rebuttal

Company. As for the Company placing RESA in a position that they could 1

misinform a customer or not offer the best service is inexplicable as the members of 2

RESA are presumably very sophisticated energy companies that have been in the 3

business of managing EUT customer gas supplies and balances on the Company’s 4

system for a long time. The Company has not received complaints as depicted by 5

RESA on consumption accuracy related to EUT accounts from other gas suppliers 6

or energy managers and have not received complaints from RESA members until 7

this general rate case. The Company is confident that the unsupported concerns 8

described by RESA are not echoed by other gas suppliers and energy managers 9

providing services to the Company’s EUT customers. 10

11

Q40. Does the Company provide electronic remote metering services? 12

A40. Yes, the Company provides electronic remote metering for customers taking service 13

under the Company’s EUT rate schedules. Remote metering service is available for 14

precisely the reasons RESA uses to argue for rate book changes - timely and accurate 15

meter information to aid in managing EUT customer gas procurement and storage 16

balancing decisions. The Company would be pleased to work with RESA and the 17

EUT customers to have remote metering installed at customer facilities that are 18

supplied and managed by RESA members. 19

20

Gas Customer Choice (GCC) 21

Q41. What is RESA Witness Rittimann proposing regarding the GCC program? 22

A41. Witness Rittimann proposes that a tariff provision be added to DTE’s rate book to 23

provide accurate, timely and reliable customer usage data to suppliers. 24

25

H. J. DECKER

Line U-20642

No.

HJD-21-Rebuttal

Q42. Why is RESA proposing this change? 1

A42. Witness Rittimann claims the Company does not send usage data to suppliers 2

in an accurate, timely and reliable manner. Witness Rittimann further claims 3

the suppliers cannot address customer complaints related to usage without the 4

ability to view the customer’s invoice. 5

6

Q43. Does the Company agree with Witness Rittimann’s assertion that it does not 7

provide the suppliers with accurate, timely and reliable usage data? 8

A43. No. DTE provides usage data to the suppliers each working day of the month based 9

on the customer’s billed actual or estimated consumption. DTE is compliant with 10

providing Gas Suppliers the necessary data as described in DTE’s Rate Book. 11

12

Q44. Does DTE agree with Witness Rittimann’s claim that the suppliers must be able 13

to view the customers’ invoices to provide appropriate support? 14

A44. No. Customer questions pertaining to usage should be directed to the Company, 15

while the Supplier should respond to customer inquiries related to the gas 16

commodity rates. It is not necessary for DTE Gas to, nor is it required to, provide 17

the supplier with a copy of the customer’s invoice. 18

19

Q45. Are Witness Rittimann’s concerns about cancelled billing transactions 20

associated with GCC customer accounts valid? 21

A45. No. DTE is obligated to adhere to MPSC billing rules, including rules associated 22

with adjustments that result in cancel and rebills. These rules apply to all customers, 23

including those enrolled in the GCC program. As a result, DTE may sometimes 24

cancel and rebill a customer back to the point of the original transaction requiring 25

H. J. DECKER

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No.

HJD-22-Rebuttal

correction. The Company assists customers with questions or concerns associated 1

with cancelled and rebilled invoices. 2

3

Q46. Is this general rate case the appropriate forum for Witness Rittiman to propose 4

changes to the GCC program? 5

A46. No. Section F5 of the Company’s rate book clearly establishes how supplier 6

complaints against the Company should be addressed. RESA has not adhered to 7

Section F5, and instead appears to be inserting a complaint into a general rate case 8

proceeding. It is not appropriate to address this issue in a general rate case. 9

10

Q47. If the Commission believes it appropriate to address Witness Rittimann’s 11

concerns in this rate case, how should this matter proceed? 12

A47. In Witness Rittiman’s testimony, there are no details, data, facts, or any other 13

evidence that the Company is not providing the suppliers with accurate, timely and 14

reliable usage data. The parties should be required to provide specific details and 15

facts supporting their assertions, and the Company should be afforded the 16

opportunity to respond accordingly. 17

18

SECTION 4: CITIZENS UTILITY BOARD of MICHIGAN (CUBM) REBUTTAL 19

5-Year Versus 3-Year Historical Average EUT Volumes for Power Generation 20

Customers 21

Q48. What is CUBM Witness Veerapaneni’s basis for using 3-year average historical 22

volumes in projecting the Company’s EUT volumes use by its power generation 23

customers? 24

H. J. DECKER

Line U-20642

No.

HJD-23-Rebuttal

A48. Witness Veerapaneni’s has two unsupported reasons for using a 3-year average 1

instead of a 5-year average because: 1) he presumes the Company chooses the term 2

that supports a higher rate increase, and 2) the volume consumed by the Company’s 3

power generation customers during 2019 is more than the 3-year average supported 4

by Witness Veerapaneni. Neither reason is supported nor would either be a 5

substantive reason to use the 3-year historical average power generation volumes. 6

7

Q49. Why has the Company used a 5-year historical average calculation to project 8

the EUT volumes consumed by the Company’s power generation customers? 9

A49. The Company’s power generation customer volumes vary significantly due to 10

weather, gas prices, and power plant outages that are not easily forecasted. The 11

Company’s 5-year average methodology captures a broad a range of warm and cold 12

winter weather conditions including the cold winter of 2014, warm and cool summer 13

weather conditions including the warm summers of 2016 and 2018 and the cool 14

summer of 2014, higher gas prices experienced during 2013 to 2014 and low gas 15

prices of early 2016 and during 2018. This wide variety of factors provides an 16

expansive and representative reflection of average usage for the Company’s power 17

generation customers. Limited to using only 2016 to 2019 gas volumes, CUBM’s 18

calculation does not represent the wide variability provided in the Company’s EUT 19

power generation volume forecast. 20

21

Q50. What was the Commission’s Order in the Company’s general rate case No. U-22

18999 concerning the use of 5-year versus 3-year historical average as the basis 23

to calculate the power generation average consumption used in its projected 24

year forecast? 25

H. J. DECKER

Line U-20642

No.

HJD-24-Rebuttal

A50. The use of the average 5-year period ending with historical test year was 1

extensively litigated and approved by the Commission in the Company’s last 2

general rate case No. U-18999. In that case the Company provided convincing 3

evidence supporting the Company’s power generation customer volumes vary 4

significantly due to weather, gas prices, and power plant outages that are not easily 5

forecasted. The Commission’s Order in case No. U-18999 states on page 63 of the 6

Order: 7

The Commission finds that DTE Gas’ five-year historical period best 8

represents the company’s average gas use. While the Attorney 9

General’s three-year historical period captures an apparent uptrend in 10

gas use, it does not account for variances in Michigan weather, which 11

may be warmer or colder than is typical and may influence customer 12

gas use. In addition, the Commission agrees with the ALJ that the 13

Attorney General failed to prove that EUT customers will be using 14

more gas in the test year as power generation transitions from coal to 15

natural gas. Although there is a current transition from coal to natural 16

gas, the shift to gas power generation is being phased in and 17

complemented by increased renewable energy and demand-side 18

management. Plans for new gas generation in the DTE Gas service 19

area are well beyond the test year. See, April 27, 2018 order in Case 20

No. U-18419, pp. 19, 30, 40-41, 76-80, and 117-118. 21

22

The Commission finds that the company provided convincing 23

evidence that the warm weather in 2016 resulted in more volume used 24

by power generation customers. Finally, the Attorney General did not 25

provide a basis for rejecting the EWR volume reduction. Accordingly, 26

the Commission finds that DTE Gas’ EUT test year revenue of $88.3 27

million should be approved. 28

29

Q51. Should the Commission reject CUBM’s power generation volume forecast for 30

the projected year? 31

A51. Yes. Witness Veerapaneni’s testimony does not provide meaningful evidence 32

supporting his power generation calculation methodology. If the Commission 33

adopts CUBM’s position, it should correct the apparent error in calculating the 34

H. J. DECKER

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No.

HJD-25-Rebuttal

proposed disallowance value. The calculation of a “proportionate increase” 1

results in applying an unrealistic transportation rate of $1.77 per Mcf which is 2

then applied to the unsupported increase in power generation volumes. This 3

result is overstated by more than 1,000 percent. 4

5

Other Considerations 6

Q52. Are there any other factors that CUBM Witness Veerapaneni was unable to 7

consider at the time he developed his EUT projected volume forecast analysis? 8

A52. Yes, there are. As noted elsewhere in my testimony, the ongoing Coronavirus 9

health crisis has dramatically, and in a short period of time, altered many views of 10

the economic environment. At the time of this writing, the communities in DTE 11

Gas’s service territory have already been severely impacted with many businesses 12

closing, and others reducing operations. Although it’s difficult to project the exact 13

impact of the health crisis on forecasted EUT volumes in the projected test year, it 14

is anticipated that the volumes will be lower than what the Company filed and well 15

below what Witness Veerapaneni has projected. 16

17

Q53. Does this conclude your rebuttal testimony? 18


STATE OF MICHIGAN


In the matter of the Application of )


increase its rates, amend its rate ) Case No. U-20642

schedules and rules governing the )


and for miscellaneous accounting authority. )

QUALIFICATIONS

AND

REBUTTAL TESTIMONY

OF

PHILIP W. DENNIS

DTE GAS COMPANY

QUALIFICATIONS OF PHILIP W. DENNIS

Line

No.

PWD-1-Rebuttal

Q1. What is your name, business address and by whom are you employed?1

A1. My name is Philip W. Dennis. My business address is One Energy Plaza, Detroit, 2

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

subsidiary of DTE Energy Company (DTE) as Manager, Regulatory Economics. 4

5

Q2. On whose behalf are you testifying? 6

A2. I am testifying on behalf of DTE Gas Company (DTE Gas or Company). 7

8

Q3. What is your education background? 9

A3. I received a Bachelor of Science Degree in Business Administration from Central 10

Michigan University. In addition, I received a Master of Finance Degree from 11

Walsh College. 12

13

Q4. What work experience do you have? 14

A4. In 1981 I was employed by ANR Pipeline Company (ANR) as a Finance Trainee. 15

ANR is an interstate natural gas (gathering, storage and transmission) company 16

regulated by the Federal Energy Regulatory Commission (FERC). I had varying 17

and increasing responsibilities within ANR, including positions in their 18

Controller’s organization, Regulatory Affairs and Marketing groups. While 19

working in the Regulatory Affairs organization, I assisted in the preparation and 20

analysis of general rate cases, purchased gas adjustments, and various surcharge 21

recovery filings. While in Regulatory Affairs, I presented testimony at the FERC 22

sponsoring various cost of service components and participated as a witness in 23

ANR’s rate case hearings. In 1994 I was promoted to Manager of Transportation 24

Rates. I transferred to ANR’s Marketing department in 1999 as Manager of Market 25

P. W. DENNIS

Line U-20642

No.

PWD-2-Rebuttal

Analysis. I remained there until early 2001, when ANR, as part of a merger, was 1

moved to Houston and I left the Company. In 2001, I began working for Michigan 2

Consolidated Gas Company (MichCon) as a Principal Financial Analyst in the 3

Regulatory Affairs department. In 2001, MichCon’s parent, MCN Energy, was 4

acquired by DTE Energy, DTE Electric’s (formerly The Detroit Edison Company) 5

parent. In 2005, I was promoted to Regulatory Affairs Consultant and was project 6

manager for DTE Electric’s general rate cases Case Nos. U-15244, U-15768 and 7

U-16472. In 2011, I assumed my present position of Manager, Regulatory 8

Economics. 9

10

Q5. What are your current duties and responsibilities with DTE? 11

A5. My responsibilities include the management of regulatory activities relative to 12

DTE’s Tariffs, and DTE Electric’s Load Research, Pricing, and Rate Design. 13

14

Q6. Have you previously sponsored testimony before the Michigan Public Service 15

Commission (MPSC or Commission)? 16

A6. Yes. I sponsored testimony and exhibits in the following DTE Electric cases: 17

Case No. Description 18

U-17437 Transitional cost recovery plan associated with the disposition of the 19

City of Detroit Public Lighting System 20

U-17761 Years 2013/2014 Reconciliation of Transitional Reconciliation 21

Mechanism associated with the disposition of the City of Detroit 22

Public Lighting System. 23

U-18005 Year 2015 Reconciliation of Transitional Reconciliation 24


P. W. DENNIS

Line U-20642

No.

PWD-3-Rebuttal


U-18248 Implementation of Section 6w of 2016 PA341 (“Capacity Filing”) 2




U-18262 Years 2018/2019 Energy Waste Reduction Plan Filing 6

U-18419 Certificate of Necessity Filing 7




U-18232 Renewable Energy Plan (REP) Proceeding 11

U-20162 DTE Electric 2018 General Rate Case 12

U-20284 DTE Electric Credit B Refunds 13

U-20561 DTE Electric 2019 General Rate Case 14

U-20657 Complaint Case 15

16

Q7. Did you file direct testimony in this proceeding on behalf of DTE Gas? 17

A.7 No I did not. 18

19

DTE GAS COMPANY

REBUTTAL TESTIMONY OF PHILIP W. DENNIS

Line

No.

PWD-4-Rebuttal


Q8. What is the purpose of your testimony?2

A8. The purpose of my testimony is to respond to the Michigan Public Service 3

Commission Staff’s (“Staff”) proposal, as described in the direct testimony of Staff 4

Witness Revere, to change the method of recovering customer costs (sometimes 5

referred to as service charges) from all of DTE Gas’ rate schedules. The Company 6

currently recovers such costs through a monthly charge; Witness Revere proposes 7

changing to a daily charge. 8

9


A9. Yes. I am sponsoring the following exhibit: 11


A-35 Z1 Distribution of customer bills based on billing cycle days 13

14


A10. Yes, it was. 16

17

Q11. Why is Staff proposing to change the method of recovering customer charges 18

from a monthly charge to a daily charge?19

A11. Staff’s proposal may result from a misunderstanding of how DTE Gas charges its 20

customer related costs. Staff explains a perceived risk that customers will be billed 21

more than 12 customer charges, and therefore the Company may over-recover 22

customer charges using the monthly method, saying: 23

Due to the timing of billing cycles and potential delays in meter reading, 24

it is currently possible for a customer to be charged 13 monthly customer 25

charges in a year, rather than 12 as assumed when calculating rates. If 26

DTE GAS COMPANY


Line

No.

PWD-5-Rebuttal

the Company charges 13 customer charges in a year, it results in revenue 1

to the Company above what was assumed when setting rates1. 2

Staff further states “if the Company were to charge 13 customer charges to all 3

customers at Staff’s proposed customer charges, it would result in additional revenue 4

to the Company of approximately $21.3 million.”2 5

6

Q12. Do you agree with the proposed change to a daily charge?7

A12. I do not agree with the proposed change, for the following reasons: 8

1. Actual DTE Gas data from 2019 does not show Staff’s theoretical gain in 9

revenue occurring. In addition, recovering more or less than anticipated within 10

charging components (i.e. customer charge, distribution charge, gas cost 11

recovery, IRM, reservation charge, etc) is the normal course of business as 12

utilities set rates based on various assumptions, including number of customers, 13

expected load, costs, etc. 14

2. Any costs to implement the recommended change in the billing system would 15

not be cost justified. 16

3. More than likely, daily charges would cause additional customer confusion and 17

drive more calls to both the Company and the Michigan Public Service 18

Commission. 19

4. Daily customer charges are not the industry standard. 20

21

Q13. What is the Company’s current method for addressing variations in days per 22

billing cycle as discussed by Staff?23

1 Direct testimony of Staff Witness Nicholas M. Revere in U-20642, Pg 5. 2 Direct testimony of Staff Witness Nicholas M. Revere in U-20642, Pg 5

DTE GAS COMPANY


Line

No.

PWD-6-Rebuttal

A13. The Company bills customers on an approximately monthly basis. A bill issued for 1

a period between 26 and 35 days includes the regular monthly customer charge of 2

$11.25. Any billing cycle with fewer than 26 days or more than 35 days includes 3

a customer charge modified on a pro-rata basis to reflect the “short” or “long” 4

billing cycle. This has been the Company’s method for determining customer 5

service charges since at least when I joined the Company in 2001 for both the gas 6

and electric utilities. 7

8

Q14. Is the scenario discussed by Witness Revere, where the Company could charge 9

a customer for 13 monthly service charges in a year, even possible? 10

A14. Customers are billed on a billing cycle basis and every customer will get only one 11

bill per billing cycle each year. While customers (because of the number of days 12

included in cycle one, and/or cycle twenty), may get a thirteenth bill in a calendar 13

year, the next calendar year (or previous, depending on timing) would contain only 14

11 bills. The current billing cycle methodology actually prevents the situation 15

Witness Revere describes. In addition, under Mr. Revere’s scenario of a 13-month 16

service charge, the customer would have 390 days of service and thus the Company 17

would appropriately charge an additional $11.25. Under his daily methodology, 18

the customer would be charged the exact same as the Company’s current method. 19

20

Finally, in a given year, there is a scenario where a customer could be charged more 21

than $135 ($11.25 x 12 months) due to a few long bills in a particular month. 22

However, this is appropriate since such customers are receiving service for greater 23

than one month in that scenario. There are also scenarios in which a customer could 24

be charged less than $135 due to a few short bills (receiving service for less than one 25

DTE GAS COMPANY


Line

No.

PWD-7-Rebuttal

month in the billing cycle). Therefore, instead of developing a multitude of various 1

possible scenarios, I’ve reviewed data from 2019 to determine if an issue actually 2

exists. 3

4

Q15. Can you please describe the results of your analysis? 5

A15. Across all bills issued in 2019, approximately 96.9% reflected a regular billing 6

cycle and a regular customer charge. Of the about 3.1% that received a short or long 7

bill, approximately 2.8% were short bills related to Move-In / Move-Out and 8

outside of any Company control.3 In those situations, the Company’s current 9

methodology appropriately calculates a pro rata customer charge so that the 10

customer is not paying a full month customer charge. The much lower volume of 11

long bills (only 0.2%) is generally characterized by inaccessible, inside analog 12

meters and AMI misreads. 13

14

Q16. Does the Company’s billing approach create a timing mismatch with the 15

customer charge?16

A16. No, it does not. A month has approximately 30.4 days4 and the weighted average 17

billing cycle length in 2019 was an equivalent 30.4 days when accounting for the 18

impact of short bills generated by Move-In / Move-Out.5 19

20

Q17. Does the Company’s billing approach drive a deviation in recovery of 21

customer charges from what was authorized by the Commission?22

3 See Exhibit A-35, Schedule Z1 4 365.25 days in a year, 12 months in a year 5 See Exhibit A-35, Schedule Z1

DTE ELECTRIC COMPANY

DIRECT TESTIMONY OF PHILIP W. DENNIS

Line

No.

PWD-8-Rebuttal

A17. No, it does not. Statistically and on average, there is no over or under recovery of 1

the monthly customer charge based on the timing or length of billing cycles. This 2

is evident based on the nearly identical length of an average month and an average 3

billing cycle. Variances in the number of actual customers compared to the 4

forecasted customer count in a general rate case may impact total recovery 5

associated with the customer charge but is unrelated to any billing method applied 6

by the Company. Similar variances exist when comparing the Company’s forecast 7

of expected load to actual load for any given year. 8

9

Q18. Does the monthly customer charge methodology lead to customer complaints?10

A18. There is no evidence of repeated customer contacts associated with the Company’s 11

current methodology. As a matter of fact, in a review of the more 39,000 informal 12

customer contacts with DTE’s Executive Consumer Affairs Center since 2018, only 13

97 were associated with DTE Gas “rate” related issues. Of those, only one 14

customer had an inquiry related to the gas customer charge methodology. This 15

customer was non-residential and did not understand the “long bill” pro-rata 16

method; the case was closed after explaining the pro-rata approach. 17

18

Q19. Are there customer benefits associated with a change to daily customer 19

charges? 20

A19. I have not identified any improvements to customer satisfaction or engagement that 21

would be unlocked with a daily customer charge. As a matter of fact, there are 22

several negatives associated with making a change. 23

24

Q20. What other impacts would the proposed change create?25

DTE ELECTRIC COMPANY

DIRECT TESTIMONY OF PHILIP W. DENNIS

Line

No.

PWD-9-Rebuttal

A20. Days in a billing cycle is not a billing determinant for any portion of a Residential-1

A customer bill at present; all charges are either fixed (customer and IRM) or driven 2

by consumption. Changing the billing determinants could create a handful of 3

adverse impacts, and incurring associated costs to address a topic that has generated 4

no complaints and causes no apparent adverse outcomes, would be neither prudent 5

nor reasonable. The adverse impacts of the proposed change include: 6

• Billing system changes would be required to ensure the correct calculation 7

and presentation of the new billing determinant and unit rate. 8

• Ongoing increase in call center volume from customers both generally 9

unfamiliar with the new billing practice and dissatisfied or confused about 10

their fluctuating customer charge. 11

• Increased billing exceptions as a new billing determinant is added. 12

13

Q21. Are daily customer charges typical in the industry?14

A21. No, they appear to be atypical. While Staff identifies three smaller utilities in 15

Michigan with daily customer charges, more than 90% of Michigan gas customers 16

are billed monthly for their customer charge.6 A brief survey of base residential 17

tariffs at gas LDCs in ten states,7 ranging from approximately 250k to more than 4 18

million customers, confirms the widespread use of monthly customer charges, 19

revealing 80% use monthly customer charges. 20

21

Q22. Does this conclude your testimony?22

A22. Yes, it does. 23

6 DTE Gas and Consumers Energy Gas total ~2.9 million customers 7 CMS – MI, ConEd – NY, Washington Gas – VA, Eversource– MA, PG&E – CA, Peoples – IL, NJ

Natural Gas – NJ, Eversource – CT, Wisconsin Gas – WI, Xcel - MN

STATE OF MICHIGAN



)

REBUTTAL TESTIMONY

OF

ANDREW D. DEWEY

DTE GAS COMPANYREBUTTAL TESTIMONY OF ANDREW D. DEWEY

LineNo.

ADD-1-Rebuttal


employed?2

A1. My name is Andrew D. Dewey. My business address is One Energy Plaza, Detroit,3

Michigan 48226. I am employed by DTE Gas Company (DTE Gas or Company)4

as Director – Gas Operations – Construction.5

6


Company?8

A2. Yes.9

10



A3. The purpose of my testimony is to rebut:13

1. The Michigan Public Service Commission (MPSC) Staff Witness Creisher’s14

testimony regarding the proposed 2020 capital expenditures for the MMO15

program.16

2. The Michigan Public Service Commission (MPSC) Staff Witness Creisher’s17

testimony regarding the proposed 2020 capital expenditures for the MRP.18

3. The Attorney General Witness Coppola’s testimony regarding the proposed19

capital expenditure levels and disallowances for the Main Renewal Program.20

21


A4. Yes. In addition to the exhibits I sponsored with my direct testimony, I am also23

sponsoring the following exhibit:24

25

A. D. DEWEYLine U-20642No.

ADD-2-Rebuttal


A-27 Q1 2020 Plans – Main Renewal and Meter Move Out Programs2

3


A5. Yes, it was.5

6

Meter Move Out7

Q6. What spending level is Staff Witness Creisher proposing for DTE Gas’s Meter8

Move Out Program?9

A6. Witness Creisher proposes that DTE Gas’s Meter Move Out program operate with10

a capital expenditure level of $25,835,800 in 2020. However, DTE Gas is proposing11

the Meter Move Out program operate with a capital expenditure level of12

$27,668,000.13

14

Q7. Do you agree with the recommendation of Staff Witness Creisher’s proposed15

spending level for the Meter Move Out program?16

A7. No. The recommendation proposed by Witness Creisher utilizes the 2018 actual17

cost per inside meter impacted of $2,020 per meter experienced by the MMO18

program, as a basis for the capital expenditure level she is proposing. DTE Gas is19

proposing to utilize a cost per inside meter impacted of $2,163 per meter, which is20

approximately 7% higher than what Ms. Creisher is proposing.21

22

Q8. Why do you feel utilizing the 2018 actual cost per inside meter impacted is not23

appropriate when projecting capital expenditures for the MMO program in24

2020?25


ADD-3-Rebuttal

A8. Utilizing the 2018 actual cost per inside meter impacted is not appropriate when1

projecting our expected MMO capital expenditure for 2020 due to the significant2

changes to our internal work force since the beginning of 2018.3

4

In order to support the expansion of the Main Renewal Program approved by the5

Commission in Case No. U-18999, the Gas Renewal Program (GRP) began an6

internal hiring campaign to support the expected increase in annual work volume7

between both the MMO and MRP programs. Between the second half of 2018 and8

the first quarter of 2019, GRP has hired and retained a total of 78 Maintenance9

Fitter Apprentices, as referenced in Rebuttal Exhibit A-27 Schedule Q1. As these10

new employees are hired into the company, they must go through new hire and on-11

the-job training, which is conducted in the field. For the vast majority of 2018 and,12

through the duration of this training, the labor costs associated with these newly13

hired employees were not charged to either the MMO or MRP program budgets.14

Each of these employees has since been fully trained and qualified to begin 2020.15

As qualified employees, their labor will now be included in MMO and MRP16

expenditures and needs to be accounted for when projecting our MMO capital17

expenditure.18

19

Q9. Do we anticipate any effects on productivity due to the significant number of20

newer employees, impacting overall 2020 MMO capital expenditures?21

A9. Given the large number of employees that have recently been hired, we do expect22

to see a slightly lower overall productivity in 2020. Prior to the hiring campaign23

that started in 2018, the majority of our internal employees had several years, or24

decades, of work experience, leading them to be extremely efficient on a day to day25


ADD-4-Rebuttal

basis. Since the completion of the internal hiring campaign, the makeup of our1

internal employees has shifted and now, roughly half of our employees have some2

to very little work experience. While these newer employees are fully qualified and3

trained, they will continue to need many more months, if not several years, of4

further work experience in order to reach the productivity levels of our more5

experienced employees.6

7

Q10. Are there any additional cost impacts that are different from 2018 capital8

expenditures?9

A10. In addition to the expected productivity levels and labor costs we are anticipating10

for 2020, we must also take into account annual wage increases for our represented11

employees. Per the agreed upon collective bargaining agreement for our12

represented employees, they are subject to annual base wage increases of 2.95%.13

Our 2018 cost per inside meter impacted of $2,020 per meter does not account for14

the two years of annual base wage increases for our represented employees and15

would need to be adjusted when projecting 2020 capital expenditures.16

17

Q11. How do you project these cost drivers will impact MMO capital expenditures18

in the years 2021-25?19

A11. Given the recent level of internal hiring, we cannot know all potential impacts on20

future MMO capital expenditures. We are committed to ensuring that our requests21

are prudent and reasonable and best reflect our true capital expenditure needs.22

Therefore, we have not proposed any increases for our MMO capital expenditures23

beyond the year 2020 in Case No. U-20642.24

25


ADD-5-Rebuttal

Main Renewal Program1

Q12. What proposed spending level is Staff Witness Creisher proposing for DTE2

Gas’s Main Renewal Program?3

A12. Witness Creisher proposes that DTE Gas’s Main Renewal Program operate with a4

capital expenditure level of $234,400,000 in 2020. However, DTE Gas is proposing5

the Main Renewal Program operates with a capital expenditure level of6

$244,500,000.7

8

Q13. Do you agree with the recommendation of Staff Witness Creisher’s proposed9

spending level for the Main Renewal Program?10

A13. No, DTE Gas does not agree with Staff Witness Creisher’s proposed Main Renewal11

spending level of $234,400,000 in 2020.12

13

Q14. Why is Staff Witness Creisher recommending a reduction in the level of 202014

MRP capital expenditures?15

A14. Staff Witness Creisher believes that given the variability of actual costs in prior16

years, DTE Gas’s 2020 expenditures should be lowered to reflect a conservative17

approach. Witness Creisher recognizes that DTE Gas considers many factors when18

projecting costs but believes a conservative approach is more appropriate. In19

support of her recommendation, she notes the large variation in 2019 costs and units20

between projected and actual turn-key work performed by contractors, as well as21

the $4 million variance between total projected and actual spend.22

23

Q15. Does DTE Gas understand Witness Creisher’s recommendation, lowering24

2020 MRP expenditures?25


ADD-6-Rebuttal

A15. No. It is unclear to DTE Gas why a change in the proportion of work performed by1

external resources from a prior year, in addition to exceeding minimum spend2

limitations, would lead to the conclusion that a variance would result in a reduction3

in overall expenditures. DTE Gas believes that it has regularly spent, at a minimum,4

the total amount it has projected and agreed to as a minimum for the MRP. To5

achieve its targets for 2020, DTE Gas has projected an appropriate level of6

expenditures.7

8

Q16. Why did the company complete less turn-key service work and spend less in9

associated costs than originally projected in 2019?10

A16. When the Company initially projected the amount of turn-key service work in 2019,11

the Company anticipated that service work in Modified Grid Approach areas would12

require additional resources for the Company to achieve our year-end targets. As13

work progressed into the end of the year throughout the entire company, internal14

resources from other programs were available to complete this service work. This15

unexpected internal resource availability eliminated the need for external resources.16

As referenced DTE Gas’s annual March 31st, 2020 Report of 2019 activity, 8617

employees were temporarily transitioned from other South East Michigan stations18

throughout the year to support work included in the Gas Renewal Program. This19

change between contractor and internal resources in 2019 is an example of how20

DTE Gas carefully manages its work and resources to provide the maximum21

amount of work at the most reasonable cost.22

23


ADD-7-Rebuttal

Q17. For 2020, did the Company consider hiring more internal resources to support1

this anticipated increase in service work, rather than utilizing outside2

contractors?3

A17. Yes. The Company considered many impacts that would result from the hiring of4

even more internal employees, when determining the most prudent way to handle5

the increase in service work for 2020. As we experienced in 2019, there are many6

challenges that come with hiring many internal resources at a time. In addition to7

the long-term fixed costs associated with hiring internal resources, new hire8

employees go through extensive on-the-job training, conducted by already qualified9

and experienced employees. These experienced employees not only have to10

complete their daily construction work, but also have to take the time to train newly11

hired employees on every aspect of the construction work. This on-the-job training12

limits currently qualified and experienced employees from being fully efficient and13

productive. While hiring more internal resources seemingly reduces the need to14

utilize external resources, it doesn’t provide the immediate benefit of being able to15

complete more work, as would be required to complete all forecasted work for16

2020. As illustrated in Rebuttal Exhibit A-27 Schedule Q1, page 5, the amount of17

service work forecasted for 2020 is more than that completed in 2019 and what is18

forecasted to be completed in 2021. Because of this one-time increase of service19

work, the Company did not feel it was appropriate to hire internal resources who20

may not be needed in future years. Maintaining resource flexibility by utilizing21

external resources for turn-key work is currently the most prudent way to manage22

this spike in service work, specifically as it relates to our 2020 workload.23

24


ADD-8-Rebuttal

Q18. Has the Company implemented any proactive measures to mitigate cost1

impacts associated with this level of turn-key service work in 2020?2

A18. Yes, the Company has been able to utilize our experience in 2019 regarding turn-3

key work and has efficiently planned out the necessary turn-key work for 2020.4

Due to the volume of turn-key work required in 2020, the service work selected for5

turn-key is predominately made up of tie-over and elevation work types. These6

work types have the lowest associated unit costs, helping to mitigate the overall7

cost impacts from this volume of turn-key service work. Without leveraging this8

experience, the costs to complete the work would have been even higher.9

10

Q19. Are there any additional external influences that would further support the11

need for this volume of turn-key service work that the witness could not have12

anticipated when developing her testimony?13

A19. Yes. As experienced not just in Detroit, but across the entire state of Michigan and14

throughout all of DTE Gas’s service territory, the impacts of the 2020 health15

pandemic have been far reaching and profound. Due to the health and safety16

concerns of our employees and our customers, DTE Gas has made the difficult17

decision to temporarily stop all non-emergency operations work – this includes all18

infrastructure upgrades associated with the MRP and MMO programs. However,19

the Governor’s order includes an exception for energy companies, so many of our20

normal operations to keep gas flowing and to keep our customers and our system21

safe, continue during this crisis. And while DTE Gas is in the process of fully22

assessing the effects of the Governor’s prolonged stay-home-stay-safe executive23

order on our planned capital programs, it is currently understood that the need for24


ADD-9-Rebuttal

at least the originally planned amount of turn-key services remains in order to meet1

our annual targets.2

3

Because the temporary suspension of non-emergency work is impacting programs4

throughout the entire company, internal resources from other stations across the5

Company are likely to be fully utilized throughout the rest of the year. In all6

likelihood, the Main Renewal Program will not have the ability to utilize internal7

resources from other programs to support the completion of service work, putting8

further demands on our needs for at least the originally planned amount of turn-key9

services.10

11

Q20. Do we anticipate the impacts from 2020 health pandemic will prevent DTE12

Gas from achieving the annual targets committed to in Rate Order U-18999?13

A20. At this point and based on the Governor’s extended stay-home-stay-safe executive14

order, effective March 24 through April 30, the Company is confident it will be15

able to meet all of our annual goals.16

17

Due to the unprecedented uncertainty resulting from COVID-19, we will closely18

monitor our ability to enter residences and businesses to perform all associated19

meter work. Our plan is to educate customers regarding the safety precautions DTE20

Gas will take to ensure the safety of both our customers and our employees.21

Additionally, if the Governor decides to further extend the stay-home-stay-safe22

executive order and this situation continues to escalate, the Company will reassess23

our ability to complete all planned capital work and meet our annual targets. We24


ADD-10-Rebuttal

are committing to stay in close communication with Staff regarding the impacts1

from COVID-19 and will continue to reevaluate our plans throughout the year.2

3

Q21. What does Attorney General Witness Coppola propose regarding capital4

expenditure levels for the Main Renewal program going forward?5

A21. Attorney General Witness Coppola’s testimony recommends the Commission6

approve Main Renewal spending levels of $193 million going forward, which is7

consistent with the approved spending levels in Case No. U-18999. Additionally,8

Witness Coppola’s testimony recommends that $51,541,000 of additional Main9

Renewal capital costs in 2020 and 2021 be disallowed, with $12,885,000 being10

included in rate base for the 12-month period ending September 2021. Furthermore,11

Witness Coppola is recommending that the additional $39,400,000 being requested12

for Main Renewal in 2021 and beyond not be included in the IRM surcharge for13

these years, but only include the $193,000,000 in the IRM surcharge, which has14

already been approved by the Commission in Case No. U-18999.15

16

Q22. Do you agree with Attorney General Witness Coppola’s proposed spending17

level for the Main Renewal Program?18

A22. No, DTE Gas does not agree with Witness Coppola’s recommended capital19

expenditure levels for the Main Renewal Program. The capital expenditure amounts20

proposed by the Company for 2020-2025 are necessary to complete all21

infrastructure renewal work required to achieve the annual targets approved by the22

Commission in Case No. U-18999 and meet DTE’s goal to complete this program23

by 2035. Witness Coppola cites leak repair data filed by the Company with Pipeline24

and Hazardous Materials Safety Administration (PHMSA) unit of the U.S.25


ADD-11-Rebuttal

Department of Transportation as the basis for recommending capital expenditure1

levels consistent with what has already been approved in Case No. U-18999.2

However, as described in detail in my direct testimony, the Company has proposed3

increases in Main Renewal capital expenditure due to increases in construction cost4

estimates and increases in contractor construction contracts. The Company is not5

proposing an increase to the annual miles renewed in this rate case, but an increase6

in recovery to reflect the latest cost projections based on actual results from7

2018/2019 work as discussed in detail in my direct testimony.8

9

Q23. How is Witness Coppola substantiating his proposal for capital expenditure10

disallowance for the Main Renewal program?11

A23. Witness Coppola is not substantiating his proposal for capital expenditure12

disallowance with any argument. He is merely stating his recommendation for13

disallowance pertaining to Main Renewal capital expenditures in 2020 and 2021.14

Furthermore, the assertion that the company will recover the proposed disallowance15

of $39,400,000 in 2021 through the IRM anyways beginning in 2021 is not16

accurate. The Company will only recover the $39,400,000 through the IRM if the17

Commission approves the spending levels proposed for the IRM surcharge.18

19

Q24. Do the recommendations from Witness Coppola’s testimony align with the20

recommendations from the Commission?21

A24. No, Witness Coppola has recommended capital expenditure levels for the Main22

Renewal Program that are much lower than what Staff Witness Creisher expressed23

her support for on page 16 and 17 of her testimony. Witness Coppola recommends24


ADD-12-Rebuttal

spending levels of $193 million going forward, whereas Staff Witness Creisher has1

supported DTE Gas’s proposed spending levels of $232 million through 2025.2

3

Q25. If the proposed spending levels by witness Coppola are approved going4

forward, what effects would that have on DTE’s Main Renewal Program?5

A25. DTE Gas believes is has proposed appropriate levels of capital expenditure for its6

Main Renewal Program which are necessary to achieve the annual targets approved7

by the Commission in Case No. U-18999. As the Main Renewal Program continues8

to evolve, we continually work to better understand and forecast all costs associated9

with the completion of this work while doing everything we can to mitigate related10

cost pressures. While some of these additional expenditures were not initially11

included in cost estimates in Case No. U-18999, they are nonetheless required to12

complete all work that has been identified through 2025. Without the ability to13

invest in the Main Renewal program at the levels proposed by the Company and14

supported by Staff Witness Creisher, DTE would not be able to complete all15

necessary construction work required to achieve its annual targets.16

17


A26. Yes it does.19

STATE OF MICHIGAN



)

REBUTTAL TESTIMONY

OF

MARK C. JOHNSON

DTE GAS COMPANYREBUTTAL TESTIMONY OF MARK C. JOHNSON

LineNo.

MCJ-1-Rebuttal


employed?2

A1. My name is Mark C. Johnson. My business address is One Energy Plaza, Detroit,3

Michigan 48226. I am employed by DTE Energy Corporate Services, (LLC).4

5


Company?7

A2. Yes.8

9



A3. The purpose of my testimony is to address the following:12

- The Attorney General’s testimony concerning the increased O&M expense for13

the expansion of the damage prevention program,14

- The Michigan Public Service Commission (MPSC) Staff Witness Creisher’s15

testimony regarding O&M expenses for excavation damages,16

- MPSC Staff Witness Creisher’s testimony regarding O&M expenses for17

Maximum Allowable Operating Pressure (MAOP) Distribution records18

remediation and Transmission Fitting Conversion contingencies.19

- MPSC Staff Witness Miller’s testimony regarding O&M expenses for pipeline20

integrity, and21

- MPSC Staff Witness Wang’s testimony regarding O&M expenses for the22

Picarro Gas Survey Program23

24


M. C. JOHNSONLine U-20642No.

MCJ-2-Rebuttal



A-29 S1 U-20642 STDG-1.05 Pipeline Integrity and MAOP Trans3

Records O&M Supplemental4

A-29 S2 U-20642 Pipeline Integrity 2020 Assessments Cost Estimates5

A-29 S3 U-20642 Pipeline Integrity Project Estimates6

7



10

Damage Prevention Program11

Q6. What does the Attorney General recommend with regard to the Company’s12

Damage Prevention program?13

A6. The Attorney General recommends the removal of $1.5 million of increased14

expense from the projected test year O&M relating to the Company’s proposed15

expansion of the damage prevention program (page 120, lines 1-2).16

17

Q7. Why does the Attorney General recommend the removal of the increased18

O&M expense for damage prevention?19

A7. DTE Gas expanded the damage prevention program in 2019 with the addition of20

staff members and predictive risk ranking software. Based on this success, DTE21

Gas intends to expand further in 2020 with three additional employees. The22

Attorney General states (page 119, lines 9-11) that DTE Gas presented insufficient23

evidence to justify the $1.5 million of increased expense for the expansion of the24

program. Furthermore, the Attorney General believes that any increased O&M25


MCJ-3-Rebuttal

expense will be offset by savings from decreased damage incidents as a result of1

the program (page 119, lines 12-16).2

3

Q8. How do you respond to the assertions of the Attorney General with respect to4

the proposed new damage prevention employees?5

A8.I disagree. DTE Gas believes that the additional $1.5 million of O&M expense is6

needed for the expansion of the damage prevention team. Michigan has one of the7

highest excavation damage rates (damages per 1000 tickets), with an average rate of8

4.9 compared to a national average of 2.7 (2018 Annual Distribution Report, Form9

PHSMA F7100.1-1). There is a chance for a catastrophic incident with each damage10

incident putting public safety at risk. DTE Gas is committed to reducing this rate to11

increase the safety and reliability of the Company’s system in order to keep our12

customers safe. To accomplish this, additional resources were added to the damage13

prevention team in 2019, with further expansion planned for 2020 and beyond.14

15

The addition of team members and risk-ranking software in 2019 was by all16

accounts successful, reducing DTE’s damage rate by more than 20% versus 2018.17

In fact, the approach taken by the damage prevention team has been considered a18

best practice by the MPSC Gas Operations section and has been benchmarked by19

gas utilities within and outside of Michigan. The expanded team uses the output of20

the risk-ranking software to identify MISS DIG tickets that are at highest risk for a21

damage and/or would pose the highest consequence level if a damage were to occur.22

These employees work in the field with the excavators to identify the risks23

associated with the job, observe the work, and coach to prevent damages. The team24

evaluated over 5000 excavation locations in 2019. They also provide safety25


MCJ-4-Rebuttal

presentations to the excavation crews proactively or in response to damages. They1

patrol the service territory identifying locations where excavation is occurring2

without a MISS DIG ticket or without proper markings, violations of PA 174 that3

continue to be the source of approximately a third of damages. When discovered,4

the damage prevention team members stop this work immediately, educate the5

excavators, and assist them in getting the proper markings to allow the work to6

continue safely. The team shut down or slowed work at just under 1000 sites in7

2019 related to unsafe digging practices.8

9

Based on the success observed in 2019, DTE Gas intends to expand the effort to10

cover additional geographic scope (current efforts are concentrated in Southeast11

Michigan, and the expansion will allow the same efforts in the Greater Michigan12

territory). While DTE Gas expects there to be a decrease in damage incidents as a13

result of the expansion of the program, savings will not offset the incremental O&M14

costs. Based on 2019 results of the damage prevention program, we believe we15

were able to avoid approximately $500,000 of incremental damage costs, although16

some portion of those costs would likely have been recovered from excavator17

billing. While the damage prevention program does yield some likely cost savings,18

it is largely a safety-focused effort; we cannot put a cost to the potential for avoided19

catastrophic incidents and the safety and security of DTE’s customers.20

21

Excavation Damages22

Q9. What does Staff Witness Creisher recommend with respect to excavation23

damages?24


MCJ-5-Rebuttal

A9. Witness Creisher recommends that DTE Gas target a reduction in excavation1

damage O&M expense that should be passed on to customers. Witness Creisher2

states (page 12, lines 15-116) that the Company should target $0.5 million in 20203

and $1.0 million in 2021 of reduced cost that be allocated evenly between O&M4

expenses and capital expenditures. This results in a decrease of $437,500 in O&M5

expense for the projected test year (page 12, lines 21-22).6

7

Q10. How does Witness Creisher propose DTE Gas meet the targets she advocates?8

A10. Witness Creisher believes Staff’s targets can be met through a reduction in the9

number of excavation pipeline damages, an increase in billing and collection for10

third party damages, and recovery of first/second party damages (page 12, lines 9-11

13).12

13

Q11. How do you respond to Staff’s excavation damage proposal?14

A11. We agree with Witness Creisher that billing responsible excavators for excavation15

damages reduces the related costs for these repairs borne by our customers. DTE16

Gas actively pursues the activities suggested by Witness Creisher. This includes17

billing any liable third parties for excavation damages, engaging with a collection18

agency for any unpaid damage billing and working with the MPSC Gas Operations19

team to identify and improve the practices of excavators with frequent damages.20

The collection of third-party payments for damages resulted in $304,000 O&M21

savings for customers in 2019. These collections are already accounted for as22

offsets to our O&M expenses.23

24


MCJ-6-Rebuttal

Maximum Allowable Operating Pressure (MAOP) Distribution records remediation1

and Transmission Fitting Conversions Contingencies2

Q12. What does Staff Witness Creisher recommend with respect to MAOP3

Distribution records and Transmission Fitting Conversions?4

A12. Witness Creisher recommended a disallowance of $650,855 (page 8, lines 14-19)5

of O&M expense for MAOP Distribution records remediation and $73,167 (page6

8, lines 22-23) of O&M expense for Transmission Fitting Conversions related to7

the recovery of contingency.8

9

Q13. Why does Witness Creisher recommend the disallowance of MAOP10

Distribution records remediation and Transmission Fitting Conversions11

contingency?12

A13. Witness Creisher, as supported by Witness Wang, states that contingency is not a13

recoverable item and all costs must be supported by data.14

15

Q14. Why does DTE Gas include contingency expense in its project estimates?16

A14. A project estimate, including contingency expense, added together provides the17

total forecasted expenditure for a particular project. At the time of a project18

estimate, cost categories such as labor, outside services, and materials are often19

estimated and are subject to some amount of variability. Contingency is considered20

an ordinary part of project estimates. DTE Gas budgets for the full amount because21

it intends to spend the entire project estimate including contingency. The22

elimination of contingency would result in an inaccurate and underestimation of23

project costs.24

25


MCJ-7-Rebuttal

Pipeline Integrity1

Q15. What does Staff Witness Miller recommend with respect to pipeline integrity?2

A15. Witness Miller is proposing a downward adjustment of $4.195 million in O&M3

expense from an incremental additional $8.39 million for Pipeline Integrity4

operation and maintenance (page 27, lines 9-11).5

6

Q16. Is the incremental additional $8.39 million expense for Pipeline Integrity7

operation and maintenance accurate?8

A16. After receiving Staff Witness Miller’s recommendation, DTE Gas further reviewed9

its filing regarding pipeline integrity expense and determined that its initial10

incremental additional pipeline integrity expense amount of $8.39 million11

contained an error and should be reduced to an incremental additional $6.4 million.12

The Company confirmed this revision through STDG-1.5 Item 1 supplemental13

(Exhibit A-29 Schedule S1). This discovery response confirms that the level of14

incremental additional operation and maintenance expenses requested by the15

Company is $6.4 million, not the $8.39 million referenced by Witness Miller.16

Therefore, the additional incremental pipeline integrity expense that remains in17

dispute is $2.205 million.18

19

Q17. Why does Witness Miller recommend an adjustment in O&M expense for20

Pipeline Integrity operation and maintenance?21

A17. While Witness Miller is supportive of DTE’s efforts to improve pipeline safety in22

his testimony, but concludes that the Company did not adequately support the23

increased expense with data and that the requested amount. (page 27, lines 2-5).24

Discovery request STG-1.5 requested a spreadsheet on how each expense was25


MCJ-8-Rebuttal

determined. The Company provided a cost breakdown between Labor, Material,1

Contract Services, and Other in STG-1.5. Witness Miller had anticipated a more2

detailed breakdown of costs. (page 26, lines 18-24).3

4

Q18. How would you characterize the Company’s determination of the requested5

incremental additional pipeline integrity expenditure amount?6

A18. It was not arbitrary. The Company approaches cost estimating on a per project basis7

by either using similar prior work to estimate or it develops detailed cost estimates.8

This is the case for all 2021 projects and four of the 2020 projects as noted in9

Exhibit A-29 Exhibit S3. The assessment project costs in 2021 (except for the10

Menominee-Powers Pipeline which is based on assessments of similar pipelines in11

size and length) are based on prior assessment costs incurred since the pipelines to12

be assessed in 2021 have been assessed in the past.13

14

For the 2020 assessment projects, detailed cost estimates were developed to arrive15

at the dollar amounts for each project. Please refer to Exhibit A-29 Schedule S2 for16

these detailed cost estimates and Exhibit A-29 Schedule S3 on how the costs for17

the 2020 and 2021 projects align to the Company’s response to Discovery request18

STG-1.519

20

Q19. So, in light of the foregoing, what is your response to Witness Miller’s21

downward pipeline integrity expense adjustment recommendation?22

A19. DTE Gas does not agree with the conclusions reached by Witness Miller. Although23

Staff was not satisfied with the information the Company provided in discovery,24

the Company in good faith provided responses to the discovery requests based on25


MCJ-9-Rebuttal

what the Company understood was being requested. The Company makes its best1

attempt to be responsive to and transparent with the MPSC and any request they2

submit. Clearly, we misinterpreted Staff’s request and our initial response did not3

provide the detail for which Staff was looking, which we have now provided in4

Exhibit A-29 Schedule S2 and A29 Schedule S3 as mentioned above. The Company5

is increasing its O&M expenses for Pipeline Integrity in response to various6

regulatory drivers as explained in Witness Sandberg’s testimony. In addition, the7

MPSC Staff themselves recognize that the Company is increasing the miles of pipe8

assessable by ILI and therefore increased O&M costs are a reasonable and prudent9

request.10

11

Picarro Gas Survey Program12

Q20. What does Witness Wang recommend with regard to the Picarro Gas Survey13

Program proposed by the Company?14

A20. Witness Wang recommends a disallowance of one-third of the Picarro Gas Survey15

Program (page 25, lines 14-15). This would disallow $1,139,465 of capital16

expenditures in the bridge year and $40,888 of capital expenditures in the test year17

(page 25, lines 15-17).18

19

Q21. Why is Witness Wang recommending the disallowance of one-third of the20

Picarro Gas Survey Program?21

A21. The Company is requesting capital expenditures for three survey vehicles and22

Picarro units for the Picarro Gas Survey Program. Witness Wang asserts that three23

vehicles are not necessary to cover the Southeast Michigan Territory and two24

vehicles would suffice (page 27, lines 6-8). Witness Wang states that two vehicles25


MCJ-10-Rebuttal

would be consistent with the Picarro pilot program at Consumers Energy (page 27,1

lines 8-10).2

3

Q22. How do you respond to the recommendation by Staff Witness Wang?4

A22. I disagree and believe that three vehicles and Picarro units are necessary to5

completely replace the traditional leak survey process.6

7

Q23. What is the basis for your conclusion that three vehicles and Picarro units are8

necessary for the DTE Gas Picarro project?9

A23. The need for three vehicles and Picarro units is based on the size of the Company’s10

service territory, the number of passes through the survey area, and expected11

vehicle down time. Witness Wang’s calculation of 2,080 available work hours12

annually is based on full availability for the entire year, which is not realistic.13

Vehicles and the associated Picarro units will need down time for vehicle/unit14

maintenance, employee time off, and inclement weather.15

16

Q24. How does the DTE Gas Picarro Project differ from the Consumers Picarro17

pilot?18

A24. DTE Gas intends to fully replace traditional leak survey methods with Picarro for19

its entire service territory. The Consumers Picarro pilot is a multi-month trial to20

compare Picarro survey versus traditional methods of leak survey.21

22


A25. Yes it does.24

STATE OF MICHIGAN



)

REBUTTAL TESTIMONY

OF

TAMARA D. JOHNSON

DTE ELECTRIC COMPANYREBUTTAL TESTIMONY OF TAMARA D. JOHNSON

LineNo.

TDJ-2-Rebuttal


employed?2

A1. My name is Tamara D. Johnson. My business address is One Energy Plaza, Detroit,3

Michigan 48226. I am employed by DTE Energy Corporate Services, (LLC).4

5


Company (DTE Gas or Company)?7

A2. Yes.8

9



A3. The purpose of my testimony is to rebut the following:12

Staff’s recommendation to use a three-year average based on the cash basis13

of uncollectible accounts to calculate Uncollectible Accounts Expense14

Staff’s recommendation to reduce projected year uncollectible account15

expense by $648,000 with the implementation of Experian Precise ID16

AG’s recommendation to decrease Uncollectible Expense by $1.2 million17

Staff’s recommendation to reject the expansion of RIA enrollments from18

55,000 to 70,00019

Staff’s recommendation to reject the expansion of LIA enrollments from20

33,000 to 45,00021

22

23

24

25

T. D. JOHNSONLine U-20642No.

TDJ-3-Rebuttal


A4. Yes. In addition to the exhibits sponsored in my direct testimony I am also2

sponsoring the following exhibits:3


A-32 V1 U-20642 MST-1.7 response5

A-32 V2 2018 U-18999 Gas Rate Case Order (pg. 108-109)6

A-32 V3 DOL March 2020 News Release7

A-32 V4 Gas Sales UCX UETM8

9

Uncollectible Accounts Expense10

Cash Basis Methodology11

Q5. Does the Company agree with the methodology presented by Staff Ruekert on12

Page 6 of his testimony for the calculation of Uncollectible Expense?13

A5. No, the Company disagrees with the cash basis accounting presented by Staff14

Witness Ruekert. As Witness Uzenski states Question 13, line 10 of her rebuttal15

testimony, the cash basis method for estimating uncollectible expense is16

inconsistent with how expense is recorded and with how other costs and revenues17

are calculated for both MPSC reporting and for rate-making. The Company18

determines uncollectible accounts expense based on an accrual method as required19

by the Uniform System of Accounts (USofA), General Instruction number 11.20

Rates are set to cover the Company’s expenses expected to be recorded for21

accounting purposes. The estimation of future expenses should therefore be22

consistent with the practice used to record the actual expenses to ensure recovery23

of the Company’s prudent and reasonable costs. An average of the amounts24

charged to account 904 provides such consistency. The use of a three-year25


TDJ-4-Rebuttal

historical average of uncollectible expense is consistent with, and was the approach1

approved by the Commission in recent DTE cases (DTE Electric rate cases U-2

18255 and U-18014, and DTE Gas rate cases U-18999 and U-17999).3

4

Staff’s recommendation that the Company use cash basis accounting of gross write5

offs less recoveries to gas service revenue fails to consider that there is a significant6

timing lag between revenue recognition and when the net write-offs occur. Witness7

Uzenski’s rebuttal testimony provides additional detailed analysis supporting the8

use of the 3-year average when calculating the Uncollectible Expense.9

10

Non Energy Write-Offs11

Q6. Why is the Company rejecting the adjustment made by Staff Witness12

Rueckert in Exhibit S-15.1 Page 1 of their testimony to exclude “Non Energy13

Write-Offs”?14

A6. In an audit request, Staff requested information on “Non Energy Write-Offs”15

(Exhibit SMR-2.2a) and asked us to compare that to revenue in column (g) “Total16

Gas Services Revenue” of the Company’s 2018 Natural Gas Utility Company17

Annual Report Form P-522 (“2018 Form P-522”), filed with the Commission.1 . To18

meet Staff’s request, we had to exclude any write-offs that were unrelated to this19

revenue (which would exclude Choice, EUT HPP). When Staff submitted its20

uncollectible expense calculation based on the information we provided, Staff21

changed its revenue view and included line 17 from the 2018 Form P-522, which22

1 The Company’s 2018 Natural Gas Utility Company Annual Report Form P-522 ispublicly available on the Commission’s web site at:https://www.michigan.gov/mpsc/0,9535,7-395-93308_93325_93422_94200_94201_94316---,00.html.


TDJ-5-Rebuttal

would include the revenue associated with the write-offs Staff was trying to1

exclude. Staff either needs to exclude the write-off adjustment or adjust the revenue2

back to its original request to make sure write-offs and revenue are considered on3

a apples to apples basis.4

5

Therefore, the write-offs used in Staff’s calculation do not correspond to the6

revenue being used in the calculation and the adjustment should be removed for7

Non Energy Write-Offs. See Company adjustment to Staff proposed Uncollectibles8

on Witness Uzenski’s Exhibit A-30, Schedule W3, column (c), which adds back9

Non-Energy Write-Offs that were removed by Staff.10

11

Staff’s cash basis methodology should also include direct charges to expense (201812

Form P-522, Pg. 228A, Line 11) as these ongoing charges are driven by Low13

Income Self Sufficiency Plan (LSP) enrollments. This expense can be driven by14

MEAP funding shortfalls for the customers enrolled on LSP or customers on LSP15

who’s usage has exceeded designated caps and require additional assistance. When16

MEAP funding is exhausted, the Company addresses the shortage with direct17

expense. See Company adjustment to Staff proposed Uncollectibles on Witness18

Uzenski’s Exhibit A-30, Schedule W3, column (e), which includes the 3-year19

average of direct charges for 2016-18:20

Direct Charges – Three Year Average ($000)21

2016 $1,71522

2017 $41623

2018 $92324

Three Year Average $1,01825


TDJ-6-Rebuttal

1

Experian Precise ID2

Q7. Staff Witness Theresa McMillan-Sepkoski recommends on Page 31, Line 9-143

of her testimony that anticipated savings from the use of the new Experian4

Precise ID product should be reflected in the projected test year Uncollectible5

Account Expense. Do you agree with Staff’s adjustment reducing Uncollectible6

Account Expense by $648,000?7

A7. No, I do not agree with Staff’s adjustment. Staff assumes that the estimated $1.88

million savings in arrears has already been proven and realized. The Company was9

clear in stating there is an expectation of savings and lowering of uncollectibles10

with the implementation of Precise ID (U-20642 TMS-14.15a). It is improper to11

impute savings to uncollectibles at this time based upon the estimate as it is yet12

uncertain. Any realized uncollectible reduction because of implementation of the13

Experian product will be reflected in the historical uncollectible expense of any14

future case. See Company adjustment to Staff proposed Uncollectibles on Witness15

Uzenski’s Exhibit A-30, Schedule W3, column (f), which removes Staff’s16

adjustment for Precise ID Impact.17

18

Attorney General19

Q8. Does the Company agree with the Attorney General Witness Coppola’s20

adjustment at page 115, lines 6-7 of his testimony of $1.2 million to the21

Uncollectible Accounts Expense for the projected test period?22

A8. Mr. Coppola cites to Exhibit AG-46 – AGDG-1.141c in stating that “uncollectible23

costs were avoided in 2016 when customers with bills in arrears used credit cards24

to pay their outstanding bill. The amount of the avoided cost was $2.3 million in25


TDJ-7-Rebuttal

2019.” The Company presumes Mr. Coppola meant 2019, not 2016. Mr. Coppola’s1

subsequent analysis, found on pages 115-116 of his direct testimony, in which he2

projects $1.2 million in savings in the test year due to credit card usage based upon3

expected increases in merchant fees for residential customers, is flawed on two4

points.5

First, though a customer may have paid a final account by credit or debit card, this6

fact does not indicate that the customer would not have paid by another method if7

credit/debit card payment was not available. The analysis included in the8

Company’s discovery response was a snapshot of a small subset of customers’9

payment behavior for 2019 (Exhibit AG-46 AGDG-2.141c). This is a lagging10

indicator, not a leading indicator; we cannot predict that these customers will11

behave the same way in a future period. Second, a correlation cannot be drawn12

between customers who decide to change their payment methods by paying by13

credit card on a final account and the increase of merchant fees in the projected test14

year. Merchant fees have to do with costs associated with using a credit card billed15

by the credit card company as a percentage of the total amount charged. The16

Company predicts these fees based upon a three-year compound average growth17

rate, as explained by witness Campbell at page 13, line 11-16. The number of18

customers using a credit card to pay a final account is thus not determinative of the19

amount of merchant fees.20

21

Q9. Other than your specific responses to Staff regarding credit/debit card usage22

discussed above, are there any other factors the MPSC Staff or the Attorney23

General may not have taken into consideration in their testimony that the24


TDJ-8-Rebuttal

Commission should consider to not reduce uncollectible expense as the Staff1

and Attorney General suggest?2

A9. Yes. DTE Gas expects numerous customers will experience some form of3

economic hardship from job loss, reduced work hours, and unpaid sick time due to4

business closures resulting from emergency public health and safety measures5

ordered by federal, state and local governments in response to the 2020 pandemic.6

Customers may also experience increased medical costs. These circumstances are7

likely to meaningfully increase DTE Gas uncollectible expense beyond the three-8

year average the Company is proposing to include as a basis for rate making. Over9

500,000 customers in our service territory are classified as low income. In addition,10

we also have a significant number of customers classified as working poor. These11

populations of customers consistently struggle making timely payments, even in12

the best of times. The current pandemic, and resulting job losses, creates added13

pressures as their resources will decline. Customers with otherwise strong payment14

histories experiencing job elimination or reduced hours will also find it difficult to15

pay their bills. The U.S. Department of Labor recently published data showing the16

following significant steep upward trend, of 5,909% from March 14 to April 4, in17

initial unemployment claims filed in Michigan, the largest weekly spikes ever18

experienced in Michigan:19


TDJ-9-Rebuttal

1

Exhibit A-32.2- U.S. Depart. Of Labor Unemployment Insurance Weekly Claims.]2

3

In addition, we anticipate that small and medium sized businesses, as they are4

required to shutter their doors, will also experience additional hardship.5

Approximately 20% of these Gas customers are currently past due with ~$15M and6

we expect this to grow exponentially.7

8

During the 2008 recession, the Company experienced a 72% increase in9

uncollectibles from 2007 (DTE Gas increased from $70 million in 2007 to $12610

million in 2008) and it took two years to recover to pre-recession levels. This11

increase happened without a moratorium on service shut-offs. As the Commission12

is aware, the Company has already implemented a suspension on service shutoffs13

for all residential customers and an expansion of the winter protection program for14

senior customers. These actions, while necessary to protect the health and safety15

of our customers, is nevertheless expected to exacerbate the level of uncollectibles16

expense. Using the increased uncollectible expenses we experienced during the17

2008 recession as a basis for what we can expect our uncollectible expenses to grow18

0

100000

200000

300000

400000

500000

5-Mar 10-Mar 15-Mar 20-Mar 25-Mar 30-Mar 4-Apr 9-Apr

Unemployment Weekly Claims


TDJ-10-Rebuttal

to in 2020 and 2021 Exhibit 32-V4 Gas Sales UCX UETM, this overall 72%1

increase would grow DTE’s 2019 actual uncollectible expense from $38 million to2

almost $65 million; and as previously mentioned, this does not take into account3

the moratorium on service shut-offs the Company has implemented. Given the4

likelihood that uncollectible expense will be higher than forecasted in the test year,5

the Commission should not decrease uncollectible expense as Staff suggests.6

7

Q10. Are there any solutions that would address both the Staff’s concerns and your8

concerns?9

A10. Yes. Company Witness Telang, in his rebuttal testimony at Question 9, Line 10-1910

page (RMT-6 Rebuttal Telang) proposes a symmetrical uncollectible expense true-11

up mechanism (“UETM”), similar to what was done in response to the 200812

recession and the expected significant increase expected in uncollectible expense.13

14

Low Income Credits15

Q11. What is the goal of providing credits to low income customers?16

A11. As stated in my direct testimony (TDJ-6 Line 21), despite improvements in17

Michigan’s economy, many low-income gas customers in our service territory18

continue to struggle with paying their utility bill. Distribution of low-income credits19

such as Residential Income Assistance (RIA) and the Low Income Assistance Pilot20

(LIA) help alleviate the customer’s energy burden. These credits assist our most21

vulnerable customers, those customers at or below 150% Federal Poverty Level22

(FPL). The low-income credits are utilized to assist customers with arrears and23

who are vulnerable to interruption of services.24

25


TDJ-11-Rebuttal

It is important that our most vulnerable customers not experience interruption of1

their services. Disconnection rates for customers who are enrolled in the LSP2

program when paired with a LIA credit experience a 1.5% disconnect rate,3

compared to a disconnect rate of 16% for those receiving LIA alone.4

5

Q12. Does the Company agree with Staff Madison Todd, (Pg. 93 line 21-23) position6

that the enrollment for the RIA credit should remain at 55,000?7

A12. No, I do not agree with Staff Witness Madison Todd’s position on RIA enrollment8

numbers as stated on Page 93, Line 21-23 of her testimony. Utilizing Staff’s Exhibit9

S-8.2, both the 3-year (61,945) and 5-year (74,691) average enrollments exceed the10

current 55,000 enrollment allowance. The Company’s reduced enrollment average11

(42,723) for 2018 reflects a system defect of the C360 billing system that prevented12

automated enrollment. Excluding the 2018 enrollment numbers, the actual average13

enrollment for RIA would be even greater (3-year 88,678 and 4-year 82,683). As14

for Staff’s assertion that RIA enrollments have been on a steady decline, the15

greatest decline from 2016 to 2017 can be attributed to the development of the LIA16

credit and customers moving from RIA to LIA. There are enough eligible customers17

to justify the increase from 55,000 to 70,000 as the 2019 enrollment numbers18

indicate. At the end of 2019, DTE had 79,910 and a monthly average of 72,10319

customers receiving an RIA credit.20

21

Additionally, I expect that as the economic impact of the 2020 Pandemic health22

crisis begins to surface, more customers will seek state and federal assistance,23

which will result in increased RIA enrollment, likely beyond DTE Gas’s projection24

and even the highest multi-year averages.25


TDJ-12-Rebuttal

1

Q13. If credits are under-utilized, as Staff witness Madison Todd projects, what2

does the Company propose?3

A13. Consistent with other utilities, in this case the Company has requested a low-income4

tracker as stated in Witness Uzenski’s testimony at Page 36, Line 19-24. This will5

allow unused credits to roll over into the next fiscal year for distribution to6

customers and ensure that all credits are appropriately distributed to the customers7

they are intended to protect. Staff continues to state the Company’s sole purpose of8

the low-income credits is for financial gain, yet approval for this tracker which will9

roll over any unused credits would demonstrate otherwise.10

11

Q14. MPSC Staff Witness Madison Todd asserts on Page 93, Line 18 of her direct12

testimony that RIA enrollments are outside of the Company’s control as13

customers must request the credit or be referred from a qualifying agency. Is14

this accurate?15

A14. No, it is not. Customers who receive state and federal energy assistance are16

automatically enrolled to receive the RIA credit. Additional customers are enrolled17

on request. Audits are conducted to ensure that those customers who identify at the18

required less than or equal to 150% FPL receive the credit. Changes in how the19

state allocates such energy assistance could also impact auto enrollment.20

21

Q15. What was the Company’s response to Staff’s question about variances in22

customer counts for the RIA credit?23

A15. As stated in the Company’s response to Staff’s audit request, attached as Exhibit24

A-32. V1 U-20642 MST-1.7 Response:25


TDJ-13-Rebuttal

In the instance of U-17999 the monthly counts were rounded whereas1the counts in U-18999 were actual. However, there is a discrepancy in2the 2013 month to month comparison. Unfortunately, the logic cannot3be provided to explain the variance due to the updated billing system in42017. As for what was submitted in Part III subsection 5, question 9,5that view is from a financial report that includes accounting practices6including corrections from month to month which do not align with the7customer counts at the Customer Service business unit reporting. Going8forward the Company will take internal steps to reconcile the two system9modules (customer relationship management and financials) with the10customer counts and financial reporting.11

12

Q16. Do you agree with Staff witness Madison Todd position that ratepayers are13

ultimately subsidizing the LSP program?14

A16. No, I do not. LSP is the most successful Affordable Payment Plan (APP) available15

to our low-income customers. Low income customers can experience an affordable16

monthly payment plan amount while reducing any arrears over the course of the17

program. Pairing the LIA credit with the LSP program allows the expansion of the18

LSP program where it may otherwise be limited by financial constraints. Staff19

witness Madison Todd’s position, at page 88, line 6 of her direct testimony that20

ratepayers are ultimately subsidizing the LSP program is flawed. The LIA credit is21

going to eligible customers whether LSP or Non-LSP. The fact that we can reach22

more customers with the LSP program when a low-income customer is receiving23

the LIA credit is a benefit, not an additional burden on ratepayers as Staff suggests.24

Where it becomes a burden is when customers who need more support than just the25

LIA credit fall into disconnect and final account status. These become uncollectible26

expenses that get passed to customers in rates.27

28

Exhibit A-32 V2 2018 U-18999 Order (pg. 108-109) supports pairing LIA with29

LSP, as the program demonstrated progress in avoiding disconnection, reduced30


TDJ-14-Rebuttal

energy consumption and comprehensive support that helps eligible customers1

afford their utility. Most of the gas LIA credits are received by Non-LSP2

customers. It is only the electric LIA credit that is automatically applied when a3

customer enrolls in the LSP program. The gas LIA credits are manually applied4

during the LSP enrollment due to the current number of enrollments available.5

Expansion of enrollments will allow a seamless pairing with LSP.6

7

Q17. Do customers enrolled in LSP and receiving the LIA credit lose their LIA8

credit when they are no longer in the LSP program?9

A17. No, customers eligible to receive the LIA credit continue to do so even when no10

longer enrolled in LSP. The Company recognizes the importance of continued11

support for customers when they graduate or default from the LSP program.12

13



16

STATE OF MICHIGAN



)

REBUTTAL TESTIMONY

OF

ROBERT J. LEE

DTE GAS COMPANYREBUTTAL TESTIMONY OF ROBERT J. LEE

LineNo.

RJL-1-Rebuttal


employed?2

A1. My name is Robert J. Lee and my business address is One Energy Plaza, Detroit,3

Michigan 48226-1279. I am employed by DTE Energy Corporate Services, LLC4

as Manager of Environmental Management and Resources for DTE Gas Company5

(DTE Gas or Company) and I am responsible for managing the remediation6

program for the Company.7

8


Company?10

A2. Yes.11

12



A3. The purpose of my testimony is to rebut and clarify the following:15

Rebut and clarify DTE’s position regarding Staff’s recommendation that16

incurred costs should not be recovered through the Commission’s stated policy17

regarding recovery of MGP expense for the following Company properties: (i)18

properties that are not designated as a Facility, as defined in the Natural19

Resources and Environmental Protection Act (NREPA), Act 451 of 1994,20

Environmental Remediation, MCL §324.20101 et seq. (Part 201); (ii) properties21

that have already received an approved Remedial Action Plan (RAP) or No22

Further Action (NFA), in part or sitewide; or (iii) properties that DTE Gas23

considers closed.24

R. J. LEELine U-20642No.

RJL-2-Rebuttal

Clarify DTE’s position regarding Staff’s recommendation that the company1

recover the non-incremental recurring costs for routine monitoring and2

reporting and other operations and maintenance activities, in operations and3

maintenance (O&M) expenses, rather than by a deferral and amortization4

method more appropriate for extraordinary incremental expenses.5

6


A4. No.8

9

Q5. Do you agree with the Staff’s recommendation to recover the non-incremental10

recurring costs for routine monitoring and reporting and other operations and11

maintenance activities in operations and maintenance (O&M) expenses12

beginning August 2019?13

A5. While the Company does not object to this recommendation, the Company would14

need approximately $314,000 per year beginning August 2019 in O&M to cover15

these expenses. These O&M expenses are presented in the following table.16


RJL-3-Rebuttal

Expected Annual Recurring O&M Costs1

Project Annual Recurring TasksExpected

Annual Cost

Broadway

- Cap inspections and maintenance

$25,000-Annual groundwater monitoring

Muskegon

-Operation and maintenance of dual recovery wellgroundwater hydraulic control system

$274,000-Monitoring, reporting and site inspections (including financialassurance and wastewater discharge expenses for waterdisposal to the Muskegon County wastewater system)

WealthyMGP and

Annex

-Semiannual surface cover inspection and maintenance tomitigate exposure to subsurface soil impacts

$5,000

-Groundwater sampling at one well until concentrations arebelow the generic residential cleanup criteria

-Annual Report consisting of documenting surface coverinspections and groundwater sampling results is sent toEGLE annually

Greenville-Potential periodic cap maintenance required as identified infuture annual inspections $10,000

Total= $314,000

2

Q6. Do you agree with the Staff’s recommendation regarding the treatment of3

costs incurred for environmental investigation and remediation at the4

Company’s properties that: (i) are not designated as a Facility under Part 201;5

(ii) that have received an approved Remedial Action Plan (RAP) or No Further6

Action (NFA), in part or site wide; or (iii) that is considered closed by the7

Company?8

9

A6. While the Company understands the intent of the Staff’s recommendation, the10

Company objects, in part, to the Staff’s recommendation regarding the treatment of11

future costs for properties not designated as a Facility under Part 201, properties12

that have received an EGLE approved RAP or NFA, in part or site wide, or13


RJL-4-Rebuttal

properties that are considered closed by the Company. The Company agrees with1

Staff’s position that costs should not be incurred at sites that are not a Facility under2

Part 201. However, the Company disagrees with Staff’s position that a Facility that3

has received EGLE approval of a RAP or NFA, in whole or in part (informally4

considered “closed”) may not receive future recovery through the Commission’s5

stated policy regarding recovery of MGP expenses.6

7

To clarify, the Company does not object to Staff’s position that certain ongoing8

expenses be treated as O&M, as discussed in Question 5 above, subject to treatment9

of certain expenses as O&M in determining base rates. The Company does object10

to the concept that a Facility that has received EGLE approval of a RAP or NFA,11

in whole or in part, may not recover future expenses through the Commission’s12

stated policy regarding recovery of MGP expenses. While the Company has greatly13

reduced the overall future environmental risk by obtaining EGLE approved RAPs14

and NFAs, receiving such an approval is not a guarantee that future non-15

incremental spend may be necessary. Specifically, the determination by EGLE that16

No Further Action is required at a Facility is specific to the known conditions at the17

Facility that were addressed as part of the remedial actions. Conditions unknown18

to the Company or EGLE, future identification of currently unknown contaminants,19

or future changes to applicable Part 201 cleanup criteria, could require additional20

non-incremental spend that would be best accounted for through the Commission’s21

stated policy regarding recovery of MGP expenses.22

23


A7. Yes, it does.25

STATE OF MICHIGAN



)

REBUTTAL TESTIMONY

OF

SHOSHANNAH M. LENSKI

DTE GAS COMPANYREBUTTAL TESTIMONY OF SHOSHANNAH M. LENSKI

LineNo.

SML-1-Rebuttal


employed?2

A1. My name is Shoshannah M. Lenski. My business address is One Energy Plaza,3

Detroit, Michigan 48226. I am employed by DTE Gas Company as the Director of4

Productivity and Work Standards.5

6


Company?8

A2. Yes.9

10



A3. My testimony will rebut Staff Witness Joy Wang’s proposed $2.7 million13

disallowance related to meter purchases and her recommendation regarding14

Advanced Metering Infrastructure (AMI) benefits reporting.15

16


A4. No.18

19

Staff Disallowance of Meter Purchases20

Q5. Why does Witness Wang propose a $2.7 million disallowance to meter21

purchases costs?22

A5. Witness Wang explains on page 6 of her testimony that she is proposing this23

disallowance because she believes that DTE Gas will not be installing all the meters24

S. M. LENSKILine U-20642No.

SML-2-Rebuttal

it purchases. Also, Witness Wang does not believe the Company should purchase1

more AMI and AMR modules than it anticipates installing.2

3

Q6. Does DTE Gas plan to purchase more meters than it anticipates installing, and4

if so, why?5

A6. Yes. DTE Gas plans to purchase the number of meters required to meet demand6

from installations plus the number required to build up safety stock to protect7

against shortfalls due to demand variability and vendor delivery delays. In recent8

years, DTE Gas has operated with extremely low safety stock volumes, which has9

posed operational challenges. In some instances, we have run out of meters and/or10

modules when vendors have been delayed in shipping. In total, our proposed11

purchases will ensure availability of meters and modules to meet company and12

customer needs at all times.13

14

Q7. How many meters does DTE Gas estimate it will need for the purposes of15

installation and safety stock?16

A7. In the bridge period, DTE Gas anticipates needing approximately 61,000 meters for17

installations, and 13,000 meters for safety stock. In the test period, DTE Gas18

anticipates needing approximately 42,000 meters for installation and an additional19

5,000 meters to build up its safety stock. In total, over these two periods, 85% of20

meter purchases are intended for installation and 15% to build up safety stock.21

22

Q8. Do you agree with Staff's recommendation regarding meter purchases?23

24


SML-3-Rebuttal

A8. No, we do not agree with this recommendation. The disallowance of $2.7 million1

in meter and module purchases, as proposed by Staff, may result in insufficient2

supply of meters and modules to cover all needs through the end of the projected3

test year ending September 30, 2021. We believe that Witness Wang’s disallowance4

calculation may have excluded a number of instances in which DTE Gas installs a5

new meter and module. For example, in addition to the AMI project and growth, as6

Witness Wang identified, DTE Gas also requires meters and modules for intest7

sampling and remediation, customer-requested meter changes, meter move out with8

meter changes, and other meter issues that result in a meter change. The table below9

summarizes the specific meter installation and safety stock needs that inform our10

request.11

12

Q9. Do you agree with the Staff recommendations regarding meter benefit13

reporting as seen in Exhibit A-21, Schedule K1?14

A9. No. On page 16 of Staff Witness Wang’s direct testimony, she recommends “…the15

Company provide the forecasted benefits for past years, as well as future16

projections, to allow a comparison of forecasted benefits with actual realized17


SML-4-Rebuttal

benefits. This data should be collected for the life of the AMI module installations1

to provide “important evidence on the record regarding the ongoing and long-term2

benefits of AMI” (MPSC Case No. U-18255, 4/18/2018 Order, p. 84). In prior rate3

cases, the Company provided data to both quantify and provide justification for the4

benefits associated with recovery of the initial cost of the AMI investment. The5

Company and Staff both agree on the numerous benefits of AMI. However, the6

amount of data being requested by Staff would require a full-time employee to build7

a model, mine the data, and continue to report on the data going forward. The8

Company believes that given the effort involved to produce the data, with no real9

benefit to show to customers or DTE, this expense would not be reasonable or10

prudent. AMI will continue to be used indefinitely into the future and the Company11

is actively seeking new ways in which to leverage its investment. If more “real-12

time” information is needed by the Staff than is provided in the annual Smart Grid13

report filed each February in Case No. U-17999, the Company is open to meeting14

with Staff and other parties to share its current learnings, operational improvements,15

and future plans.16

17

Q10. Does this complete your rebuttal testimony?18


STATE OF MICHIGAN



)

REBUTTAL TESTIMONY

OF

HABEEB J. MAROUN

DTE GAS COMPANYREBUTTAL TESTIMONY OF HABEEB J. MAROUN

LineNo.

HJM-1-Rebuttal


employed?2

My name is Habeeb J. Maroun. My business address is One Energy Plaza, Detroit,3

Michigan, 48226. I am employed by DTE Energy Corporate Services, LLC (DTE4

Energy or DTE) as a Principal Financial Analyst in the Revenue Requirements5

Department of the Regulatory Affairs Organization.6

7


Company?9

Yes, I did.10

11



The purpose of my testimony is to rebut the following party positions:14

The Attorney General (AG) Witness Mr. Coppola’s position that current15

monthly customer charges for Rate Schedules A, 2A and GS-1 should be16

maintained, or increased no more than $117

Michigan Power LP / Verso Corporation (MPLP/Verso) Witness Mr. Phillips’18

proposal to change the method for allocating costs on Average and Peak (A&P)19

to just Peak Day or 75/2520

The Association of Businesses Advocating Tariff Equity (ABATE) Witness21

Mr. Pollock’s proposal to change the method of allocating costs on A&P to22

Customer and Peak or just Peak Day as well as addressing various issues in23

ABATE’s testimony24

H. J. MAROUNLine U-20642No.

HJM-2-Rebuttal

Correction to the discount allocator sponsored by MPSC Staff Witness Mr.1

Krause2

3

Q4. Are you sponsoring any exhibits associated with your rebuttal testimony?4

No. I am not sponsoring any rebuttal exhibits.5

6

AG’s Recommendation for Monthly Customer Charges7

Q5. What is AG Witness Coppola’s position regarding DTE’s proposed monthly8

customer charges for Rates A, 2A, and GS-1?9

AG Witness Coppola, on page 134 of his direct testimony, recommends that “[T]he10

Commission maintain the current [Rate A and 2A] rate of $11.25…However, if the11

Commission sees some merit in increasing the monthly service charge, in the12

interest of rate gradualism, I recommend that the Commission not increase the13

monthly charge by more than $1, to $12.25. Similarly, for the GS-1 rate, the14

Commission should limit the increase to no more than $1 and preferably keep it at15

the current level of $31.00.”16

17

Q6. How do you respond to Witness Coppola’s position on monthly customer18

charges?19

I disagree. AG Witness Coppola provided no cost-based calculations supporting20

his proposed recommendations. Therefore, because his proposal is not based on any21

actual cost-based calculation, it clearly does not follow the Commission’s long-22

standing approved methodology for calculating monthly customer charges.23

24


HJM-3-Rebuttal

Q7. What methodology has the Commission previously established regarding1

customer charges?2

The Commission previously provided guidance regarding the calculation of3

customer charges in MPSC Case Nos. U-4771 and U-4331 in which it stated:4

Specific distribution plant such as meters and service drops used5exclusively for a given customer shall be treated as customer related. All6other distribution plant shall be treated as demand related. (MPSC Case7No. U-4771, Order, Attachment A, Part One, p 2, May 10, 1976).8

The maximum allowable service charge would be limited to those costs9associated directly with supplying service to a customer. Only costs10associated with metering, the service lateral, and customer billing are11includable since these are costs that are directly incurred as a result of a12customer’s connection to the gas system. [MPSC Case No. U-4331,13Order, p. 30, January 18, 1974; 3 TR 1251.]14

15

The guidance in Case Nos. U-4771 and U-4331 was reconfirmed by the16

Commission in its final order in Case No. U-17999 and used to design current17

customer charges approved by the Commission in Case No. U-18999.18

19

Q8. Is the proposed methodology employed by DTE consistent with accepted20

regulatory practice?21

Yes. The NARUC Gas Rate Design Manual (June 1989) states on page 12 that “the22

basis for the customer charge is that there are certain fixed costs that each customer23

should bear whether any gas is used at all. Examples of such costs are those24

associated with a service line, a regulator and a meter, recurring meter reading25

expenses and administrative costs of servicing the account.” DTE’s methodology26

for calculating monthly customer charges for Rates A, 2A, and GS-1 is consistent27

with these guidelines.28

29


HJM-4-Rebuttal

Average & Peak Allocation Method1

Q9. What does MPLP / Verso Witness Phillips propose regarding DTE Gas’ use2

of the A&P allocation method in its Class Cost of service (CCOS) study?3

On page 3 of his direct testimony, MPLP/Verso Witness Phillips states “I4

recommend that a peak day demand allocation method be used in place of DTE’s5

proposed demand and throughput.” He further recommends at page 3, that as an6

alternative solution, the “75/25” method, which allocates fixed costs, 75% on7

demand and 25% on average energy “is a far superior and more equitable form of8

cost allocation than DTE's current A&P method.”9

10

Q10. Do any other intervenors propose replacing the A&P allocation method?11

Yes, ABATE Witness Pollock proposes reclassifying distribution mains as a12

customer- and demand-related cost as stated on page 34 of his testimony,13

advocating to:14

Classify 40% of all distribution mains as a customer-related cost or,15alternatively, allocate distribution mains entirely on peak day design.16

17

Q11. How do you respond to the allocation proposals made by either MPLP/Verso18

Witness Phillips or ABATE Witness Pollock?19

I disagree. The Commission has consistently approved the use of the A&P method20

since December 1988 in DTE Gas’s general rate case U-8812.21

22

ABATE’s Class Cost of Service Study23

Q12. Can you describe the other topics you will be addressing in ABATE Witness24

Pollock’s testimony?25


HJM-5-Rebuttal

I will be addressing the following topics: (1) Witness Pollock’s use of inconsistent1

XXLT peak design day values in Table 1 and Exhibit AB-14; (2) ABATE’s2

incorrect claim that DTE “double-counts” facilities costs for transmission-serviced3

customers; and (3) ABATE’s proposal for a specific credit for transmission-4

serviced customers.5

6

Q13. ABATE Witness Pollock attempts to adjust the A&P allocator so that no7

distribution-related costs are allocated to customers served from transmission.8

What are your observations regarding Witness Pollock’s efforts to adjust the9

A&P allocator?10

ABATE Witness Pollock attempts to adjust the A&P allocator in Exhibit AB-14 by11

removing transmission-serviced customers, but it is not clear that the adjustment is12

made correctly. Specifically, the direct-served transmission Peak Day Demand for13

XXLT, on line 19, Column (2) of Exhibit AB-14 (94.3 MMcf), does not match the14

equivalent number on Table 1 of Witness Pollock’s direct testimony (145.1 MMcf).15

Therefore, it is unclear which transmission Peak Day Demand ABATE is16

supporting and thus none of ABATE’s Peak Day Demand positions should be17

utilized.18

19

Q14. Regarding DTE’s proposed allocation of distribution facilities, ABATE20

Witness Pollock states on page 8 of his direct testimony that “DTE’s CCOS21

double-counts the allocation of these facilities to the direct-served transmission22

customers.” How do you respond?23

Mr. Pollok in incorrect. DTE Gas is not allocating the same costs twice. Rather,24

ABATE Witness Pollock has a fundamental misunderstanding of various FERC25


HJM-6-Rebuttal

Accounts. DTE Gas continues to allocate distribution facilities (FERC Account1

Nos. 374, 375, 377, 378 and 379) and transmission facilities (FERC Account Nos.2

365, 366, 368, and 369) at the rate class level using the same methodology approved3

by the Commission in every DTE Gas rate case since Case No. U-15985. While4

the accounts share similar names, Witness Pollock fails to recognize that5

distribution and transmission facilities are separate and distinct.6

7

Q15. Regarding the allocation of distribution-related costs to transmission-serviced8

customers, ABATE Witness Pollock proposes on page 21 of his direct9

testimony that “the lower cost to provide direct-transmission service should be10

reflected by implementing a specific credit to the Rate LT, Rate XLT, and Rate11

XXLT classes.” How do you respond to this suggestion?12

I disagree with the position and the approach proposed by Mr. Pollock. In general,13

DTE Gas designs rates at the rate class level; the Company does not design different14

rates for individual customers or a subset of customers within a rate class. The15

reason is that while customer classes often share many similar characteristics, no16

two customers will be exactly the same. Not every customer within a class uses17

every facility or benefits from every expense. Because of this, a fundamental18

principle in COSS is that customers within a rate class share cost responsibility.19

20

Correction to Staff’s Calculation of the Discount Allocator21

Q16. Did you review the COS Excel models prepared by MPSC Staff (Staff), which22

were provided along with their direct testimony?23

Yes. I reviewed their COS Excel models and found that the discount allocator24

sponsored by Staff Witness Mr. Krause in Exhibit S-6, Schedule F1.2 p23 was25


HJM-7-Rebuttal

calculated incorrectly. It is important to calculate the discount allocator correctly1

because it is used to allocate the discount to each rate class in proportion to its2

benefit by having the discounted customers remain as DTE Gas customers.3

4

Q17. Why do you believe the discount allocator was calculated incorrectly?5

I identified a number of errors in Staff’s main and alternative COS models provided6

with their direct testimony. I have prepared workpaper “WP HJM-Rebuttal 1”,7

which identifies these errors and corrected values. I will also be providing Staff8

COS models with corrections highlighted in yellow to Staff for review.9

10

Q18. Did you recalculate the discount allocator?11

Yes, I recalculated the discount allocator using Staff’s models and numbers as12

shown in Table 1 below (col. (d) and (e)) but with the errors corrected. I also13

provided Staff’s filed values for comparison (col. (c) and (d)). Prior to the14

Commission’s final order in this rate case, I propose Staff either incorporate my15

corrections into their existing models or use the corrected models.16


HJM-8-Rebuttal

1

Discount Allocator ($000)2

(a) (b) (c) (d) (e)

Staff Filed Corrected

Rate Class Amount % of Total Amount % of Total

GS-1/2 $15,823 17.201% $1,160.8 18.086%

A 40,434 43.955% 3,467.1 54.019%

2A 1,602 1.742% 156.3 2.435%

S 541 0.588% 28.7 0.447%

ST 3,634 3.950% 391.8 6.105%

LT 3,004 3.265% 341.1 5.314%

XLT 3,201 3.480% 285.8 4.453%

XXLT 6,696 7.279% 267.0 4.161%

DIG 15,844 17.224% 163.9 2.554%

Exelon 1,210 1.315% 155.8 2.427%

Total 91,989 100.000% 6,418 100.000%

3


Yes, it does.5

STATE OF MICHIGAN



REBUTTAL TESTIMONY

OF

ALIDA D. SANDBERG

DTE GAS COMPANYREBUTTAL TESTIMONY OF ALIDA D. SANDBERG

No.

ADS-1-Rebuttal


employed?2

A1. My name is Alida D. Sandberg. My business address is One Energy Plaza, Detroit,3

Michigan 48226. I am employed by DTE Gas Company (DTE Gas or Company)4

and hold the position of Director, Gas Integrity and Compliance.5

Q2. Has your work experience changed since your direct testimony filing in 2019?6

A2. Yes. As of December 2019, I have accepted my present position with DTE Gas as7

Director, Gas Integrity and Compliance. Although I have accepted a different8

position within DTE Gas, I am continuing to support DTE Gas Capital9

Expenditures in this proceeding.10

Q3. Did you file direct testimony in this proceeding on behalf of DTE Gas Company11

(DTE Gas or Company)?12

A3. Yes.13

14



A4. The purpose of my rebuttal testimony is to address the following:17

1. Staff and Attorney General’s (AG) proposals to exclude capital expenditures18

classified as “contingency”. I will show that DTE Gas contingency is an19

inherent part of project estimates.20

2. Attorney General’s proposal to exclude capital expenditures for the Gas Quality21

Assurance Program. I will show that DTE Gas Quality Assurance Program22

should be included in rate recovery.23

A. D. SANDBERGLine U-20642No.

ADS-2-Rebuttal

3. Attorney General’s proposal to exclude certain capital expenditures for the Fort1

Street Main Replacement Project. I will show that the expenditures should be2

included in rate recovery.3

4. MPSC Staff’s proposal to exclude certain capital expenditures for meter4

purchases. Witness Lenski will show that the expenditures should be included5

in rate recovery.6

5. Attorney General and Staff proposal to exclude certain capital expenditures for7

Routine Transmission Plant. I will show that the expenditures should be8

included in rate recovery.9

6. Attorney General and MPSC Staff proposal to exclude certain capital10

expenditures for Routine General Plant – Computers and Related Equipment.11

Witness Busby will show that the expenditures should be included in rate12

recovery.13

7. Attorney General’s proposal to exclude certain capital expenditures for the14

NEXUS project. I will show that the expenditures should be included in rate15

recovery.16

8. MPSC Staff proposal to exclude the capital expenditures for the DTE Gas Site17

Security program. I will show that the expenditures should be included in rate18

recovery.19

9. MPSC Staff proposal to exclude certain capital expenditures for the Traverse20

City – Alpena Reinforcement Project (TCARP). I will show that the21

expenditures should be included in rate recovery.22

10. Attorney General and MPSC Staff proposal to exclude certain capital23

expenditures for the Van Born Project. I will show that the expenditures should24

be included in rate recovery.25


ADS-3-Rebuttal

11. Attorney General’s proposal to exclude certain capital expenditures for four1

Pipeline Integrity projects. I will show why the expenditures should be included2

in rate recovery.3

12. Attorney General and MPSC Staff proposed recommendations and general4

concerns for the Pipeline Integrity projects. I will provide response to these5

recommendations and general concerns.6

7




A-23 M1 TCARP Project Capital11

A-23 M2 DTE Gas Site Security – Summary of Project List, Costs,12

and Risk Mitigation - Confidential13

A-23 M3 Revised Exhibit A-12 B5.3 Southfield 24 in Pipe14

Replacement15

A-23 M4 JSG-1 Supplement dated e-mail16

A-23 M5 E-mail providing 2019 updates to exhibits A-12 Schedule17

B5, B5.1 and B5.318

A-23 M6 Routine Transmission Plant Detailed Calculations19

A-23 M7 Menominee-Powers ILI Expansion Cost Estimate -20

Confidential21

A-23 M8 South Grand Rapids ILI Expansion Cost Estimate -22

Confidential23

A-23 M9 Southfield Pipe Replacement Cost Estimate - Confidential24


ADS-4-Rebuttal

A-23 M10 2019 Northeast Belt ILI Expansion Cost Estimate -1

Confidential2

A-23 M11 2020 Northeast Belt ILI Expansion Cost Estimate -3

Confidential4

5



8

Contingency9

Attorney General’s Disallowance10

Q7. What is the AG’s position on capital contingency costs?11

A7. Witness Coppola is recommending the Commission exclude $22.6 million from the12

forecasted capital expenditures in this rate case filing. Witness Coppola states in13

his testimony (page 18, lines 7-8) that it is not fair or reasonable for the Company14

to recover the depreciation expense and the return on the investment on potential15

costs that may not be actually incurred but have been added to rate base.16

17

Q8. Does the Company agree with Witness Coppola’s position?18

A8. No. Including contingency costs in a project estimate is common practice within19

the industry. It is routine practice to include labor, outside services, materials, and20

other potential costs, whether undefined or estimated, when a cost estimate is21

prepared. The project estimate, including contingency, is the forecasted spend for22

the project and the Company has full intention of spending the entire project23

estimate including contingency. For this reason, the Company does not agree with24


ADS-5-Rebuttal

Witness Coppola’s recommendation to disallow $22.6 million in capital1

contingency.2

3

Staff’s 2019 Disallowance4

Q9. What amount of capital contingency disallowance related to 2019 does Staff5

Witness Wang recommend?6

A9. Witness Wang recommends a $3.7 million disallowance.7

8

Q10. What is Witness Wang’s rationale for recommending the 2019 disallowance of9

$3.7 million?10

A10. Witness Wang recommends this disallowance based on her interpretation of the11

Commission’s order in Case No. U-20233, stating in her direct testimony12

“projected bridge year contingency costs, included in the initial filing but which13

later became known costs during the rate case proceedings, are still disallowed”14

(Page 18, lines 13-15).15

16

Q11. What did the Commission rule in that case?17

A11. In Case No. U-20322, the Commission ruled against recovery of Consumers’18

proposed contingency costs stating, “These 2018 contingency costs only became19

“actual” costs on rebuttal (in 2019) and thus could not be properly reviewed by the20

Staff or other parties.”21

22

Q12. Does Witness Wang’s testimony omit critical language provided by the23

Commission in its order in Case No. U-20322?24


ADS-6-Rebuttal

A12. Yes. Witness Wang failed to include or address the Commission’s language stating1

these costs “could not be properly reviewed by the Staff or other parties” in her2

testimony. This language is crucial given the timing differences in data production3

between the Consumers case, U-20322 and DTE Gas case, U-20642.4

5

Q13. What are the important timing differences between Consumers Case No. U-6

20322 and the instant proceeding?7

A13. In Case No. U-20322, Consumers filed direct testimony on November 30, 2018.8

On April 5, 2019, the MPSC Staff and other intervenors filed their testimony.9

Consumers responded to the third parties in rebuttal testimony on April 29, 2019.10

According to the Commission’s order in that case, Consumers did not provide11

updated 2018 actual capital costs until its April 29, 2019 rebuttal filing.12

In contrast, in this case, the Company provided Staff with data regarding 201913

actual capital costs before Staff’s testimony was due and prior to DTE Gas rebuttal14

testimony. Witness Wang’s Exhibit S-17.12 pages 2 and 3, audit response showing15

no contingency for 2019, was provided on February 12, 2020. This is more than16

five weeks prior to Staff’s direct testimony filing date. Exhibit A-23, Schedule M417

includes a copy of the dated email provided to Staff. Additionally, 2019 actual18

capital costs were provided by the Company on February 29, 2020, three weeks19

prior to Staff’s March 24, 2020 direct testimony filing date. Exhibit A-23, Schedule20

M5 includes a copy of the dated e-mail provided to Staff with the attached 201921

actual updated data. Thus, the Staff and other third parties were provided the 201922

actual costs and had the opportunity to perform their review of and ask additional23

audit and discovery questions of those costs prior to filing their direct testimony or24

receiving the Company’s rebuttal testimony for reasonableness and prudency.25


ADS-7-Rebuttal

Therefore, the Commission should include the $3.7 million of costs originally1

identified as contingency, which were actually spent on project costs in rate base in2

this case.3

4

Q14. What other relevant facts should be considered in assessing the5

appropriateness of Witness Wang’s recommendation?6

A14. Witness Wang focuses on a perceived inconsistency between Exhibit A-127

Schedule B5.3 and audit response JHW-1.22a and b. As stated in audit response8

JSG-1.1 Supplemental, 2019 has zero contingency because DTE Gas expected to9

spend the full $514.5 million budget, which included capital contingency of $22.610

million. This fact was later supported in Audit response CLC-15, attachment “U-11

20642 CLC-15 Exhibit A-12 Schedule B5 2019 Actuals.” Line No. 19, Column c12

of this exhibit demonstrates that the Company’s actual 2019 capital spend was13

$524.5 million, or $10 million over the projected capital expenditure. These audit14

responses were provided weeks before the MPSC Staff and other third parties filed15

direct testimony.16

17

DTE Gas Capital Expenditures – 2019 Projected vs 2019 Actuals18

DTE Gas Capital Expenditures($ millions) 2019 Source:

Projected DTE Gas Capital $514.5 Exhibit A-12 Schedule B5.1 Page 1 of 2, Line 24, column (d)

Actual DTE Gas Capital Spend $524.5CLC-15 U-20642 Exhibit A-12 Schedule B5.1 2019 Actuals,Page 1 of 2, Line 24, column (d)

Projected vs Actuals Variance(Under)/Over

$10.0

19

20


ADS-8-Rebuttal

Q15. Should Witness Wang’s recommendation to disallow $3.7 million in 20191

capital contingency costs be accepted?2

A15. No. For the reasons set forth above, along with the facts depicted in the table above3

showing that actual 2019 capital expenditures exceeded filed amounts by $10.04

million, Witness Wang’s recommendation should be rejected in its entirety because5

these costs are no longer projected, but actual.6

7

Staff’s Traverse City-Alpena Reinforcement Project Disallowance8

Q16. What disallowance does Staff Witness Wang recommend related to the9

Traverse City-Alpena Reinforcement Project (TCARP)?10

A16. Witness Wang recommends a disallowance of $6.5 million associated with11

TCARP. She questions the integrity and accuracy of the TCARP contingency12

amount provided by the Company. Specifically, Witness Wang believes the $3.113

million in contingency provided by the Company for the 12 months ending14

September 30, 2021 is unreasonable and seems low. Witness Wang goes on to15

make a decision that the total contingency for 2021 of $8.8 million should be evenly16

spread across 2021. Based on this decision, Witness Wang calculated a17

disallowance of $6.5 million.18

19

Q17. Should Witness Wang’s recommended TCARP disallowance be accepted?20

A17. No. The TCARP contingency in 2021 is budgeted in December outside of the21

projected test year for the purpose of better managing the monthly forecasting, not22

knowing exactly what month the contingency will be needed and utilized. Witness23

Wang’s recommendation to evenly spread TCARP contingency has no relevance24

on how DTE Gas is managing the TCARP project contingency. She provides no25


ADS-9-Rebuttal

facts explaining why an even distribution of contingency is more reasonable other1

than the opinion of “seems low to Staff” (page 20, line 11). As such, this2

recommendation should be rejected by the Commission in its entirety.3

4

Staff’s Bridge and Test Period Disallowances5

Q18. What amount of capital contingency disallowance associated with the bridge6

and test periods does Staff Witness Wang recommend?7

A18. Witness Wang recommends either a $81.3 million or $32.9 million disallowance.8

9

Q19. Are either of these amounts supported by the facts of the case?10

A19. No. The Company’s as-filed capital bridge and test period contingency costs equal11

$22.6 million, and its Test Year contingency costs are $15 million as depicted on12

Exhibit S-17.12, (Audit Response JSG-1.1) page 3. Witness Wang’s two proposed13

disallowance amounts bear no relationship to the facts provided by DTE Gas.14

Rather, her recommended disallowance amounts are based on assumptions15

regarding relationships between past and future contingency and a series of intricate16

calculations. These assumptions and calculations result in a $81.3 million17

contingency amount, over 350 percent greater than DTE Gas’s actual contingency18

of $22.6 million. Witness Wang’s speculative analysis should be granted no19

credence.20

21

Q20. Should Witness Wang’s recommendation to disallow either $81.3 million or22

$32.6 million associated with bridge and test period capital contingency be23

accepted?24


ADS-10-Rebuttal

A20. No. As explained above, Witness Wang’s recommendation to disallow either $81.31

million or $32.6 million should be rejected in its entirety.2

3

Routine Capital Expenditures - Quality Assurance Program (QA)4

Q21. Is there a proposal to disallow capital expenditures for the Quality Assurance5

Program?6

A21. Yes. Witness Coppola is recommending a disallowance of $3.1 million for the7

Quality Assurance Program.8

9

Q22. Why is Witness Coppola recommending disallowance of capital expenditures10

of $3.1 million for the Quality Assurance Program?11

A22. Witness Coppola indicates that the Company has not made a compelling case that12

a QA program is necessary and is proposing a program to perform activities that13

are already being done.14

15

Q23. Does the Company agree with the proposed disallowance of the Quality16

Assurance Program?17

A23. No. I will attempt to clarify why a Quality Assurance is necessary. Upon placing18

a pipeline into service after the completion of construction work at DTE Gas’s19

Milford Compressor Station, a leak occurred that resulted in a gas reportable20

incident. The Company was cited for lack of oversight, which created an21

environment where poor construction practices could exist. DTE Gas22

acknowledged the improvement opportunity and responded by implementing a23

Quality Assurance Program to strengthen pipeline safety during construction24

activities. As a direct result of the above incident, the program’s initial objective25


ADS-11-Rebuttal

has been to ensure best welding and strength testing practices are implemented and1

utilized during construction. DTE Gas hired an external quality assurance firm in2

2019 and will use an external firm in 2020 to provide supplemental oversight while3

the Company builds its Quality Assurance Program internally.4

5

Q24. How is a Quality Assurance Program different than DTE Gas’s current6

company procedures?7

A24. A November 2015 American Gas Association (AGA) Whitepaper on Developing8

and Implementing a Quality Assurance Program for Natural Gas Operations9

stated, “A quality management program is distinct from and addresses more than merely10

inspecting work to ensure compliance with federal and state regulations for pipeline11

safety.” Inspection for conformance to federal and state regulations and better12

training programs for an attriting workforce, as Witness Coppola suggests, would13

not alone have prevented this incident from occurring. A Quality Assurance14

Program is designed to encompass the totality of a process from conception of a15

design to construction, rather than procedure adherence alone.16

17

Q25. Is there industry and/or regulatory support for implementation of a Quality18

Assurance Program?19

A25. Yes. The AGA further stated in its whitepaper that “The need to ensure quality has20

led many natural gas utilities to create quality management programs. Historically,21

’quality management’ has been mostly associated with industries that have22

manufacturing processes. However, over the last decade, many natural gas utilities23

and pipeline operators have placed greater emphasis on pursuing more24

comprehensive and effective quality management programs”. In addition, an25


ADS-12-Rebuttal

August 2011 Federal Register stated that, “PHMSA recognizes that pipeline1

operators strive to achieve quality, but our experience has shown varying degrees2

of success in accomplishing this objective among pipeline operators. PHMSA3

believes that an ordered and structured approach to quality management can help4

pipeline operators achieve a more consistent state of quality and thus improve5

pipeline safety. PHMSA’s pipeline safety regulations do not now address process6

management issues such as Quality Management Systems (QMS)…. PHMSA is7

considering whether and how to impose requirements related to QMS….” DTE8

plans to develop its Quality Assurance Program following ISO (International9

Organization for Standardization) 9001, which is an internationally recognized10

Quality Management System. ISO 9001 has been implemented across many11

industries and provides the structured framework for quality that PHMSA12

references.13

14

Routine Distribution Plant – System Reliability15

Q26. Why is Witness Coppola recommending disallowance of $1.7 million in capital16

expenditures for Fort Street Main Replacement?17

A26. Witness Coppola indicated that because the 2019 actuals for this project came in18

below the projected 2019 spend, the variance should be disallowed.19

20

Q27. Does the Company agree with the proposed disallowance of the Fort Street21

Main Replacement?22

A27. No. Although the 2019 project actual expenditures were accomplished under the23

forecast, total capital expenditures for the Company in 2019 exceeded the forecast24

and are reflected in the revenue requirements of this case. The savings on this25


ADS-13-Rebuttal

project were spent and used to accomplish additional capital work. The 2019 DTE1

Gas Capital Expenditures forecast included in the Company’s direct filing was2

$514.5 million. The 2019 DTE Gas Capital Expenditures actuals are $524.53

million. Therefore, despite the Fort Street Main Replacement 2019 project actuals4

coming in under forecast, the total Company capital expenditures forecast was5

incurred. See table provided above in this rebuttal testimony for evidence of 20196

actual capital expenditures. Furthermore, since only $514.5 million was included7

in rate base for this case, while the company invested $524.5 million, $10.0 million8

is already subject to regulatory lag and will not be included in the Company’s9

revenue requirement until our next rate case filing.10

11

Routine Distribution Plant – Meters12

Q28. Is there a proposal to disallow capital expenditures for meter purchases?13

A28. Yes. MPSC Staff is recommending a disallowance of $2.7 million in Routine14

Distribution Plant – Meters.15

16

Q29. Why is MSPC Staff recommending a disallowance of $2.7 million for meter17

purchases?18

A29. Witness Wang is recommending disallowance due to the projected meter purchases19

are overstated. Witness S. M. Lenski rebuts these disallowances.20

21

Routine Transmission Plant22

Q30. Is there a proposal to disallow capital expenditures for Routine Transmission23

Plant?24


ADS-14-Rebuttal

A30. Yes. MPSC Staff is recommending disallowance of $3.1 million and Attorney1

General is recommending a disallowance of $4.7 million in Routine Transmission2

Plant.3

4

Q31. Why is MPSC Staff recommending a disallowance of $3.1 million capital5

expenditures in Routine Transmission Plant?6

A31. Witness Miller indicates that the amounts reflected in Company Exhibit A-12,7

Schedule B5.1, Page 1, Line 2 for the projected bridge year and projected test year8

are not “consistent with the five-year historical average 2014-2018 capital spend9

level” after the Sales and Use Tax Settlement and River Rouge Insurance Recovery10

proceeds one-time credits are excluded as stated by Witness Sandberg in testimony.11

Rather, there is a 49.21% increase from the 2014-2018 five-year historical average12

to the projected test year.13

14

Q32. Does the Company agree with Staff Witness Miller’s recommended15

disallowance of $3.1 million?16

A32. No. DTE intended to more accurately represent the historical actuals by excluding17

River Rouge insurance recovery proceeds and Sales and Use Tax Settlement one-18

time credits as indicated in Witness Sandberg direct testimony, ADS-19, lines 3-9.19

However, DTE’s rationale for excluding the River Rouge insurance recovery was20

incorrect, because the insurance proceeds nearly offset the expenditures for the21

River Rouge incident, which are also in the historical average. DTE should only22

have excluded the Sales and Use Tax Settlement one-time credits in 2017 and 2018.23

Staff’s comparison using the $6.0 million five-year historical actual average was24

based on Exhibit A-12 Schedule B5.1 Page 1 of 2, Line 2, column b, which25


ADS-15-Rebuttal

incorrectly included both the River Rouge insurance recovery proceeds and Sales1

and Use Tax Settlement one-time credits.2

3

Q33. What historical average should Staff have used in its comparison?4

A33. Staff’s comparison should have used the more appropriate five-year historical5

actual average of $7.4 million provided in Exhibit A-12 Schedule B5.1, page 2 of6

2, Line No. 12, column (b), which only includes the River Rouge Insurance7

Recovery proceeds. In Exhibit A-23, Schedule M6, I have completed calculations8

using Staff’s methodology and the corrected average, $7.4 million five-year9

historical average, to calculate the adjustment based on Staff’s and DTE Gas’s10

Routine Transmission Plant assumptions. Exhibit A-23 Schedule M6, provides11

1) a table detailing the 2014-2018 five-year historical actual average including the12

River Rouge insurance proceeds only and a second calculation including the13

River Rouge insurance proceeds and Sales and Use Tax Settlement one-time14

credits,15

2) a table using Staff’s methodology and the $6.0 million historical average16

resulting in Staff’s recommended $3.1 disallowance and17

3) a table using Staff’s methodology and the corrected five-year historical average18

of $7.4 million. This corrected average results in a variance of $0.7 million.19

20

Q34. What is the Company recommending for the Routine Transmission Plant21

disallowance?22

A34. DTE Gas respectively regrets any confusion, but based on the explanation and23

exhibit provided, contends that the increase in Routine Transmission Plant capital24

expenditures is primarily for the Quality Assurance Program in the 9 months ending25


ADS-16-Rebuttal

September 2020 and the projected test year, which Staff supports, and lowering of1

the Cedar River pipeline in the projected test year due to the pipeline being exposed.2

The Company recommends that the Commission reject Staff’s recommended3

disallowance of $3.1 million.4

5

Q35. Why is Attorney General recommending a disallowance of $4.7 million capital6

expenditures in Routine Transmission Plant?7

A35. Witness Coppola is recommending disallowance of:8

1) $2.1 million capital expenditures for 2019 because the 2019 actual for the9

Routine Transmission Plant came in below the projected 2019 spend and10

2) $1.0 million capital expenditures for the 9 months ending September 2020,11

and $1.6 million capital expenditures for the 12 months ending September12

2021 because “the Company’s forecasted capital expenditures are overly13

inflated and excessive.”14

15

Q36. Does the Company agree with witness Coppola’s proposed disallowance of $2.116

million in Routine Transmission Plant for the year 2019?17

A36. No. Although the Routine Transmission Plant 2019 actual capital spend was under18

the forecast, the capital expenditures for the Company in 2019 exceeded the19

forecast and are reflected in the revenue requirements of this case. The savings in20

Routine Transmission Plant were spent and used to accomplish additional work.21

See table DTE Gas Capital Expenditures – 2019 Projected vs 2019 Actuals above22

in this rebuttal testimony.23

24


ADS-17-Rebuttal

Q37. Does the Company agree with Witness Coppola’s recommended disallowance1

of $2.6 million for 9 months ending 9/30/2020 and 12 months ending 9/30/2021?2

A37. No. Witness Coppola compares normalized capital expenditure for the five years3

from 2015 to 2019 to the projected years as his basis for the $2.6 million4

disallowance. For the same reasons stated above, this comparison does not take5

into account the additional capital expenditures needed in the 9 months ending6

September 2020 and the projected test year to fund the Quality Assurance Program7

and lowering of the Cedar River pipeline in the projected test year due to the8

pipeline being exposed. Therefore, the Company requests the Commission to reject9

the $2.6 million disallowance recommended by witness Coppola.10

11

Routine General Plant – Computers and Related Equipment12

Q38. Is there a proposal to disallow capital expenditures for computers and related13

equipment?14

A38. Yes. Attorney General and MPSC Staff is recommending a disallowance of $13.015

million in Routine General Plant – Computers and Related Equipment. Please refer16

to Witness J. J. Busby rebuttal testimony for response to the recommended17

disallowance from Attorney General and MPSC Staff.18

19

Other Capital Projects – NEXUS20

Q39. Is there a proposal to disallow capital expenditures for the DTE Gas NEXUS21

project?22

A39. Yes. Witness Coppola is recommending disallowance of $10.6 million in capital23

expenditures for the NEXUS project.24

25


ADS-18-Rebuttal

Q40. Why is Witness Coppola recommending disallowance of $10.6 million from the1

NEXUS project?2

A40. Witness Coppola indicates that the $10.6 million increased capital spend due to the3

delay of the NEXUS Pipeline, which is partially owned by an affiliate, is an issue4

between DTE Gas and the NEXUS Pipeline Company.5

6

Q41. Does the Company agree with the proposed disallowance of the NEXUS7

project?8

A41. No. Because the NEXUS Pipeline is partially owned by an affiliate is not relevant.9

If a third-party pipeline were providing this connection to the DTE Gas system, the10

circumstances and result of the delay would have been the same. NEXUS Pipeline11

is a FERC regulated system. Due to a lack of a quorum at FERC in the first 812

months of 2017, NEXUS’ application along with many other pipelines could not13

be approved causing the construction delay. DTE Gas could not place the station14

modifications into service until the NEXUS Pipeline was commissioned in October15

2018. The increased expenditures were prudent based on the timing of the FERC16

certificate. In addition, as discussed in DTE Gas’s last rate case no. U-18999, the17

return of and on the investment in the NEXUS project was more than offset by the18

revenue it generated for the Company, providing revenue credits for our customers19

to the revenue requirement, thereby reducing the rates our customers pay. Even20

with the $10 million additional cost, the revenue related to the NEXUS project21

continues to more than offset the return of and on the total investment in the project22

and continues to provide a benefit to DTE customers through the revenue credits23

that reduces rates our customers pay. Therefore, the incremental NEXUS costs24

should not be disallowed.25


ADS-19-Rebuttal

1

Other Capital Projects – DTE Gas Site Security2

Q42. What DTE Gas Site Security expenditures is MPSC Staff proposing for3

disallowance in this case?4

A42. Witness Miller is recommending disallowance of $9.5 million in capital5

expenditures for the DTE Gas Site Security program.6

7

Q43. Why is Staff recommending a $9.5 million disallowance of capital expenditures8

for DTE Gas Site Security?9

A43. While Staff agrees with the response DTE Gas provided to discovery request10

STDG-6.4B, Witness Miller indicated that “The Company response failed to11

identify the specific risk associated with each identified project” and, therefore,12

recommends disallowing recovery of these expenditures at this time.13

14

Q44. Does the Company agree with the proposed disallowance of the DTE Gas Site15

Security project?16

A44. No. The protection of critical facilities ensures safety of employees and the public,17

reliability of service to customers and avoids financial impact to DTE and its18

customers from a security-related incident. The assets being installed at all stations19

are valid capital investments that are required for DTE Gas to continue to serve its20

customers safely and reliably. DTE regretfully acknowledges that detailed site-21

specific information was not provided in the original response to the discovery22

question. DTE is providing such details in this rebuttal testimony and exhibit for23

reconsideration of the disallowances, as provided in Exhibit A-23 Schedule M224

DTE Gas Site Security – Summary of Security Projects, Costs, and Risk Mitigation.25


ADS-20-Rebuttal

1

Q45. What are the specific risks that the DTE Gas Security Program is attempting2

to mitigate?3

A45. DTE has embarked on a multi-year effort to reinforce its critical stations and4

facilities to protect them from the risk of intentional external and internal threats5

and unintentional events, such as vehicle impacts, intentional software and network6

intrusions in control centers, and unauthorized entrance to facilities. These risk7

mitigation efforts fall into three areas of risk: (i) Physical Security, (ii) Cyber8

Security and (iii) Facility Protection.9

Physical and Cyber Security10

Both physical and cyber security measures implemented or planned at each facility11

are intended to address internal or external threats that may:12

- cause damage to equipment, including by explosion or fire13

- affect reliability of service14

- affect customer and/or public safety15

- harm employees or take hostages16

- cause reputational/financial harm to DTE17

Facility Protection18

Over the last four years, DTE Gas has had six incidents of vehicular hits of gas19

facilities. These include three incidents at Rouge (Melvindale) Station (one in 201620

and two in 2019), one incident at Trenton Channel power plant (2019) and two21

incidents at receipt meter stations (2017). The most impactful incident was the22

Rouge incident in 2016 that resulted in loss of supply to two major industrial23

customers – Marathon Oil and DIG (a power plant). Following the Rouge incident24

in 2016, DTE identified 100 facilities within 100 ft of roads as vulnerable facilities25


ADS-21-Rebuttal

that require protection from vehicular hits and began installing protection at such1

facilities.2

3

Q46. What specific projects were developed/implemented at each facility to address4

the risks and vulnerabilities identified at each facility?5

A46. Physical security projects were developed to address the identified vulnerabilities6

and close the gap from current state to a secured facility that would assure safe and7

reliable supply of gas to customers. These projects include new chain linked fences,8

retrofit of existing fences with barbed wire to raise height to corporate standard of9

7 ft, upgrade of existing egress gates, installation/upgrade of egress gates,10

automation of access gates, installation of cameras/CCTV, installation of intrusion11

detection systems, installation of new/standardized door locks and implementation12

of lock management system for critical buildings and key card access control to13

station control rooms.14

Cyber security projects include operational technology (OT) enhancements such as15

enhanced SCADA back-up, device/network activity monitoring system, enhanced16

log-in system, malicious threat protection and security patching.17

For Facility Protection, projects were developed to install engineered crash rated18

gates and fences, guard rails, concrete barriers and bollards as appropriate to the19

risk exposure at each facility. As a result of the crash rated fence installed at Rouge20

in 2016, the other two incidents at Rouge in 2019 only caused minor damages to21

the fence and did not affect gas piping.22

23

Q47. Should the Commission reject Staff’s recommendation to disallow $9.5 million24

in capital expenditures for the DTE Gas Site Security program?25


ADS-22-Rebuttal

A47. Yes. DTE Gas has provided the additional details requested by Staff and1

respectfully requests recovery of the full amount of the capital expenditures for the2

DTE Gas Site Security program as submitted in Witness Sandberg’s direct3

testimony.4

5

Other Capital Projects – TCARP6

Q48. Is there a proposal to disallow capital expenditures for the TCARP project?7

A48. Yes. Witness Miller is recommending disallowance of $29.6 million for the8

TCARP project.9

10

Q49. Why is witness Miller recommending disallowance of $29.6 million from the11

TCARP project?12

A49. Witness Miller 1) indicates that ACT-9 Filings for the 10” Lincoln-Traverse City13

Pipeline Loop (U-20460) and the 8” Frankfort Pipeline Loop (U-20461) already14

include costs for interconnects and, therefore, should not be included as an15

additional expense in this rate case and 2) construction work that exists beyond the16

projected test year is not suitable for inclusion in this proceeding.17

18

Q50. Does the Company agree with Witness Miller’s recommendation for the19

proposed disallowance of the TCARP project?20

A50. No. 1) The costs for the interconnects with a third party are not included in the21

submitted Act 9 filings. Those costs were planned for a subsequent filing. It22

appears that Witness Miller has incorrectly surmised that when the Act 9 filings23

state “the expansion of existing facilities to provide an interconnection with existing24

DTE Gas pipelines,” the Company is referring to the planned interconnections with25


ADS-23-Rebuttal

DTE Michigan Gathering Holding Company. That is not correct. These Act 91

filings explain the planned connection to the existing DTE Gas system that will2

provide system redundancy (not an alternate supply source). Case U-20460 details3

the connection to the existing 10” Lincoln-Traverse City Pipeline in Paradise4

Township, Grand Traverse County. Case U-20461 describes the connection to the5

existing 8” Frankfort Pipeline in Blair Township, Grand Traverse County. As6

communicated in a presentation to Staff on September 16, 2019, and as filed as7

Exhibit A-12 Schedule B-5.4 in this proceeding, a third Act 9 filing was scheduled8

to be submitted in Q3 of 2020 to complete the scope of the TCARP project, thus9

providing an alternate supply source. Therefore, the combined costs of the two10

submitted Act 9 filings ($64.5 million = $26.8 + $37.7 from the above table and11

Exhibit A-23 Schedule M1 TCARP Project Capital) and the recovery requested in12

this rate case ($83.3 million) will not align.13

It should be noted that since filing of this proceeding, DTE Gas has determined that14

a third Act 9 filing for the remaining scope is not required, rather R502 notifications15

will be submitted to inform Staff of the construction plans for the six16

interconnections with DTE Michigan Gathering Holdings, one new DTE Gas gate17

station near Manistee and modifications to five existing DTE Gas stations. This18

added information neither changes the clarification provided in this rebuttal, nor19

the expenditures presented in this proceeding, but serves to inform the intervenors20

that we are not reliant upon receiving an Act 9 certificate to complete the21


ADS-24-Rebuttal

interconnections work included in the above table for $29 million as included in1

my direct testimony.2

3

2) In discovery responses (STDG-1.1A and STDG-1.1B), DTE Gas intended to4

explain that construction of the 8” Frankfort Pipeline Loop and the facilities5

associated with the third Act 9 filing will begin during the projected test year and6

end after the projected test year. Only costs associated with the bridge year and7

projected test year are included in this rate case. The Act 9 filings include total8

costs for their respective portions of the project. Refer to the table above and9

Exhibit A-23 Schedule M1 TCARP Project Capital. Witness Miller incorrectly10

interpreted the response to mean that construction costs beyond the projected test11

year are included in the rate case.12

13

Q51. Does the Company agree with the proposed disallowance of the TCARP14

project?15

A51. No. For the reasons stated above, DTE Gas does not agree with disallowance of16

$29.6 million in TCARP capital expenditures.17

18

Other Capital Projects – Van Born Project19

Q52. Is there a proposal to disallow capital expenditures for the Van Born project?20

A52. Yes. Witness Miller is recommending disallowance of $8.8 million and Witness21

Coppola is recommending a disallowance of $10.6 million for the Van Born22

project.23

24


ADS-25-Rebuttal

Q53. Why is Witness Miller recommending disallowance of $8.8 million from the1

Van Born project?2

A53. Witness Miller indicates that Staff typically only supports recovery of the $1.853

million in engineering expenses to support an accurate and detailed Act 94

submission.5

6

Q54. Does the Company agree with the proposed disallowance of the Van Born7

project?8

A54. No. In discovery STDG-1.19, Staff requested a cost estimate for the Van Born9

Project consistent with what DTE provided in the Act 9 applications for the Lincoln10

Traverse City/Alpena Reinforcement Project. DTE Gas responded to the request,11

but only with the expenditures included in this proceeding ($12.4 million). DTE12

Gas should have responded to the discovery request based on the conceptual project13

cost estimate of $96.0 million identified in discovery request AGDG-3.164. Below14

is the overall conceptual cost estimate for the project consistent with the Act 915

filings.16

Van Born Project Costs17

18

19

20

21

22

23

24

25

Project Cost Breakdown ($000s)Total Project

Cost

Land/Right-of-Way $1,600

Material $16,320

Engineering/Corp A&G $17,863

Construction $41,977

Contingency $14,400

AFUDC $3,840

Total Project Cost - Van Born $96,000

Van Born Project


ADS-26-Rebuttal

STDG-1.19 Van Born PipelineTotal Project

Cost

Project Cost Breakdown ($000s)1/1/2019-9/30/2021

Land/ROW $1,600

Material $1,500

Engineering $1,850

Construction $5,383

AFUDC $292

Contingency $1,775

Total Project Cost - Van Born $12,400

1

Witness Miller has indicated Staff’s support for this project and for the recovery of2

engineering expenses to prepare the submission of an accurate and detailed Act 93

filing. DTE plans to file the Act 9 for the Van Born Project in Q1 of 2021.4

Described herein are the expenses that will be incurred by DTE Gas related to the5

Van Born Act 9 submission. Staff has recommended approval of $1.85 million for6

internal engineering labor expenses as part of this proceeding. However, to fully7

complete a detailed and accurate Act 9 filing, DTE Gas will, also, incur engineering8

related expenses for the detailed design and that is estimated to be $5.38 million.9

Furthermore, DTE Gas contends that engineering expenses alone are not sufficient10

to prepare an accurate and detailed Act 9 submission.11

12

Q55. What expenses beside engineering expenses are necessary for DTE Gas to13

prepare an accurate and detailed Act 9 submission?14

A55. It is necessary for DTE Gas to voluntarily secure majority of the easements with15

landowners along the route prior to submission of the Act 9 filing. The estimated16

land acquisition cost for the easements is $1.6 million. In addition to the17

engineering expenses described above and to allow construction to begin in 202218


ADS-27-Rebuttal

as planned, it will be necessary for DTE Gas to make commitments for material1

during the projected test year and that is estimated to be $1.5 million. This amount2

includes the initial progress payments to equipment suppliers for certified3

engineering drawings and down payment to the line pipe supplier for the 7 miles of4

24” pipe. The final portion of the requested amount is $0.3 million for AFUDC.5

Therefore, for the reasons described above, DTE Gas requests recovery of the $10.66

million in capital expenditures identified above for the Van Born Project.7

8

Q56. Why is Witness Coppola recommending disallowance of $10.6 million for the9

Van Born project?10

A56. Witness Coppola indicates that the disallowance is due to the premature nature of11

the project and the incomplete solution offered by the Company.12

13

Q57. Q. Does the Company agree with the proposed disallowance of the Van Born14

project?15

A57. No. Despite this project being in the conceptual phase, Staff is supportive of the16

project as indicated in Witness Miller’s testimony and, for the reasons stated above,17

the Company contends that the capital expenditures in this proceeding are necessary18

to support the initial phase of the Van Born Project and are not premature.19

Regarding the solution for the remaining 40,000 customers, as part of the overall20

strategy to mitigate the potential 160,000 outages, DTE Gas evaluated various21

solutions. One of these solutions includes extending the new 24” pipeline loop by22

an additional 10 miles to include the 40,000 customers. However, the further east23

the new loop line is extended, the more congested construction becomes. DTE Gas24

is continuing to evaluate if a more cost-effective solution exists to mitigate the25


ADS-28-Rebuttal

outage potential for the remaining 40,000 customers. The eventual solution does1

not impact the estimated $96 million for the first phase of the Van Born Project2

and, therefore, DTE Gas contends the $10.6 million should not be disallowed.3

4

IRM – Pipeline Integrity5

Q58. Is there a proposal to disallow capital expenditures for Pipeline Integrity6

projects?7

A58. Yes. Witness Coppola is recommending disallowance of $10.9 million for the8

following four Pipeline Integrity projects:9

1. Northeast Belt 24” ILI Expansion $1.8 million10

2. Loreed Ludington 16” ILI Expansion $2.0 million11

3. Southfield 24” Pipe Replacement $4.0 million12

4. South Grand Rapids 22” ILI Expansion $3.0 million13

14

Q59. Why is witness Coppola recommending disallowance of $3.8 million in capital15

expenditures for Northeast Belt 24” ILI expansion and Loreed Ludington 16”16

ILI expansion projects (#1-2 above)?17

A59. Witness Coppola indicates that because the 2019 actual for the projects came in18

below the projected 2019 spend, the variance should be disallowed.19

20

Q60. Does the Company agree with the proposed disallowance of the Northeast Belt21

24” ILI expansion and Loreed Ludington 16” ILI expansion projects?22

A60. No. Both projects are part of the Commission approved Pipeline Integrity IRM,23

which is one of the four processes making up DTE Gas’s IRM capital expenditures.24

In both cases, although the single project was accomplished under the forecast, the25


ADS-29-Rebuttal

capital expenditures of the Infrastructure Recovery Mechanism (IRM) program1

they were performed under exceeded that forecast and are reflected in the revenue2

requirements in this case. The savings on these projects were spent and used to3

accomplish additional work.4

5

The Northeast Belt 24” ILI Expansion and the Loreed Ludington 16” ILI Expansion6

projects are in the IRM program. The 2019 IRM forecast was $255.2 million. The7

2019 IRM actuals are $263.2 million, exceeding capital spend by $19.0 million.8

Therefore, despite the actuals for the single projects coming under forecast, the9

IRM capital expenditures forecast was spent.10

11

Q61. Is $4.0 million included in rate base in this proceeding for the Southfield 24”12

Pipe Replacement project (#3 above)?13

A61. No. As stated in Witness Sandberg’s direct testimony on page 47, lines 9-14, $3.514

million in non-IRM Pipeline Integrity expenditures have been included in base rates15

through September 30, 2021, $3.0 million of which is for the Southfield 24” Pipe16

Replacement as referenced in response to discovery question AGDG-3.166. The17

$4.0 million in the projected test year ending September 30, 2021 as referenced by18

Witness Coppola in Company’s Exhibit A-12, Schedule B5.3, was incorrect. The19

exhibit should have shown $3.0 million in the projected test year. See Exhibit A-20

23 Schedule M3 Revised Exhibit A-12, B5.3, Southfield 24” Pipe Replacement.21

22

Q62. Why is witness Coppola recommending disallowance of capital expenditures23

for the Southfield 24” Pipe Replacement project?24


ADS-30-Rebuttal

A62. Witness Coppola states in his testimony that because the engineering will not be1

completed until 2021 and the current estimate is simply a placeholder based on2

conceptual designs, the project is premature for inclusion in the projected rate base3

and the Commission has rejected preliminary cost amounts for inclusion in rate4

base in prior rate cases.5

6

Q63. Is witness Coppola’s statement that “the Commission has rejected such7

preliminary cost amounts for inclusion in rate base” correct?8

A63. No. Witness Coppola is incorrect in his statement. In the Commission’s Final9

Order for case U-18999, the Commission authorized in rate base the $3.0 million10

additional expenditures for non-IRM Pipeline Integrity.11

12

Q64. Does the Company agree with Witness Coppola’s statement that the Southfield13

24” Pipe Replacement Project is premature for inclusion in the projected rate14

base?15

A64. No. As stated in Exhibit A-23 Schedule M3 and AGDG-3.170b, the Southfield16

24” Pipe Replacement project needs to be completed in 2021 based on the corrosion17

growth rates determined from the previous ILI assessment on this pipeline and the18

complex scope of work included to perform this work. This portion of the pipeline19

is expected to exceed 80% wall thickness loss before the next assessment in 2023.20

CFR Part 192 Subpart O requires remediation of pipeline that exceed 80% wall21

thickness loss therefore this portion of the pipe must be remediated prior to the next22

assessment. As a prudent operator, due to the complexity of work, the Company23

would not wait until the year prior to assessment to complete this major24

construction project, an important fact that Witness Coppola did not provide in his25


ADS-31-Rebuttal

direct testimony. Witness Coppola instead focuses his disallowance1

recommendation on timing of engineering work and cost estimating of this project2

and assuming this project is premature, which has no bearing on the main driver for3

completing this project in 2021.4

However, the Company will respond to witness Coppola’s reason for disallowance.5

As shown in Exhibit A-23 Schedule M3, the project schedule identifies the6

engineering design to be completed months prior to the construction and in-service7

of the project. Additionally, the cost estimate for the Southfield 24” Pipe8

Replacement project is similar to other pipe replacement projects the Company has9

completed, and used historical actual capital spend to support cost estimation. The10

Company requests the Commission to reject witness Coppola’s $4.0 recommended11

disallowance to ensure Southfield 24” Pipe Replacement project is completed in12

2021 to provide a safe and reliable pipeline system for DTE Gas customers.13

14

Q65. Why is witness Coppola recommending disallowance of $3.0 million in capital15

expenditures of the South Grand Rapids 22” ILI Expansion project (#4 above)?16

A65. Witness Coppola states in his testimony that because the engineering will not be17

completed until 2020 and the current estimate is simply a placeholder based on18

conceptual designs, the project is premature for inclusion in the projected rate base.19

20

Q66. Does the Company agree with the proposed disallowance of the South Grand21

Rapids 22” ILI Expansion project?22

A66. No. The $3.0 million capital expenditures for the South Grand Rapids 22” ILI23

Expansion project are included in the $11.1 million PI IRM surcharge starting24

January 1, 2021 as supported by IRM Company Witness Dewey. DTE Gas sought25


ADS-32-Rebuttal

recovery for the cost of service for PI capital expenditures in Case No. U-16999,1

and the Commission authorized the capital spending plan in its final order. A2

disallowance of the South Grand Rapids 22” ILI expansion project will result in3

underspending the $11.1 million PI IRM expenditures authorized by the4

Commission in its final order in case U-17999. The cost estimate is comparable5

with ILI expansion projects that the company has performed in the past. The cost6

for this project will be incurred in 2021. For these reasons, DTE Gas recommends7

the Commission reject Witness Coppola’s recommendation to disallow $3.08

million for the South Grand Rapids 22” ILI Expansion project.9

10

Recommendations and Concerns11

Q67. What observations has witness Coppola communicated to the Company?12

A67. Witness Coppola on page 32, line 3, of his direct testimony states that there are13

MRP projects that have been completed or scheduled for completion that are very14

low in the risk ranking system. He concludes that the Company is deviating from15

its stance of improving safety and reliability and insteadfocusing on projects that16

are of lower risk ahead of projects that have higher risk projects.17

18

Q68. Does the Company agree with witness Coppola’s conclusion?19

A68. No. Witness Coppola suggests that a ranking below 200 would not be considered20

high risk. This conclusion is not correct. Out of approximately 350,000 total pipe21

segments, a project with a rank of 200 falls in the top 0.25% of riskiest pipes by22

footage, which by any reasonable definition would be considered high risk. The top23

5% riskiest pipes by footage would include pipe segments with ranks as low as24

approximately 10,000. The specific projects called out by witness Coppola with25


ADS-33-Rebuttal

ranks of 25,171 and 85,356 are projects that were selected by field recommendation1

and were not selected based on their calculated risk score.2

3

Q69. What additional observations has witness Coppola communicated to the4

Company?5

A69. Witness Coppola on page 33, line 16, of his direct testimony states that a6

probabilistic risk model should more accurately assess distribution main and7

service segments for replacement and would help determine pipe replacement rates8

and schedules when combined with pipe material analysis and engineering9

research. On page 34, line 1, Witness Coppola recommends the Company use the10

probabilistic model to prioritize MRP projects and other asset replacement projects,11

when combined with pipe material analysis and engineering research.12

13

Q70. Does the Company agree with witness Coppola’s recommendation?14

A70. No. The Company’s intent is to make use of the probabilistic model for prioritizing15

MRP projects and other asset replacement projects. The Company’s16

implementation of a probabilistic model does not include laboratory pipe material17

analysis and the engineering research on that laboratory pipe material analysis to18

determine deterioration rates. The Company, based on recommendation from the19

probabilistic risk model third party vendor being used for implementation, will20

instead determine deterioration rates by utilizing the Company’s leak data and then21

perform engineering analysis to incorporate that data into the probabilistic risk22

model.23

24


ADS-34-Rebuttal

Q71. Does the MPSC Staff have any general concerns that is communicated in direct1

testimony?2

A71. Yes. Witness Miller in his testimony, page 32, states that there were several3

discovery requests to obtain detail from the Company regarding capital4

expenditures. Staff requested spreadsheets detailing how the requested amounts5

were calculated. In response to this request, the Company provided these6

expenditures without any calculations to support the values submitted. Witness7

Miller states that the lack of detail is either due to the analysis not being performed8

or that the Company is intentionally withholding information.9

10

Q72. Does the Company agree with the statements made by Witness Miller?11

A72. No. The Company provided responses to the discovery requests based on the12

discovery request language as was understood by the Company. Detailed cost13

information was developed and available for each of the projects requested by Staff14

and the Company did not intentionally withhold information. The Company strives15

to be transparent with the MPSC and any request they submit. Exhibits containing16

detailed cost estimates for the four projects requested in discovery response are17

being provided in this rebuttal filing to address the general concern raised by18

Witness Miller. Please refer to Exhibit A-23 Schedule M7, Exhibit A-23 Schedule19

M8, Exhibit A-23 Schedule M9, Exhibit A-23 Schedule M10 and Exhibit A-2320

Schedule M11 for the detailed cost estimates as requested. In an effort to better21

align future rate case direct testimony with the Commission Staff expectations,22

DTE Gas plans to work closely with Staff to better understand their expectations23

and make sure we meet them moving forward.24

25


ADS-35-Rebuttal


A73. Yes it does.2

3

4

STATE OF MICHIGAN








)

REBUTTAL TESTIMONY

OF

EDWARD J. SOLOMON

DTE GAS COMPANY

REBUTTAL TESTIMONY OF EDWARD J. SOLOMON

Line

No.

EJS-1-Rebuttal


employed?2

My name is Edward J. Solomon. My business address is DTE Energy, One 3

Energy Plaza, Detroit, Michigan 48226. I am employed by DTE Energy 4

Corporate Services, LLC. 5

6


Company (DTE Gas or Company)? 8

Yes. 9

10



The purpose of my rebuttal testimony is to rebut both Staff Witness Joseph E. 13

Ufolla and Attorney General (AG) Witness Sebastian Coppola’s 14

recommendation that DTE Gas’s capital structure should be composed of 50% 15

equity as opposed to 52%. Also, I will rebut the AG’s increase in short-term debt 16

by $62 million. 17

18


Yes. I am sponsoring the following exhibit: 20


A-34 X1 Peer Equity Ratio 22

23


Yes, they were. 25

E. J. SOLOMON

Line U-20642

No.

EJS-2-Rebuttal

1

Q6. Do you agree with the Staff’s and the Attorney General’s recommendation 2

of a 50% common equity ratio? 3

No, as stated in my direct testimony, a more appropriate ratio is a 52% common 4

equity ratio. Mr. Ufolla stated that a 52% equity ratio is too high and that an 5

equity ratio of 50-51% is more appropriate while Staff used a 50% ratio for the 6

development of exhibits in the case. Mr. Coppola also increased long-term debt 7

and reduced common equity to achieve a 50% common equity ratio. 8

9

Q7. Do you agree with Staff that the average authorized capital structure and 10

capital trends in the regulated gas utility industry support a 50% equity 11

ratio and with the AG’s assessment that the common equity ratio of the peer 12

group is around 50%? 13

No. Mr. Ufolla states, on page 8 of his testimony, that, according to S&P Global, 14

the average authorized equity ratio for 2017, 2018, and 2019 are 49.88%, 15

50.09% and 51.75% respectively. The Company agrees that the equity ratios are 16

correct. However, the Company wants to recognize that the ratios are increasing 17

not decreasing over time and that when looking at the data for 2019, the equity 18

ratio was closer to 52% and found the 2020 ratio to be 52.53%, which is higher 19

than our recommended 52%. Mr. Ufolla’s Exhibit S-4, which lists Gas Proxy 20

Group Corporate Statistics, column (h), shows the average equity ratio to be 21

56.28%. 22

23

In the AG’s Exhibit AG-26, the average equity ratio of the peer group is shown 24

at 50.3%. However, the equity ratios in this Exhibit appears to use the equity 25

E. J. SOLOMON

Line U-20642

No.

EJS-3-Rebuttal

ratio of the peer holding companies and not operating LDC companies. Using 1

holding company data is not a fair comparison to a gas utility operating company 2

because holding companies may be impacted by accounting impairments and 3

other factors. A more appropriate comparison is to look at the operating 4

company equity ratio as shown in U-20642 Exhibit A-34 Schedule X1 Peer 5

Equity Ratio. The equity ratio of the operating companies using the AG’s peer 6

group is approximately 57% for fiscal year 2018 (the last full year data was 7

available). These statistics clearly show that the average authorized capital 8

structure and ratio of peer gas operating companies fully support an equity ratio 9

of 52% rather than a lower ratio of 50%. 10

11

Q8. Mr. Ufolla’s and Mr. Coppola’s testimony states that the Commission 12

signaled its preference for DTE Gas to have a more balanced equity ratio. 13

Have there been any significant events that have occurred since DTE Gas’s 14

last general rate case No. U-18999 that would materially impact the 15

appropriate equity ratio in this case? 16

Yes. In DTE Gas’ last general rate case, the Commission stated that “[a]lthough 17

DTE Gas asserts the recently-passed TCJA will adversely affect its financials, 18

the company failed to provide sufficient evidence to support this argument.” 19

However, subsequent to the Commission order in DTE’s last general rate case, 20

DTE Gas was downgraded by Moody’s in July of 2019. Moody’s downgrade is 21

sufficient evidence to support the argument that its credit position has been 22

harmed. In fact, DTE Gas’ Moody’s credit rating is now lower than that of DTE 23

Electric and Consumers Energy. The Company further feels that the passing of 24

the TCJA has affected the credit quality of DTE Gas. Witness Ufolla mentioned 25

E. J. SOLOMON

Line U-20642

No.

EJS-4-Rebuttal

that the Company did not provide any mathematical explanation showing the 1

consequences to the Company if a 52% equity ratio was not approved. However, 2

mathematical calculations are typically used to demonstrate that credit metrics 3

are at a level that could lead to a downgrade. Moody’s downgrade by itself is 4

more than sufficient demonstration that the metrics were indeed not supportive 5

of the then current rating level. In fact, what is worth noting, that per the July 6

2019 Moody’s report, DTE Gas’s financial forecast were more indicative of a 7

Baa rating. It was the other factors in their ratings analysis, the non-quantitative 8

factors (e.g., timeliness of recovering operating and capital costs), that provided 9

the support for the A1 rating. 10

11

Q9. Does Mr. Ufolla’s statement that there is not any conclusive reason to 12

believe an adjustment from 52% to 50% equity would affect the Company’s 13

current credit rating mean that the current credit rating is not in danger if 14

the capital structure moved from 52% to 50% equity? 15

No. Mr. Ufolla agrees that Moody’s has stated the factors that could lead to a 16

further downgrade are two specific risks: Cash from Operations (“CFO”)/Debt 17

falling below 15% or an adverse change in Michigan’s regulatory environment. 18

A change in the authorized capital structure would impact both these factors 19

negatively. The Company’s CFO/Debt ratio would move closer to the threshold 20

level as the Company adds more debt and it could very well be perceived as an 21

adverse change in the regulatory environment. It also does not allow the 22

Company to have much cushion to weather unforeseen shocks such as referred 23

to in the next question. 24

25

E. J. SOLOMON

Line U-20642

No.

EJS-5-Rebuttal

Q10. Are there any other significant developments that Mr. Ufolla may not have 1

taken into consideration when developing his testimony? 2

Yes. Prior to the filing of Staff and intervenor testimony in this proceeding, the 3

Coronavirus Disease 2019 (“Covid-19”) was already impacting countries, 4

communities, supply chains and markets, including those in the US. DTE Gas 5

cannot predict whether, and the extent to which, Covid-19 will have a material 6

impact on our liquidity, financial condition, and results of operations. We require 7

access to the capital markets to fund capital requirements. In times of increased 8

volatility, investors favor companies that are viewed as safer and have stronger 9

credit ratings. The extent to which Covid-19 may impact our liquidity, financial 10

condition, and results of operations will depend on future developments, which 11

are highly uncertain and cannot be predicted. To date, we have experienced a 12

disruption in the commercial paper market and Tier 2 issuers, (based on short 13

term debt rating of A2/P2 by S&P and Moody’s) like DTE Gas, have had limited 14

to no access to this market. The long-term debt markets have also seen dramatic 15

increases in credit spreads and companies with weaker credits have experienced 16

limited access to the capital markets and at much higher costs. On April 2, 2020, 17

S&P announced its outlook for North American utility industry is now negative. 18

For the three weeks ending April 4, Michigan has seen 817,585 unemployment 19

claims per the U.S. Department of Labor. This represents more than a 5,000% 20

increase over the three preceding weeks. Unemployment claims in Michigan 21

filed during the first few weeks of the Covid-19 outbreak outpaced those made 22

during the Great Recession of 2007 to 2009 per Michigan Governor Gretchen 23

Whitmer and are expected to grow. Maintaining a strong balance sheet, and 24

E. J. SOLOMON

Line U-20642

No.

EJS-6-Rebuttal

ample liquidity, is important in times of uncertainty and further supports the need 1

to stay at 52% equity. 2

3

Q11. Do you agree with Attorney General Witness Coppola’s recommendation 4

to increase short-term debt level by $62 million because the proposed 5

reduction in short-term debt from $207 million in 2018 to $145 million in 6

the projected test year is unsupported? 7

No. The short-term debt level of $145 million is a more appropriate balance to 8

use in the projected test year. The 13-month average short-term debt for the 9

period ending December 31, 2018 was $211 million. Looking back at 2018, the 10

variability of cash flows in the first part of 2018 was due in part to colder than 11

forecasted weather and higher gas prices. The average short-term debt level for 12

the test period of $145 million assumed a more normalized weather pattern. This 13

2018 average included four months where the short-term debt balance was $250 14

million or greater and for three of those months the balance was above $300 15

million. With a commercial paper program limit of $300 million, running 16

balances at $250 million or greater is not practical and not good risk 17

management. It is always important to hold excess liquidity to be able to respond 18

to respond to unforeseen needs and to manage peak needs, which we know are 19

meaningful at DTE Gas. As evidence of this, in the current financial markets, 20

DTE Gas drew on its bank revolver because commercial paper markets were not 21

available. If the Company did not have adequate liquidity under its $300 million 22

limit, then the Company would have been at risk in meeting its daily and future 23

cash needs. Maintaining an adequate level of liquidity is critical so that we can 24

continue to reliably manage and support DTE Gas operations. 25

E. J. SOLOMON

Line U-20642

No.

EJS-7-Rebuttal

1

Q12. Do you agree with the Attorney General Witness Coppola’s arguments 2

supporting a 50% common equity ratio? 3

No. As discussed in detail in my response to Staff’s common equity 4

recommendation, a 52% equity ratio helps maintain the Company’s credit rating 5

and ensures access to capital. The Moody’s downgrade in July of 2019 provides 6

evidence that financial health of DTE Gas is under pressure and the then current 7

credit metrics were not to sufficient to avoid a downgrade. 8

9

Mr. Coppola states that the previous Moody’s rating for DTE Gas of Aa3 as 10

somewhat “out of line” and higher than the ratings assigned by other agencies. 11

Each rating agency has their own methodology and rating process. Both DTE 12

Electric and Consumers Energy are rated Aa3 by Moody’s and A by Standard & 13

Poor’s. The downgrade at Moody’s to A1 now puts DTE Gas “out of line” with 14

the ratings of DTE Electric and Consumers. 15

16

Mr. Coppola states the Company provided no analysis on its credit metrics and 17

how they might be impacted by moving to a 50% equity ratio, and states his own 18

analysis shows there is no near-term problem. His analysis shows that the 2018 19

CFO Pre-WC to Debt ratio would likely fall to 17% and still be well above the 20

Moody’s 15% downgrade trigger level if the equity ratio was 50% as opposed 21

to 52%. It is not reasonable and prudent to operate with little cushion between 22

metrics and the next downgrade. As noted previously, in Answer 8, Moody’s is 23

already forecasting that the Company is operating with financial metrics that are 24

below DTE Gas’s current rating, and only because of the non-quantitative factors 25

E. J. SOLOMON

Line U-20642

No.

EJS-8-Rebuttal

that they have the company rated A1. Lowering the equity ratio will only put 1

more pressure on our rating, which will be perceived negatively by the credit 2

agencies and investors. Additionally, the Company needs to be in a position to 3

weather unforeseen shocks to its credit metrics that may result from events like 4

the one referred to in Question 10 regarding the Covid-19 pandemic. 5

6

The AG disputes the Company’s claim that DTE Gas faces higher business risks 7

for serving the city of Detroit with its high poverty level and declining 8

population, stating among other things, poverty levels and declining population 9

are not unique to Detroit and the city of Detroit is experiencing a major 10

resurgence. While the downtown Detroit area is seeing revitalization, the 11

surrounding Detroit neighborhoods still have their challenges. The US Census 12

Bureau data shows that 36.4% of the residents of the city of Detroit live in 13

poverty compared to 14.1% for the State of Michigan. Furthermore, the 14

economic impact of Covid-19 will stretch across Michigan, hitting almost every 15

industry and community. The City of Detroit has been hit particularly hard by 16

Covid-19 and is experiencing the worst outbreak in the State of Michigan (and 17

is one of the hardest hit cities in the country). Michigan, with its industrial base, 18

will feel a larger impact. Morgan Stanley is predicting a nine percent drop in 19

auto sales this year, which would affect domestic automakers that are still some 20

of the largest employers in the state. The service territory for DTE Gas will 21

certainly be impacted by Covid-19, which is another factor that supports a higher 22

equity ratio at this time. 23

24


https://www.autonews.com/retail/morgan-stanley-us-sales-could-slip-9-coronavirus

E. J. SOLOMON

Line U-20642

No.

EJS-9-Rebuttal

Yes, it does.1

STATE OF MICHIGAN


In the matter of the application of ) DTE GAS COMPANY for authority to ) to increase its rates, amend its rate ) schedules and rules governing the ) Case No. U-20642 distribution and supply of natural gas, ) and for miscellaneous accounting authority ) )

REBUTTAL TESTIMONY

OF

THERESA M. UZENSKI


employed. 2

A1. My name is Theresa M. Uzenski. I am employed by DTE Energy Corporate 3

Services, LLC, a subsidiary of DTE Energy Company (DTE Energy). My business 4

address is One Energy Plaza, Detroit, MI 48226. 5

6


Company (DTE Gas or Company)? 8

A2. Yes. 9

10



A3. The purpose of my rebuttal testimony is to refute certain positions taken by the 13

other parties as described in more detail below. The absence of a discussion of 14

other matters in my testimony should not be taken as an indication that I agree with 15

all other aspects of intervenor testimony. 16

• Staff’s two adjustments to reduce the capital usage charge should be 17

rejected because they are duplicative and would understate the expenses that 18

will be billed to DTE Gas. In addition, one of the adjustments is based on 19

a presumed disallowance in DTE Electric’s current rate case (U-20561), in 20

which an order has not yet been issued by the Michigan Public Service 21

Commission (MPSC or Commission). 22

• The Attorney General’s (AG) adjustment to reduce the capital usage charge 23

should be rejected because it is based on a presumed disallowance in DTE 24

Electric’s current rate case (U-20561). 25

T. M. UZENSKI Line U-20642 No.

TMU-2-Rebuttal

• Staff’s adjustment to benefits capitalized and transferred should be rejected 1

because there is no basis for using 2019 as the starting point for their 2

calculation. 3

• Staff’s proposal to use the cash basis method for determining uncollectible 4

expense should be rejected because the accrual method is more accurate and 5

is the basis for the Company’s recorded uncollectible expense. 6

• ABATE’s proposed disallowance of all industry association dues should be 7

rejected because there is no sound basis to conclude that none of the costs 8

are reasonable and prudent. DTE Gas agrees to an expense reduction of 9

$100,000. 10

• Staff’s proposal to remove the receivable for the Customer Attachment 11

Program (CAP) is unnecessary because customers are appropriately 12

compensated by the related interest revenue. 13

I also address Staff’s comments regarding the accounting classification for certain 14

capital projects and discuss the accounting for an uncollectible tracker proposed by 15

Company Witness Telang. 16

17


A4. Yes. I am sponsoring the following exhibits: 19


A-30 W1 Industry Dues 2018 21

A-30 W2 Industry Associations Descriptions 22

A-30 W3 Uncollectibles Expense (Staff Proposal Adjusted). 23

24

25


TMU-3-Rebuttal


A5. Yes, they were. 2

3

O&M Expenses 4

Q6. What are the reductions to the capital usage charge proposed by Staff? 5

A6. On page 9, lines 1-8 of Staff Witness Putnam’s direct testimony, he proposes a 6

reduction of $7.3 million in rent expense based on the corresponding shared asset 7

revenue amount in the current DTE Electric rate case (U-20561). In addition, Staff 8

Witness Wang proposes a reduction of $4.2 million related to five IT projects that 9

Staff proposed should be disallowed in the DTE Electric rate case. She describes 10

this in her direct testimony starting on page 23, line 14. Upon further review, 11

Witness Wang revised her recommended disallowance from $4.2 million to $1.3 12

million in response to the Company’s 2nd discovery request. 13

14

Q7. Do you agree with Witness Putnam’s proposed $7.3 million reductions to rent 15

expense? 16

A7. No. The revenue in the DTE Electric rate case did not reflect an increase in the 17

shared asset charge to DTE Gas for all new IT projects. Thus, by default, Mr. 18

Putnam’s adjustment to set the DTE Gas expense equal to DTE Electric’s revenue 19

removes the increase in the expense for the added projects. However, the Company 20

continues to support the projects currently under litigation. From an accounting 21

perspective, it is inappropriate to assume a disallowance before the Commission 22

issues its order in Case No. U-20561. Therefore, the Commission should approve 23

the $42.3 million shared asset charge for Gas, inclusive of all the new IT projects. 24

25


TMU-4-Rebuttal

Q8. Why didn’t DTE Electric’s projected revenues include the charge related to 1

the IT projects? 2

A8. The Company was updating its capital projections for IT projects at the same time 3

the Company was completing the DTE Electric rate case application. The IT capital 4

expenditures were added to the models, but the related shared asset revenue update 5

was overlooked at the time the models were finalized. The Company plans to file 6

a new Electric rate case in 2020 and will reflect the appropriate increase in shared 7

asset revenue in that filing. 8

9

Q9. Do you agree with the $1.3 million reduction to the capital usage amount 10

calculated by Witness Wang? 11

A9. No. Ms. Wang’s $1.3 million additional disallowance is duplicative of the 12

adjustment that Mr. Putnam has already proposed. In response to the Company’s 13

2nd Discovery Request, Ms. Wang determined the percentage of historic Shared 14

Asset capital expenditures associated with the five IT programs expected to be 15

disallowed in the DTE Electric rate case (3.64%). She then applied that percentage 16

to the historic rent expense of $35.6 million ($35.6M x 3.64% = $1.3M). 17

18

Ms. Wang is incorrectly assuming the 2018 expenditures related to the IT programs 19

expected to be disallowed in the DTE Electric rate case are reflected in the historical 20

rent expense. The shared asset charge is based on the return on and of plant in 21

service. To forecast the charge, the Company assumes that capital projects are 22

placed in service the year subsequent to the expenditures. Therefore, these 23

expenditures were not reflected in the historical expense of $35.6 million. 24

25


TMU-5-Rebuttal

Q10. What adjustment does AG Witness Coppola propose as a reduction to the 1

capital usage charge? 2

A10. AG Witness Coppola recommends a $1.8 million reduction in the capital usage 3

charge (aka shared asset charge) based on certain projects he proposed for 4

disallowance in the DTE Electric rate case, U-20561. Mr. Coppola points to seven 5

projects on page 130 of his direct testimony, starting on line 12. 6

7

Q11. Do you agree that the capital usage charge should be reduced for the identified 8

projects? 9

A11. No. On page 131, line 4, Mr. Coppola states, “Although the Commission has not 10

yet issued an order in Case No. U-20561, the Administrative Law Judge in her 11

Proposal for Decision has recommended the full disallowance of the capital 12

expenditures proposed by DTE Electric pertinent to those 7 projects.” However, 13

the Company continues to support the projects currently under litigation. From an 14

accounting perspective, it is inappropriate to assume a disallowance before the 15

Commission issues its order in Case No. U-20561. Therefore, Mr. Coppola’s 16

proposed $1.8 million reduction must be rejected. 17

18

Q12. What is the disallowance of industry association dues proposed by ABATE? 19

A12. ABATE witness Mr. Pollock discusses industry association dues starting on page 20

28 of his direct testimony. On page 30, line 21, he asserts “Several of the 21

organizations listed by DTE in Exhibit AB-25 engage in political activities.” On 22

page 32, starting on line 15, Mr. Pollock recommends a disallowance of amounts 23

identified by the Company as related to political activity and further recommends 24

that all industry association dues be disallowed until the Company demonstrates 25


TMU-6-Rebuttal

their benefit to customers. The total amount of industry dues is $816,000 as shown 1

on Exhibit A-30, Schedule W1. 2

3

Q13. Do you agree with ABATE’s proposed disallowance? 4

A13. I agree that $100,000 should be removed from the revenue requirement. This 5

amount includes: $5,400 for The HR Policy Association, and $19,196 for the 6

American Gas Association. To minimize the issues in this case, the Company also 7

agrees to remove $47,000 for Energy Solutions Center, Inc., $25,000 for 8

Conference Board, Inc., and $3,000 for the American Society of Employers. 9

However, the Company maintains that a portion of these association dues may be 10

recoverable in future cases pending an analysis of what portion (if any) of the dues 11

is spent on political activities. 12

13

Q14. Why should the remaining balance of $716,000 be included in the revenue 14

requirement? 15

A14. As noted in Mr. Pollock’s testimony, only a portion of the HR Policy Association 16

and American Gas Association dues is related to political activity. The total dues 17

paid for those two items is $628,000, of which less than $25,000 is for political 18

activity. This leaves $603,000 as recoverable. In addition, the full $29,000 for the 19

Gartner Group and $80,000 for Corporate Executive Board (now one combined 20

company), and $4,000 for the National Safety Council are recoverable. These 21

organizations provide the Company with access to research and best practices at a 22

lower cost than it could obtain on its own. A more detailed description of the 23

organizations is provided in Exhibit A-30, Schedule W2. 24

25


TMU-7-Rebuttal

Q15. What was Staff Witness Mr. Welke’s proposal regarding Employee Benefits 1

capitalized and transferred? 2

A15. Mr. Welke has proposed that the Company’s projected Employee Benefits 3

capitalized and transferred be increased by $289,000. He calculated this amount 4

by inflating 2019 actual expense through the projected test period. 5

6

Q16. Do you agree with Witness Welke’s proposed adjustment? 7

A16. No. Mr. Welke based his adjustment on the amount from 2019 while the remainder 8

of the Staff’s Operations and Maintenance expense (O&M) is based on the 9

Company’s 2018 historical test year. At the top of page 5 of his direct testimony 10

he states, “The Company used 2018 expense levels as their basis for projecting 11

Other Benefits Expenses. Staff used 2019 expense levels instead.” Mr. Welke 12

offers no explanation of why the use of 2019 is appropriate or provides a better 13

forecast than using 2018; thus, the adjustment should be rejected. If 2018 is used 14

as the basis, the Company supports a credit for A&G capitalized of $2.5 million 15

and a credit for transfers of $1.2 million as shown on Company Witness Mr. 16

Cooper’s rebuttal Exhibit A-26, Schedule MSC-2, lines 32 and 33. The 17

inconsistency of forecast methods is further addressed by Company Witness 18

Cooper. 19

20

Uncollectibles Expense 21

Q17. What methodology does Staff recommend for forecasting uncollectibles 22

expense? 23

A17. Starting at line 4 on page 6 of her direct testimony, Staff Witness Mr. Rueckert 24

suggests a cash basis method based on a ratio of gross write offs less recoveries. 25


TMU-8-Rebuttal

He applies the resulting percentage to gas service revenue in the projected test 1

period to arrive at an estimate of $27.8 million, as shown on Staff Exhibit S-15.1, 2

line 7. This is a $5.9 million reduction from the Company’s projection of $33.7 3

million. He suggests this method is preferable to the Company’s use of a historical 4

average of actual expense “because it presents a more accurate picture of the actual 5

cash flows the Company receives annually.” Mr. Rueckert makes an additional 6

adjustment on line 8 to reduce expense by another $648,000 to reflect the impact 7

of Precise ID, a new tool the Company began using in April 2019, resulting in a 8

total reduction in uncollectibles expense of $6.5 million. 9

10

Q18. Do you agree with the cash basis method for estimating uncollectible expense? 11

A18. No. The cash basis method for estimating uncollectible expense is inconsistent 12

with how expense is recorded and with how other costs and revenues are calculated 13

for both MPSC reporting and for rate-making. The Company determines 14

uncollectible accounts expense based on an accrual method as required by the 15

Uniform System of Accounts (USofA), General Instruction number 11. Rates are 16

set to cover the Company’s expenses expected to be recorded for accounting 17

purposes. The estimation of future expenses should therefore be consistent with 18

the practice used to record the actual expenses to ensure recovery of the Company’s 19

prudent and reasonable costs. An average of the amounts charged to account 904 20

provides such consistency. The use of a three-year historical average of 21

uncollectible expense was the approach approved by the Commission in recent 22

DTE cases (DTE Electric rate case U-18255 and case U-18014 and DTE Gas rate 23

case U-18999 and case U-17999). 24

25


TMU-9-Rebuttal

In addition, the cash-basis method does not factor in special circumstances that are 1

accounted for under the accrual method. For example, the write-off of some 2

accounts is delayed because they are being disputed or negotiated and need to show 3

as open in the billing system until a final decision is made. Another example is that 4

the write-offs for certain accounts were not processed due to a system issue that 5

occurred with the implementation of C360 (the new billing system). The balances 6

in these examples are expected to be charged-off, so under the Company’s accrual 7

method they are fully reserved. These situations would not be reflected in the cash 8

basis method that Staff has proposed. 9

10

Q19. Do you have other concerns with Mr. Rueckert’s forecast? 11

A19. Yes. If the Commission decides the cash basis method should be applied, there are 12

three flaws in Mr. Rueckert’s calculation that must be corrected. 13

1. Direct charges, primarily relating to the Company’s forgiveness match to 14

low-income customers, must be included in uncollectibles expense. 15

2. Non-energy write-offs should be included because the revenue figure used 16

by Staff includes the related non-energy revenue. 17

3. The write-off ratio should be applied to proposed revenue instead of present 18

revenue. Mr. Rueckert claims his method more closely predicts actual cash 19

flow but does not properly consider that customer accounts receivable 20

balances will be higher (all other impacts remaining equal) resulting from 21

rate relief in the instant case. 22

Points one and two are addressed in more detail by Company Witness T. Johnson. 23

The corrections for these three items result in an increase of $3.0 million to Staff’s 24

number, as shown on Exhibit A-30, Schedule W3, line 15, column (i). Witness T. 25


TMU-10-Rebuttal

Johnson also rebuts Staff’s reduction of $0.6 million related to the Precise ID 1

project on line 16, for a total adjustment of $3.6 million. 2

3

Q20. How will uncollectibles expense be impacted by the 2020 pandemic? 4

A20. Company Witness T. Johnson supports the Company’s expectation that 5

uncollectibles expense will increase. To mitigate this risk, Company Witness 6

Telang, proposes an uncollectibles true up mechanism to address the uncertainty in 7

expense resulting from the pandemic and other factors beyond the Company’s 8

control. 9

10

Q21. How would the accounting for an uncollectibles tracker work? 11

A21. The difference between actual uncollectibles expense and the base set in the instant 12

case would be deferred to a regulatory asset or liability. The Company requests the 13

use of accounts 182.3, Other Regulatory Assets, and 254, Other Regulatory 14

Liabilities, for this purpose. The regulatory asset or liability, plus interest at the 15

Company’s short-term debt rate, would be filed for review following the end of 16

each calendar year. If the Commission approves the accuracy of the filing, a 17

surcharge or credit would be implemented to collect or refund the balance as further 18

discussed by Witness Telang. 19

20

Customer Attachment Program 21

Q22. What is Staff’s recommendation regarding the Company’s Customer 22

Attachment Program? 23

A22. Staff Witness Mr. Witt states that the note receivable balances related to the 24

Customer Attachment Program totaling approximately $8 million be disallowed. 25


TMU-11-Rebuttal

This consists of $987,000 of current notes receivable and $6,990,000 of long-term 1

notes. On page 4 of his testimony, starting at line 11 he states, “the Company’s 2

cost is recovered from the projects through section C8 of its tariff book (Staff 3

Exhibit S-13.1). Thus, it would be inappropriate to include an item in the 4

determination of base rates that is already being collected through a separate 5

mechanism.” As discussed by Staff Witness Mr. Todd on the top of page 21 of his 6

direct testimony, he removes the related interest revenue of $109,000 from the 7

projected period on line 21 of Staff Exhibit S-6.0, Schedule C-3, entitled “Projected 8

Revenue.” 9

10

Q23. Do you agree that the CAP amounts should be removed? 11

A23. It is not appropriate to remove the CAP balance and the interest. The note 12

receivable is established with a credit (CIAC) to plant. Interest revenue is 13

calculated by applying the authorized pre-tax return on permanent capital to the 14

outstanding note balance and is included as a reduction to the revenue requirement. 15

Should the Commission agree with Staff’s approach, the Company will exclude the 16

interest revenue in future rate filings. Assuming the Commission agrees with my 17

position and keeps the CAP balance and the interest, the interest revenue should be 18

increased by $629,000 to correct for an error that was disclosed by the Company in 19

response to audit question TGW-2. 20

21

Accounting for Certain Capital Projects 22

Q24. What question did Staff raise regarding DTE Gas’s capitalization policy? 23

A24. Starting on page 11 at line 22, through the middle of page 14, of Staff Witness 24

Miller’s direct testimony, Mr. Miller suggests the Company is capitalizing projects 25


TMU-12-Rebuttal

that should be classified as O&M expense. He points specifically to the project, 1

BRM Unit #4 Engine Rebuild, to make his point. On page 12 he claims the 2

Company identified the project as maintenance expense because of the description 3

used: “To complete major maintenance per the manufacturers' recommended 4

schedule (prior to 25,000 hours of runtime since last rebuild). This will help ensure 5

engine operational reliability. Evaluation and rebuild, as necessary, of all major 6

components on the engine and major auxiliary units. Following manufacturer 7

recommendations will ensure unit reliability for Midstream sales and Gas Control 8

winter and summer needs.” 9

10

On page 13 Mr. Miller states: “The engine that was rebuilt as part of this project 11

would have already been included as gas plant when it was originally installed and 12

the inclusion of maintenance tasks in Account 354 are inappropriate. The USofA 13

provides a maintenance account for the type of activity that the Company 14

performed; Account 834 entitled ‘Maintenance of compressor station equipment’.” 15

16

Q25. Do you agree with Mr. Miller’s accounting analysis? 17

A25. No. Utility companies capitalize work based on definitions of retirement units. 18

Retirement units are components of larger assets. If part of an existing asset is 19

replaced, and that part is a retirement unit, the new part is capitalized, and the old 20

part is retired. Regarding the BRM project, the Company performed a major 21

overhaul of unit #4, which included the replacement of major components such as 22

cylinder liners, pistons, piston rods and bearings. All other material was evaluated 23

and replaced, as necessary. All components replaced during the overhaul are 24

retirement units as defined in DTE Gas’s capital policy. 25


TMU-13-Rebuttal

1

Q26. Did Staff propose a disallowance for the BRM Unit #4 project? 2

A26. No. On page 14, starting at line 11, Mr. Miller says that Staff recommends “that 3

the Commission direct the Company to review the projects that it identifies as 4

capital projects to ensure that they are aligned with the accounting practices 5

specified by the USofA.” The Company will continue to review projects that it 6

identifies as capital to ensure they align with its Retirement Unit Catalog and are in 7

compliance with the accounting practices specified by the Uniform System of 8

Accounts. 9

10

Q27. What question regarding DTE Gas’s application of the Uniform System of 11

Accounts was raised by Staff? 12

A27. Starting at line 14 on page 30 of his direct testimony, Staff Witness Miller questions 13

DTE Gas’s use of account 303, Intangible Plant, to classify costs to review 14

maximum allowable operating pressures and develop a records management 15

system. Mr. Miller recommends the Company classify the costs in account 182.2, 16

Unrecovered Plant and Regulatory Study Costs, which is amortized to account 17

407.1, Amortization of Property Losses, Unrecovered Plant and Regulatory Study 18

Costs. 19

20

He states at the top of page 32: “Refer to Staff Exhibit S-7.14 for the USofA. The 21

Company’s review of maximum allowable operating pressures was required per a 22

Pipelines and Hazardous Materials Safety Administration (PHMSA) Advisory 23

Bulletin issued on January 10, 2011, and a final rule entitled ‘Safety of Gas 24

Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment 25


TMU-14-Rebuttal

Requirements and Other Related Amendments’ that was finalized on October 1, 1

2019. Therefore, because this work is being conducted commensurate to those 2

regulatory requirements, Staff recommends that the Company utilize Account 3

182.2 for these expenditures, which is intended to house “regulatory study costs.” 4

5

Q28. Do you agree that DTE Gas should classify the costs in account 182.2 instead 6

of plant account 303? 7

A28. Yes, as long as the Commission approves the use of account 407.1 to record the 8

related amortization expense over five years, the Company does not object to using 9

account 182.2 for these projects and similar costs in the future. This accounting 10

classification change will not impact the revenue deficiency in the instant case. 11

12



15

Rebuttal Testimony of Bente Villadsen DTE Gas Company

Case No. U-20642

BEFORE THE

MICHIGAN PUBLIC SERVICE COMMISSION

DTE GAS COMPANY

)

)

)

)

CASE NO. U-20642

REBUTTAL TESTIMONY

OF

DR. BENTE VILLADSEN

LIST OF TOPICS ADDRESSED:

COST OF COMMON EQUITY CAPITAL

APRIL 3, 2020


Case No. U-20642

Table of Contents

Page

I. INTRODUCTION AND SUMMARY ......................................................................................1

A. Summary of Recommendations ....................................................................................... 4

B. The MPSC Staff, AG, and ABATE Recommendations Are Too Low ........................... 4

II. FINANCIAL LEVERAGE MATTERS ....................................................................................5

A. Preliminaries .................................................................................................................... 5

B. Financial Economics ...................................................................................................... 10

C. Precedents ...................................................................................................................... 17

III. OTHER RISK MATTERS ......................................................................................................20

IV. WATER UTILITIES IN PROXY SAMPES ...........................................................................21

V. MESSRS. UFOLLA, COPPOLA, AND MS. LACONTES APPROACHES TO COST OF

EQUITY ESTIMATION .........................................................................................................23

A. Overall Approach ........................................................................................................... 23

B. Sample Selection ............................................................................................................ 23

C. Cost of Equity Estimation Methods ............................................................................... 25

VI. RESPONSE TO CRITIQUE OF ECAPM ...............................................................................34

VII. CAPITAL MARKETS UPDATE ..........................................................................................39


Case No. U-20642

Page 1 of 46

BEFORE THE

MICHIGAN PUBLIC SERVICE COMMISSION

DTE GAS COMPANY

)

)

)

)

CASE NO. U-20642

REBUTTAL TESTIMONY OF DR. BENTE VILLADSEN

I. INTRODUCTION AND SUMMARY 1

Q1. Please state your name, occupation and business address. 2

A1. My name is Bente Villadsen and I am a Principal of The Brattle Group, whose business 3

address is One Beacon Street Suite 2600, Boston, MA 02108. 4

Q2. Are you the same Bente Villadsen who filed Direct Testimony in this matter? 5

A2. Yes. 6

Q3. Please provide a glossary of acronyms used in your testimony. 7

A3. I frequently use the following acronyms in my testimony: 8

• ATWACC – After tax weighted average cost of capital 9

• CAPM – Capital Asset Pricing Model 10

• DCF – Discounted Cash Flow Model 11

• ECAPM – Empirical Capital Asset Pricing Model 12

• MISO – Midcontinent Independent System Operator 13

• MRP – Market equity risk premium 14

• NETO – New England Transmission Operators 15

• ROE – Return on equity 16

• SML – Securities Market Line 17

18

19


Case No. U-20642

Page 2 of 46


A4. I have been asked to review and comment on the testimony of Mr. Joseph Ufolla (“Ufolla 2

Testimony”) filed on behalf of the Michigan Public Service Commission Staff (“MPSC 3

Staff”), the testimony of Mr. Sebastian Coppola (“Coppola Testimony”) filed on behalf of 4

the Michigan Attorney General (“AG”), and the testimony of Ms. Billie S. LaConte 5

(“LaConte Testimony”) filed on behalf of the Association of Businesses Advocating Tariff 6

Equity (“ABATE”). 7

Q5. Is there anything in Messrs. Ufolla, Coppola, or Ms. LaConte’s Testimonies that 8

caused you to change your recommendation regarding DTE Gas’s cost of capital? 9

A5. No. Having reviewed Messrs. Ufolla, Coppola, and Ms. LaConte’s Testimonies as well as 10

considering the recent changes in economic conditions, I continue to find that my original 11

recommendations for a return on equity (“ROE”) of 10½ percent at a 52 percent equity 12

capital structure remains reasonable. I acknowledge that since I developed my Direct 13

Testimony, economic conditions have changed; most recently due to the COVID-19 14

pandemic and I address these impacts in further detail in Section VII. 15

Q6. Please summarize your testimony. 16

A6. Having reviewed the testimonies of Messrs. Ufolla, Coppola, and Ms. LaConte, I 17

summarize my findings as follows: 18

A. The ROEs recommended by Mr. Coppola and Ms. LaConte are much too low and well 19

beyond that of recently authorized ROEs for other gas utilities. Mr. Uffola’s 20

recommended ROE is also too low. 21

B. There are several reasons why the ROEs recommended by the interveners are downwardly 22

biased: 23

1. Their recommendations, which I acknowledge was developed prior to the depths of the 24

COVID-19 pandemic, do not recognize the substantial increase in required returns due 25

to extremely volatile market conditions. 26


Case No. U-20642

Page 3 of 46

2. Their recommendations fail to take the interaction of financial leverage and ROE into 1

account. Both approaches that I use to consider financial risk—the overall cost of 2

capital and the Hamada method—are standard methodologies taught in MBA textbooks 3

and considered in several jurisdictions. 4

3. The interveners fail to consider relevant information about other highly regulated utility 5

companies, such as water utilities that would provide reasonable comparisons in a 6

proxy sample. Investors can and do compare returns across highly regulated utilities 7

and it’s difficult to imagine DTE Gas’ investors would require a return that is 8

substantially lower than that of highly regulated water utilities with a similar business 9

risk profile. 10

4. The recommendations of Messrs. Ufolla, Coppola, and Ms. LaConte do not reflect DTE 11

Gas’ higher level of risk. 12

C. Mr. Ufolla’s projected capital asset pricing model (“CAPM”) results in an estimated ROE 13

of 9.33%. This is approximately 150 basis points above his historical CAPM estimate. 14

Mr. Ufolla’s projected CAPM results are consistent with my reasonable range and 15

supportive of my 10.5% ROE recommendation for DTE Gas. 16

D. Mr. Ufolla and Mr. Coppola put forth a faulty implementation of the Risk Premium 17

models whereby they rely on inconsistent numbers and misinterpret data sources. This 18

produces unreliable results, which should be disregarded. 19

E. I disagree with certain approaches taken by Messrs. Ufolla, Coppola, and Ms. LaConte in 20

implementing their cost of capital models, which downwardly bias the ROE results. 21

F. Finally, I disagree with Mr. Ufolla’s and Coppola’s suggestion of reducing DTE Gas’s 22

equity ratio to 50%. This equity ratio is too low considering the risk profile of DTE Gas. 23

It is 200 basis points below the average and median equity ratio of 52% for U.S. natural 24

gas utility companies and given the current economic conditions maintaining DTE Gas’ 25


Case No. U-20642

Page 4 of 46

capital structure and a capital structure in line with that allowed other gas utilities is 1

warranted. 2

In the remainder of this rebuttal testimony, I first discuss the reasonableness of the 3

interveners’ recommendations. Second, I provide an update on the current capital markets’ 4

conditions. Third, I comment on Messrs. Ufolla, Coppola, and Ms. LaConte’s cost of 5

equity estimation approach. Fourthly, I address the criticism of my estimation approach. 6

Finally, I address recent changes in the capital markets due to the impacts of the COVID-7

19 pandemic. 8

A. SUMMARY OF RECOMMENDATIONS 9

Q7. Please summarize the recommendations. 10

A7. Figure R-1 below summarizes Messrs. Ufolla, Coppola, and Ms. LaConte 11

recommendations for the allowed ROE. 12

Figure R-1: Summary of Recommendations for DTE Gas

ROE Low Range High Range

Villadsen 10.5% 9.5% 10.75%

Ufolla 9.6% 8.9% 9.9%

Coppola 9.5% 7.6% 9.1%

LaConte 8.9% 7.1% 14.1%

Sources: Ufolla Testimony, p. 10; Coppola Testimony, p. 84; LaConte Testimony, p. 18. 13

I note that Mr. Ufolla and I agree to place DTE Gas towards the upper end of the range. 14

However, Mr. Coppola recommends a ROE above his estimated range after adding a 91 15

bps premium to account for interest rate uncertainties.1 16

B. THE MPSC STAFF, AG, AND ABATE RECOMMENDATIONS ARE TOO LOW 17

1 Coppola Testimony, p. 84.


Case No. U-20642

Page 5 of 46

Q8. What is your reaction to Messrs. Ufolla, Coppola, and Ms. LaConte’s recommended 1

ROEs and capital structures? 2

A8. They are simply too low. In 2019, the average and median allowed ROE for natural gas 3

utilities was 9.71% and 9.70% on an average and median equity percentage of 4

approximately 52 percent equity.2 Therefore, the average natural gas utility was allowed a 5

higher ROE than what was recommended by Messrs. Ufolla (range of 8.90-9.90% with a 6

recommended ROE of 9.60% at a 50% equity ratio)3, Coppola (range of 7.63-9.08% with 7

a recommended ROE of 9.5% at a 50% equity ratio)4, and Ms. LaConte (range of 7.1-8

14.1% with a recommended ROE of 8.9% at a 52% equity ratio)5. 9

I note that Mr. Ufolla’s range of ROE estimates overlaps my reasonable range of 9.5-10

10.75%. Furthermore, I agree with Mr. Ufolla in awarding a ROE in the upper half of the 11

range.6 As I discuss in my Direct Testimony and below, DTE Gas has an elevated risk 12

profile given their relatively large capital expenditure program as compared to revenues 13

when compared to other utilities. I further note that in the prevailing economic conditions, 14

market expectations have changed as discussed in Section VII below. Simply put, I find it 15

is not an appropriate time to reduce DTE Gas’ allowed ROE and equity percentage. 16

The degree to which these recommendations are too low has increased due to the financial 17

markets’ reaction to the COVID-19 pandemic. As discussed in Section VII below, market 18

volatility is extreme and the premium investors require to invest in securities that are not 19

risk-free has increased. 20

II. FINANCIAL LEVERAGE MATTERS 21

A. PRELIMINARIES 22

2 S&P Global Intelligence, Rate Case History (online version) as of January 15, 2020.

https://www.snl.com/web/client?auth=inherit#industry/pastRateCases?Type=1

3 Ufolla Testimony, p. 4.


5 LaConte Testimony, pp. 9, 18.


https://www.snl.com/web/client?auth=inherit#industry/pastRateCases?Type=1


Case No. U-20642

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Q9. What do you cover in this section of your rebuttal testimony? 1

A9. I respond to the critiques and misunderstandings of my direct testimony regarding financial 2

leverage. Specifically, I address the concerns of Messrs. Ufolla, Coppola, and Ms. LaConte 3

regarding the use of the overall cost of capital and the Hamada adjustment to account for 4

financial leverage. I also present the regulatory precedent for taking financial leverage into 5

account. Finally, I assess the impacts on Messrs. Ufolla, Coppola, and Ms. LaConte failure 6

to consider the impact of their capital structure recommendations on the required ROE. 7

Q10. Please summarize Messrs. Ufolla, Coppola, and Ms. LaConte testimonies regarding 8

financial risk. 9

A10. Collectively, Messrs. Ufolla, Coppola, and Ms. LaConte take issue with my use of the 10

after-tax weighted average cost of capital (“ATWACC”) adjustment7 and Mr. Coppola and 11

Ms. LaConte also take issue with my use of the textbook Hamada methodology.8 Specific 12

critiques of the financial risk adjustment fall into the following categories: 13

1. Market value vs. book value of capital structure: Mr. Ufolla asserts that because 14

market weights for equity are typically higher than book value, the after-tax weighted 15

average cost of capital will always result in a higher cost of equity. 16

2. Overall cost of capital: Mr. Ufolla incorrectly concludes that the after-tax weighted 17

average cost of capital methodology cannot be used to determine the cost of equity, 18

but instead is only suited for determining the overall cost of capital. 19

3. “Circular” rate making: Mr. Coppola asserts without support that “[t]he subsequent 20

calculated ROEs in new rate cases under the after-tax weighted average cost of capital 21

method would then produce even higher awarded ROEs because the after-tax 22

7 Ufolla Testimony, pp. 16-17; Coppola Testimony, p. 69; LaConte Testimony, pp. 39-40.

8 Coppola Testimony, p. 73; LaConte Testimony, p. 41. Mr. Ufolla does not directly address the Hamada

methodology.


Case No. U-20642

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weighted average cost of capital would use the higher stock market equity 1

capitalization.”9 2

4. Ignoring the textbook Hamada method: Messrs. Ufolla and Coppola largely ignore 3

the Hamada adjustment. 4

5. Regulatory precedent: Messrs. Ufolla, Coppola, and Ms. LaConte argue that the 5

financial risk adjustments lacks regulatory precedent in the U.S. 6

Q11. What is your reaction to the intervener’s critique of your leverage considerations? 7

A11. My general reaction to the above critiques is that the interveners disregard basic tenets of 8

financial theory by failing to consider the impact of leverage on the cost of equity, thereby 9

creating a downward bias in the calculated cost of equity. The specific criticisms the 10

interveners have offered in this case have numerous flaws. 11

First, for the purpose of determining the ROE for DTE Gas or any regulated company, the 12

relevant starting benchmark consists of market data such as the stock prices and estimated 13

market returns to investors in similarly risky companies—i.e. the proxy group. However, 14

the cost of equity that I estimate for the proxy group relies on market returns (except for 15

the risk premium model) and hence the estimated market returns for any one company 16

cannot be meaningfully compared to those of other companies without accounting for 17

differences in financial risk. Financial risk is measured by financial leverage which is based 18

on the same measure that was used in developing a cost of equity estimate (i.e. market 19

value). Thus, any cost of equity comparison between companies requires normalizing for 20

capital structure. These principles are not disputed by Messrs. Ufolla, Coppola, and Ms. 21

LaConte and are implicit in their discussion of DTE Gas’ risk relative to comparable 22

companies. However, what Messrs. Ufolla, Coppola, and Ms. LaConte fail to grasp is that 23

this same normalization must occur to make a market-derived ROE properly applicable to 24

a book-derived equity rate base in regulatory settings. 25



Case No. U-20642

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Second, Mr. Coppola’s assertion that accounting for financial leverage is “circular”10 is 1

unsupported and defies financial logic (let alone the fact that adjusting for financial 2

leverage is routine in some regulatory jurisdictions). As discussed below, accounting for 3

financial leverage would not lead to an increase in allowed ROE in future rate cases beyond 4

a one-time adjustment for financial leverage, all else equal. 5

Third, there are numerous regulatory precedents for the application of financial leverage 6

adjustments and the use of the after-tax weighted average cost of capital to determine return 7

on equity, as discussed further below. 8

Q12. What about Messrs. Ufolla, Coppola, and Ms. LaConte point that there is little 9

precedent for a financial risk adjustment in U.S. regulatory jurisdictions? 10

A12. Messrs. Ufolla, Coppola, and Ms. LaConte overstate this point. I provide several examples 11

of regulatory precedents in Section II.C below. 12

Q13. How do you respond to Mr. Ufolla’s assertion that because market weight for equity 13

typically higher than book value, the overall cost of capital will always result in a 14

higher cost of equity? 15

A13. Standard cost of equity estimation methods including the capital asset pricing model 16

(“CAPM”) and discounted cash flow (“DCF”) express a company’s cost of equity in 17

percentage terms per dollar of equity at the observed market capital structures. This tells 18

us the unit price of risk, but it is only the correct rate if applied to the corresponding amount 19

of equity. However, cost of service regulation (in Michigan) applies the rate of return to 20

book value and not market value, for good reasons: It is striving to give a fair return on and 21

recovery of the utility’s investment costs, not their economic value. If rates of return were 22

awarded against market value, then it would create a circular situation whereby the allowed 23

rate would either boost or suppress the market value gaining the allowance according to 24

whether it was high or low. 25



Case No. U-20642

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Most utilities have a much greater share of debt in their book capital structure than in their 1

market value capital structure, i.e., they are more leveraged in book terms. As a result, if 2

the market cost of equity were granted against the book amount (cost basis), then the utility 3

shareholders would not be earning enough to offset the risk of full cost recovery. The 4

additional debt in the book capital structure simply puts investors at risk for non-recovery. 5

The leverage adjustment in turn takes this additional leverage into account and adjusts the 6

allowed return of equity from the market measured rate just enough to ensure the risk of 7

cost recovery is compensated. Making the adjustment keeps investors whole, and the equity 8

competitive with other investment opportunities. 9

Q14. What is wrong with Mr. Coppola’s assertion of “circularity of the [after tax weighted 10

average cost of capital] process”? 11

A14. Mr. Coppola’s assertion that “the Commission should recognize the inherent circularity of 12

the [after tax weighted average cost of capital] process”11 is unsupported and wrong. Mr. 13

Coppola posits a “chain reaction” consisting of higher ROEs, higher earnings, higher stock 14

prices, and higher market-to-book ratios, all leading to still higher ROEs in the next rate 15

case. What Mr. Coppola continues to fail to recognize is that this sequence of events does 16

not continuously spiral forward, as he seems to imagine. This is because the market 17

weighted average cost of capital does not change with capital structure and is therefore 18

unaffected by explicit consideration of financial risk. By holding the market weighted 19

average cost of capital constant, all else being equal, a higher stock price would correspond 20

to a lower market return on equity, thus breaking the cycle asserted by Mr. Coppola. This 21

step-down of market returns would offset what would otherwise be increases in regulatory 22

ROEs in future rate cases. The financial risk adjustment is therefore a one-time event, all 23

else being equal. Importantly, this principle of non-circularity is also applicable to the 24

Hamada adjustment. 25



Case No. U-20642

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B. FINANCIAL ECONOMICS 1

Q15. How should capital structure be taken into account with respect to ensuring that the 2

allowed returns meet the fair return standard? 3

A15. The proportion of debt in the capital structure—also known as financial leverage—4

influences the risk borne by equity investors. For a given degree of business risk, a higher 5

proportion of debt financing increases the expected variability of equity returns. Thus, to 6

compare the fair returns of two otherwise identical firms, on a risk adjusted basis, the 7

capital structures must be taken into account. For example, if more debt is used, the greater 8

financial risk imposed by the greater financial leverage must be compensated by a 9

commensurately higher expected return on equity. Otherwise, the more leveraged firm will 10

not receive a fair return and will be at a disadvantage in the competition to attract capital 11

in equity markets. 12

Q16. Please briefly explain the relationship between leverage and the cost of equity. 13

A16. Financial risk or capital structure is a large topic in financial economics. The principle that 14

financial leverage amplifies the variability of equity returns and thereby increases the 15

financial risk to equity investors is a firmly established core principal of corporate finance. 16

It is directly connected to the Modigliani Miller proposition that, except as influenced by 17

the tax-deductibility of debt and the cost of financial distress, the value of a firm’s assets 18

is independent of its choice of financing. This intuitive framework means that some 19

measures of the overall cost of capital for firms with comparable systematic business risk 20

should be the same regardless of capital structure,12 even if the cost of the equity and/or 21

debt components of financing vary in proportion to the degree of financial leverage. 22

It is commonly recognized in finance textbooks that financial leverage impacts the cost of 23

equity for a company. A replication from a standard MBA textbook is provided below:13 24

12 Except in cases of extremely high or low leverage, where the tax and financial distress effects may dominate.

13 Jonathan Berk and Peter DeMarzo, “Corporate Finance,” Third Edition, 2013 (Berk & DeMarzo 2013), p.

492.


Case No. U-20642

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1

As Professors Berk and DeMarzo further note: 2

The levered equity return equals the unlevered equity return, plus an extra 3

“kick” due to leverage…The amount of additional risk depends on the 4

amount of leverage, measured by the firm’s market value debt-equity 5

ratio, D/E…14 (emphasis added) 6

This relationship is further illustrated in Figure R-2, reproduced from the seminal textbook 7

Principles of Corporate Finance by Brealey, Myers, and Allen. It illustrates that as capital 8

structure shifts to use a greater proportion of lower cost debt financing, the investor 9

required return on equity (and debt, especially at higher leverage ratios) increases to 10

compensate for the greater financial risk, such that the overall required return on assets 11

remain unchanged. 12

14 Berk & Peter DeMarzo 2013, p. 489. Similar comments appear in Richard A. Brealey, Stewart C. Myers,

and Franklin Allen, 2014, Principles of Corporate Finance, 11th edition, McGraw-Hill Irwin (Brealey,

Myers & Allen 2014), p. 433.


Case No. U-20642

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Figure R-2: Illustration of the Modigliani Miller Principle15

1

Financial economics simply do not leave any doubt that the cost of equity increases with 2

financial leverage and that the relevant measure of financial leverage depends on market 3

value. I—like other witnesses—estimate the cost of equity using market data in the CAPM 4

and DCF-based models. Since the Risk Premium model is based on book values, the 5

relevant leverage for this methodology is book value based. 6

Q17. Could you provide a numerical example to illustrate the impact of financial leverage 7

on cost of equity? 8

A17. Yes. As a simple example, think of an investor who takes money out of her savings and 9

invests $100,000 in real estate. The future value of the real estate is uncertain. If the real 10

estate market booms, she will realize a gain. However, if the real estate market declines, 11

she will realize a loss. Figure R-3 below provides an illustration of this: 12

15 Brealey, Myers, and Allen, Principles of Corporate Finance, 10th Ed. (2011), p. 429, Figure 17.2


Case No. U-20642

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Figure R-3: Return on an All-Equity Investment

1

Compare this to the situation illustrated in Figure R-4 below, where the investor finances 2

the same real estate purchase using 50% cash from her savings (equity) and finances 50% 3

using funds from a mortgage (debt). In this case, the variability in the investor’s expected 4

equity return is two-times greater than in Figure R-3. The entire fluctuation of 10% from 5

rising or falling real estate prices falls on the investor’s equity investment, which is smaller 6

($50,000) for the leveraged investment depicted in Figure R-4 as compared to the all-equity 7

$100,000 investment shown in Figure R-3. The equity return for the leveraged investment 8

goes up or down by 20% in the leverage scenario even though the actual change in the 9

value of the real estate (+/- 10%) is the same as depicted in Figure R-3 for the all-equity 10

investment. The lesson from this example is obvious: debt adds risk because, while there 11

is more potential gain on the equity investment by using debt, there is a higher potential 12

loss on that equity investment that goes with it. This concept is colloquially referred to as 13

“high risk, high reward.” 14

Equity Equity

- 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000

100,000 110,000 120,000 130,000 140,000 150,000

Initial Investment 10% Appreciation

or Depreciation

Buy Real Estate for $100,000 Using Only Equity

If Real Estate Prices Increase or Decrease by 10%, Gain or Lose 10%.

$90,000

$110,000

If Real Estate increases by 10% $110,000/$100,000=110%

If Real Estate falls by 10% $90,000/$100,000=90%

Changes in Equity Value: +/-10%

10% Gain in Real Estate Value 10% Gain in Equity Value

10% Loss in Real Estate Value 10% Loss in Equity Value


Case No. U-20642

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Figure R-4: Return on a Leveraged Equity Investment

1

Q18. Do finance textbooks also address the question of how financial leverage affects the 2

cost of equity? 3

A18. Yes. Standard textbooks on corporate finance provide examples, like the one I presented 4

above, to illustrate how the introduction of debt financing amplifies the variability of equity 5

returns and thus increasing the risk to equity holders which causes them to demand higher 6

expected returns. For example, Professors Brealey, Myers, and Allen write: 7

Our example shows how borrowing creates financial leverage or gearing. 8

Financial leverage does not affect the risk or the expected return on the 9

firm’s assets, but it does push up the risk of the common stock. Shareholders 10

demand a correspondingly higher return because of this financial risk.16 11

Similarly, Professors Berk and DeMarzo summarize the effect of leverage on the cost of 12

capital as follows. 13

16 Brealey, Myers and Allen (2017), Principles of Corporate Finance, 12th Edition, p. 446 (emphasis in

original).

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000

100,000 110,000 120,000 130,000 140,000 150,000

Initial Investment Change in Value

10% Loss in Real Estate Value 20% Loss in Equity Value

10% Gain in Real Estate Value 20% Gain in Equity Value

$50,000

$100,000 $110,000

$90,000

Buy Real Estate for $100,000 with a $50,000 Mortgage

If Real Estate Prices Increase or Decrease by 10%, Gain or Lose 20%.

If Real Estate increases by 10%: $110,000 - $50,000 = $60,000

$60,000/$50,000=120%

If Real Estate falls by 10%: $90,000 - $50,000 = $40,000

$40,000/$50,000=80%

Changes in Equity Value: +/-20%

Mortgage Mortgage

Equity Equity


Case No. U-20642

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…[L]everage increases the risk of equity even when there is no risk that the 1

firm will default. Thus, while debt may be cheaper when considered on its 2

own, it raises the cost of capital for equity. Considering both sources of 3

capital together, the firm’s average cost of capital with leverage is … the 4

same as for the unlevered firm.17 5

These statements by preeminent finance scholars in widely-used Corporate Finance 6

textbooks highlight two important points that can also be intuitively observed based on the 7

real estate investment example: 8

• The variability of returns on the asset itself (e.g., the piece of real estate) is unchanged 9

by the introduction of financial leverage, therefore “leverage does not affect the risk 10

or the expected return on the firm’s assets.” Rather, it is the risk and required returns 11

of the equity and debt financing instruments that are changed by the degree of 12

financial leverage. 13

• The mechanism by which leverage adds variability to returns is independent of any 14

effect of increased leverage on the risk that the firm will be unable to fulfill its fixed 15

financial obligations, and thus (as Berk and DeMarzo put it) “leverage increases the 16

risk of equity even when there is no risk that the firm will default.” 17

Q19. Do financial economist recognize the calculation of after-tax weighted-average cost of 18

capital based on market values? 19

A19. Yes. Looking to the most widely-used MBA textbook by Professor Brealey, Myers, and 20

Allen, they explain that: 21

The formula for the after-tax weighted average cost of capital is18 22

𝑊𝐴𝐶𝐶 = 𝑟𝐷(1 − 𝑇𝐶) (𝐷

𝑉) + 𝑟𝐸 (

𝐸

𝑉) 23

17 Berk and DeMarzo (2014), Corporate Finance, 3rd Ed., p. 482 (emphasis in original).

18 This specification ignores preferred shares, but such financing could easily be added.


Case No. U-20642

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where rD and rE are the expected rate of return demanded by investors in the 1

firm’s debt and equity securities, D and E are the current market values of 2

debt and equity and V is the total market value of the firm (V = D + E).19 3

Professors Brealey, Myers, and Allen then show that the after-tax weighted average cost 4

of capital is flat over a broad range of capital structures and calculates the cost of equity 5

using the same formula as I do.20 6

Q20. Do financial economists recognize the Hamada technique? 7

A20. Yes. The Technical Appendix (Appendix B) to my direct testimony provides a detailed 8

description of the standard textbook formulas used to implement the Hamada technique for 9

unlevering measured equity betas based on the proxy companies’ capital structure to 10

calculate “asset betas” that measure the proxy companies’ business risk independent of the 11

financial risk imposed by differing capital structures. I also note that standard MBA 12

textbooks,21 practitioner texts22 as well as the CFA manual23 all describe the Hamada 13

approach and use formula like those relied upon in my direct testimony. Thus, the Hamada 14

method is simply a well-established methodology taught in business schools as well as to 15

CFA applicants. 16

Q21. What are the implications for these fundamental financial principles for Messrs. 17

Ufolla, Coppola, and Ms. LaConte’s ROE results? 18

A21. Failing to recognize the impact of financial leverage on the cost of equity results in a non-19

trivial downward bias in the cost of equity estimates. This can readily be illustrated by 20

looking to the differences in sample betas obtained at an assumed capital structure for the 21

proxy group utilizing the same beta at their recommended equity ratio. This is shown in 22

19 Brealey, Myers and Allen (2014), p. 501. TC is the corporate tax rate. (emphasis in original)

20 Brealey, Myers and Allen (2014), p. 492.

21 Brealey, Myers and Allen (2014), pp. 492-493, Berk and DeMarzo (2014) pp. 415-417, Ross, Westerfield

and Jaffe (2013), pp. 571-573.

22 Roger A. Morin, “New Regulatory Finance,” Public Utilities Reports, Inc., 2006, pp. 221-225; Leonardo R.

Giacchino and Jonathan A. Lesser, “Principles of Utility Corporate Finance,” Public Utilities Report, Inc.,

2011, pp. 229-232.

23 See, for example, 2016 CFA Level I Volume 4: Corporate Finance and Portfolio Management, Chapter 4.


Case No. U-20642

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Figure R-5 below, where I calculate first the asset (or zero debt financing) beta using the 1

betas provided by the interveners along with an assumed market value capital structure for 2

the proxy group. Next, I calculate the re-levered beta that is consistent with an equity ratio 3

of 50%. By failing to account for these fundamental financial principles, it is evident that 4

the estimates provided by the interveners are downwardly biased by 109 to 125 basis 5

points. 6

Figure R-5: Illustrative Impact of the Leverage Adjustment

7

This approach in Figure R-5 is exactly as described in standard textbooks such as Brealey, 8

Myers and Allen (2014), Berg and DeMarzo (2014), and Ross, Westerfield and Jaffe 9

(2013).24 10

Q22. What do you conclude from the discussions above? 11

A22. Overall, I conclude that Messrs. Ufolla, Coppola, and Ms. LaConte’s ROE estimates are 12

both inaccurate and downwardly biased by failing to account for financial leverage on the 13

cost of equity utilizing standard financial techniques. 14

C. PRECEDENTS 15

Q23. How do you respond to the criticism that adjusting for financial leverage has no 16

regulatory precedent? 17

A23. I disagree. Multiple regulatory agencies in the U.S. and most outside of North America 18

have adopted a similar approach. 19

24 Brealey, Myers and Allen (2014), pp. 492-493, Berk and DeMarzo (2014) pp. 415-417, Ross, Westerfield

and Jaffe (2013), pp. 571-573. In all cases, they apply the Hamada method to the market value capital

structure.

Levered

Beta

Assumed

Debt Beta

Market

Equity

Asset

Beta

Recommended

Debt%

Equity

Beta

[1] [2] [3] [4] [5] [6]

Recommendations

Coppola Levered Beta 0.66 0.05 66% 0.49 50% 0.82

LaConte Levered Beta 0.64 0.05 66% 0.48 52% 0.82 6.91% 9.45% 1.24% - 1.21%

Ufolla Levered Beta 0.67 0.05 66% 0.50 50% 0.83 7.16% 9.30% 1.15% - 1.25%

MRP (lowest and

Highest)

Increase in ROE at

Recommended MRP

[7] [8]

6.91% 1.09%


Case No. U-20642

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In the U.S., the Federal Communications Commission (“FCC”), the Surface Transportation 1

Board (“STB”) and the FERC have accepted the use of weighted-average cost of capital 2

methodologies to determine the cost of capital. Specifically, the FCC in a 2016 order 3

acknowledged that it is reasonable (1) to use market values to estimate the capital structure 4

and (2) derive an implied return on equity from the estimated weighted average cost of 5

capital.25 Thus, the FCC acknowledged that market value capital structures are the relevant 6

measure of leverage and impact the ROE using an approach similar to what I used. The 7

FERC, in Cost of New Entry (“CONE”) studies for the PJM,26 has used the weighted 8

average cost of capital and the Surface Transportation Board calculates the weighted 9

average cost of capital to assess the revenue adequacy for freight railroads.27 Finally, the 10

Alabama Public Service Commission has found the method “compelling”: 11

[t]he Commission recognizes that the [after tax weighted average cost of 12

capital] analysis is not a prevalent methodology in the United States; 13

however, the focus of that methodology on the relationship between the 14

market value and the associated financial risk of the utility is compelling.28 15

Considering next the Hamada approach, I note that the California Public Utilities 16

Commission in the past has relied on results from the method,29 the Oregon Public Service 17

Commission staff commonly relies on a version of the Hamada method to assess the impact 18

25 Federal Communications Commission, “Report and Order, Order and Order on Reconsideration, and Further

Notice of Proposed Rulemaking,” FCC 16-33, issued March 30, 2016 ¶270 and ¶ 322.

26 Federal Energy Regulatory Commission, “Order Conditionally Accepting Tariff Revisions Subject to

Compliance Filing,” Docket ER14-2940-000, November 28, 2014, ¶59.

27 See, for example, Surface Transportation Board, “Docket No. EP 558 (Sub-No. 18), dated August 6, 2015,

p. 15.

28 Report and Order, In re: Public Proceedings established to consider any necessary modifications to the Rate

Stabilization and Equalization mechanism applicable to the electric service of Alabama Power Company,

Dockets 18117 and 18416, August 21, 2013, p. 20.

29 The California Public Utilities Commission (“CPUC”) relied on Hamada unlevered / relevered data in D.12-

12-034 at. 38. Here the CPUC pointed to Southern California Edison’s CAPM results and ROE range of

9.73 percent to 11.71 percent, which was derived using the Hamada adjustment.


Case No. U-20642

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of leverage on the cost of equity,30 and the Florida Public Service Commission uses an 1

equivalent methodology to determine the ROE for small water utilities. 31 2

o The cost of equity is an exponential function of the equity ratio but a linear function 3

of the debt to equity ratio over the relevant range; 4

o The marginal weighted average cost of investor capital is constant over the equity 5

ratio range of 40 percent to 100 percent. 6

Looking outside the U.S., Mexico’s Comisión Reguladora de Energía32 relies on the 7

Hamada method, while regulators in the U.K., the Netherlands, Australia, and New 8

Zealand rely on a mixture of an after-tax weighted average cost of capital and the Hamada 9

method.33 10

Q24. Are the methods “unorthodox” in utility regulation? 11

A24. No. While not all methods I rely upon are widely used by regulatory commissions, several 12

regulatory entities have found the methods used in financial economics to consider 13

leverage useful. Several of the adoptions are relatively new in that the FERC (for CONE 14

studies) and the FCC only adopted the leverage adjustment within the last five years. Thus, 15

these jurisdictions have moved towards accepting the importance of leverage. The methods 16

are also standard curriculum in finance textbooks and commonly used by practitioners who 17

provide cost of capital measures.34 18

30 Opening Testimony of Matt Muldoon in Docket No. UE 319, Staff Exhibit 500, p. 15.

31 Florida PUC for water and wastewater utilities (Order No. PSC-12-0339-PAA-WS); “Florida 2012 Order”),

p. 4. 32 CRE, “Directiva sobre la determinación de tarifas y el traslado de precios para las actividades reguladas en

materia de gas natural DIR-GAS-001-2207.”

33 Villadsen, Bente et. al, “Risk and Return for Regulated Industries,” Academic Press, 2017, Chapter 9 and

references herein.

34 For an example of a commercial data provider’s application, see Duff & Phelps, “2019 Valuation Handbook

– U.S. Guide to Cost of Capital,” Chapter 1 pp. 1-21 For examples of tax authorities applications, see, for

example, Utah Rule R884-24P-62 “Valuation of State Assessed Unitary Properties Pursuant to Utah Code

Ann. Section 59-2-201”, which states “The discount rate (k) shall be based upon a weighted average

cost of capital (WACC) considering current market debt rates and equity yields.”

(https://rules.utah.gov/publicat/code/r884/r884-24p.htm#T32)


Case No. U-20642

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III. OTHER RISK MATTERS 1

Q25. Please summarize Ms. LaConte’s argument related to DTE Gas’ Adjustment 2

Clauses? 3

A25. Ms. LaConte asserts that DTE Gas has a lower level of financial risk due to its “piecemeal 4

cost recovery clauses” and revenue decoupling which allow it automatically adjust rates 5

and recover costs.35 Ms. LaConte states that DTE recovers 37% of its costs through 6

surcharges and cost recovery factors.36 She concludes that these mechanisms afford DTE 7

Gas a lower risk profile since they shift risk from shareholders to ratepayers. 8

Q26. How do you respond to these arguments? 9

A26. Ms. LaConte’s arguments are misguided. Adjustment clauses are common regulatory 10

mechanisms utilized to reduce regulatory lag and allow utilities to recover costs on a timely 11

basis. Like many utilities, DTE Gas benefits from supportive regulatory policies such as 12

forward test years, revenue decoupling, and adjustment clauses which reduce the risk of 13

regulatory lag. In fact, the number of adjustment clauses awarded to DTE Gas is in line 14

with number of adjustment clauses awarded to other Michigan utilities and other utilities 15

across the country as shown in Figure R-6 below. 16

I understand it is common for taxes based on net present values to use a market-value based after-

tax weighted-average cost of capital as the discount rate. 35 LaConte Testimony, p. 11.

36 Id. p. 12.


Case No. U-20642

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Figure R-6: Regulatory Adjustment Clauses

1

IV. WATER UTILITIES IN PROXY SAMPES 2

Q27. Did Messrs. Ufolla, Coppola, and Ms. LaConte consider companies other than 3

natural gas utilities in their proxy sample? 4

A27. No. Messrs. Ufolla, Coppola, and Ms. LaConte only considered companies included in 5

Value Line’s “natural gas utilities industries” segment.37 6

Q28. What criticisms did Messrs. Ufolla, Coppola, and Ms. LaConte raise concerning your 7

inclusion of water utilities in your proxy group? 8

A28. Mr. Ufolla’s stated that the water utilities included in my proxy sample “are not similar to 9

DTE Gas” and do not experience similar risks to natural gas utilities.38 Mr. Coppola raises 10

concerns related to water utilities size relative to gas utilities which also makes them targets 11

of acquisitions. Mr. Coppola also asserts that water utilities do not face the same structural 12

risks as gas utilities such as state mandated energy conservation programs and pipeline 13

ruptures.39 Ms. LaConte simply criticizes the water utilities as “not comparable to a natural 14

gas utility.”40 15

Q29. How do you respond to these criticisms regarding the inclusion of water utilities in 16

your proxy group? 17

37 Ufolla Testimony, p. 13, Coppola Testimony, p. 63, LaConte Testimony, p. 20.

38 Ibid.

39 Coppola Testimony, pp. 64-65.

40 LaConte Testimony, p. 23.

# of adjustment clauses

DTE Gas 4.00

All Michigan 3.56

All US Utilities 4.04

Source: S&P Global Markets Intelligence, 2019


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A29. As discussed extensively in my Direct Testimony I developed my proxy group utilizing 1

companies with similar business risk profiles as DTE Gas, namely their operations are 2

concentrated in regulated industries or have similar lines of business and/or business 3

environments.41 The companies in my proxy group also share many characteristics with 4

DTE Gas, namely (a) in most jurisdictions, natural gas and water utilities share the same 5

regulators;42 (b) both have networked assets; (c) both have obligations to serve; (d) both 6

industries serve a mixture of residential, commercial, and industrial customers, and, (e) 7

both industries are capital intensive. I continue to find that water utilities provide a relevant 8

proxy for the risk profile of natural gas utilities including DTE Gas. 9

Messrs. Ufolla and Coppola’s assertions that significant structural and risk profile 10

differences exist between the two industries are simply incorrect and misguided. For 11

example, Mr. Coppola says that natural gas companies are facing state mandated energy 12

conservation programs, whereas water utilities are not subject to similar conservation 13

programs except in arid areas in the west coast. However, a recent survey of state 14

conservation laws found that 30 states have urban water conservation programs.43 In 15

addition, an industry survey of 383 water utilities across the US and Canada found that 282 16

utilities (74%) have formal water conservation or water use efficiency programs for their 17

commercial, industrial, or institutional customers.44 With the natural gas industry rapidly 18

changing and being forced to reduce its carbon footprint through conservation programs, 19

water utilities are an appropriate low-carbon utility proxy group with very similar business 20

operations characteristics including those related to conservation. 21

Mr. Coppola’s assertion that water utilities do not face the same risk of main ruptures is 22

also incorrect—water utilities face significant risk from water mains breaks. While I 23

41 Villadsen Direct Testimony p. 35

42 I recognize that the Commission does not regulate water utilities, but in 43 of the 50 states the same

commissions that regulate electric and gas utilities also regulate water utilities.

43 Alliance for Water Efficiency, “Water Efficiency and Conservation State Scorecard,” December 12, 2017,

p. 8.

44 American Water Works Association, “2016 National Survey of CII Water Efficiency Programs,” 2016, p.

2.


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acknowledge that the consequences of a gas main rupture is different from a water main 1

rupture, both industries are aggressively spending their capital expenditure budgets to 2

replace aging infrastructure and prevent ruptures. Similar to natural gas companies, these 3

capital intensive replacement programs are subject to regulatory oversight. 4

Regarding Mr. Coppola’s concern that water utilities are smaller than DTE Gas, the size 5

studies by, for example, Duff & Phelps would indicate that the CAPM and DCF models 6

applied to such companies are under estimated.45 7

V. MESSRS. UFOLLA, COPPOLA, AND MS. LACONTES APPROACHES TO COST 8 OF EQUITY ESTIMATION 9

A. OVERALL APPROACH 10

Q30. How do Messrs. Ufolla, Coppola, and Ms. LaConte approach estimating the cost of 11

equity for DTE Gas? 12

A30. Messrs. Ufolla, Coppola, and Ms. LaConte each select a proxy group of natural gas utilities, 13

similar to the natural gas utilities I consider in my sample. As previously discussed in 14

Section IV, none of the other witnesses considered other highly regulated utilities, such as 15

water utilities, in their proxy groups. After determining their proxy group, each witness 16

utilized versions of the CAPM, DCF, and Risk Premium models to estimate a return on 17

equity for DTE Gas. As discussed in Section II, neither Messrs. Ufolla, Coppola, nor Ms. 18

LaConte utilized standard financial techniques to consider the impacts of financial leverage 19

in their analyses. 20

B. SAMPLE SELECTION 21

Q31. What are the differences between Messrs. Ufolla, Coppola, and Ms. LaConte’s proxy 22

groups and your proxy group? 23

A31. Mr. Ufolla’s proxy group is much smaller—composed of only 9 companies—compared to 24

my proxy group (14 companies) because he does not consider other regulated utilities, such 25

45 Duff and Phelps / Ibbotson, “SBBI 2018 Classic Yearbook,” Chapter 7.


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as water utilities. The gas utilities that Mr. Ufolla considers is largely consistent with the 1

gas utilities that I consider, except Mr. Ufolla disregards Chesapeake Utilities for having a 2

below investment grade rating from Moody’s;46 Mr. Ufolla also includes UGI Corp. in his 3

sample. Reviewing Chesapeake Utilities credit history, I have found no evidence of the 4

company having a below investment grade ratings from Moody’s as Mr. Ufolla states. 5

Instead, I find that they are currently not rated by S&P or Moody’s. However, reviewing 6

the financial reports of Chesapeake Utilities, they would most likely receive an investment 7

grade rating if they were rated and their 2019 10-K explicitly states that the company is 8

“committed to maintaining a sound capital structure and strong credit ratings.”47 9

Mr. Coppola’s proxy group is even smaller and only contains 8 utilities. Mr. Coppola 10

utilizes Value Line Investment survey to identify natural gas utilities and then he removes 11

two companies—UGI due to its sizable foreign business operations and Chesapeake 12

Utilities due to its small size and having revenue of “approximately $600 million in 2018” 13

and because less than 50% of its revenues come from regulated operations.48 Mr. Coppola 14

provides no reasoning why a company should be excluded for having revenues of $600 15

million. Furthermore, Mr. Coppola inconsistently includes Northwest Natural in his proxy 16

group,49 which had annual revenues of comparable size to Chesapeake Utilities.50 17

Chesapeake Utilities’ annual revenue in 2019 was $700 million and Northwest Natural’s 18

annual revenue in 2019 was $727 million. Lastly, Mr. Coppola’s assertion that Chesapeake 19

Utilities business operations lay outside of regulated operations is simply incorrect. As 20

46 Ufolla Testimony, p. 13, lines 12-13. While Chesapeake Energy Corporation (CHK) has a non-investment

grade rating from Moody’s, Chesapeake Utilities (CPK) has no rating from Moody’s Investor Service as of

March 2020. Source: Moody’s Investor Service website. It is also noteworthy that Chesapeake Utilities

issued uncollateralized Senior Notes at an interest rate of 2.98 percent in December 2019 according to

Chesapeake Utilities 2019 10-K, p. 35. This is an interest rate much in line with that of an investment grade

entity.

47 Chesapeake Utilities 2019 10-K, p. 35.


49 Coppola Testimony, Public Exhibits AG-23.

50 Villadsen Testimony, Figure 12, p. 39.


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shown in Figure 12 of my Direct Testimony, over 80% of Chesapeake Utilities’ assets are 1

dedicated to regulated activities. 2

Ms. LaConte’s proxy group is even smaller with only 5 utilities. Ms. LaConte also starts 3

with companies classified as natural gas utilities by Value Line. She then excludes 4

companies based on a consistent dividend history; coverage by multiple equity analysts; 5

greater than 50% of revenues from natural gas operations; positive earnings estimates from 6

Value Line, Yahoo! Finance, and/or Zack’s Investment Research; and no merger or 7

acquisition activities in the prior six months.51 8

Q32. Do you agree with Mr. Coppola and Ms. LaConte’s focus on regulated operating 9

revenues to exclude companies? 10

A32. No. Regulated utilities are capital intensive entities that operate long-lived assets. 11

Therefore, the relevant measure of the degree to which a utility is in a specific industry best 12

measured by assets devoted to the industry. Income and revenue even more so can vary 13

substantially year over year and therefore this measurement may cause an entity to switch 14

industry from year to year. This is even more problematic if a single year of revenue or 15

operating income is used as is the case for Mr. Coppola.52 It is also worth noting that 16

Chesapeake Utilities “must maintain an aggregate net book value in [its] regulated business 17

assets of at least 50.0 percent of [the Company’s] consolidated total assets”53 to meet its 18

debt covenants. Thus, Chesapeake Utilities’ lenders are concerned about assets – not 19

revenue or income. 20

C. COST OF EQUITY ESTIMATION METHODS 21

CAPM 22

Q33. How do Messrs. Ufolla, Coppola, and Ms. LaConte implement the CAPM? 23

51 LaConte Testimony p. 20.

52 Coppola Testimony, Exhibit AG-26, p. 1 of 1.

53 Chesapeake Utilities 2019 10-K, p. 35.


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A33. All three witnesses use a forecasted risk-free rate based on long-term government bond 1

yields are current beta estimates based on Value Line data. Messrs. Ufolla, Coppola, and 2

Ms. LaConte used historic market equity risk premiums (MRP) in their analysis, however 3

Ms. LaConte also considers a forecasted MRP and Mr. Ufolla evaluates the CAPM under 4

both historical and forecasted MRPs. 5

Q34. What estimates for the projected risk-free rate do the other witnesses rely on? 6

A34. Mr. Ufolla relied on projected treasury bond yields from IHS Markit over the last quarter 7

to derive a projected risk-free of 2.540% for 2020 and 3.077% for 2021, which he then 8

weighs to arrive at 2.943%.54 Mr. Coppola utilizes IHS Markit’s forecasted 10-year U.S. 9

Treasury bond yield and then added a 50 basis point spread to account for the historical 10

spread between 30-year and 10-year U.S. Treasury Bonds.55 Similarly, Ms. LaConte uses 11

the projected 30-year U.S. Treasury bond yield.56 I agree with the witnesses that a 12

forecasted risk-free rate based on long-term Treasury bond yields is appropriate. I also 13

agree with Mr. Coppola that it is not appropriate to determine a cost of equity estimate 14

utilizing information from the current, temporary unusual market conditions.57 As 15

discussed in Section VII, current government bond yields are at historic lows and should 16

not be considered to determine a fair return for DTE Gas. I continue to find my estimate 17

for the CAPM reasonable based on the time period at which I performed my analysis. 18

Q35. Do you agree with Mr. Ufolla’s implementation of the CAPM? 19

A35. No. My primary concern with Mr. Ufolla’s CAPM implementation is his failure to consider 20

the impact financial leverage has on the cost of equity. As discussed extensively in Section 21

II, the failure to consider financial leverage results in an inaccurate cost of equity estimate 22

which does not meet the fair return standard, particularly the comparability aspect. I also 23


55 Coppola Testimony, p. 72




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disagree with Mr. Ufolla’s assertion that the risk-free rates utilized in my CAPM 1

implementation is too high.58 I utilized the most recent forecasted 10-year government 2

yields bond available from Blue Chip Economic Forecast at the time of estimation. To that 3

I added 50 basis points to account for the typical spread between 10 year and 20 year 4

government bond yields. This spread adjustment is similar in size to that used by the other 5

witnesses. I do agree with Mr. Ufolla’s use of a projected CAPM.59 The cost of capital is a 6

forward-looking measure and therefore the estimation models require forward-looking 7

inputs. I find it notable that Mr. Ufolla’s projected CAPM produced an estimate 8

significantly (about 150 basis points) higher than Mr. Ufolla’s other CAPM estimate. 9

Q36. Do you agree with Mr. Coppola’s implementation of the CAPM? 10

A36. Not entirely. I have two concerns. My main concern with Mr. Coppola’s implementation 11

of the CAPM is his failure to recognize the importance of financial risk. Second, I disagree 12

with his reliance on historical data only for the MRP60 and I do not understand Mr. 13

Coppola’s statement that my forecasted MRP of 7.91 percent is “based upon witness 14

Villadsen’s opinion that MRP rates have escalated since the 2007-2008 financial crisis.”61 15

I explicitly discuss the forward-looking MRP and the data supporting an MRP well above 16

the historical average on pages 22-25 of my Direct Testimony citing recent Bloomberg 17

data and FERC precedents for a forecasted MRP of over 9 percent. As I discuss in Section 18

VII, the current MRP under FERC’s methodology is well above 9 percent. Thus, there is 19

clearly both theoretical support62 and regulatory precedent for using a forecasted MRP and 20

the current forecasts are non-trivially higher than the historical MRP. 21

Q37. Do you agree with Ms. LaConte’s implementation of the CAPM? 22


59 Ibid, pp. 20-21.


61 Ibid. pp. 76-77

62 See, for example, the Duarte and Rosa article cited in the Villadsen Direct Testimony, pp. 24-25.


Case No. U-20642

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A37. My main concern with Ms. LaConte’s analyses is that she also ignores the impacts of 1

financial leverage in her implementation of the CAPM. Secondly, Ms. LaConte’s 2.74% 2

estimate of the risk-free rate is the lowest amongst the witnesses. Ms. LaConte derived her 3

risk-free rate using Blue Chip’s forecast for 2021 and added the average maturity premium 4

of the 30-year Treasury bond over the 10-year Treasury bond.63 As rates are likely to be 5

in place beyond 2021, the reliance on a forecast for 2021 is likely to downward bias her 6

forecasted risk-free rate and hence the CAPM estimate. 7

Ms. LaConte also incorrectly asserts that lower government bond-yields will more than 8

offset the currently high MRP, thereby resulting in a net reduction to the estimated ROE.64 9

This is much too simple. As discussed in my Technical Appendix, yield spreads on 10

corporate bonds is a combination of a default premium, a tax premium, and a systematic 11

risk premium with the systematic risk premium explaining the vast majority of the yield 12

spread increases.65 In other words, unless the risk-free rate is underestimated, the market 13

equity risk premium is elevated relative to its “normal” levels. For example, assuming a 14

beta of 0.25 for A rated debt means that an increase in the market equity risk premium of 15

one percentage point translates into a ¼ percentage point increase in the risk premium on 16

A rated debt (i.e., 0.25 (beta) times 1 percentage point (increase in market equity risk 17

premium) = ¼ percentage point increase in yield spread). Thus, a 25 bps increase in the 18

yield spread is therefore consistent with a one percentage point increase in the market 19

equity risk premium. Therefore, the decrease in the risk-free rate will not more than offset 20

increases in the market equity risk premium. 21

DCF 22

Q38. How do. Messrs. Ufolla, Coppola, and Ms. LaConte implement the DCF model? 23

63 LaConte Testimony, p. 32 and Exhibit AB-8.

64 Ibid, p. 32.

65 “Explaining the Rate Spread on Corporate Bonds,” Edwin J. Elton, Martin J. Gruber, Deepak Agarwal, and

Christopher Mann, The Journal of Finance, February 2001, pp. 247-277.


Case No. U-20642

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A38. Messrs. Ufolla, Coppola, and Ms. LaConte all use the single-stage (constant growth) DCF 1

model, as do I. However, their implementation of the single-stage DCF model utilizes 2

annualized dividend yields and growth rates, where I use quarterly dividend yields and 3

growth rates. Ms. LaConte also utilizes a multi-stage DCF model, as do I. 4

Q39. Do you agree with Mr. Ufolla’s implementation of the DCF? 5

A39. No. First, Mr. Ufolla fails to account for the full growth rate in his calculation of the 6

expected dividend yield. In his implementation, he calculates the dividend yield (D1/P0) as 7

𝐷1

𝑃0= 𝐷0 × (1 + 0.5𝑔)/𝑃0 8

Where Dt is the dividend at time t, Pt is the price at time t and g is the growth rate.66 This 9

0.5 growth rate adjustment factor implies an assumption that dividends are paid quarterly, 10

but are grown on an annual basis with growth occurring on average during the middle of 11

each year. However, the full amount of the “adjusted” dividend is still assumed to reach 12

investors at the end of the first year. By delaying the growth and timing of dividends, Mr. 13

Ufolla’s use of a 0.5 growth rate adjustment in the annualized model artificially lowers his 14

ROE estimate. 15

Second, similar to Ms. LaConte, Mr. Ufolla utilizes growth rates sources from Value Line, 16

Yahoo! Finance, and Zack’s Investment Research.67 I disagree with this approach because 17

of the substantial overlap of equity analyst opinions when averaging across all the services. 18

While Value Line is a separate independent provider of financial data, Yahoo! Finance and 19

Zack’s rely on averages of estimates provided by equity analyst to publish a “consensus” 20

forecast. Since some equity analysts may provide their estimates to multiple financial data 21

providers, averaging across multiple consensus based services will overly weight the 22

estimates of certain analyst. This will bias Mr. Ufolla’s growth estimate to the degree that 23

these equity analyst estimates are higher or lower than the consensus average. 24

66 Ufolla Testimony, Exhibit S-4, Schedule D-5, p. 3-5.

67 Id, p. 15.


Case No. U-20642

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Q40. How about Mr. Coppola’s implementation of the DCF? 1

A40. Mr. Coppola also relies upon an annualized version of the DCF model which delays the 2

estimated payment of dividends to investors, which underestimates the cost of equity. 3

Q41. Do you have any comments regarding Ms. LaConte’s implementation of the DCF? 4

A41. In her single-stage and multi-stage implementations of the DCF, Ms. LaConte also relies 5

upon annualized dividend growth rates, which as previously discussed, downwardly biases 6

the cost of equity estimate. Similar to Mr. Ufolla, Ms. LaConte also incorrectly averages 7

growth rates from Value Line, Yahoo! Finance, and Zack’s, which over weights the 8

opinions of analysts who provide estimates to multiple services.68 Ms. LaConte also relies 9

on stock prices from February 10, 2020 through March 10, 2020 and growth rates 10

downloaded from a similar time.69 This period marks the beginning of the unprecedented 11

market conditions as discussed in Section VII which makes her DCF estimates anomalous 12

and, in isolation, not appropriate comparators for the forward looking cost of capital 13

estimation. 14

Risk Premium Model 15

Q42. Please summarize the Risk Premium model implemented by Messrs. Ufolla, Coppola, 16

and Ms. LaConte? 17

A42. Mr. Ufolla calculates three risk premium estimates. Two approaches examine the spread 18

between natural gas utility equity returns and utility bond returns and a third approach 19

examines the spread between utility equity returns and U.S. Treasury bond returns.70 Mr. 20

Ufolla finds ROE estimates of 7.38% to 8.34% based on these approaches. 21

Mr. Coppola utilizes a similar approach and relies upon a projected risk-free rate of 3.10%; 22

the historic spread between natural gas utility equity returns and the 30 year U.S. Treasury 23


69 Ibid.



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bond rate; and the historical spread between natural gas utility equity returns and natural 1

gas utility bonds. Mr. Coppola estimates a ROE of 8.55% utilizing his implementation of 2

the Risk Premium model.71 3

Ms. LaConte estimates the ROE by combining the project return on long-term government 4

bond yields of 2.74% and the historical risk premium of 5.62%. Similar to my analysis, 5

Ms. LaConte uses the spread between historical authorized return on equities for natural 6

gas utilities and the historical yield on 30-year U.S. Government bonds as the risk premium. 7

Ms. LaConte arrives at a ROE estimate of 8.36%.72 8

Q43. Do you agree with Mr. Ufolla’s implementation of the Risk Premium model? 9

A43. No. Mr. Ufolla attempts to review the “average natural gas market return[s]” by utilizing 10

the Dow Jones Utilities index from 2001 to 2019.73 However, the Dow Jones Utility index 11

is not a pure-play natural gas index and includes several electric utilities and water utilities, 12

including American Water Works, First Energy, American Electric Power, and NextEra 13

Energy.74 This index simply does not measure what Mr. Ufolla asserts it measures; instead 14

it measures the market return on a group of large utilities. Secondly, Mr. Ufolla calculates 15

the historical risk premium of 3.97% based on the spread between the Dow Jones Utility 16

index and A-rated utility bond yields. He then calculates a premium derived from the 17

historic A-rated utility bond yields and then adds it to the current Baa-rated utility bond 18

yields. From this, he arrives at his Risk Premium model ROE result of 7.76%. As Mr. 19

Ufolla admits, this is a mismatch but yet he still combines the two non-comparable data 20

points. From beginning to end, Mr. Ufolla’s Risk Premium model has many issues and 21

should be disregarded. 22

Q44. Do you agree with Mr. Coppola’s implementation of the Risk Premium model? 23



73 Ufolla Testimony, p. 24, lines 6-9.

74 Yahoo! Finance, Down Jones Utilities Average Components, accessed March 31, 2020

https://finance.yahoo.com/quote/%5EDJU/components/

https://finance.yahoo.com/quote/%5EDJU/components/


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A44. No. Mr. Coppola’s implementation relies on an unusual and unnecessary two-step 1

methodology. He adds the average spread between utility bond yields and government 2

bond yields to his projected risk-free rate. He conflates his estimated spread by averaging 3

the spread of A-rated and BBB-rated utility bonds to U.S. Treasury yields. Next, Mr. 4

Coppola adds this spread to the historical average premium of utility stock returns over 5

utility bond yields. If his intention is to add a historical risk premium to his risk-free rate, 6

then he could have done so by using a simpler and more direct method of by utilizing the 7

historical premium relative to government bonds. 8

Q45. Do you agree with Ms. LaConte’s implementation of the Risk Premium model? 9

A45. Not entirely. I agree with Ms. LaConte’s use of authorized return on equities as I did.75 In 10

my Direct Testimony, I discuss how this approach measures the cost of equity for the 11

regulated entity and not the holding company and that these allowed returns are readily 12

observable by market participants.76 However, Ms. LaConte calculates her risk premium 13

by using 30-year bond yields. Ms. LaConte then utilizes a simple averaging of the 14

differences between the average authorized ROEs and the annual 30-year bond yield 15

whereas I take a more rigorous statistical approach utilizing ordinary least squared 16

regression to estimate the risk premium.77 17

Conclusions Regarding Model Implementations 18

Q46. What do you conclude regarding Messrs. Ufolla, Coppola, and Ms. LaConte model 19

implementations? 20

A46. First, I reiterate my arguments from Section IV that other highly regulated companies, such 21

as water utilities provide relevant comparisons for DTE Gas. I also object to the 22

unnecessary and inconsistent application of restrictions when screening for proxy group 23

companies. This has resulted in the elimination of companies such as Chesapeake Utilities 24

75 LaConte Testimony, pp. 32-33.

76 Villadsen Testimony, p. 55.

77 Ibid.


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from Mr. Ufolla’s and Mr. Coppola’s proxy groups despite the company’s size being 1

equivalent to other proxy companies and its debt being priced similar to other investment 2

grade utilities. I also object to Mr. Coppola’s and Ms. LaConte’s focus on regulated 3

revenues to eliminate companies when regulated assets is a more appropriate metric for 4

comparing business risk. 5

Second, I find that the currently very volatile financial markets and uncertainty regarding 6

DTE Gas’ load and potential bad debt merits an authorized ROE towards the upper end of 7

what the implementation of models can calculate to ensure risk-averse investors continue 8

to find the Company attractive. 9

Thirdly, I find issue that none of the witnesses considered financial leverage in their 10

analysis. As discussed in Section II, account for financial leverage is a standard financial 11

technique taught in MBA textbooks, the CFA program, and used in other regulatory 12

jurisdictions. By failing to consider financial leverage, Messrs. Ufolla, Coppola, and Ms. 13

LaConte’s estimates are downwardly biases and do not meet the fair return standard. 14

Fourth, I emphasize that the ROE is a forward-looking measure that is estimated based on 15

projected (forward-looking inputs) rather than historical (backward-looking) inputs. Mr. 16

Ufolla implemented a projected CAPM that results in an ROE estimate of 9.33%.78 This 17

estimate is over 150 basis points above his historical/backwards looking CAPM 18

implementation. Mr. Ufolla’s project CAPM results are consistent with my reasonable 19

range and supportive of my 10.5% ROE recommendation for DTE Gas. 20

Fifth, I find issue with Mr. Ufolla and Mr. Coppola’s implementation of the DCF which 21

utilizes annualized dividend growth. As discussed above, this in effect delays receipt of 22

dividends by investors and downwardly biases the results of the DCF models. 23

Sixth, Mr. Ufolla and Mr. Coppola make errors or inappropriate assumptions in the 24

implementation of their Risk Premium model. As previously discussed, the errors are 25



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related to incorrect comparisons and misinterpretation of data sources. I find that the results 1

from their implementations have many issues and should be disregarded. 2

Lastly, based on my analysis of the calculations of the Ufolla, Coppola, and LaConte 3

testimonies, I find that their implementation of the models downward bias the cost of equity 4

by approximately 90 to 160 basis points. 5

VI. RESPONSE TO CRITIQUE OF ECAPM 6

Q47. Are there other issues you want to respond to in this rebuttal testimony? 7

A47. Yes. In addition to the topics addressed in Section 0, I address the critique of using an 8

Empirical Capital Asset Pricing Model (“ECAPM”). 9

Therefore, I respond to (i) the Coppola and Ufolla Testimonies’ argument that the ECAPM 10

is unnecessary because most witnesses uses a long-term risk-free rate,79 (ii) the LaConte 11

and Ufolla Testimonies critique that the ECAPM is not needed when using adjusted betas,80 12

and (iii) the Coppola Testimony’s argument that the ECAPM methodology is not widely 13

accepted.81 14

Q48. How do you respond to the argument that the ECAPM is unnecessary because 15

witnesses use long-term risk-free rates? 16

A48. I disagree. As discussed in the response to JEU-1-31, the empirical value of alpha was 17

estimated to be in the range of 1% to 7.32%. I choose an alpha value in the lower half of 18

that range, in part, to take into account the use of long-term risk-free rates. Addressing Mr. 19

Coppola’s statement that “the classic CAPM typically uses short-term treasury rates as the 20

risk-free rate,”82 I take the use of the long-term risk-free rate into account as it reduces the 21

size of the alpha parameter – the average estimated by researchers cited in my appendix 22

79 Coppola Testimony, pp. 75-76, Ufolla Testimony, p. 23.

80 Ufolla Testimony, pp. 22-23, LaConte Testimony, p. 43.

81 Coppola Testimony, pp. 76.



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was 4.45%; yet my estimate was only 1.5% and thus allowing for a maturity premium of 1

almost 300 bps.83 2

Q49. What about the argument that the use of the simultaneous use of the ECAPM and 3

adjusted betas lead to biased results? 4

A49. Mr. Ufolla and Ms. LaConte are concerned that I use ECAPM in combination with Value 5

Line betas, which are subject to the Blume adjustment.84 They believe the adjustment is 6

inappropriate. However, the Blume adjustment and the ECAPM are two fundamentally 7

different and complementary adjustments and both are well supported by the academic 8

literature. The reason for these necessary adjustments can be shown by reference to, which 9

illustrates the empirical security market line (“SML”). The adjustment to beta corrects the 10

estimate of the relative risk of the company, which is measured along the horizontal axis 11

of the SML. The ECAPM adjusts the risk-return tradeoff (i.e., the slope) in the SML, which 12

is on the vertical axis. In other words, the expected return (measured on the vertical axis) 13

for a given level of risk (measured on the horizontal axis) is different from the predictions 14

of the theoretical CAPM. Getting the relative risk of the investment correct does not adjust 15

for the slope of the SML, nor does adjusting the slope correct for errors in the estimation 16

of relative risk. 17

83 In comparison, the historical maturity premium for 20-year risk-free treasury bonds over 90-day treasury

bills for the longest period I have access to (April 1953 through February 2020) is 1.62% while the average

for the period 1953 – 1991 (the period covered by the articles) is lower at 1.16%. Source: Federal Reserve,

FRED.

84 Ufolla Testimony, pp. 22-23, LaConte Testimony, p. 43.


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Figure R-7: The Empirical Security Market Line

Importantly, the Blume adjustment has the effect of moving the beta along the x-axis 1

whereas the ECAPM is using the y-axis. The Value Line relied upon method to make betas 2

more precise was developed by Professor Blume.85 As shown in Professor Blume’s paper, 3

it is possible to apply a consistent adjustment procedure to historical betas that increased 4

the accuracy in forecasting realized betas. Essentially, Professor Blume’s adjustment 5

transforms a historical beta into a better estimate of expected future beta. It is this expected 6

“true” beta that drives investors’ expected returns according to the CAPM. 7

The backward-looking empirical tests of the CAPM that gave rise to the ECAPM did not 8

suffer from bias in the measurement of betas as do a forward-looking use. Researchers 9

plotted realized stock portfolio returns against betas measured over the same time period 10

to produce plots such as Figure R-8 below, which comes from the 2004 paper by Professors 11

Eugene Fama and Kenneth French.86 The fact that betas and returns were measured 12

contemporaneously means that the betas used in the tests were already the best possible 13

measure of the “true” systematic risk over the relevant time period. In other words, no 14

adjustments were needed for these betas. Despite this, researchers observed that the risk-15

85 Blume, Marshall E. (1971), “On the Assessment of Risk,” The Journal of Finance, 26, p. 1-10.

86 Fama, Eugene F. & French, Kenneth R, (2004), “The Capital Asset Pricing Model: Theory and Evidence,”

Journal of Economic Perspectives, 18(3), p. 25-46.


Case No. U-20642

Page 37 of 46

return trade-off predicted by the CAPM was too steep to accurately explain the realized 1

returns. As explained above the ECAPM explicitly corrects for this empirical observation. 2

Figure R-8: Evidence from Empirical Tests of the CAPM87

Q50. Did the empirical tests that gave rise to the ECAPM use raw betas in their analyses? 3

A50. They did. However, this is simply because the researchers were able to measure raw betas 4

and realized returns from the same historical period. In other words, no adjustment to the 5

raw beta was necessary to evaluate the market return realized for the same historical period 6

– that is different from using betas to determine the cost of equity for future periods. Hence, 7

the raw betas they measured accurately captured the systematic risk that impacted the 8

returns they measured. In a sense, the measured betas and realized returns were already 9

contemporaneous in the tests of the CAPM that identified the effect shown in Figure R-7 10

and Figure R-8. 11

This is explicit in the article by Litzenberger et al.,88 who explain (on page 376) that the 12

estimate of “alpha” they obtain when using historical (i.e., “raw”) betas is a linear 13

combination of the alpha that would be obtained with a perfect estimate of “true” beta and 14

the weighting factor employed in the Blume “global adjustment” procedure, which they 15

describe with the equation 𝛽𝑖 = 𝜔𝛽𝑖(ℎ𝑖𝑠𝑡𝑜𝑟𝑖𝑐𝑎𝑙) + (1 − 𝜔)1. Using the equations that the 16

authors present along with their results presented in the “Raw Betas” panel of Table 1 (on 17

87 Id., p. 33.

88 Robert Litzenberger, Krishna Ramaswamy and Howard Sosin, “On the CAPM Approach to the Estimation

of a Public Utility’s Cost of Equity Capital,” Journal of Finance, vol 35, 1979.


Case No. U-20642

Page 38 of 46

page 380 of the paper), it is possible to derive the estimate of alpha implied for use of 1

Blume adjusted beta with 𝜔 = 0.67: 2

𝑎 = 𝑎′ − 𝑏′ (1 − 𝜔

𝜔) = 0.326 − 0.330 (

0.33

0.67) = 0.163 3

In other words, the results of Litzenberger et. al.’s study is consistent with an 4

ECAPM alpha factor of approximately 2.0% when applying Blume-adjusted betas.89 In 5

that light my use of an alpha factor of 1.5% is conservative. 6

Q51. How about the argument that the ECAPM is not widely used in regulatory 7

proceedings? 8

A51. First, I believe the Commission should be presented with the best possible analysis 9

regardless of whether the analysis is “widely used” by regulators. Second, there certainly 10

are regulatory commissions that have adopted the ECAPM methodology. Examples 11

include the Mississippi Public Service Commission90 and the New York State Public 12

Service Commission.91 Also, the Alabama Public Service Commission recognized the 13

methodology.92 Importantly, all of these regulators rely on the ECAPM in conjunction 14

with adjusted betas and the California Public Utilities Commission did not distinguish 15

between CAPM and ECAPM when reporting results.93 This list is not exhaustive as many 16

commissions review the evidence before them, based on which they decide on an allowed 17

return without explicitly accepting or rejecting any specific methodology. 18

Q52. What do you conclude regarding the ECAPM? 19

89 Since Litzenberger, et. al. used monthly return data, their monthly alpha estimate of 0.163% corresponds to

(1.00163)12 − 1 = 1.97% when annualized.

90 Mississippi Power, PEP-5A, p. 24.

91 NY PSC Case 19-E-0065, Staff Finance Panel Testimony, May 2019, p. 141. 92 Alabama Public Service Commission, “Report and Order in Dockets 18117 and 18416,” August 21, 2013,

p. 13.

93 California Public Utilities Commission, “Decision 19-12-056,” December 19, 2019.


Case No. U-20642

Page 39 of 46

A52. For the reasons discussed above, the ECAPM has merit and there is no double-counting in 1

using adjusted betas in the ECAPM. Not only is the ECAPM of merit, but failing to 2

consider the results will downward bias the results by approximately half a percent. 3

Q53. Does the fact that you have not addressed all criticisms of you testimony mean that 4

you agree with those criticisms? 5

A53. No. 6

VII. CAPITAL MARKETS UPDATE 7

Q54. What has changed since you filed your Direct Testimony? 8

A54. Since filing my Direct Testimony, long standing economic uncertainties weight on capital 9

markets subsided somewhat but new global uncertainties related to the COVID-19 10

pandemic have increased economic risk and market volatilities to levels never seen before. 11

In January 2020, a series of trade deals were signed by the U.S. easing global trade 12

tensions—Phase 1 of the U.S.-China trade deal was signed on January 15 and the USMCA 13

was signed on January 31 this year. In addition, after years of negotiations, Brexit was 14

finalized and the United Kingdom withdrew from the European Union on January 31, 2020. 15

However, around the same time, early indications of a new virus was spreading in China. 16

By March 11, the World Health Organization had declared that the COVID-19 outbreak 17

was a pandemic.94 Governments around the world have been working to contain the spread 18

of the virus and have encouraged people to practice social distancing with some countries, 19

U.S. states, and cities issuing stay-at-home orders for their populations. This has led to 20

large portions of the economy shutting down and record levels of unemployment. Adding 21

to the economic turmoil, OPEC+ members failed to reach an agreement on production cuts 22

94 World Health Organization, “WHO Director-General’s opening remarks at the media briefing on COVID-

19 – 11 March 2020”, press release, March 11, 2020. https://www.who.int/dg/speeches/detail/who-director-

general-s-opening-remarks-at-the-media-briefing-on-covid-19---11-march-2020

https://www.who.int/dg/speeches/detail/who-director-general-s-opening-remarks-at-the-media-briefing-on-covid-19---11-march-2020

https://www.who.int/dg/speeches/detail/who-director-general-s-opening-remarks-at-the-media-briefing-on-covid-19---11-march-2020


Case No. U-20642

Page 40 of 46

in response to decreased demand.95 Saudi Arabia and Russia have increased production to 1

defend their market share, which has caused a substantial drop in global oil prices that 2

further increases market uncertainty and, by extension, the premium investors require to 3

invest in securities that are not risk-free. 4

Q55. How have recent global events impacted capital markets and the economy? 5

A55. While the full extent to which the COVID-19 pandemic will impact the economy is still 6

unknown, it has already created extraordinary changes in capital markets and the economy, 7

which by and large have no historical precedents. Investors reacted to the increasing risk 8

by fleeing riskier assets for safer assets. In the government bond markets, this flight-to-9

quality behavior caused yields to drop rapidly. On March 9, the entire U.S. yield curve fell 10

below 100 bps for the first time in history and the 10-year U.S. government bond yield hit 11

a record low of 0.339%.96 In addition, on March 26, short-term Treasury bills closed at 12

negative rates (-0.072%) for the first time since 2015.97 After the U.S. stock market reached 13

an all-time high on February 19, equity markets fell by 30% in just a month. As shown in 14

Figure R-9, the VIX volatility index closed at a high of 82.69 on March 16, 2020—the 15

highest closet in VIX’s history, thereby surpassing the peak during the during the financial 16

crisis of 82.69.98 In comparison, the VIX was never above 15 in September 2018, when 17

the Commission issued its order in U-18999. 18

95 Rania El Gamal, Alex Lawler, Olesya Astakhova, “OPEC's pact with Russia falls apart, sending oil into

tailspin,” Reuters March 6, 2020, accessed March 31, 2020, https://www.reuters.com/article/us-opec-

meeting/opecs-pact-with-russia-falls-apart-sending-oil-into-tailspin-idUSKBN20T0Y2

96 Sunny Oh, “Treasury yield curve sinks below 1% after oil and coronavirus worries rout stocks,” Market

Watch, March 9, 2020, accessed March 31, 2020, https://www.marketwatch.com/story/30-year-treasury-

yield-tumbles-below-1-after-oil-and-coronavirus-worries-rout-stocks-2020-03-09

97 Caitlin Ostroff, Paul J. Davies, “Short-Term Yields Go Negative in Scramble for Cash,” Wall Street Journal,

March 26, 2019, accessed March 31, 2020, https://www.wsj.com/articles/short-term-yields-go-negative-in-

scramble-for-cash-11585227369

98 “VIX Index Historical Data,” Cboe Exchange, Inc., accessed March 19, 2020,

http://www.cboe.com/products/vix-index-volatility/vix-options-and-futures/vix-index/vix-historical-data

https://www.reuters.com/article/us-opec-meeting/opecs-pact-with-russia-falls-apart-sending-oil-into-tailspin-idUSKBN20T0Y2

https://www.reuters.com/article/us-opec-meeting/opecs-pact-with-russia-falls-apart-sending-oil-into-tailspin-idUSKBN20T0Y2

https://www.marketwatch.com/story/30-year-treasury-yield-tumbles-below-1-after-oil-and-coronavirus-worries-rout-stocks-2020-03-09

https://www.marketwatch.com/story/30-year-treasury-yield-tumbles-below-1-after-oil-and-coronavirus-worries-rout-stocks-2020-03-09

https://www.wsj.com/articles/short-term-yields-go-negative-in-scramble-for-cash-11585227369

https://www.wsj.com/articles/short-term-yields-go-negative-in-scramble-for-cash-11585227369

http://www.cboe.com/products/vix-index-volatility/vix-options-and-futures/vix-index/vix-historical-data


Case No. U-20642

Page 41 of 46

Figure R-9: VIX

1

The heightened volatility has increased the premium that investors require to hold risky 2

assets, especially when measured based on forward-looking methodologies that estimate 3

expected market returns with reference to (currently spiking) dividend yields. Bloomberg’s 4

estimate of the market equity risk premium for the U.S. increased to as high as 9.84% and 5

is currently at 9.00%. At the same time the market equity risk premium that results from 6

the FERC’s methodology has increased to 9.64 and 10.02 percent as of March 20, 2020 7

using the Midcontinent Independent System Operator (“MISO”) and New England 8

Transmission Owners’ (“NETO”) methodology, respectively.99 At the same time, 9

Barclays believes that the market cost of equity has increased by 100-400 basis points and 10

that the MRP over the next two years is above 9%,100 which is consistent with an increase 11

99 FERC Opinion No. 569, Docket No. EL14-12-003, EL15-45-000, November 21, 2019, FERC Order

Directing Briefs, Docket No. EL11-66-001 et al., October 16, 2018; see also attached workpaper

100 Barclays, “Cost of Equity Analysis,” March 28, 2020. (Confidential) Barclay’s find a two-year return on

the S&P 500 of 12.9%, which leads to a very high MRP regardless of which risk-free rate is used (using my

risk-free rate of 3.6%, the MRP is 9.3%).

0

10

20

30

40

50

60

70

80

90

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Ind

ex L

evel

Source: Bloomberg as of 3/31/2020

Long Run Average: 19.2(1/2/1990 - 3/31/2020)

VIX at 12.4 at time of prior DTE Gas Cost of Capital

Decision (9/13/2018)


Case No. U-20642

Page 42 of 46

in the market equity risk premium of well over 200 basis points given the drop in risk-free 1

rates of at least 100 bps. 2

Figure R-10: Bloomberg’s Daily Market Equtiy Risk Premium, Market

Return, and Risk Free Rate

3

In addition, corporate bonds spreads have increased substantially over the past month as 4

investors require additional compensation to hold corporate debt. For example, Figure R-5

11 below shows the spread between BBB-rated utility debt versus 20 year U.S. Treasuries. 6

Utility bond spreads have increased 194 basis points from their pre-financial crisis average. 7

I note that spreads have nearly doubled since September 2018, when the Commission 8

issued its order in U-18999. 9

0.00%

2.00%

4.00%

6.00%

8.00%

10.00%

12.00%

03/30/2003/16/2003/02/2002/14/2001/31/2001/16/2001/02/2012/17/19

RF Rate PremiumSource: Bloomberg as of 3/31/2020

Market Equity Risk Premium at 6.96% at time of prior DTE Gas Cost of Capital Decision (9/13/2018)


Case No. U-20642

Page 43 of 46

Figure R-11: Utility BBB-rated Bond Yields vs. 20 Year U.S. Treasury Yields

1

The U.S. Government has attempted to stem the economic impacts from the outbreak. In 2

March, the U.S. Federal Reserve has cut its policy rate twice to its current level of 0 to 0.25 3

percent—a level last seen in the global financial crisis. In addition, the U.S. Federal 4

Reserve has announced “unlimited”101 quantitative easing and emergency liquidity 5

programs to support financial markets, which has caused the Federal Reserve’s balance 6

sheet to top $5 trillion for the first time in history.102 On March 27, the government passed 7

the Corona Virus Relief and Economic Security (“CARES”) act which provides a $2.1 8

trillion stimulus to the economy, which is 60% larger than the U.S. Government’s 2019 9

discretionary spending.103 10

101 U.S. Federal Reserve, “Federal Reserve Announces Extensive New Measures to Support the Economy,”

Press Release, March 23, 2020.

102 Dan Burns, “Fed balance sheet tops $5 trillion for first time as it enters coronavirus war mode,” Reuters,

March 26, 2020, accessed March 31, 2020, https://www.reuters.com/article/us-health-coronavirus-fed-

balancesheet/fed-balance-sheet-tops-5-trillion-for-first-time-as-it-enters-coronavirus-war-mode-

idUSKBN21D3K9

103 Congressional Budget Office, “10 Year Budget Projections – March 2020”, accessed March 31, 2020,

https://www.cbo.gov/about/products/budget-economic-data

Spread

0%

1%

2%

3%

4%

5%

Source: Bloomberg as of 3/31/2020..

Spread at 1.63% at time of prior DTE

Gas Cost of Capital Decision

Source: Bloomberg as of 3/31/2020..

March 2020 Spread: 3.17%

Average Spread(April 1991 - Dec. 2007): 1.23%

https://www.reuters.com/article/us-health-coronavirus-fed-balancesheet/fed-balance-sheet-tops-5-trillion-for-first-time-as-it-enters-coronavirus-war-mode-idUSKBN21D3K9



https://www.cbo.gov/about/products/budget-economic-data


Case No. U-20642

Page 44 of 46

Unfortunately, the protective measures to slow down the spread of the virus have caused 1

non-essential businesses to close their doors, which has led to a massive increase in 2

unemployment. The first unemployment figures, which reflect the impacts of the COVID-3

19 outbreak were released on March 25, 2020 by the U.S. Department of Labor—nearly 4

3.3 million initial unemployment insurance claims in just one week.104 This is a substantial 5

increase from the previous record of weekly initial unemployment claims of 695,000 in 6

1982.105 7

Q56. What are expectations going forward? 8

A56. The extent or length of economic impacts from the COVID-19 pandemic are unknown. 9

Many companies are re-evaluating their business plans and financial outlooks for the 10

remainder of the year. In the past month, over 200 companies have filed 8K’s informing 11

investors that they are withdrawing financial guidance—a nearly 8x increase from 12

historical averages.106 The impacts from a potential recession are just now becoming 13

apparent—such as unemployment and bankruptcy of businesses—and such impacts may 14

persist for the near to medium-term. 15

Q57. How does this impact the cost of equity estimation for DTE Gas? 16

A57. It is important to remember that the cost of equity and capital structure set forth by this 17

proceeding are expected to be in effect beyond the current extraordinary economic impacts 18

of the COVID-19 pandemic. The analysis and recommendations should reflect expected 19

market conditions and not exclusively the current market conditions. As discussed above, 20

many of the input parameters to cost of equity estimation methodologies are currently at 21

unprecedented levels. Sole reliance on the current economic conditions to anchor DTE 22

104 U.S. Department of Labor, “Unemployment Insurance Weekly Claims,” News Release, March 26, 2020.

105 Lucia Mutikani, “U.S. weekly jobless claims soar to record 3.28 million,” Reuters, March 26, 2020, accessed

March 31, 2020, https://www.reuters.com/article/us-health-coronavirus-usa-unemployment/u-s-weekly-

jobless-claims-surge-to-record-3-28-million-idUSKBN21D1WJ

106 Peter Kafka and Rani Molla, “The people running the world’s biggest companies have no idea what’s going

to happen, either,” Vox Media, March 27, 2020, accessed March 29, 2020,

https://www.vox.com/recode/2020/3/27/21197318/coronavirus-pandemic-wall-street-guidance

https://www.reuters.com/article/us-health-coronavirus-usa-unemployment/u-s-weekly-jobless-claims-surge-to-record-3-28-million-idUSKBN21D1WJ

https://www.reuters.com/article/us-health-coronavirus-usa-unemployment/u-s-weekly-jobless-claims-surge-to-record-3-28-million-idUSKBN21D1WJ

https://www.vox.com/recode/2020/3/27/21197318/coronavirus-pandemic-wall-street-guidance


Case No. U-20642

Page 45 of 46

Gas’ return on equity or capital structure would unfairly lock DTE Gas or its customers 1

into the current economic conditions and not provide a fair return, especially when 2

compared to other utilities that did not undergo a cost of capital proceeding during this time 3

period. At the same time, the current market conditions create an exorbitant amount of 4

uncertainty and if the financial crisis can be used as a guide, investors’ appetite for risk is 5

likely to linger.107 6

Q58. Has this increased the business risk profile of regulated utilities? 7

A58. Yes. The business risk of regulated utilities including DTE Gas are heighted as a result of 8

the economic impacts from the COVID-19 pandemic. The primary risks that utilities will 9

face are a decline in load that is not fully compensated and customer non-payment resulting 10

from businesses shutting down or people being laid off. Specific to Michigan, 129,000 11

initial unemployment claims were filed for the week ending March 20, 2020 and an 12

additional 183,080 filed for the week ending March 28, 2020.108 As shown in Figure R-12, 13

Michigan experienced more initial unemployment claims in either week than it had during 14

any week since at least 2000, including during the global financial crisis. Utilities across 15

30 states, including DTE Gas, have implemented service termination moratoria during the 16

COVID-19 pandemic.109 Furthermore, many utilities are seeing decreases in demand due 17

to non-essential businesses closing.110 Even with revenue decoupling, utilities that use 18

volumetric based charges to recover fixed costs can be impacted. Taken together it is 19

107 See, for example, Fernando Duarte and Carlo Rosa, “The Equity Risk Premium: A Review of Models,”

Federal Reserve of New York, 2015. The authors show that not only did the MRP increase dramatically

during the financial crisis of 2008-09, but the effect lingered through 2012-13.

108 U.S. Department of Labor, Unemployment Insurance Weekly Claims Data, accessed April 1, 2020.

https://oui.doleta.gov/unemploy/claims.asp; U.S. Department of Labor, “Unemployment Insurance Weekly

Claims,” Press Release, April 2, 2020, https://www.dol.gov/sites/dolgov/files/OPA/newsreleases/ui-

claims/20200551.pdf

109 Lillian Federico, “State Regulators take first steps to address COVID-19 costs to utilities,” S&P Global

Market Intelligence, March 31, 2020, accessed March 31, 2020

https://platform.marketintelligence.spglobal.com/web/client?auth=inherit#news/article?id=57823563&Ke

yProductLinkType=24

110 Robert Walton, “Utilities beginning to see the load impacts of COVID-19 as economic shutdown widens,”

Utility Dive, March 23, 2020, accessed March 29, 2020, https://www.utilitydive.com/news/utilities-are-

beginning-to-see-the-load-impacts-of-covid-19-as-economic-sh/574632/

https://oui.doleta.gov/unemploy/claims.asp

https://www.dol.gov/sites/dolgov/files/OPA/newsreleases/ui-claims/20200551.pdf

https://www.dol.gov/sites/dolgov/files/OPA/newsreleases/ui-claims/20200551.pdf

https://platform.marketintelligence.spglobal.com/web/client?auth=inherit#news/article?id=57823563&KeyProductLinkType=24

https://platform.marketintelligence.spglobal.com/web/client?auth=inherit#news/article?id=57823563&KeyProductLinkType=24

https://www.utilitydive.com/news/utilities-are-beginning-to-see-the-load-impacts-of-covid-19-as-economic-sh/574632/

https://www.utilitydive.com/news/utilities-are-beginning-to-see-the-load-impacts-of-covid-19-as-economic-sh/574632/


Case No. U-20642

Page 46 of 46

evident that the business risk of regulated utilities is elevated. While I continue to find my 1

ROE recommendation reasonable, I find the heightened business risk environment lends 2

additional supports to awarding DTE Gas an ROE towards the upper half of my reasonable 3

range. 4

Figure R-12: Michigan Unemployment – U.S. Department of Labor

5

6


A59. Yes. 8

Initial Claims

Continued Claims

0

50

100

150

200

250

300

350

400

Jan

-00

Jan

-01

Jan

-02

Jan

-03

Jan

-04

Jan

-05

Jan

-06

Jan

-07

Jan

-08

Jan

-09

Jan

-10

Jan

-11

Jan

-12

Jan

-13

Jan

-14

Jan

-15

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-16

Jan

-17

Jan

-18

Jan

-19

Jan

-20

UN

em

plo

ym

en

t C

laim

sTh

ou

san

ds

> 311,000 Initial ClaimsWeek Ending 3/28

STATE OF MICHIGAN



DTE GAS COMPANY for authority )





)

PROOF OF SERVICE

STATE OF MICHIGAN )

) ss.

COUNTY OF WAYNE )

ESTELLA R. BRANSON, being duly sworn, deposes and says that on the 14th day of

April, 2020, she served a copy of DTE Gas Company’s Rebuttal Testimony of Witnesses, Jaison

J. Busby, Robert J. Lee, Shoshannah M. Lenski, Habeeb J. Maroun, and Rajan M. Telang, and

Rebuttal Testimony and Exhibits of Witnesses, Andrew D. Dewey, Mark C. Johnson, Tamara

Johnson, Henry N. Campbell, George Chapel, Michael S. Cooper, Henry J. Decker, Philip W.

Dennis, Alida D. Sandberg, Edward J. Solomon, Theresa M. Uzenski, and Dr. Bente Villadsen,

via electronic mail upon the persons referred to in the attached service list.

______

ESTELLA R. BRANSON

Subscribed and sworn to before

me this 14th day of April, 2020

Lorri A. Hanner, Notary Public

Wayne County, Michigan

My Commission Expires: 4-20-2020

of 1

SERVICE LIST MPSC CASE NO. U-20642

ADMINISTRATIVE LAW JUDGE Honorable Martin D. Snider Administrative Law Judge Section 7109 West Saginaw Hwy Lansing, MI 48917 [email protected] ABATE Michael J. Pattwell Bryan A. Brandenburg Stephen A. Campbell Clark Hill, PLC 212 East César E. Chávez Avenue Lansing, MI 48906 [email protected] [email protected] [email protected] ATTORNEY GENERAL (ENRA) Joel King Assistant Attorney General G. Mennen Williams Bldg. 525 W. Ottawa Street, 6th Floor P.O. Box 30755 Lansing, MI 48909 [email protected] [email protected] CITIZENS UTILITY BOARD OF MICHIGAN John R. Liskey John R Liskey Attorney At Law PLLC 921 N. Washington Avenue Lansing, MI 48906 [email protected] DETROIT THERMAL, LLC Arthur J. LeVasseur Fischer Franklin & Ford 24725 W. 12 Mile Road Southfield, MI 48034 [email protected]

MICHIGAN POWER LIMITED PARTNERSHIP; RETAIL ENERGY SUPPLY ASSOCIATION Jennifer Utter Heston Fraser Trebilcock Davis & Dunlap, P.C. 124 W. Allegan, Ste. 1000 Lansing, MI 48933 [email protected] MPSC STAFF ATTORNEYS Michael J. Orris Amit T. Singh Daniel E. Sonneveldt Nicholas Q. Taylor 7109 West Saginaw Hwy, 3rd Floor Lansing, MI 48917 [email protected] [email protected] [email protected] [email protected] RESIDENTIAL CUSTOMER GROUP Don L. Kekey Brian W. Coyer University Office Place 333 Albert Avenue, Suite 425 East Lansing, MI 48823 [email protected] [email protected] VERSO CORPORATION Laura A. Chappelle Timothy J. Lundgren 201 N. Washington Square, Suite 910 Lansing, MI 48933-1323 [email protected] [email protected]

mailto:[email protected]















NDA SERVICE LIST MPSC CASE NO. U-20642

As of March 16, 2020

Page 1 of 2

ABATE Michael J. Pattwell Bryan A. Brandenburg Stephen A. Campbell Clark Hill, PLC 212 East César E. Chávez Avenue Lansing, MI 48906 [email protected] [email protected] [email protected] Consultants for ABATE Jeffry Pollock Joseph Selsor Jonathan Ly Kitty Turner J. Pollock, Incorporated 12647 Olive Blvd., Suite 585 St. Louis, Missouri 63141 [email protected] [email protected] [email protected] [email protected] CITIZENS UTILITY BOARD OF MICHIGAN John R. Liskey Attorney At Law PLLC 921 N. Washington Avenue Lansing, MI 48906 [email protected] Consultants for CITIZENS UTILITY BOARD OF MICHIGAN Douglas B. Jester [email protected] Ram Veerapaneni [email protected]

MICHIGAN ATTORNEY GENERAL Joel King Michael E. Moody Amanda Churchill Assistant Attorney General G. Mennen Williams Bldg. 525 W. Ottawa Street, 6th Floor P.O. Box 30755 Lansing, MI 48909 [email protected] [email protected] [email protected] Consultant for Michigan Attorney General Sebastian Coppola President Corporate Analytics 5928 Southgate Rd. Rochester, MI 48306 [email protected] MICHIGAN POWER LIMITED PARTNERSHIP; RETAIL ENERGY SUPPLY ASSOCIATION Jennifer Utter Heston Angela Babbitt Fraser Trebilcock Davis & Dunlap, P.C. 124 W. Allegan, Ste. 1000 Lansing, MI 48933 [email protected] [email protected] MPSC STAFF ATTORNEYS Michael J. Orris Amit T. Singh Daniel E. Sonneveldt Nicholas Q. Taylor 7109 West Saginaw Hwy, 3rd Floor Lansing, MI 48917 [email protected] [email protected] [email protected] [email protected]





















NDA SERVICE LIST MPSC CASE NO. U-20642

As of March 16, 2020

Page 2 of 2

Lori Mayabb Brian Welke [email protected] [email protected] VERSO CORPORATION Laura A. Chappelle Timothy J. Lundgren 201 N. Washington Square, Suite 910 Lansing, MI 48933-1323 [email protected] [email protected] Steven Brooks [email protected]






lauren d. donofrio @dteenergy

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