Paula Johnson- Bacon - MPSC Electronic Docket Filings

August 5, 2021 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-20940 Dear Ms. Felice:

Attached for electronic filing in the above captioned matter is DTE Gas Company’s Initial Brief along with a Proof of Service.

Very truly yours,

Paula Johnson-Bacon PJB/erb Attachments cc: Service List

Paula Johnson-Bacon (313) 235-7052 [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 ) increase its rates, amend its rate ) Case No. U-20940 schedules and rules governing the ) distribution and supply of natural gas, ) and for miscellaneous accounting authority. ) )

DTE GAS COMPANY’S INITIAL BRIEF Dated: August 5, 2021

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TABLE OF CONTENTS

I. INTRODUCTION ....................................................................................................... 1

II. HISTORY OF PROCEEDINGS ................................................................................. 4

III. JURISDICTION, STANDARD OF REVIEW AND RATE SETTING LAW. ......... 7

A. Jurisdiction and Standard of Review. ................................................................... 7

B. Ratemaking Principles Overview. ....................................................................... 10

IV. TEST YEAR. ............................................................................................................. 13

V. RATE BASE. ............................................................................................................. 14

A. Adjusted Total Rate Base .................................................................................... 14

B. Capital Expenditures. .......................................................................................... 14

1. Gas Delivery Plan (GDP) .................................................................................. 15

2. Routine Capital Spending ................................................................................. 16

a. Communications & Control - Meters ......................................................... 16

b. Service Renewals ......................................................................................... 19

c. Service Abandonments................................................................................ 20

d. New Market Attachments ........................................................................... 21

e. Service Alterations ...................................................................................... 22

f. Belle Isle Main Replacement ....................................................................... 24

g. System Reliability ........................................................................................ 24

h. Routine Transmission Plant........................................................................ 25

3. Gas Information Technology (IT) Spending .................................................... 27

4. Large Capital Projects. ..................................................................................... 32

a. TCARP ........................................................................................................ 33

b. Van Born ..................................................................................................... 34

c. Middlebelt Deration Project ....................................................................... 35

d. East Jefferson Project ................................................................................. 37

5. Contingency....................................................................................................... 38

C. Working Capital .................................................................................................. 44

VI. RATE OF RETURN .................................................................................................. 46

A. Capital Structure ................................................................................................. 46

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B. Debt Cost Rates. ................................................................................................... 51

1. Long-Term Debt. .............................................................................................. 51

2. Short-Term Debt. .............................................................................................. 51

C. Return on Common Equity. ................................................................................ 52

1. CAPM and ECAPM Estimates ........................................................................ 54

2. DCF Estimates .................................................................................................. 57

3. Risk Premium Estimate .................................................................................... 58

4. DTE Gas’s Return on Equity in Relation to Risk ............................................ 58

5. The Connection Between Equity and Capital Structure ................................. 60

6. Summary and Recommendations Regarding DTE Gas’s Cost of Equity. ...... 60

D. Other Cost Rates. ................................................................................................. 61

E. Overall Rate of Return. ....................................................................................... 61

VII. ADJUSTED NET OPERATING INCOME AND OTHER REVENUE-RELATED ISSUES. .................................................................................................. 61

A. Throughput .......................................................................................................... 62

1. Weather Normalization. ................................................................................... 62

2. Customer Usage. ............................................................................................... 63

3. Exelon Energy Company (Exelon) ................................................................... 65

4. Cost of Gas. ....................................................................................................... 65

5. End-Use Transportation (EUT)........................................................................ 65

B. Midstream Revenue ............................................................................................. 68

C. Other Operating Revenue ................................................................................... 69

D. Operating and Maintenance (O&M) Expenses .................................................. 70

1. Inflation ............................................................................................................. 71

2. Storage, Transmission, and Distribution O&M Expenses. ............................ 72

a. TCARP ........................................................................................................ 72

b. Transmission Integrity Management Program (TIMP) ............................ 73 c. Maximum Allowable Operating Pressure (MOAP) Records Remediation

…………………………………………………………………………….....74

d. Pipeline Safety Management System (PSMS) ............................................ 75

e. Meter Abnormal Operating Condition (AOC) Initiative .......................... 76

3. Customer Service O&M Expenses. .................................................................. 76

a. Meter Reading ............................................................................................. 77

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b. Customer Service Representatives (CSRs) ................................................. 78

c. Merchant Fees ............................................................................................. 79

4. Marketing, and Administrative and General O&M Expenses. ....................... 80

a. Injuries and Damages ................................................................................. 81

b. Rent Expense for Shared Assets and Related Information Technology(IT) O&M Costs .......................................................................................... 81

c. Contingency ................................................................................................. 96

5. Employee Benefits Expenses ........................................................................... 100

a. Pension. ...................................................................................................... 100

b. Other Post-Employment Benefit (OPEB) Expense. ................................. 102

c. Active Employee Benefits. ......................................................................... 103

d. Other Employee Benefit Costs. ................................................................. 106

6. Employee Compensation. ............................................................................... 108

E. Manufactured Gas Plant (MGP) Remediation Expenses ................................. 114

F. Uncollectible Expense ........................................................................................ 115

G. Lost And Unaccounted For (LAUF) and Company Use (CU) Gas, and Gas-In-Kind (GIK) ......................................................................................................... 116

H. Depreciation and Amortization ......................................................................... 118

I. Property and Other Taxes ................................................................................. 118

J. Income Tax Expenses ........................................................................................ 118

VIII. OTHER ISSUES. ..................................................................................................... 118

A. Revenue Decoupling Mechanism (RDM) .......................................................... 119

B. Infrastructure Recovery Mechanism (IRM) ..................................................... 120

1. Gas Renewal Program (GRP - combined MRP and MMO). ........................ 122

2. Meter Assembly Check Meter Move-out (MAC MMO) Program. ............... 122

3. Pipeline Integrity (PI) Program. .................................................................... 123

C. Leak Backlog ...................................................................................................... 126

D. Research and Development Cost Recovery....................................................... 126

E. Demand Response (DR) ..................................................................................... 129

F. Advanced Metering Infrastructure (AMI) Benefits Reporting ........................ 130

G. Accounting Requests .......................................................................................... 131

IX. REVENUE DEFICIENCY AND REQUESTED RATE RELIEF. ........................ 135

X. RATE DESIGN AND TARIFF REVISIONS. ........................................................ 135

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A. Allocation of Revenue Deficiency ...................................................................... 135

B. High-pressure and low-pressure distribution main plant, and volume-by-type studies ................................................................................................................. 139

C. Tariff Changes for All Customers ..................................................................... 140

D. Tariff Changes for Sales Rate Schedules .......................................................... 141

1. Revised IRM. ................................................................................................... 141

2. Low-Income Energy Assistance...................................................................... 142

E. Tariff Changes for EUT Service ........................................................................ 144

F. Tariff Changes for Off-System Storage and Transportation Service .............. 148

G. Proposed Monthly Customer Charges and Rate Schedule Economic Break-Even Points ......................................................................................................... 148

XI. REQUEST FOR RELIEF ....................................................................................... 149

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I. INTRODUCTION

The filing of this case was driven by DTE Gas Company’s expected revenue shortfall of

$195 million for the Calendar year ended December 21, 2022. The real impact to customer rates

is about $157 million, since $38 million of this request will already have been recovered through

the Company’s existing Infrastructure Recovery Mechanism (“IRM”) surcharge that will terminate

when new base rates are established in this proceeding. Throughout the course of this case the

Company has agreed upon proposals or identified errors that have reduced its revenue deficiency

by $17.7 million to $177 million. The adjustments from its filed position are as follows:

Adjustments from Filed Position In millions1

Capital Expenditures O&M Service Renewal PPE / Vehicle Rental ($ 0.278) Uncollectible Expense ($ 2.4) Gas Information Technology ( 0.450) Transmission Right of way ( 2.0) TCARP Demand Charge ( 11.6) Shared Assets Customer Service ( 0.8) Shared Assets Other than

Customer Service ( 0.8)

Total Capital Expenditure Adj1 ($ 0.728) Total O&M Adjustments ($17.6)

DTE Gas filed its last application for rate relief on November 26, 2019. The Company

understands that the financial impacts of the Covid-19 pandemic are still lingering and was able to

delay filing a rate increase application in 2020 by controlling costs and implementing continuous

improvement to mitigate the impact of increasing operating costs. However, as we continue to

move forward, DTE Gas’s currently authorized rates will no longer be sufficient to provide the

level of safe and reliable service that the Company currently provides its customers.

1 Attachments A and B to this brief provide detailed calculations including tax impacts, half year convention and other resultant changes required to arrive at the final $17.7 million adjustment to the revenue requirement.

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The Company has always had a positive economic impact on the communities it serves

and will continue to be a positive economic force during and after the pandemic by employing

over 1,800 employees, utilizing local contractors and vendors that also employ Michigan residents,

and continuing to pay millions of dollars in property taxes ($63 million in the 2019 historical test

year) to the cities and townships it serves. The rate relief requested in this case will allow the

Company to continue to provide economic support by sustaining employment and providing a

dependable revenue source to local communities. Additionally, although the low-income credit

proposals in this case do have an associated revenue increase, the increase in available credits will

provide added financial assistance to our most vulnerable customers.

The revenue request in this case is borne in large part out of a need to continue the

significant progress the Company has made in identifying and replacing its aging pipelines,

relocating customer meters from inside their homes to safer outside locations, create system

redundancies to improve reliability, increase security and resilience at gas facilities, reduce the

risk of catastrophic outages or damages, and enhance the Company’s safety programs. These

programs, and the resources required to support them, are necessary for the Company’s provision

of safe and reliable gas service now and into the future.

The Company has also presented a need for continued investment in its IT systems. The

investments made in this space are necessary to support all aspects of the Company’s operations

as well as general security and customer service programs. To create cost savings and efficiencies,

DTE Electric and DTE Gas share a substantial amount of IT resources. DTE Electric implements

these projects and DTE Gas pays DTE Electric for its proportionate share of the assets. Typically,

DTE Electric will receive approval in its general rate case for a particular level of Shared Asset IT

spending, which will flow through to DTE Gas’s next general rate case. This Shared Asset

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reimbursement mechanism has been in place since the merger between MichCon and Detroit

Edison, and has been presented in DTE Gas’s prior rate cases at least since 2012. Due to the Covid-

19 pandemic and the electric company’s commitment to postpone its general rate case, the timing

of these asset approvals is out of sync. As a result, DTE Gas has presented evidence in this case to

support the increased Shared Asset charge resulting primarily from IT spending that will be

completed by DTE Electric for certain projects.

Inflation, primarily due to contracted wage increases and escalating contractor costs,

increased employee healthcare and benefit costs, and costs to comply with State and Federal

requirements are also driving the Company’s increased revenue requirement. These increased

costs, coupled with decreased sales due to energy waste reduction measures our customers are

implementing, lead to the rate relief requested in this case.

Last, as part of its rate structure, the Company is also requesting that the Commission

approve a well-balanced capital structure and sufficient return on equity to ensure that DTE Gas

maintains full access to capital at reasonable rates, terms, and conditions. Without solid financial

health, the Company’s cost of providing utility services to its customers could increase

significantly. The Company’s proposed return on equity of 10.25% is also necessary to ensure that

DTE Gas continues to be an attractive investment in the marketplace. Any decrease in the

Company’s capital structure will require a corresponding increase in return on equity to maintain

the Company’s financial health.

Each component of DTE Gas’s revenue requirement is supported by hundreds of pages of

testimony, 36 exhibits with multiple schedules, volumes of workpapers that were provided to Staff

and all intervenors at the outset of this case, and responses to more than 1,717 discovery requests

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and 244 audit requests. The Company’s projected costs are reasonable and necessary as

contemplated by the laws governing utility rate setting and should be approved by the Commission.

II. HISTORY OF PROCEEDINGS

DTE Gas Company (DTE Gas or the Company) is presently serving its retail natural gas

transportation, storage and distribution customers under rates, terms and conditions established in

the Michigan Public Service Commission’s (MPSC or Commission) August 20, 2020 Order in

Case No. U-20642 that approved a settlement agreement related to general service rate relief and

other associated matters. On February 12, 2021, DTE Gas filed its Application (amended February

15, 2021), direct testimony, and exhibits with the Commission requesting to raise revenues by

approximately $195 million annually ($157 million net of the infrastructure surcharge that is

already reflected in rates). By February 24, 2021, DTE Gas published notice of its above request.

On March 11, 2021, a pre-hearing conference was held by Administrative Law Judge Sally

L. Wallace (the ALJ) who granted petitions to intervene filed by the Association of Businesses

Advocating Tariff Equity (ABATE); the Michigan Attorney General (AG); Citizens Utility Board

of Michigan (CUB); Dearborn Industrial Generation LLC (DIG); Detroit Thermal, LLC (Detroit

Thermal); Energy Michigan; Michigan Power Limited Partnership (MPLP); Residential Customer

Group (RCG); Retail Energy Supply Association (RESA); and Verso Corporation (Verso). Staff

also participated at the pre-hearing conference and a case schedule was established in accordance

with the March 4, 2021 Order in Case Nos. U-20940 and U-20962 (1T 8). On March 23, 2021,

the ALJ granted Vicinity Energy Grand Rapids, LLC’s (Vicinity Energy) petition to intervene out-

of-time.

DTE Gas sponsored the direct testimony and exhibits of 21 witnesses. Jennie Aud is DTE

Gas’s Director, Gas Control and Planning (qualifications and direct testimony at 5T 501–17); W.

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Scott Bennett (who adopted the originally-filed testimony of Edward Solomon) is DTE Energy’s

Manager of Corporate Finance (qualifications and direct revised testimony at 5T 531–65); Daniel

Brudzynski is DTE Gas’s Vice President of Gas Sales and Supply (qualifications and revised direct

testimony at 5T579–619); Benjamin Burns is DTE’s Director of Electric Marketing and

Electrification (qualifications and direct testimony at 5T 643–49); Jaison Busby is DTE’s IT

Director of Power Supply, Energy Gas, and Enterprise Innovation (qualifications and revised

direct testimony at 5T 656-748); Henry Campbell is the Director of DTE’s Customer Care

Organization (qualifications and direct testimony at 5T 777–94); George Chapel is DTE Gas’s

Manager, Market Forecasting (qualifications and revised direct testimony at 5T 801-33); Michael

Cooper is DTE Energy Corporate Services LLC’s Director of Compensation, Benefits & Wellness

(qualifications and revised direct testimony at 5T 847–909); Henry Decker is DTE Gas’s Director,

Gas Sales and Marketing (qualifications and direct testimony at 5T 417–69): Mark C Johnson is

DTE Gas’s Director of Southeast Michigan Gas Operations (qualifications and revised direct

testimony at 5T 932–82); Tamara D. Johnson is DTE’s Director of Revenue Management and

Protection (RM&P) (qualifications and revised direct testimony at 5T 1000–1021); Robert Lee is

DTE Gas’s Manager of Environmental Management and Safety (qualifications and direct

testimony at 5T 1034–53); Habeeb Maroon is a Principal Financial Analyst in the Revenue

Requirements Department of DTE’s Regulatory Affairs organization (qualifications and direct

testimony at 5T 1056–85); Angie Pizzuti is DTE’s Vice President and Chief Customer Officer,

Customer Service (qualifications and direct testimony at 5T 1102–61); Alida Sandberg is DTE

Gas’s Director, Pipeline Safety and Regulatory Compliance (qualifications and direct revised

testimony at 5T 1175–1239); Rajan Telang is the Director, Regulatory Affairs for DTE Energy

(qualifications and revised direct testimony at 5T 1273–1315); Renee Tomina is DTE Gas’s

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Director of Gas Operations (qualifications and revised direct testimony at 5T 1329–66); Theresa

Uzenski is the Manager of Regulatory Accounting for DTE Electric and DTE Gas (qualifications

and revised direct testimony at 5T 320–80); Kirk Vangilder is a Principal Financial Analyst for

Revenue Requirements in DTE’s Regulatory Affairs organization (qualifications and revised

direct testimony at 5T 1375–95); Dr. Bente Villadsen is a principal in The Brattle Group, which is

an economic, environmental and management consulting firm (qualifications and revised direct

testimony at 5T 1398–1500); and Sherri Wisniewski is DTE Energy’s Director of Tax Operations

(qualifications and direct testimony at 5T 1546–60);

On June 3, 2021, the Commission Staff, the and Intervenors filed their testimony, although

CUB, MPLP, RCG, RESA and Verso did not file any testimony. Staff sponsored Paul R. Ausum

(qualifications and direct testimony at 5T 1982–88);

On June 23, 2021, DTE Gas filed the rebuttal testimony and exhibits of witnesses Marisa

Ayala, DTE Gas’s Manager - Gas Operations (qualifications and rebuttal testimony at 5T 519–

28), Bennett (revised, 5T 566–76), Brudzynski (5T 620–40), Burns (5T 650–53), Busby (5T 749–

75), Campbell (5T 795–98), Chapel (5T 834–44 ), Cooper (5T 910–29), Decker (revised, 5T 470–

92), Mark C. Johnson (5T 983–98), Tamara D. Johnson (5T 1022–32 ), Maroun (5T 1086–99),

Pizzuti (5T 1162–72), Sandberg (revised, 5T 1240–71), Telang (5T01316–26), Tomina (revised,

5T 1367–72), Uzenski (5T 381–97), and Villadsen (5T 1501–43).

Cross-examination and binding-in of testimony was held on July 12 and 13, 2021. The

record consists of 2,131 pages of transcript and supporting exhibits.

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III. JURISDICTION, STANDARD OF REVIEW AND RATE SETTING LAW.

A. Jurisdiction and Standard of Review.

The Commission has jurisdiction over this case pursuant to 1909 PA 106, as amended,

MCL 460.551 et seq.; 1919 PA 419, as amended, MCL 460.51 et seq.; 1939 PA 3, as amended,

MCL 460.1 et seq.; 1969 PA 306, as amended, MCL 24.201 et seq.; and the Commission’s Rules

of Practice and Procedure, as amended, 1999 AC, R 460.17101 et seq.

All Commission decisions must be authorized by law, and the Commission’s findings must

“be supported by competent, material and substantial evidence on the whole record.” Const 1963,

art 6, § 28. Substantial evidence is evidence “that a reasoning mind would accept as sufficient to

support a conclusion.” Monroe v State Employees’ Retirement Sys, 293 Mich App 594, 607; 809

NW2d 453 (2011). Expert testimony is “substantial” only if it is offered by a qualified expert who

has an informed and rational basis for his or her view, even if other experts disagree. Great Lakes

Steel v Public Service Comm, 130 Mich App 470, 481; 334 NW2d 321 (1983).

The preponderance of evidence standard applies in this proceeding. Aquilina v General

Motors Corp, 403 Mich 206, 210-211; 267 NW2d 923 (1978) (“The proof required in an

administrative proceeding…is the same as that required in a civil judicial proceeding: a

preponderance of the evidence.”). The preponderance of evidence standard is the lightest of all

evidentiary standards when compared to the heightened “clear and convincing” standard2 or the

“beyond a reasonable doubt” standard that is only applicable to criminal proceedings.3 The

“preponderance of the evidence” standard is generally defined as follows:

The greater weight of the evidence, not necessarily established by the greater number of witnesses testifying to a fact but by evidence that has the most convincing force; superior evidentiary weight that, though not sufficient to free the

2 In re Moss, 301 Mich App 76, 89-90; 836 NW2d 182 (2013). 3 Thangavelu v Dep’t of Licensing & Regulation, 149 Mich App 546, 554-555; 386 NW2d 584 (1986).

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mind wholly from all reasonable doubt, is still sufficient to incline a fair and impartial mind to one side of the issue rather than the other. [Black’s Law Dictionary 1301 (9th ed 2009).] DTE Gas has the initial burden to prove its case by a preponderance of the evidence.

“[O]nce a utility has satisfied its initial burden of proof, another party ‘may challenge that evidence

and present evidence of unreasonableness.’ However, at that point, the other party has the burden

to demonstrate its position is correct.’” October 25, 2017 Order in Case No. U-18224, pp 14-15,

quoting January 11, 2010 Opinion and Order in Case Nos. U-15768 and U-15751, p 38. This

evidentiary standard also effectively bars last-minute criticisms of the Company’s evidentiary

presentation, as the Commission further explained:

The Commission finds that a delicate balance must be maintained concerning the burden of proof. The company has the burden of going forward and demonstrating that it has proposed just and reasonable rates. In this instance, Detroit Edison made that showing. The Staff in response may challenge that evidence and present evidence of unreasonableness. At that point, however, the Staff has the burden to demonstrate its position is correct. The company may then rebut the Staff’s criticisms of its case. The problem here is that the specific criticism that the company had not adequately explained itself came too late in the process for a fair determination on that issue, particularly given the evidence the company presented in support of its position. [January 11, 2010 Opinion and Order in Case Nos. U-15768 and U-15751, pp 37-38.] The Administrative Procedures Act (APA) precludes the Commission from making

decisions based on non-record materials. MCL 24.276 provides: “Evidence in a contested case . .

. shall be offered and made part of the record. Other factual information or evidence shall not be

considered in determination of the case except as permitted under [MCL 24.277] concerning

official notice of judicially cognizable facts and facts within the agency’s specialized expertise].”

Noncompliance with the APA is reversible error. In re Public Service Commission Guidelines for

Transactions Between Affiliates, 252 Mich App 254, 267; 652 NW2d 1 (2002).

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The ability to take official notice is limited under applicable rules.4 See also Freed v Salas,

286 Mich App 300, 341; 780 NW2d 844 (2009), where the Court of Appeals affirmed the trial

court’s refusal to take judicial notice of a speed limit, explaining in part: “Given that the signage

and the traffic control order did not agree as to the speed limit for the area, the fact could not

reasonably be said to have been undisputed or capable of accurate and ready determination.”

The Commission recently explained that “because of the unforgiving time limits under

MCL 460.6a [which at that time had a 12-month deadline], official notice requests, especially

those that may generate controversy regarding the materiality or weight of the evidence proffered,

can rarely, if ever, be entertained after the close of the record” (December 11, 2015 Order in Case

No. U-17767, p 136, agreeing with ALJ’s denial of official notice request).

In Kar v Hogan, 399 Mich 529, 539; 251 NW2d 77 (1976), our Supreme Court explained

that “[t]he party alleging a fact to be true should suffer the consequences of a failure to prove the

truth of that allegation.” Thus, unproven allegations cannot stand in the place of evidence. Things

not proven must be taken as not existing, since a decision cannot be based upon conjecture. Star

4 Rule 428 of the Commission’s Rules of Practice and Procedure provides:

Except as otherwise provided by law, the commission and the presiding officer may take official notice of judicially cognizable facts and may take notice of general, technical, or scientific facts within the commission’s specialized knowledge. The commission or the presiding officer shall notify the parties at the earliest practicable time of any noticed fact that pertains to a materially disputed issue that is being adjudicated and, on timely request, the parties shall be given an opportunity before the final decision to dispute the fact or its materiality. The commission may use its expertise, technical competence, and specialized knowledge in the valuation of evidence presented to it.” [R 792.10428. Emphasis added.]

MRE 201(b) similarly provides: A judicially noticed fact must be one not subject to reasonable dispute in that it is either (1) generally known within the territorial jurisdiction of the trial court or (2) capable of accurate and ready determination by resort to sources whose accuracy cannot reasonably be questioned. (Emphasis added).

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Steel v USF&G, 186 Mich App 475, 481; 465 NW2d 17 (1990); see also, Skinner v Square D Co,

445 Mich 153; 516 NW2d 475 (1994).

It is similarly well established that an agency decision may not be based on speculation.

Ludington Service Corp v Comm’r of Insurance, 444 Mich 481, 483, 494-97, 500-501, 507; 511

NW2d 661 (1994), amended 444 Mich 1240 (1994) (unanimously reversing agency decision that

exceeded the limits of the agency’s statutory authority, and that was based on speculation instead

of the required competent, material, and substantial evidence); In re Complaint of Pelland, 254

Mich App 675, 685-86; 658 NW2d 849 (2003); Battiste v Dep’t of Social Services, 154 Mich App

486, 492; 398 NW2d 447 (1986).

B. Ratemaking Principles Overview.

DTE Gas has constitutional protections against “takings” and confiscatory rates under the

Fifth Amendment to the U.S. Constitution, which is applicable to the states through the Fourteenth

Amendment. Similarly, Mich Const 1963, art 10, § 2 provides in part, “Private property shall not

be taken for public use without just compensation therefore being first made or secured in a manner

prescribed by law.” These constitutional protections have been recognized and applied to public

utility rates in well-established case law.5

The Michigan Supreme Court has provided further guidance that the Commission must use

in setting DTE Gas’s rates. Specifically, creating rates that recognize reductions in certain costs,

while ignoring the increase in other costs, violates the due process rights of utilities. The Court

5 See generally, Missouri ex rel Southwestern Bell Telephone Co v Public Service Comm of Missouri, 262 US 276; 43 S Ct 544; 67 L Ed 981 (1923); Federal Power Comm v Natural Gas Pipeline, 315 US 575; 62 S Ct 736; 86 L Ed 1037 (1942); Duquesne Light Co v Barasch, 488 US 299; 109 S Ct 609; 102 L Ed 2d 646 (1989). See also, Northern Michigan Water Co v Public Service Comm, 381 Mich 340; 161 NW2d 584 (1968); Consumers Power Co v Public Service Comm, 415 Mich 134; 327 NW2d 875 (1982); ABATE v Public Service Comm, 430 Mich 33; 420 NW2d 81 (1988).

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cited with approval the conclusions of a circuit court judge granting an injunction against such

unlawful rates:

Certainly at first blush it would appear to anyone steeped in ‘due process’ considerations that it is grossly unfair to include certain items of decreased cost in rate determination while at the same time to exclude items of increased cost. [Michigan Consolidated Gas Company v Public Service Comm, 389 Mich 624, 633; 209 NW2d 210 (1973).] As a matter of fundamental ratemaking law, DTE Gas is entitled to a commensurate return

of and on its investment in providing utility service.6 It is axiomatic that utility rates are overall

rates. Federal Power Comm, supra, 320 US at 602; Michigan Bell Telephone Co v Public Service

Comm, 332 Mich 7, 37; 50 NW2d 826 (1952); MCL 460.6a(2)(b).

DTE Gas’s constitutional rights would be violated by a failure to acknowledge (and

establish rates based on) both decreasing and increasing costs. The United States Supreme Court,

in construing the Fifth Amendment mandates in conjunction with utility ratemaking, aptly

concluded:

Regulation may, consistently with the Constitution, limit stringently the return recovered on investment, for investors’ interests provide only one of the variables in the constitutional calculus of reasonableness (citations omitted). It is, however, plain that the ‘power to regulate is not a power to destroy,’ (citations omitted) and that maximum rates must be calculated for a regulated class in conformity with the pertinent constitutional limitations. Price control is “unconstitutional if arbitrary, discriminatory, or demonstrably irrelevant to the policy the legislature is free to adopt.” [Permian Basin Area Rate Cases, supra, 390 US at 769-770 (Emphasis added).]

The Commission has an obligation to facilitate DTE Gas’s financial health for the benefit

of its customers and shareholders. See, by way of example and not limitation, MCL 460.6a(2)(3);

6 See Bluefield Waterworks Improvement Co v Public Service Commission of West Virginia, 262 US 679, 690-694; 43 S Ct 675; 67 L Ed 1176 (1923); Federal Power Comm v Hope Natural Gas Co, 320 US 591, 603; 64 S Ct 281; 88 L Ed 333 (1944). See also Permian Basin Area Rate Cases, 390 US 747, 769-70; 88 S Ct 1344; 20 L Ed 2d 312 (1968); FPC v Memphis Light, Gas and Water Division, 411 US 458; 43 S Ct 1723; 36 L Ed 2d 426 (1973); General Telephone Co v Public Service Comm, 341 Mich 620; 67 NW2d 882 (1954); Michigan Consolidated Gas Co v Public Service Comm, 389 Mich 624; 209 NW2d 210 (1973).

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Smith v Illinois Bell Telephone Co, 270 US 587, 591; 46 S Ct 408; 70 L Ed 747 (1926). Federal

Power Comm, supra, 320 US at 602; Michigan Bell Telephone Co, supra, 332 Mich at 37;

MichCon, supra, 389 Mich at 633; Michigan Bell Telephone Co v Engler, 257 F3d 587, 594-96

(CA 6, 2001). Furthermore, our Supreme Court has clearly stated that:

Statutes will be construed in the most beneficial way which their language will permit to prevent absurdity, hardship or injustice; to favor public convenience, and to oppose all prejudice to public interests. [Attorney General v Marx, 203 Mich 331, 335; 168 NW 1005 (1918).]

Under well-established ratemaking law, rates for utility service are set prospectively so that

the utility provides service and its customers receive service at established rates, which are based

on the estimated costs of providing that service, plus a reasonable return on the utility’s investment.

See ABATE v Public Service Comm, 208 Mich App 248, 257-258; 527 NW2d 533 (1994). This is

part of the “regulatory compact,” under which the utility dedicates its private property to serve the

public, and correspondingly receives a reasonable return on the value of its private property. In

Board of Public Utility Comm’rs v New York Telephone Co, 271 US 23; 46 S Ct 363; 70 L Ed 808

(1926), the United States Supreme Court explained that the just compensation safeguarded to the

utility by the Fourteenth Amendment is a reasonable return on the value of the property used at

the time that the property is being used for the public service. Rates that are not sufficient to yield

that present return are confiscatory. 271 US at 31. To the extent that the utility might have earned

sufficient revenue in the past, such past revenue cannot be used to sustain confiscatory rates in the

future. Id. at 32. Thus, it would be unconstitutional for the Commission to use hindsight or

otherwise base DTE Gas’s rates on past events.

The Michigan Supreme Court has recognized that the Commission has only limited

statutory authority, which does not include the authority to retroactively reduce rates. Michigan

Bell Telephone Co v Public Service Comm, 315 Mich 533, 347; 24 NW2d 200 (1946). A lawfully

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established rate remains in force until altered by a subsequently established lawful rate. Id., at

544. A regulatory body cannot penalize a utility for collecting a rate during the period elapsing

between the date of the order prescribing the rate and the date of the subsequent order reducing it.

Id. at 543-44. Where the Commission establishes a reasonable rate in its legislative capacity, the

Commission cannot later, in its quasi-judicial capacity, find that the utility violated the law because

it charged that rate. Id. at 550-51.

The prohibition against retroactive ratemaking remains in effect and applies in this case so

that rates may only be set prospectively. “[T]he essential principal of the rule against retroactive

ratemaking is that when the estimates prove inaccurate and costs are higher or lower than predicted,

the previously set rates cannot be changed to correct for the error; the only step that the MPSC can

take is to prospectively revise rates in an effort to set more appropriate ones.” The Detroit Edison

Co v Public Service Comm, 416 Mich 510, 523; 331 NW2d 159 (1982) (opinion by Fitzgerald,

C.J.).

IV. TEST YEAR.

DTE Gas proposes a projected test year of January 1, 2022 through December 31, 2022

(5T 1282). Staff agrees (e.g., Exhibit S-1, Schedule A1) and there appears to be no disagreement

with respect to the projected test year among the parties.

Prior to 2008 PA 286, which allows utilities to use fully forecasted projected test years in

requesting rate relief,7 Commission policy called for the use of prior actual experience adjusted

for known and measurable changes. Notwithstanding the statutory authority to use a fully-

forecasted test period, DTE Gas used actual financial results from the historical test year ended

7 MCL 460.6a(1) relevantly states: “A utility may use projected costs and revenues for a future consecutive 12-month period in developing its requested rates and charges.”

14

December 31, 2019 as a starting point, and then normalized and adjusted those results for inflation

and other known and measurable changes, to arrive at a fully projected test year revenue deficiency

of approximately $195 million (5T 1281–82, 1385, 1394–95; Exhibit A-11, Schedule A1).8 In

other words, DTE Gas essentially utilized the Commission’s prior methodology, which produced

the equivalent of a fully-projected test year. This methodology is also reasonable in light of the

significant effects, and lingering uncertainties, from the COVID-19 pandemic (5T 1282).

V. RATE BASE.

A utility’s rate base consists of the net amount of capital invested in plant, plus the utility’s

working capital requirements. DTE Gas’s Total Rate Base for the projected test year is $5,610.6

million, which consists of $4,581.3 million of Net Utility Plant, and $1,029.3 million of Working

Capital (5T 1386; Exhibit A-12, Schedule B1).

A. Adjusted Total Rate Base

As discussed in Section II and Attachment A, page 2 of 4, the Rate Base adjustments the

Company is adopting pertain to 1) Service Renewal expenditures for personal protective

equipment and vehicle rentals arising from COVID safety requirements and 2) certain Gas

Information Technology projects. DTE Gas’s Total Rate Base as adjusted in this brief for the

projected period ending December 31, 2022 is reduced from $5,610.6 million to $5,610.3 million.

B. Capital Expenditures.

DTE Gas has made or will make approximately $1.5 billion of capital expenditures from

the end of the historical test year to the end of the projected test year (January 1, 2020 through

December 31, 2022). (Exhibit A-12, Schedule B5, line 28, columns (e) and (f)). These

8 DTE Gas’s $195 million Revenue Deficiency is based on a 13-month average Projected Rate Base of $5,611 million, Projected Net Operating Income (NOI) of $170 million, and an overall rate of return of 5.59%. The $5,611 million Total Rate Base is detailed on Exhibit A-12, Schedule B1. The $170 million NOI is developed on Exhibit A-13, Schedule C1. The 5.59% overall rate of return is set forth on Exhibit A-14, Schedule D1 (5T 1386).

15

expenditures should be approved because they are prudent investments in DTE Gas’s natural gas

system that are necessary for DTE Gas to maintain its safe and reliable system for distributing

natural gas to its customers. They are also integral parts of the Gas Delivery Plan (GDP), discussed

below (5T 1189, 1194).

The capital expenditure amount indicated above excludes new Infrastructure Recovery

Mechanism (IRM) expenditures beginning January 1, 2022 (5T 1194). DTE Gas proposes to

establish a new IRM surcharge beginning on January 1, 2022 to recover the incremental revenue

requirement associated with invested IRM capital, as further discussed in Sections VIII. B, and X.

D. 1 (5T 1194; Exhibit A-12, Schedule B5.5 Revised provides additional detail on DTE Gas’s 25

largest projects from January 2020 through December 2022 (5T 1179).

1. Gas Delivery Plan (GDP)

DTE Gas developed the GDP in accordance with the U-20642 settlement.9 The GDP is the

Company’s ten-year investment plan for its natural gas infrastructure (transmission, distribution,

and storage and compression assets). (Exhibit A-12, Schedule B5.6). It provides a roadmap for the

Company to continue to provide safe and reliable service to its 1.3 million customers, while

maintaining customer affordability in an environmentally responsible manner. The GDP is

intended to provide a clear and transparent ten-year framework setting forth: (1) the next decade

of natural gas capital investments planned by the Company, (2) how the Company plans to meet

the needs for natural gas supply and demand, and (3) how the Company will prioritize its pipeline

safety investments. The GDP should be viewed as a flexible working guide that will be updated in

response to new information and future events. It is also important to not view requests for

9 Paragraph 11 of the U-20642 settlement states: “DTE Gas will include a Natural Gas Delivery Plan in its next general rate case filing based on collaboration with and feedback from the MPSC Staff, which will provide the framework for the next ten years of investments in DTE Gas’s natural gas infrastructure.”

16

recovery in isolation, since they are part of a larger, deliberate long-term plan (5T 1188–91, 1290–

91).

A large portion of the risk mitigation capital expenditures in the GDP are prioritized to

address DTE Gas’s aging distribution and transmission pipeline infrastructure (5T 1188, 1291–

92). The capital safety and reliability projects identified in this case reflect the first three years of

the GDP (5T 1194).

2. Routine Capital Spending

Routine capital spending supports distribution, transmission, storage, and general plant

assets. DTE Gas has made or will make $712.3 million of routine capital expenditures from the

end of the historical test year to the end of the projected test year (December 31, 2019 through

December 31, 2022). (5T 583–84, 1196; Exhibit A-12, Schedule B5.1, line 6, columns (f) and (g),

with components reflected in lines 2 through 5). Mr. Brudzynski explained and supported the

routine capital expenditures required for distribution plant (5T 587–609), transmission plant (5T

610–13), storage plant (5T 613–15), and general plant (5T 615–19). Exhibit A-12, Schedule B5.5

Revised (DTE Gas Highest Cost Top 25 Capital projects), pages 3-14, provides project level detail

supporting the capital expenditures for the Gordie Howe International Bridge (GHIB), Howard

City System Supply, Southfield 24” Pipe Replacement, Myers Lake Community Expansion, Ferry

Rd Community Expansion, K-Line Pipe Replacement, Alpena West Branch Drain Line Lowering,

and Belle River/Columbus Valve Upgrade projects (5T 1196).

a. Communications & Control - Meters

Distribution includes Communications & Control – Meters. The Company supports $40.9

million of capital expenditures from January 1, 2020 through December 31, 2022 (illustrated in

Exhibit A-12, Schedule B5.1, page 2, line 10, columns (f) and (g)). The yearly average of $13.6

17

million is an increase of $1.3 million compared to the 5-year historical average, which was driven

primarily by additional meter purchases in 2020 (5T 600).

Staff took issue with the Company maintaining safety stock, inaccurately characterizing it

as “akin to contingency” (5T 1906). The Company disagrees. Witness Ayala explained that the

purpose of DTE Gas’s safety stock is to keep a sufficient supply of meters and modules on hand

to support unexpected field work and vendor shipping delays. Safety stock is planned and unique

for each meter depending on vendor lead time and the variability of usage. DTE Gas maintains

safety stock consisting of quantities (less than six months) required to meet business demand

variability, and to provide for any vendor delivery and shipping shortfalls. Recent experience with

vendor delays has demonstrated the importance of maintaining an ambient level of safety stock for

meters and modules, and it is critical to keeping customers’ gas flowing seamlessly (5T 522–23).

Staff’s concern also seems to be based on taking the word “contingency” out of context

from Mr. Brudzynski’s testimony. He more fully testified: “Carrying a certain level of inventory

contingency for unforeseen factors (weather, vendor delays, material shortages, etc.) called safety

stock, is a means to ensure an appropriate level of inventory is available during the year. At times

in the past, DTE Gas has experienced inventory shortages of available meters to timely perform

customer work” (5T 602). In contrast, a “contingency” is an undefined amount included in a

project that is above the best forecast for that project (5T 522).

Staff “concludes it is reasonable and prudent to only support purchases that cover the

company’s forecasted installations” (5T 1907). To the contrary, DTE Gas purchases meters for

non-forecasted installations and meter replacements that are driven by customer demand. The

Company always needs to have available stock to service customers. Therefore, it is reasonable

and prudent to purchase enough meters and modules to replenish safety stock. This is a standard

18

supply chain practice followed in all industries, especially in industries such as natural gas where

keeping energy flowing is critical to public health and safety (5T 523).

As Witness Ayala explained, Staff’s forecast represents only AMI/AMR first-time

installations, and does not include all other customer-requested work, Company-generated work,

and emergent meter work that is performed, which requires a new meter and module to be installed

(5T 523–26). See also Table 1 at 5T 524, which depicts the annual volume of new meters and

modules that are installed each year, based on a three-year average.

Staff “recommends a capital disallowance of $25,969 in 2020, $1,847,610 in 2021, and

$1,086,506 for AMI module purchases . . . [and a] capital disallowance of $765,785 in 2020,

$675,000 in 2021, and $1,086,206 in 2022 for AMR module purchase” (5T 1912). Staff further

“recommends a meter purchase disallowance of $1,286,634 in 2020, $7,728,000 in 2021, and

$6,824,125 in 2022. This amount removes the purchase cost associated with the Company’s

planned new installations, route maintenance, customer requested meter work, and ability to have

meter safety stock of 31,000 in 2021 and 2022” (5T 1916).

DTE Gas disagrees because, as discussed above, the proposed disallowances would limit

the number of modules and meters that it can supply for routine and non-forecasted field work.10

Staff’s proposals would also hinder the Company’s ability to serve customers in a timely fashion

and ensure their health and safety through uninterrupted service. Not having safety stock would

also lead to the above-described inefficiencies and additional logistical costs if a vender is late

with shipments (5T 527–28).

10 For every meter replacement there is a module replacement. It is imperative to have enough modules (AMI or AMR) for new meters. It is also necessary to have enough modules for other work. Approximately 10% of meter/module re-work orders (based on three years) occurs where a module is added or replaced on a meter, without a new meter installation (5T 527).

19

Staff’s proposed disallowance is also based on the inaccurate premise that “the Company

plans on purchasing more modules than they intend to install” (5T 1910). To the contrary, DTE

Gas only orders meters and modules that it plans to install in a given year and to replenish safety

stock if it has been used up. The Company follows a first-in, first-out (FIFO) approach to ensure

the use of the oldest inventory and to not hold stock longer than needed. It is critical for DTE Gas

to maintain inventory levels that allow the Company to run efficiently, ensure timely customer

service, and adhere to AGA and ASCM standards (5T 527–28).

Therefore, the Staff’s proposed meter and module disallowances should be rejected as

lacking in sound foundation, inconsistent with reasonable and prudent utility operations, and

contrary to the interests of reliability and customer safety.

b. Service Renewals

From January 1, 2020 through December 31, 2022, DTE Gas will have incurred $45.4

million of service renewal capital expenditures (5T 596; Exhibit A-12, Schedule B5.1, page 2, line

7, columns (f) and (g)). Three factors relating to COVID-19 caused an increase in service renewal

cost/unit from 2019 to 2020: (1) increased labor and labor-related overheads due to shifting

resources from O&M work to capital expenditure work, (2) increased personal protective

equipment (PPE) spend, and (3) vehicle rentals (5T 596–97).

AG witness Coppola took issue with the first factor, and calculated a proposed $6,657,000

disallowance by taking the increase in the labor and labor overheads unit cost from 2019 to 2020

($883 per unit, see Exhibit A-31, Schedule U1) and multiplying it by the forecasted units for 2020,

2021, and 2022 (5T 1648).

The Company disagrees with the AG’s recommended 2020 disallowance ($1,983,000). Mr.

Brudzynski explained that the COVID-19 pandemic caused an unprecedented economic disruption

in Michigan with the implementation of lockdowns, social distancing, and other health safety

20

measures as ordered by the Governor. As a result, many small commercial customers had to close

their businesses for extended periods of time or operate at severely curtailed capacity during 2020.

This unprecedented shutdown of large portions of the economy created uncertainty for many

companies in Michigan including DTE Gas. To mitigate some of this uncertainty, DTE Gas took

unprecedented one-time actions to re-prioritize resources from non-emergency O&M work to

capital, as previously discussed in discovery (see Exhibit A-31, Schedule U3). Shifting resources

was an efficient use of the labor force that otherwise would have been idle during unprecedented

times. Prioritizing capital work allowed DTE Gas to keep all employees gainfully employed and

productive during a period of uncertainty while completing work. Therefore, the Commission

should fully approve DTE Gas’s request for 2020 capital expenditures of $13,282,000 (5T 624).

The AG’s proposed $4,592,000 disallowance for 2021 and 2022 should also be rejected.

The shift in resources from O&M work to capital work was a one-time occurrence in 2020 in

response to the pandemic. The increased labor and labor overhead unit cost in 2020 from shifting

resources does not continue in 2021 and 2022. The increase in the labor and labor overhead unit

cost between 2019 and 2021 ($367 per unit) is due to normal costs of business including inflation,

and cost of living increases (Exhibit A-31, Schedule U2). Therefore, the AG’s proposed

disallowances for 2021 ($2,296,000) and 2022 ($2,296,000) should be rejected, and the

Commission should fully approve DTE Gas’s request for capital expenditures of $16,035,000 for

2021 and $16,096,000 for 2022 (5T 625).

c. Service Abandonments


million of service abandonment capital expenditures (5T 607; Exhibit A-12, Schedule B5.1, page

2, line 5, columns (f) and (g)). As with Service Renewals (discussed above), three factors relating

21

to COVID-19 increased DTE Gas’s service abandonments cost/unit from 2019 to 2020 (5T 607–

08).

Mr. Coppola again took issue with the first factor, and calculated a proposed $1,568,000

disallowance for 2020 by taking the increase in the labor and labor overheads unit cost from 2019

to 2020 ($834 per unit, see Exhibit A-31, Schedule U4) and multiplying it by the forecasted units

for 2020 (5T 1649).

The Company disagrees. As discussed above in the Service Renewals section, the shifting

of resources was an efficient use of DTE Gas’s labor force during the pandemic. Therefore, the

Commission should fully approve the Company’s request for capital expenditures of $4,943,000

for 2020 (5T 646).

d. New Market Attachments


million of new market attachments capital expenditures (Exhibit A-12, Schedule B5.1, page 2, line

13, columns (f) and (g)).

AG witness Coppola proposed disallowances of $10,901,000 for 2021, and $10,653,000

for 2022, based on his calculation of a lower cost per unit based on three-year average historical

costs plus 2% annual inflation (5T 1651).

The Company disagrees. Mr. Brudzynski explained that the AG’s calculations failed to

consider that contractor costs increased due to new blanket contracts (effective Q2 of 2020)

because DTE Gas’s previous contracts expired and new contracts were awarded. These new

contracts were evaluated through request for proposal process across vendors and based on

multiple performance criteria including safety, experience, resource capacity, and pricing so that

contracts were awarded to the best qualified vendors. The increased contractor costs result in

22

increases in New Markets work of approximately 10% in 2021 and 12% in 2022, compared to the

three-year average used by the AG (5T 626–27).

The AG’s calculations also failed to consider that the type or mix of attachments is

expected to change in 2021 and 2022 (fewer new home constructions that are typically on or near

a natural gas main and therefore are the least costly of attachments; 42% increase in attachment

requests requiring the extension of a main to provide service, and an increase in

EUT/Transportation New Customer Attachments), which increases the cost per attachment (5T

627).

e. Service Alterations


million of service alteration capital expenditures (5T 594; Exhibit A-12, Schedule B5.1, page 2,

line 6, columns (f) and (g)).

Staff recommended that service alterations capital expenditures be reduced to $7,191,336

in 2021, and $16,651,736 in 2022 (which would equal disallowances of $1,349,664 in 2021 and

$1,186,264 in 2022) reasoning that only a ‘fraction” of service alterations will require a cross-bore

inspection (5T 1836). A cross bore occurs when the service line intersects an existing underground

utility line during installation. With this new program, after a service alteration, the sewer line or

storm drain is inspected with a camera to ensure no intersection occurred. Any cross-bores that are

identified are remediated appropriately to ensure safe delivery of gas to customers (5T 595, 629).

Therefore, the Commission should fully approve the Company’s requested capital expenditures

for service alterations. Staff’s reasoning for their proposed disallowance is that only a ‘fraction”

of service alterations will require a cross-bore inspection (5T 1836).

The Company disagrees. Estimated costs for cross bore inspections were based on

negotiated contractual pricing and the Company’s forecasted volumes of service alterations

23

requiring cross bore inspections as required by the Company’s new safety procedure (Distribution

& Transmission procedures 4.6 - Identifying and protecting underground utilities, conduits and

structures) implemented in 4 January 1, 2021 (5T 629-630).

Staff’s calculations failed to consider increases in hard surface restoration and unit

complexity mix (5T 630). As Mr. Brudzynski explained, there has been an increasing trend for

hard surface restoration, which is driven by mains that are located under sidewalks or in roadways,

and by increased municipal permitting requirements. DTE Gas anticipates that 30% of the service

alterations completed in 2021 and 2022 will require hard surface restoration. Restoration costs will

also increase because restoration contracts were awarded in 2020 for the next three years starting

in 2021 (the average increase across contractors was 7% during restoration season and 17% for

backlog units to be completed after winter season construction). Changes in municipal permitting

requirements (outlining specifications for DTE Gas to follow in the restoration process) have also

led to increased costs (5T 628–29).

AG witness Coppola proposed disallowances of $2,372,000 for 2021, and $2,209,000 for

2022, based on his use of the cost per unit in 2020 (5T 1645). The AG’s calculations based on

2020 costs not only failed to consider the increases in hard surface restoration and unit complexity

mix discussed above, but also failed to consider that DTE Gas implemented the cross-bore safety

program on January 1, 2021 failing to address associated program costs incurred going forward.

A cross bore occurs when the service line intersects an existing underground utility line during

installation. With this new program, after a service alteration, the sewer line or storm drain is

inspected with a camera to ensure no intersection occurred. Any cross-bores that are identified are

remediated appropriately to ensure safe delivery of gas to customers (5T 595, 629). Therefore, the

24

Commission should fully approve the Company’s requested capital expenditures for service

alterations.

f. Belle Isle Main Replacement

In late November 2018, a contractor struck DTE Gas’s 4” 50 psig distribution main,

resulting in the total loss of gas service to the 20 customers on Belle Isle. In May of 2019, DTE

Gas implemented a long-term solution by installing 3400’ of 4” 6 distribution main via horizontal

directional drill (HDD) under the river. The solution cost approximately $2.5 million, $2.24

million of capital expenditure and $0.2 million of O&M. (5T 1233-34).

AG witness Coppola recommended that the Commission “remove the entire amount of

$2.4 million from rate base . . . [and] order the Company to permanently remove this amount from

rate base so that it is not included in future rate case filings” (5T 1653).

Witness Coppola’s recommendation is not appropriate as only $1.24 million has been

requested in this case. As Mr. Brudzynski explained, DTE Electric reimbursed DTE Gas $1.0

million of the $2.24 million total cost incurred (Exhibit A-31, Schedule U5). Adopting witness

Coppola’s recommendation would result in a $1.0 million disallowance of expenditures that are

not even being requested by the Company in this case (5T 631).

g. System Reliability


million of system reliability capital expenditures (5T 592; Exhibit A-12, Schedule B5.1, page 2,

line 8, columns (f) and (g)).

Staff proposed that the 2021 capital expenditure level be adjusted consistent with the 2020

capital expenditure level of $8,030,000 (which would be a $5,520,000 disallowance), reasoning

that “the Company provides no justification, support, or discussion to substantiate” increases in

capital costs related to regulator stations without take-off valves (5T 1834).

25

The Company disagrees. Mr. Brudzynski explained that Staff’s calculation apparently did

not consider the increase in projects from 2020 to 2021 (5T 632).

Staff further recommended that the Company should provide information related to the

cost drivers contributing to the increase in capital expenditures since the beginning of the program

for regulators stations without take-off valves in 2016 (5T 1835). Mr. Brudzynski responded by

listing process, design, and safety enhancements that have been implemented since the System

Reliability TOV program began in 2016. He further explained that the cost associated with TOV

program replacements depends on whether the regulator station is above or below grade. On

average, the recent enhancements result in cost increases of approximately $145,000 per below-

grade regulator installation, and approximately $58,000 per above-grade regulator installation.

This results in a total additional cost of $4,669,000 for TOV projects in 2021 (5T 633–36).11

Mr. Brudzynski further explained that the nature of the replacement work differs

significantly depending on whether the project is above or below grade. For 2021, the average

TOV project cost is $525,445 for above grade, and $107,963 for below grade. There is a

significantly higher percentage of below grade projects in 2021 compared to other years (10% in

2019; 16% in 2020; 37% in 2021; 13% in 2022), which results in a significantly higher average

cost per unit in 2021. Therefore, the Staff’s proposed $5,520,000 should not be adopted (5T 634–

35).

h. Routine Transmission Plant


million of routine transmission plant capital expenditures (5T 610–11; Exhibit A-12, Schedule

B5.1, page 1, line 3, columns (f) and (g)).

11 In response to Staff’s recommendation for further information (5T 1835), Mr. Brudzynski also provided additional detail regarding the remaining regulator station projects and a timeline for competition (5T 636).

26

AG witness Coppola recommended an $11.8 million disallowance for 2021 and 2022 for

eight soil-cover pipeline remediation projects, suggesting that the Company should explore and

evaluate alternatives (5T 1656).

The Company disagrees. Mr. Brudzynski explained that DTE Gas conducts pipeline

surveys per DTE Gas Standard 705. When an exposed pipe is identified, the Pipeline Integrity

Group ranks the exposure for risk using a relative model that considers various likelihood and

consequence factors. The remediation plan is to remediate the highest risk-ranked exposures. The

exposures in this case are ranked the highest. Prioritizing and permanently mitigating the highest

risk-ranked exposures ensures that DTE Gas provides customers with safe and reliable service.

Therefore, the AG’s proposed $11.8 million disallowance should not be adopted (5T 637–40).

In response to Mr. Coppola’s further suggestion that DTE Gas is replacing more pipeline

than necessary (5T 1630), Mr. Brudzynski explained that there are several reasons why the

replaced segment of pipeline is longer than the exposed or shallow segment. First, to avoid

significant impact to environmentally sensitive areas and connect the pipe in a non-sensitive area.

Second, the replacement plan must include considerations for pipe entry and exit space during

construction, as well as entry and exit angles that satisfy the minimum requirement of three feet of

cover at all below-grade locations on the new pipe. The increased length of the replacement pipe

due to the exit and entry bends also enables unrestricted access of in-line inspection tools during

pipeline assessments.

DTE Gas also uses alternative risk mitigation methods for pipeline restoration projects,

including adding soil cover and bank stabilization, subject to regulatory requirements and

effectiveness (5T 638–39).12 These alternatives are not suitable for the pipeline projects at issue

12 Pursuant to Michigan Gas Safety Standards, the minimum cover, in general, is 30” for a Class 1 location, and 36” for Class 2, 3, and 4 (5T 638).

27

because the projects are similar to other projects where governmental agencies denied permits

when alternative methods to add cover were proposed. The issue is that the pipelines are exposed

or extremely shallow perpendicular to the river at the original river/stream crossing location (low

point of the pipeline) due to natural scouring of the waterway at that location. Restoring cover by

adding soil and armoring structures on top of the pipeline to protect future exposure would

essentially create a weir on the river and fish passage issues. Governmental concerns resulted in

the denial of permitting for any remediation method other than pipeline replacement (5T 639–40).

3. Gas Information Technology (IT) Spending

Gas IT spending supports technology improvements necessary for DTE Gas to run its

business and provide workforce safety through cyber security programs, projects, and program

enhancements to improve systems reliability and added overall functionality. DTE Gas has made

or will make $28.2 million of IT capital expenditures from the end of the historical test year to the

end of the projected test year (December 31, 2019 through December 31, 2022). (5T 1198; Exhibit

A-12, Schedule B5, line 27, columns (e) and (f)). Exhibit A-12, Schedule B5.5 Revised (DTE Gas

Highest Cost Top 25 Capital Projects), pages 41-42, provides project level detail for the Field

Service Management (ClickSoft) and Picarro Leak Survey projects (5T 1199).

DTE Gas’s IT investment spending is part of the DTE IT Five-year Plan for 2021-2025,

which was filed on March 22, 2021 in Case No. U-20561 (5T 660–62, 1299). The IT Plan

categorizes IT projects into an IT Investment Portfolio, with IT Investment Categories (see the

matrix at 5T 662, 1301).

Witness Busby explained how the DTE enterprise IT capital investment planning process

occurs and how it tracks with the Five-Year IT Plan and that DTE Gas categorizes its IT spending

into five categories: Regulatory, Sustainment, Return to Health, IT Enhancements, and Strategic

Investments. He also provided extensive support, including approved business cases and updated

28

cost information for specific DTE Gas IT asset projects within each of these categories. In this

case, DTE Gas is requesting $28.2 million in capital expenditures for DTE Gas-specific IT projects

for the period 2020 through 2022. (Exhibit A-12, Schedule B5.4).

AG witness Coppola proposed $18.26 million of capital disallowances relating to six Gas

IT projects. The Company agrees with $450,000 of the AG’s recommendation related to the Field

Sketch Enhancement project, however, the Commission should reject $17.8 million of that

proposed disallowance, as discussed below.

ClickSoft Field Service Management

AG witness Coppola proposed a $6.8 million disallowance for capital expenditures for the

ClickSoft Field Service Management system, reasoning that “it is readily apparent that the

Company wants more current system with new features and exciting mobile phone connectivity,

although the current system is still functional and only six years old” (5T 1669).

The AG’s reasoning is incorrect. Mr. Busby explained that the current system is not six

years old; instead, it was initially implemented in 2007 (it was then known as Advantex). In 2014,

ASEA Brown Boveri (ABB) bought the Advantex software and rebranded it as Service Suite. The

vendor ABB has now deemed the application to be at the end of life. This poses many risks to

DTE Gas because ABB will no longer provide enhancements or defect remediations to this product

and will no longer invest in ensuring its stability. ABB will also no longer provide critical security

updates to ensure the software remains safe from new cyber threats. This increases the risk of

security vulnerabilities to DTE Gas’s infrastructure, which is an unacceptable risk (5T 683–85,

758–59).

Mr. Coppola also suggested that the Company did not provide business case justification

(5T 1668–69), but Mr. Busby explained in both his direct and rebuttal testimony that ABB is no

29

longer investing in product stability or security. If the system fails or is inaccessible due to a cyber-

attack, this would jeopardize the live field dispatch of gas operations employees who rely on the

dispatching and management system. From 2018-2020, unplanned outages caused an

approximately 56-hour field interruption during which the Company could not receive or send

dispatch to the field, including emergency gas leaks and outages. The Company must also perform

monthly planned outages to address performance and security-risk issues on the current end-of-

life system, which cost $10,000 to $15,000 per year. The investment is therefore justified to ensure

the timely scheduling and deployment of field resources, which will provide faster and more

efficient customer service (5T 684, 759).

Electronic Gas Management System (EGMS)

AG witness Coppola proposed a $3.3 million disallowance from 2019 to 2022 for the

Electronic Gas Management System (EGMS), claiming that “the Company failed to keep up with

vendor releases of system software updates and now finds itself in a situation where the vendor

can only provide limited support for the system” (5T 1671). He further suggested that “the

Commission should direct the Company to remove any disallowed amounts, previously

capitalized, from plant balances to avoid inclusion of these amounts in rate base in future rate

cases” (5T 1672).

The AG’s proposals should be rejected. Mr. Busby explained in both his direct and rebuttal

testimony that the EGMS application currently utilized by DTE Gas is now several versions behind

the standard version and is no longer supported. This project focuses on upgrading the application

to the current version (V 17.0) and security upgrades that will improve the Company’s ability to

mitigate security threats and associated vulnerability risk to nomination data on the EGMS system.

The AG’s assertion that the Company failed to manage the application is inaccurate. Decisions to

30

upgrade applications are frequently reviewed for priority, business value, and risk mitigation as

explained in the Company’s Five Year IT Plan. Through this process, the Company determined

that it is prudent to complete the necessary version upgrade at this time (5T 691, 760–61. See also

DTE Five Year IT Plan, section 4.B.ii, regarding asset lifecycles and refresh rates).

Mr. Coppola was similarly inaccurate in suggesting a concern that the “system will be

used by DTE Gathering Pipelines, an affiliate of DTE Gas” (5T 1671). There is a DTE Gas

Gathering software module within the EGMS system, but all expense-related information

presented in Mr. Busby’s testimony applies either to DTE Gas or the DTE Gas portion of a shared

asset (5T 761).

Gas IT Application Health

AG witness Coppola proposed that the Commission remove $3,977,000 from capital

expenditures from 2019 through 2022 for the Gas IT Application Health projects and direct the

Company to expense these costs in future years. He also proposed a $780,000 increase in O&M

for 2022. He reasoned that the description of the work “does not rise to the level of work that is

capitalizable under the Company’s accounting policy. These costs are routine operating and

maintenance costs, and they should be expenses each year” (5T 1673).

Mr. Busby disagreed, explaining that the investments should be capitalized under the

Company’s established accounting policy for IT costs. Upgrades and enhancements are capitalized

if it is probable that those expenditures will result in significant additional functionality, the

upgrade results in new software designs or a change to part of an existing software design, and a

materiality threshold of $10,000 for capitalizing upgrades and enhancements is met. In addition,

for the first 60 days following the in-service date of a software development project, the direct cost

of remediating all defects related to the originally planned design can be capitalized (5T 762). The

31

AG’s proposal to increase O&M to account for capital dollars should similarly be rejected as

inconsistent with the Company’s accounting policy (5T 762).

End of Life (EOL) Gas Device Program

AG witness Coppola proposed that the Commission remove $2,102,000 from 2019 to 2022

capital expenditures for the End of Life (EOL) Device Program, reasoning that the Company’s

end-of-life replacement cycle should be extended from five years to seven years (5T 1675)

The AG’s proposal should be rejected. Mr. Busby explained that the EOL Gas Device

Program replaces network and endpoint devices that are at the end of their serviceable lives. The

five-year life expectancy and serviceable life replacement cycle are derived from original

manufacturer specifications. Not following these specifications would lead to lost productivity and

increased risks of security threats (5T 763–64).

BioGreen Gas Program Redesign

AG witness Coppola proposed that the Commission remove $800,000 from 2020 to 2021

capital expenditures for the BioGreen Gas program, reasoning that the program and its predecessor

were not included in this case, and it was not clear to him why IT costs should be an exception.

He also questioned the benefit of this program to the larger customer base (5T 1676).

Mr. Busby explained that the Commission previously approved the program for inclusion

in rate base in Case No. U-20839, but the IT spend to enable the new DTE CleanVision Natural

Gas Program (replacing the BioGreen Gas program) was not included in that case. The investment

is justified because it is an important component of the Company’s goal to achieve net zero carbon

emissions by 2050, and it is needed to support the broader BioGreen Gas Redesign Program as

approved by the Commission. Therefore, the Commission should approve $840,000 in capital

expenditures, as reflected in Exhibit A-12, Schedule B5.4.1, line 12 (5T 700, 765–66).

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Field Sketch Enhancements

AG witness Coppola proposed that the Commission remove $1,275,000 from 2019 through

2022 capital expenditures for the Field Sketch Enhancements project, reasoning that the Company

decided to pause further investments after discovering incompatibility issues with other related

systems (5T 1677).

The Company partially agrees. The Commission should approve $825,000 of capital

expenditures ($427,000 for 2019 and $398,00 for 2020), and remove $300,000 for 2021 and

$150,000 for 2022, as reflected on Exhibit A-12, Schedule B5.4.1, line 9 (5T 767–68).

4. Large Capital Projects.

Large Capital Projects, for the most part, have rather large capital expenditures that are not

considered routine and are not part of IRM programs, but are required for the safety and reliability

of DTE Gas’s system as depicted in DTE Gas’s 10-year GDP. These large safety and reliability

projects are part of DTE Gas’s highest cost top 25 projects, and include: DTE Gas Site Security,

Traverse City / Alpena Reinforcement Project (TCARP), Van Born Project, Fort Street Main Phase

III, Middlebelt Deration Project, Grosse Ile System Supply, and East Jefferson Project. DTE Gas

has made or will make $185.0 million of large capital project expenditures from the end of the

historical test year to the end of the projected test year (December 31, 2019 through December 31,

2022). (5T 1199–1200; Exhibit A-12, Schedule B5, line 18, columns (e) and (f)). Mr. Telang

provided a high-level overview of two infrastructure projects (the TCARP and Van Born project)

having high integrity and/or customer outage risks (5T 1292–93). Ms. Sandberg provided detailed

explanations and support for these capital expenditures (5T 1203–39). Exhibit A-12, Schedule

B5.5 Revised (DTE Gas Highest Cost Top 25 Projects), pages 15-26, provides project level detail

(5T 1199).

33

a. TCARP

The TCARP entails looping the existing Lincoln-Traverse City pipeline with

approximately 8.8 miles of 10” diameter pipe, and looping the existing Frankfort pipeline with

14.4 miles of 8” diameter pipe; installation of six interconnects with pipelines owned by DTE

Michigan Gathering Holding Company (GSP- Gas Storage and Pipeline); installation of one new

gate station, and modifications to eleven existing gate stations. The TCARP will provide redundant

supply of gas, mitigating potential integrity and outage risks to approximately 91,000 customers

(5T 1207). From December 31, 2019 through December 31, 2022, DTE Gas will have incurred

$93.8 million of capital expenditures (5T 1216; Exhibit A-12, Schedule B5.2, line 6, columns (e)

and (f)).

Staff proposed a $27.5 million disallowance for expenses attributable to six

interconnections with DTE Michigan Lateral Company (DMLC) due to ongoing Case No. U-

20894, but indicated that it would revisit its proposal if the Commission approved the Act 9

application in that case (5T 1967–68). Recently, the Commission issued an order in Case No. U-

20894 authorizing DMLC to convert its existing Wet Header Pipeline from gas gathering to dry

gas transmission service (July 27, 2021 Order, p. 38) As Ms. Sandberg emphasized the $27.5

million of capital expenditures requested in this case for the interconnects are necessary in order

for the DMLC assets to provide the redundant transmission service approved in the Act 9 filing.

The interconnects are a key component in the TCARP project. Disallowance of the capital

expenditures will not provide the DTE Gas pipeline system needed backup supply to mitigate the

outage risk and evaluate the integrity of the Company’s pipelines through ILI assessment. As such,

it is appropriate for DTE Gas to recover them in this rate case (5T 1208–10, 1256–57).

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b. Van Born

The Van Born System currently consists of two pipelines: (1) a 30” 540 psig pipeline that

supplies natural gas to two large customers and one city gate station, and (2) a 36” 300 psig pipeline

that is a primary source of natural gas supply to the DTE Gas southeast markets. The Van Born

project essentially entails installing seven miles of new pipeline and related facilities, and

connecting the two existing pipelines in parallel to provide a redundant source of gas supply into

DTE Gas’s southeast market area, mitigating approximately 120,000 of the 160,000 potential

customer outages (5T 1217). DTE Gas seeks to recover $32.9 million for the period of January 1,

2020 through December 31, 2022 (5T 1220–23; Exhibit A-12, Schedule B5.2, line 7, columns (e)

and (f)).

Staff recommended a partial disallowance of $22 million, reasoning that an Act 9

application for the project has not yet been filed and approved, so the expenditures are speculative

(5T 1969).

Ms. Sandberg disagreed, explaining that the Van Born pipeline ranks as one of the top

pipelines in DTE Gas’s Transmission Renewal Program requiring remediation due to the high

customer outage potential. The $22 million in capital expenditures is critical to timely sequencing

of key activities necessary to meet the planned in-service date of January 2024. A delay in

sequencing of activities could delay the in-service date one year, which would similarly extend the

mitigation of the high customer outage potential another year (5T 1223, 1258–61; Exhibit A-12,

Schedule B5.6, DTE Gas’s Gas Delivery plan, pages 47-49).

AG witness Coppola proposed a full $32.9 million disallowance, reasoning that the project

is premature, and it is uncertain if the Act 9 application will be approved (5T 1659–60).

The Company disagrees. In addition to the discussion above, Ms. Sandberg explained that

the project is on schedule (see Exhibit A-12, Schedule B5.5 Revised DTE Gas Highest Cost Top

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25 Capital Projects, page 18). The $10.9 million in 2020 and 2021 is required for the submission

of an accurate and complete Act 9 filing in 2021. The $22.0 million in 2022 is required for the

commencement of construction (5T 1222, 1259–63).

Mr. Coppola also indicated that he was not convinced that a third pipeline is needed, based

on his belief that “the two pipelines could back each other up in the case of a supply emergency”

(5T 1658).

Ms. Sandberg clarified that the Van Born project is intended to mitigate an incident on the

36” Van Born pipeline. During the winter season, the existing 36” 300 psig Van Born pipeline has

a flow requirement of 24 MMscf/hr. The existing 30” 540 psig Van Born pipeline has a capacity

of 16 MMscf/hr. Thus, the existing 30” pipeline does not have enough capacity to supply the

existing 36” pipeline, even if flow to large industrial customers on the 30” pipeline is shut off. The

new seven miles of 24” 858 psig Van Born pipeline and associated facilities are designed to

provide a new back feed to the 36” 300 psig Van Born pipeline, while at the same time maintaining

flow to these large industrial customers. The Company evaluated alternative solutions but

determined that this is the optimum approach to reduce the maximum number of potential outages

while also considering customer affordability. Therefore, the project is justified and the entire

amount ($10.9 million for the Act 9 filing in 2021, and $22.0 million in 2022 for material

procurement and commencement of construction) should be approved (5T 1264–65).

c. Middlebelt Deration Project

The Middlebelt Deration Project consists of abandoning sections of pipeline and related

facilities and installing new pipeline and related facilities. The project is necessary to remedy 249

Maximum Allowable Operating Pressure (MAOP) record gaps and is expected to cost

approximately $3.0 million (5T 1228–32; Exhibit A-12, Schedule B5.2, line 9, columns (e) and

(f).

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AG witness Coppola proposed to disallow $1,485,000 (half the cost), stating that the

“Company has the sole responsibility to ensure it maintains adequate records of its pipelines and

related facilities . . . it is fair and reasonable for the company to absorb at least 50% of the cost and

recover the other 50% in base rates as an accommodation for the long passage of time since the

pipeline was installed” (5T 1663–64).

The Company recognizes its responsibility for maintaining records to ensure the safety and

reliability of its system; however, the AG neglects that industry record-keeping requirements have

changed. Ms. Sandberg explained that following the 2010 San Bruno incident (where one of the

key findings was that the utility did not have adequate records), in 2011 and 2012 the Pipeline and

Hazardous Materials Safety Administration (PHMSA) released Advisory Bulletins (ADB 2011-

01 and ADB 2012-06) that introduced the concept of Traceable, Verifiable and Complete (TVC)

records. The PHMSA, industry organizations, and utilities spent the next eight years developing

additional requirements to ensure operators could support the MAOP of their pipelines by having

TVC records. On July 1, 2020, the MAOP Reconfirmation rules went into effect, requiring

operators to have an MAOP Reconfirmation plan by July 1, 2021, and remediate records defects

by 2035 (5T 1230, 1266–67. See also 5T 991).

The AG’s proposed disallowance is inappropriate because records gaps are an industry

issue, as reflected by the PHMSA introducing a new TVC concept and then working eight more

years with the industry before issuing its final rules. Those rules also reflect the magnitude of the

endeavor by giving operators fifteen years to remediate their records defects. Therefore, the

Company should recover the full $3.0 million of expenditures that are required to comply with this

regulation, and which are also vital to ensuring the safety and reliability of its system (5T 1267–

68. See also 5T 999).

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d. East Jefferson Project

The East Jefferson project involves the replacement of cast iron and unprotected steel main

in connection with a major road construction project in the City of Detroit, with an estimated cost

of $15.0 million (5T 1237–39; Exhibit A-12, Schedule B5.2, line 11, columns (e) and (f)).

AG witness Coppola proposed a full $15.0 million disallowance, reasoning that the

“project is still too premature for inclusion in rate base” (5T 1661).

The Company disagrees because the City of Detroit is planning to complete a major road

construction public improvement project beginning in 2023 on East Jefferson Avenue, and has

requested that all utility upgrades be completed prior to the start of the project. When a

governmental agency decides to perform renovations in the right-of-way (which is the case here)

if DTE Gas’s facilities are in conflict, then the Company is obligated to modify the affected

facilities. These expenditures are non-discretionary. DTE Gas is required to relocate its existing

gas assets in 2022 in order to comply with the schedule for the City of Detroit’s project (5T 599,

1237, 1268–70).

The AG was similarly inaccurate in suggesting that the forecasted capital expenditures

“appear to be ballpark amounts as placeholders of future expenditures” (5T 1661). Exhibit A-12,

Schedule B5.9 (Confidential DTE Gas Project Detailed Cost Estimates) included a detailed cost

estimate for the East Jefferson project. This detailed cost estimate is based on the defined scope of

the streetscape project that the City of Detroit presented to the Company. DTE Gas performed an

engineering analysis that identified precise pipe lengths and sizes to be installed, pipes to be

abandoned, and customer services and meters that will be impacted by the road reconstruction.

The project management team then developed the cost estimate by applying current bid pricing for

material, contract services, and internal labor to the quantities identified in the engineering analysis

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(5T 1270–71; Exhibit A-23, Schedule M8 Confidential 2021 and 2022 East Jefferson Detailed

Cost Estimate).

The project also has additional benefits including that (1) it will remove 11.5 miles of larger

diameter cast iron and unprotected main, (2) the new distribution mains will benefit the City of

Detroit’s growth and revitalization efforts, and (3) the upgraded mains will also be a significant

source of higher-pressure gas for future infrastructure renewal in the area (5T 1238, 1271; Exhibit

A-23, Schedule M7 Top 25 East Jefferson Project).

5. Contingency

In response to feedback from the Commission, DTE Gas has changed how capital

contingency is handled in its project financial process. Contingency has been eliminated from

routine capital projects, however, large capital projects managed by DTE Energy’s Major

Enterprise Projects (MEP) group include contingency. These large capital projects are TCARP,

Van Born Project, Fort St Main Phase III, and Grosse Ile System Supply. It is expected that

undefined costs will arise above the best forecast for these large projects, so contingency costs are

a necessary part of overall project costs as these projects tend to be larger in scope, complexity,

and duration. Despite Staff Witness Wang and Attorney General Witness Coppola

recommendation of disallowance, DTE Gas should recover the $13.0 million of capital

contingency that it will have incurred from the end of the historical test year to the end of the

projected test year (December 31, 2019 through December 31, 2022) for those four projects. They

are the Company’s most rigorous capital projects and are expected to utilize the budgeted

contingency on unforeseen expenditures that arise due to the size and complexity of the projects.

(5T 1200–1203, 1243–44, 1254, 1294–95; Exhibit A-12, Schedule B5.10).

If DTE Gas had included contingency in those projects where it was eliminated (i.e.,

routine capital projects), then its rate base and corresponding revenue requirement would reflect

39

an additional $28.7 million in capital expenditures (5T 586; Exhibit A-12, Schedule B5.13). DTE

Gas included Exhibit A-23 Schedule M2 among its exhibits knowing other parties would be

interested in what the forecasted contingency would have been had contingency been included.

(5T 1245; Exhibit A-23, Schedule M2).

Staff misinterpreted this evidence to impute and recommend an additional disallowance of

$10,150,495 for the first ten months (January-October) of the 2020 bridge year for the TCARP

and Van Born projects (5T 1893–94). Staff did so apparently on the mistaken belief that

contingency was omitted from the first ten months of 2020 based on footnote 7 of Exhibit A-12,

Schedule B5.13 (highlighted on Exhibit A-23, Schedule M1), which states:

The 2020 estimated capital contingency was calculated to represent the 2 months of forecasted capital expenditures only. January through October would not include contingency due to these months are actual capital spend in the Projected Bridge Year and assuming capital contingency is spread evenly across each month of the year. Staff neglected to recognize that the ten months of actuals and two months of forecast was

used to replicate what contingency would have been in this case using the contingency

methodology from prior rate cases (which was changed in this case, as discussed above), and this

hypothetical information was presented only for comparison purposes. Staff even recognized this

purpose (5T 1891), but then misconstrued the footnote as a basis for assumptions leading to

imputing an additional $10.2 million contingency.

Staff also inaccurately assumed that the Company takes the position that once projected

contingency costs were spent, they become actual costs that belong in rate base (5T 1892). Staff

utilizes the Company’s position along with footnote 7 to suggest that the contingency provided

only reflects forecasted contingency for the last two months of 2020 for TCARP and Van Born.

This is not the case. Evidence was provided in Exhibit A-23 Schedule M1, M2, and confidential

40

exhibit A-23 Schedule M3 supporting that no contingency was budgeted for TCARP and Van

Born for the first 11 months of 2020 and that forecasted contingency for these two large projects

are budgeted in December 2020. Ms. Sandberg explained that the Company’s position is that

when unforeseen expenditures are incurred on large projects (for which contingency dollars were

budgeted) they become actual costs. When the Company shows that the actual costs were

reasonable and prudent, then the Company should recover those costs, which is consistent with

Commission practice.

Staff’s reference to a disallowance of contingency costs in Case No. U-20322 is not

applicable here. In contrast and for example, the Company’s initial filing provided evidence of

actual expenditures for the TCARP project through October 2020, as well as evidence that no

contingency was budgeted for TCARP from January through November 2020. The Company is

not requesting that the Commission approve actual expenditures incurred post-filing as Consumers

Energy did in Case No. U-20322 (5T 1247–48; Exhibit A-23, Schedule M3 Confidential Detailed

Cost Estimates TCARP and Van Born further reflects that forecasted contingency was not

budgeted in the first 11 months of 2020 for the TCARP and Van Born projects).

Staff’s imputed additional $10.2 million contingency ($9.8 million for the TCARP project

and $0.3 million for the Van Born project) is contrary to the record and demonstrates a fundamental

misunderstanding as TCARP’s total planned contingency of $12.6 million remains unchanged.

Imputing an additional $9.8 million of contingency would increase the total TCARP project

contingency to $22.4 million (5T 1249–50; Exhibit A-23, Schedule M-4). Similarly, adding an

additional $0.3 million of contingency to the Van Born project would raise the total project

contingency from $14.4 million to $14.7 million (5T 1250–51; Exhibit A-23, Schedule M5).

41

Therefore, these additional amounts of imputed contingency could not have been omitted from

DTE Gas’s original filing as Staff incorrectly assumed (5T 1249–51).

Staff did not impute additional contingency for the Fort St Main Phase II and Grosse Isle

projects, but asserted that “it is possible that these two projects had actual contingency

expenditures in January – October of 2020 that the Company failed to report” (5T 1893).13 Ms.

Sandberg explained that contingency did not exist, so there was nothing that the Company could

have “failed to report.” More specifically, the Fort St Main Phase III project does not begin until

2021, so there were no capital expenditures in 2020 (actual or planned) and therefore could not

have any contingency in 2020. Similarly, the Grosse Isle project had only small labor expenditures

in 2020, which did not have any contingency. (5T 1251–52; Exhibit A-12, Schedule B5.5 Revised

DTE Gas Highest Cost Top 25 Capital Project List, pages 19, 23).

Staff recommended that the Commission “clarify its definition of contingency in rate case

proceedings to include all project contingency costs (actual and forecasted capital expenditures)

in a period” (5T 1898). The Company agrees that it would be helpful for the Commission to

provide clarity but disagrees with Staff’s proposed handling of contingency. The Company

requests the Commission’s guidance on contingency, and specifically that the Commission reject

Staff’s recommendation to inappropriately include implied contingency in accounting of actual

expenditures subject to audit by FERC and the Commission (5T 1253). 14

13 An agency decision may not be based on speculation. Ludington Service Corp v Comm’r of Insurance, 444 Mich 481, 483, 494-97, 500-501, 507; 511 NW2d 661 (1994), amended 444 Mich 1240 (1994) (unanimously reversing agency decision that exceeded the limits of the agency’s statutory authority, and that was based on speculation instead of the required competent, material and substantial evidence); In re Complaint of Pelland, 254 Mich App 675, 685-86; 658 NW2d 849 (2003); Battiste v Dep’t of Social Services, 154 Mich App 486, 492; 398 NW2d 447 (1986). 14 The Court of Appeals has frequently recognized the importance of the Commission following consistent accounting practices. For example, in Attorney General v Public Service Comm, 262 Mich App 649; 686 NW2d 804 (2004), the Court affirmed the Commission’s approval of a utility’s deferral and amortization because “it is consistent with established and accepted regulatory principles… Each amortization process is consistent with accepted regulatory and accounting principles.” 262 Mich App at 658-59. See also Attorney General v Public Service Comm, 215 Mich App

42

Staff recommended that the Commission “order the Company to cease including projected

contingency in the rate case” (5T 1899). The Company maintains that it appropriately included

contingency for four large projects in this case, as discussed above. Staff’s proposal also

inappropriately threatens to deny DTE Gas and other utilities the opportunity to provide evidence

of reasonableness and prudence for recovery of forecasted contingency. The Commission should

instead preserve a non-biased and lawful ratemaking process for DTE Gas and other utilities to

follow in future cases (5T 1254). Even assuming for argument’s sake that the Staff’s suggested

change in hearing procedure would be lawful (which it is not under the United States and Michigan

Constitutions, as further discussed below), 15 it would have to be done via legislative change and

applicable to all participants (not just DTE).

Staff’s proposal to “order the Company to cease including projected contingency in the

rate case” also threatens to violate fundamental constitutional rights. DTE Gas has a fundamental

right to seek relief from the Commission.16 The right to petition extends to all departments of

356, 365; 546 NW2d 266 (1996) (affirming the Commission’s decision, which was supported by a DTE witness who “testified that standard accounting principles or standards require that a net gain or loss on a futures contract be recorded as a ‘cost’ of the gas purchased pursuant to the contract”); ABATE v Public Service Comm, 208 Mich App 248, 261; 527 NW2d 533 (1995) (affirming construction costs that were capitalized and amortized according to accepted accounting and regulatory practices); Midland Cogeneration LP v Public Service Comm, 199 Mich App 286, 301-303; 501 NW2d 573 (1993) (reversing attempt to impose accounting requirements that were unauthorized by statute); Application of Michigan Consolidated Gas Company, 304 Mich App 155, 172-73; 850 NW2d 569 (2014) (reversing attempt to re-price gas purchases that were made in accordance with a prior pricing methodology). 15 DTE Gas raises constitutional issues to preserve them for the record. Wikman v Novi, 413 Mich 617, 646-47; 322 NW2d 103 (1982) (“an agency exercising quasi-judicial power does not undertake the determination of constitutional questions”). 16 The First Amendment to the United States Constitution relevantly provides: “Congress shall make no law . . . abridging . . . the right of the people . . . to petition the Government for a redress of grievances.” The First Amendment is applicable to the State of Michigan and its political subdivisions by operation of the Fourteenth Amendment. Gault v City of Battle Creek, 73 F Supp 2d 811, 814 (WD Mich, 1999). Michigan’s Constitution similarly provides: “The people have the right peaceably to assemble, to consult for the common good, to instruct their representatives and to petition the government for redress of grievances.” Const 1963, art 1, § 3.

43

government, including administrative agencies.17 DTE Gas’s status as a privately-owned and

government-regulated company does not preclude its assertion of First Amendment rights.18 It is

inappropriate for Staff to attempt to foreclose DTE Gas from asking the Commission to decide an

issue.19

The Commission must hear the issues and receive the information that DTE Gas offers so

that the Commission can carry out its regulatory duties.20 Staff’s proposal to restrict development

of the record threatens to impede the Commission’s decision-making ability, contrary to Const

1963, art 6, § 28’s requirement that the Commission’s findings be “supported by competent,

material and substantial evidence on the whole record.” (Emphasis added).

Staff’s proposal also threatens a Due Process violation.21 Fundamental due process

includes the right to be heard.22 It is also axiomatic that decisions regarding what proposals DTE

17 California Motor Transport Co v Trucking Unlimited, 404 US 508, 510; 92 S Ct 609; 30 L Ed 2d 642 (1972). 18 Consolidated Edison Co of New York v Public Service Comm of New York, 447 US 530, 533-34; 100 S Ct 2326; 65 L Ed 2d 319 (1980) (holding that the New York Public Service Commission’s suppression of bill inserts discussing public issues directly infringed the freedom of speech protected by the First and Fourteenth Amendments). 19 Baker Driveway Co, Inc. v Bankhead Enterprises, Inc, 478 F Supp 857, 859 (ED Mich, 1979) (“Our system of government places a high value on the freedom of the public to petition the government, and such activity will not be curtailed without some extraordinary showing of abuse”). 20 Eastern Railroad Presidents Conference v Noerr Motor Freight, Inc, 365 US 127, 137; 81 S Ct 523; 5 L Ed 2d 464 (1961) (“In a representative democracy such as this, these branches of government act on behalf of the people and, to a very large extent, the whole concept of representation depends on the ability of the people to make their wishes known to their representatives”). 21 DTE Gas has due process rights under the Fourteenth Amendment to the United States Constitution. 22 Gonzales v United States, 348 US 407, 415; 75 S Ct 409; 99 L Ed 467 (1955).

44

Gas will make are the prerogative of the Company’s management.23 DTE Gas cannot lawfully be

forced to alter its proposals to conform to the Staff’s (or anybody else’s) point of view.24

C. Working Capital

As indicated above, DTE Gas’s Total Rate Base for the projected test year includes

$1,029.3 million of Working Capital (5T 1386; Exhibit A-12, Schedule B1).

AG witness Coppola proposed that Customer Accounts Receivable be set at the 2019 level

of $214.1 million instead of the Company’s filed position of $223.1 million for the projected 13-

month average at December 31, 2022. He reasoned that “the increasing number of customers who

are paying their gas bills with credit and debit cards should reduce accounts receivable as a

percentage of revenues. The Company believes this trend will continue . . ..” (5T 1680–81).

The Company disagrees and to the contrary, Mr. Burns explained that the Company has

made no claims regarding the benefits of allowing payment by credit card beyond customer

convenience. The Company has also not established a definitive correlation between credit card

usage and a reduction in uncollectible expense or arrears outstanding on the balance sheet (5T

653).

Mr. Coppola also filed Exhibit AG-20, page 2, showing a decline in customer accounts

receivable as a percentage of revenues from 2018 to 2019. Ms. Uzenski explained that Mr.

Coppola’s heuristic analysis does not prove a direct correlation between credit card payments and

receivable balances. The Company’s projection was based on adding only one month’s worth of

the $110 million revenue (or approximately $9.0 million) increase authorized by the Commission’s

23 Detroit Edison Co v Public Service Comm, 221 Mich App 370, 387-88; 562 NW2d 224 (1997). 24 Pacific Gas and Electric Co v Public Utilities Comm of California, 475 US 1, 9-16; 106 S Ct 903; 89 L Ed 2d 1 (1986) (holding that California Public Utilities Commission order that utility place third-party’s newsletter in its billing envelopes violated the First Amendment by forcing the utility to alter its speech to conform with an agenda that the utility did not set).

45

August 20, 2020 Order in Case No. U-20642. Consequently, the Company’s $223.1 million

projection is a conservative estimate because it does not attempt to increase the balance for higher

amounts that would be in arrears as a result of the rate increase. It also does not reflect any rate

increase that might be authorized in this case. Therefore, the Commission should accept the

Company’s conservative $223.1 million projection and reject the AG’s proposal (5T 382–84).

Other Accounts Receivable includes a sub-account titled “Accounts Receivable Non-

Utility/Non-Core” (Exhibit A-12. Schedule B4, line 10). Staff recommended excluding the entire

$3,957,000 balance from working capital by reasoning that this “account is not related to the

Company’s core utility operations” (5T 2119). However, the Company disagrees since Ms.

Uzenski explained that the balance at issue does in fact relate to utility operations. Staff’s proposal

appears to be based on a misperception due to the sub-account’s title instead of the actual nature

of the account (5T 382, 385).

More specifically, the sub-account primarily reflects amounts due from agencies for

donations under the Low-Income Sufficiency Program (LSP). Under the LSP, the Company

processes a credit on a participating customer’s account, and then bills the agency for the amount

owed. The sub-account also holds small balances for expected rebates related to prescription drugs

from one of the Company’s healthcare service providers (Medco), and retiree co-payments for

health care and COBRA payments due from former employees. The sub-account also holds a

receivable related to mutual aid that the Company provided to an out-of-state utility after a gas

explosion. Therefore, the balances are related to the cost of providing utility service, and they

should be included in working capital (5T 385–86).

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VI. RATE OF RETURN

DTE Gas requests a weighted after-tax rate of return of 5.59% (5T 1380; Exhibit A-14,

Schedule D1). The primary substantive issues affecting rate of return relate to capital structure

and Return on Equity (ROE).

A. Capital Structure

DTE Gas recommends, and urges the Commission to adopt, a permanent capital structure

consisting of 52% equity and 48% long-term debt, which is consistent with the Company’s current

and optimal capital structure. The Company has used a capital structure consisting of 51.9% equity

and 48.1% long-term debt, however, in accordance with the U-20642 settlement (“DTE Gas will

file a plan in its next rate case that moves toward a more balanced capital structure”). (5T 536,

539, 565, 1283–85; Exhibit A-14, Schedule D1).

Staff recommended that DTE Gas’s capital structure should be composed of 51% equity

(5T 1853). AG witness Coppola recommended 50% equity (5T 1682).

Mr. Bennett explained that these recommendations are neither reasonable nor prudent for

DTE Gas or the utility industries in general in Michigan. Investors and rating agencies view

Michigan as having a supportive regulatory platform for infrastructure modernization, safety, and

efficiency. Weakening DTE Gas’s balance sheet would send a negative message at a critical time

when Michigan is rebuilding its infrastructure (5T 567–68). DTE Gas’s recommended capital

structure is further supported by an extensive analysis that is outlined below.

Capital structure is critical because it determines a company’s access to credit markets (the

availability of capital) and ability to raise capital at reasonable terms and rates (the cost of capital).

Companies with more equity in their capital structures are less risky from a financial perspective,

and generally have a greater ability to obtain capital, and lower required returns on equity and

costs of debt than companies with weaker capital structures. Increased debt levels result in

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increased debt costs, which in turn increase customer rates. If DTE Gas is unable to raise adequate

capital, then the Company will be unable to invest in the equipment and systems necessary to

ensure efficient, reliable, and safe delivery of gas to its customers (5T 537–39).

There are compelling business and financial reasons for DTE Gas’s equity ratio to remain

at 52%, including the Company’s high short-term debt balance (rating agencies and investors

consider short-term debt to be debt, and this alone reduces the Company’s equity ratio to about

49%), potential for volatility in cash flows, and high level of future capital expenditures (5T 540–

41). DTE Gas is also committed to maintaining a 52% equity ratio, as reflected by receiving, and

its plans to receive, equity infusions from DTE Energy to maintain this equity ratio (5T 558). More

specifically, continuing the current 52% equity ratio is optimal for both the Company and its

customers for the following reasons:

1. The 52% ratio is below the 56.8 % average 2019 equity ratio for peer local distribution

company (LCD) gas companies, and average authorized equity ratios have been

trending upward to offset the negative cash flow impacts and resulting deteriorating

financial metrics as a result of the Tax Cuts and Jobs Act (TCJA). (5T 543–44, 1283;

Exhibit A-17, Schedule G3);

2. The TCJA adversely affected DTE Gas and its credit rating (5T 543, 545–46);

3. Credit rating agencies and investors include short-term debt in total debt when

calculating equity ratios, and if DTE Gas’s peak short-term debt of $300 million (which

occurred at various times in 2019) is added to debt, then the resulting equity ratio falls

3.4% to 48.6% (5T 542, 548–49, 1284);

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4. DTE Gas has higher short-term debt relative to other Michigan utilities (5T 543, 549–

50, 1284);25

5. DTE Gas’s high short-term debt is driven by the Company’s large gas-storage capacity

(third largest among 30 LDCs’ natural gas storage facilities), which benefits customers

by providing reliable gas supply and lower gas costs, but which requires a higher level

of short-term debt for gas purchases (5T 543, 550–51);

6. DTE Gas is significantly smaller than its peer Michigan utilities (DTE Electric and

Consumers Energy are four times as large), and it is less able to withstand variability

in cash flows due to events such as a change in the weather (5T 543, 551–54);26

7. Depreciation lives of gas utility assets are longer (thus lower) than electric utility assets,

resulting in lower cash flow and lower credit metrics (5T 543, 554–55, 574-575);

8. DTE Gas will be financing and funding over $1.5 billion of capital expenditures for the

period of January 2020 through December 2022 (Exhibit A-12, Schedule B5), so it is

imperative that DTE Gas be viewed as a financially-sound company with a solid

investment grade rating to ensure the reasonableness and competitiveness of the

Company’s capital costs during this period of significant capital investment (5T 543,

555–56); and

25 AG witness Coppola suggested that this argument lacks relevance because “in the Moody’s calculation the short-term debt for 2019 was at $167 million” (5T 1691). Mr. Bennett explained that the AG’s argument is incorrect. The $167 million was a year-end number as of December 31, 2020. In 2020, the Company took actions to enhance liquidity to combat the disruptions in the commercial paper market due to the COVID-19 pandemic. The year-end number was lower than normal and does not reflect the fluctuations throughout the year (5T 574). 26 AG witness Coppola responded that “[n]ot only are gas companies such as DTE Gas affected by weather, but also electric utilities” (5T 1292). The response misses the point that weather has more impacts on a small utility like DTE Gas than on a larger utility with more cash flow. The need for additional equity to withstand swings in cash flows is greater for DTE Gas, and supports the need for a stronger equity component (5T 575).

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9. The suggestion that DTE Gas should move to a more balanced capital structure assumes

that the Company’s credit metrics are too high, but DTE Gas’s credit ratings (based on

a 52% equity ratio) are at the median as compared to its peer gas utilities. If DTE Gas’s

balance sheet was too strong, then its rating would be at the higher end as compared to

its peers (Exhibit A-17, Schedule G4). (5T 541, 543, 556).

Moreover, reducing DTE Gas’s equity ratio to 50% would increase costs for customers

because, in order to minimize the impact to credit metrics and the risk of a downgrade, the

Company would need to reduce short-term debt and offset this reduction with more permanent

capital (long-term debt and equity). The net impact would increase the pre-tax weighted cost of

capital from 7.04% to 7.08%, with a corresponding increase in the projected revenue requirement

of almost $3 million, from $194.8 million to $197.3 million (5T 557–58, 1394; Exhibit A-17,

Schedule G5).27

Thus, DTE Gas’s capital structure already is “balanced” considering the factors outlined

above. To reduce DTE Gas’s equity ratio, there would have to be offsetting factors to improve

DTE Gas’s financial metrics or reduce risk as viewed by investors and rating agencies, including:

(1) ROE improvement; (2) reversal of the TCJA; (3) decrease in average depreciable life; and (4)

reduction in volatility of cash flows. If any of these factors change, then the Company would

analyze the impact and adjust the capital structure as appropriate (5T 558–59, 1285).

If the Commission does not confirm that 52% equity reflects a balanced capital structure

for DTE Gas, then the Commission should adhere to its long-standing policy of gradualism and

27 AG witness Coppola suggested that moving to 50% equity would not result in higher cost to customers (5T 1688–89; Exhibits AG-22 and AG-23). Mr. Bennett explained that the AG’s analysis failed to consider that in order to maintain the capital structure that supports the current ratings, short-term debt would need to shift to higher cost long-term debt as reflected in Exhibit A-17, Schedule G5, resulting in an increase in the projected revenue requirement by almost $3 million (5T 573–74).

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maintain Michigan’s constructive regulatory environment. DTE Gas has used a 0.1% change in

this case, which will allow the impacts of the change on the Company’s financial health to be

evaluated without leading to a significant change in ratings and costs (5T 1285).

Staff suggested that DTE Gas should have provided a “more complete analysis” of the

consequences of the Company not having a 52% equity ratio (5T 1854, quoting the September 13,

2018 Order in Case No. U-18999, p 44). Despite Staff’s assertion, DTE Gas plainly presented an

extensive analysis of various mathematical and other factors as indicated above (5T 568–69).

Staff further suggested that “there is no conclusive evidence that shows the adjustment

from 52% to 50% equity should have an effect on the Company’s current credit rating” (5T 1856).

Staff neglected that DTE Gas already experienced a downgrade, which occurred when the

Company was at a 52% equity ratio. This downgrade is a significant event showing that DTE Gas’s

financial health is under pressure, and the then-current credit metrics were insufficient to avoid a

downgrade. The Company’s current rating is also lower than that of DTE Electric. 28 A movement

to 50% equity would put DTE Gas closer to the CFO/Debt 15% threshold (Staff indicates 17.5%

at 51% equity, 5T 1856) and also demonstrate an adverse change in Michigan’s regulatory

environment. Both would have a negative impact on the Company’s current credit rating. It should

28 AG witness Coppola suggested that “the previous Moody’s rating for DTE Gas of Aa3 was somewhat ‘out of line’ and the higher than the ratings assigned by the other agencies” (5T 1690). Mr. Bennett explained that the AG’s suggestion is misleading and irrelevant because each rating agency has its own methodology and rating process. DTE Electric is rated Aa3 by Moody’s and A by Standard & Poor’s. The downgrade at Moody’s to A1 put DTE Gas “out of line” with the ratings of DTE Electric (5T 575–76). It would also not be reasonable and prudent to operate with little cushion between metrics and the next downgrade. Moody’s is already forecasting that the Company is operating with financial metrics that are below DTE Gas’s current rating, and it is only because of non-quantitative factors that Moody’s rated the Company A1. Lowering the equity ratio would only put more pressure on the Company’s rating, which would be perceived negatively by rating agencies and investors. The Company also needs to be in a position to weather unforeseen shocks to its credit metrics (5T 547, 576)

51

not take the Company to be on the brink of another downgrade for the Commission to accept a

52% equity ratio as optimal (5T 570, 575).

In summary, DTE Gas needs a strong equity component of its capital structure to maintain

adequate access to capital at the lowest reasonable cost. DTE Gas continues to face credit risk and

challenges, as well as significant ongoing and emerging business challenges. The discussion above

breaks out and supports numerous compelling business and financial reasons why DTE Gas’s

current 52% equity ratio continues to be optimal for both the Company and its customers. DTE

Gas has submitted a “plan . . . that moves toward a more balanced capital structure” in accordance

with the U-20640 settlement, but any reduction in the Company’s equity ratio threatens adverse

consequences, so it should be limited to 0.1 (to 51.9% equity). (5T 536, 539, 565, 1283–88; Exhibit

A-14, Schedule D1).

Accordingly, the Commission should maintain DTE Gas’s 52/48 capital structure, and

increase DTE Gas’s ROE from 9.9 % to 10.25%, as further discussed in Section VI. C below.

B. Debt Cost Rates.

1. Long-Term Debt.

DTE Gas recommends a 3.97% weighted cost of long-term debt, which was determined

using the net proceeds method for each issue outstanding as of December 31, 2022, including the

financing cost of the new debt issues (5T 537, 562–63, 565; Exhibit A-14, Schedule D2). Staff

agreed (5T 1857) and there appears to be no disagreement.

2. Short-Term Debt.

DTE Gas recommends a 0.95% cost of short-term debt, which includes the interest rate on

short-term borrowings and facility fees associated with the credit arrangements necessary for the

issuance of short-term debt (5T 537, 563–65; Exhibit A-14, Schedule D3). Staff agreed (5T 1857)

and there appears to be no disagreement.

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C. Return on Common Equity.

Dr. Villadsen explained and recommended that a just and reasonable Return on Equity

(ROE) for DTE Gas’s common equity capital is 10.25%. This is at the upper end of Dr. Villadsen’s

range of 9.25% to 10.25% (for the gas sample; there is a wider range for the full sample) because

DTE Gas has greater-than-average risk (5T 1402–1405, 1461).

Staff recommended 9.5% (5T 1851, 1874). AG witness Mr. Coppola recommended 9.5%

(5T 1719–20). ABATE witness Ms. LaConte recommended 9.0% (5T 194, 219, 246).

The Staff, AG, and ABATE recommendations are downward biased because they neglect

to consider the interaction of capital structure (financial risk) and ROE. They also did not

adequately capture the risk in the gas utility industry and neglected to consider relevant

information from other highly regulated companies. It is difficult to imagine, for example, that

DTE Gas’s investors require a return that is substantially lower than the return in highly regulated

water utilities with a similar business risk profile. The recommendations are also understated due

to analytical errors and the misperception that DTE Gas has average risk relative to sample

companies. Instead, the current determination of DTE Gas’s allowed ROE takes place during

uncertain economic and financial conditions due to the ongoing impacts of the COVID-19

pandemic, which has led to unprecedented low U.S. Treasury bond yields, substantial volatility in

stock prices, and uncertainty regarding how long the recovery period will be. The relative risk of

natural gas utilities has also increased, so that investors require a higher return to invest in those

utilities relative to that required in other industries (5T 1404–1407, 1418–22, 1504–1508, 1525–

26, 1537–39).

Correcting the other witnesses’ model-implementation errors (further discussed below)

results in revised average ROE estimates of 10.31% for Staff; 9.63% for the AG, and 9.71% for

ABATE, which overlaps Dr. Villadsen’s ROE range. Dr. Villadsen’s 10.25% recommendation is

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specifically supported by Staff’s 10.31% adjusted ROE, and the high end (10.12%) of ABATE’s

adjusted ROE range (5T 1537–38).

Dr. Villadsen selected two proxy groups consisting of publicly traded companies. The first

proxy group consists of nine companies providing primarily regulated natural gas distribution

services, and the second proxy group consists of six highly-regulated companies in the water utility

industry (5T 1411, 1415, 1434–40). She explained that water utilities provide a useful benchmark

when evaluating DTE Gas’s cost of equity because: (1) the natural gas distribution industry is

expected to undergo substantial changes as customers, regulators, and the legislature focus on

carbon reductions; (2) investors make comparisons across regulated industries; and (3) natural gas

and water utilities are regulated, capital-intensive, network industries that have an obligation to

serve and interface with the local community (5T 1435–36). Her rebuttal testimony objected to the

other witnesses’ unnecessary and inconsistent application of restrictions when screening for proxy

group companies, and further explained that their inappropriate exclusion of all water companies

and some gas utilities resulted in small samples with less predictive power from a statistical

perspective (5T 1525–27, 1537).

Dr. Villadsen estimated the ROE for each company in her sample using two versions of

the both the Capital Asset Pricing Model (CAPM) (the traditional version and the Empirical

CAPM (ECAMP)), and Discounted Cash Flow (DCF) approaches (a single-stage and a multi-stage

version), as well as an implied risk premium analysis, and an analysis of DTE Gas’s risks. She

then combined the ROE estimates from the CAPM and DCF models with capital structure

information. By determining the after-tax weighted-average cost of capital, she avoided

inconsistencies that could arise from estimating the cost of equity for companies without

considering differences in financial risk inherent in each company’s capital structure (the higher

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the debt-to-equity ratio, the higher the financial risk, and the higher the cost of equity). She also

considered Hamada adjustment procedures to provide further insight into the range of ROE

estimates after adjusting for financial leverage (5T 1402, 1411–16, 1494–1500). Her rebuttal

testimony discussed well-established financial principles, and responded to criticisms and apparent

misunderstandings by Staff, the AG and ABATE regarding the impact of financial leverage on the

cost of equity (5T 1508–22). By failing to account for fundamental financial principles, the Staff,

AG and ABATE ROE estimates are downward biased by 36 to 43 basis points (5T 1522).

1. CAPM and ECAPM Estimates

Dr. Villadsen developed ROE estimates based on the CAPM and on an empirical

approximation to the CAPM (ECAPM). The CAPM is based on the salient principle that risk-

averse investors demand higher returns for assuming additional risk, and higher-risk securities are

priced to yield higher expected returns than lower-risk securities. The CAPM quantifies the

additional return, or risk premium, required for bearing incremental risk using (a) a risk-free rate,

(b) beta,29 and (c) a market risk premium (5T 1441–42).

As a proxy for the CAPM’s risk-free interest rate, Dr. Villadsen used the 1.55% yield on

the 10-year U.S. Treasury bond forecasted by Blue Chip Economic Indicators (average of 1.4%

for 2022 and 1.7% for 2023), and adjusted it upward by 50 basis points (bps), which is her estimate

of the representative maturity premium for the 20-year over the 10-year Treasury bond, for a basic

risk-free rate of 2.05%. This rate is downward biased, however, as reflected for example by the

spread between A-rated (and BBB rated) utility bonds and the 20-year government bond being

elevated by 28 (and 36) bps relative to its long-run historical average. Therefore, her Scenario 1

29 Beta is a measure of the risks that cannot be eliminated by diversification. It measures the “systematic” risk of a stock – the extent to which the stock’s value fluctuates more or less than the market fluctuates (5T 1441).

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adds about half of the increase (25 bps) in the yield spread to obtain a risk-free rate of 2.3% (5T

1442).

Dr. Villadsen explained that the market risk premium (MRP) is forward looking. She used

7.15% (the historical average from 1926 to March 2016) with her risk-free rate of 2.05% in her

Scenario 1. She also used a forward-looking MRP of 7.35% (based on Bloomberg’s November 30

the forecasted yield) combined with the base risk-free rate of 2.05%. She opined that the 7.15%

long-term historical MRP is a low-end estimate of what the MRP will be during the period at issue

in this case, and that the 7.35% MRP that she used is also conservative because the FERC approach

(consistent with Order 569-A) would result in a substantially higher MRP (5T 1442–45).

Dr. Villadsen used betas reported by Value Line and noted that, importantly, natural gas

LDCs’ betas have increased substantially since Case No. U-20642. The average natural gas LDC

beta (as measured by Value Line) had risen to 0.84% (from 0.66 in September 2019). This indicates

a large increase in the systemic risk of the natural gas LDC industry (moving toward the overall

market), so allowed returns similarly need to increase (5T 1445). She also used the Hamada

technique to adjust betas to account for DTE Gas’s capital structure having a higher proportion of

debt financing (and thus financial risk) than some of the sample companies (5T 1445–46, 1497–

1500).

Dr. Villadsen’s main concern about the CAPM implementation by Staff, the AG, and

ABATE was their failure to reflect the impact of financial leverage on the cost of equity, as

indicated above (5T 1530–31). This produced a downward bias of at least 43 basis points for all

of these CAPM results. Staff’s forecasted CAPM results should also be ignored because they are

based on an unreasonably low MRP of 6.26% (1868). To the contrary, Bloomberg currently

forecast an MRP above 8%, and as of April 30, 2021, the methodology the FERC applies to

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determine MRP results in an MRP of 9.6% using Value Line growth rates and 10.86% using IBES

growth rates (5T 1530).

Dr. Villadsen also disagreed with the AG’s exclusive reliance on historical data for the

MRP, and criticism of the FERC MRP methodology. Dr. Villadsen also pointed out that ABATE’s

2.15% estimate of the risk-free rate was not only the lowest, but also based on selective data – the

use of an outdated historical risk-free rate without considering the elevated yield spread at that

time. It would have been appropriate for Ms. LaConte to either use current forecasts for the risk-

free rate, or consider the elevated yield spread as of the time of her data. Her failure to do either

resulted in an additional downward bias of 55 basis points for her CAPM results (5T 1530–32).

Dr. Villadsen further explained that empirical research has long shown that the CAPM

tends to overstate the actual sensitivity of the cost of capital to beta. Low-beta stocks tend to have

higher risk premiums than predicted by the CAPM, and high-beta stocks tend to have lower risk

premiums than predicted. Dr. Villadsen adjusted by using the ECAPM, which uses these empirical

findings to produce results that more closely match the results of empirical tests, and that are more

appropriate to use (5T 1446–47).

Staff (5T 1869) and ABATE (5T 226) suggested that it is inappropriate to both use adjusted

beta estimates and apply the ECAPM. Dr. Villadsen explained that they are two fundamentally

different and complementary adjustments with no redundancy. The adjustment to beta corrects

the estimate of the relative risk of the company. The ECAPM adjusts the risk-return tradeoff.

Both adjustments are necessary to produce the most accurate possible forward-looking estimate of

the required return on equity. Dr. Villadsen also rebutted criticisms alleging that the ECAPM is

unnecessary when using a long-term risk-free rate and that the ECAPM is not widely used in

regulatory proceedings. Thus, the ECAPM has merit and should be considered. Failure to consider

57

the ECAPM’s results downwardly biases the results by approximately half a percent. (5T 1539–

43).

Dr. Villadsen’s CAPM and ECAPM analyses produced ROE estimates of 9.2% to 10.2.

She explained, however, that the ECAPM numbers deserve more weight than the CAPM numbers

because the ECAPM adjusts for empirical findings (5T 1449–50).

2. DCF Estimates

Dr. Villadsen explained that the DCF model assumes that the market price of a stock is

equal to the present value of the dividends that its owners expect to receive. In order to apply the

growth rates used in the DCF model, two components are required: (1) the forecasted earnings

growth rates; and (2) the long-term growth rate. For the single-stage DCF and the first stage of

the multi-stage DCF, Dr. Villadsen used earnings growth rates from Value Line and Thompson

Reuters IBES. For the long-term growth rate for the final, constant-growth stage of the DCF, she

used the long-term U.S. GDP growth forecast of 4.1% from Blue Chip Economic Indicators. The

corresponding ROE estimates are 11.1% for the gas sample and 11.8% for the full (gas and water

utility) sample using the single-stage model, and 8.6% for the gas sample and 8.4% for the full

(gas and water utility) sample using the multi-stage model. The multi-stage model is downward

biased, however, because dividend yields may be expected to increase as interest rates rise, and

current growth forecasts may be impacted by the COVID-19 pandemic. Therefore, the emphasis

should be on the single-stage DFC model (5T 1450–54).

Staff and the AG used the single-stage (constant growth) DCF model, but they also used

annualized dividend yields rather than quarterly dividend yields and growth rates. This artificially

lowered their resulting ROE estimates by about 10 basis points. The AG’s use of selective data

(the elimination of NiSource) further biased results downward by 36 basis points. ABATE did not

implement the multi-stage DCF properly, so that result should be assigned little or no weight;

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however, ABATE’s single-stage mean DCF result of 10.12% is a reasonable estimate (5T 1533–

34).

AG witness Mr. Coppola further acknowledged that “a potential 10% correction in utility

stock prices due to higher interest rates or other events would produce a 0.40% increase in the cost

of capital under the DCF approach” (5T 1719). This acknowledgement is particularly significant

due to current events, as indicated above and further discussed below.

3. Risk Premium Estimate

In the risk premium model, the cost of equity capital for utilities is estimated based on the

historical relationship between allowed ROEs in utility rate cases and the risk-free rate of interest

at the time the ROEs were granted. Dr. Villadsen found that current market conditions are

consistent with an ROE of 9.4% to 9.6% for the gas sample (5T 1454–57). The other parties’ risk

premium results suffer from multiple analytical flaws that downwardly bias their results, so they

should be ignored (5T 1535–37).

4. DTE Gas’s Return on Equity in Relation to Risk

DTE Gas’s present ROE is 9.9% based on the parties’ non-precedential agreement in the

company’s last general rate case (U-20642 Settlement, paragraph 3.a). Previously in Case No. U-

18999 (DTE Gas’s prior general rate case), the Commission set the ROE at 10.0%, despite the

ALJ’s recommended lowering of DTE Gas’s ROE from 10.1% to 9.6%. The Commission noted

some improved conditions in the approximately two years since DTE Gas’s prior rate case, but

stated that it “agree[d] with DTE Gas that there [was] increased volatility in the capital markets

that may affect the cost of capital” (September 13, 2018 Order in Case No. U-18999, p 54). The

Commission also emphasized that in the present regulatory environment where rate cases are more

common, proposals to radically reduce a utility’s ROE (particularly as ABATE has made) are

neither realistic nor helpful to the Commission (September 13, 2018 Order in Case No. U-18999,

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p 52). The Commission has repeated its recent request for parties “to consider the degree of

financial adjustment they are requesting the Commission to undertake in one proceeding, because

it is not realistic to make a significant change in ROE absent a radical change in underlying

economic conditions.” Id, quoting March 29, 2018 Order in Case No. U-18322, p 44.

In Case No. U-17999 (DTE Gas’s last general rate case before U-18999), the ALJ

recommended an ROE of 10.0%, in accordance with Staff’s recommendation. The Commission

instead set the ROE at 10.1%, explaining in part: “Nationally, and in Michigan, ROEs are trending

downward, and Michigan’s economy has improved considerably since DTE Gas’s last contested

rate case. However, the Commission agrees with the company that economic conditions in parts

of its service territory remain challenging and present a degree of risk perhaps greater than the risk

associated with the proxy companies” (December 9, 2016 Order in Case No. U-17999, p 25).

Dr. Villadsen explained that capital markets have seen historic changes since DTE Gas

filed its last rate case. The extent and length of the economic and financial impacts from COVID-

19 remain unknown (5T 1419–22). The Commission also recently stated that it “will continue to

monitor a variety of market factors in future rate cases to gauge whether volatility and uncertainty

continue to be prevalent issues that merit more consideration in setting the ROE” (December 17,

2020 Order in Case No. U-20697, pp 165-66). Interest rates are expected to increase going forward,

and utility bond spreads indicate an increase in the cost of equity (5T 1422–28). Stock market

volatility has increased, which is significant because investors expect higher risk premiums during

more volatile periods. It is reasonable to expect that the current MRP will remain elevated

compared to historical levels, especially given the uncertainty related to the extent of economic

and financial impacts from COVID-19, and the historically-low interest rates (5T 1428–33).

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Dr. Villadsen further explained that DTE Gas has higher capital expenditures than the

average company in the gas sample. Capital intensity is associated with higher risks because capital

costs are fixed costs that cannot be eliminated if economic conditions deteriorate. DTE Gas’s

capital intensity was one reason that Moody’s downgraded DTE Gas in July 2019 and Moody’s

continues to view it as credit challenge. DTE Gas also faces increased risk of under-recovery

because its service territory includes Detroit, which continues to experience high unemployment,

high poverty, and declining population. ABATE’s contention that DTE Gas’s ROE should be

lowered because adjustment clauses reduce risk (5T 201) lacks merit because adjustment clauses

are common regulatory mechanisms, and DTE Gas’s adjustment clauses are in line with those

available to other gas LDCs. Therefore, DTE Gas is riskier than the sample profile (5T 1457–61,

1523–24; Exhibit A-30, Schedule T2 - Confidential).

5. The Connection Between Equity and Capital Structure

A company’s cost of equity and capital structure are inextricably intertwined because the

use of debt increases the company’s financial risk, and therefore increases the Company’s cost of

equity. A lower equity ratio component (and a correspondingly higher debt component) in the

capital structure creates a higher level of risk for shareholders and a corresponding need for a

higher rate of return on equity. Dr. Villadsen’s recommended ROE corresponds to a 51.9% equity

ratio. If DTE Gas has less equity, however (and a corresponding increase in both debt leverage as

well as financial risk), then DTE Gas’s ROE must increase to compensate for the increased risk.

A company with a lower equity share and higher financial leverage must earn a higher ROE in

order to maintain the same overall return (5T 1411–15, 1461).

6. Summary and Recommendations Regarding DTE Gas’s Cost of Equity.

Dr. Villadsen’s methodologies produced a ROE range of about 9.25% to 10.25% for the

gas sample, and about 9 to 10.5% for the full sample. DTE Gas has higher risk than the average

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sample company, so the Company should be placed at the upper end of the range, with a

corresponding ROE estimate of 10.25% based on a capital structure with 51.9% equity. If DTE’s

capital structure is weakened (which it should not be, as discussed in section V. A above), then the

Company’s cost of equity would increase, requiring a higher ROE (5T 1402–1404, 1461).

D. Other Cost Rates.

Tax law requires, and prior Commission orders have allowed, a return on Job Development

Investment Tax Credits (JDITC) at the rate of return for permanent capital, so the associated

returns for JDITC-Debt and JDITC-Equity reflect the corresponding permanent capital rates of

3.97% and 10.25%. Deferred income taxes are at zero cost of capital (5T 1383, 1389–90; Exhibit

A-14, Schedule D1).

E. Overall Rate of Return.

The sum of the weighted cost of the above-described capital components results in a

weighted, after-tax 5.59% overall rate of return, with a 1.3547 revenue conversion factor for the

projected period (5T 1386; Exhibit A-14, Schedule D1). The corresponding weighted pre-tax rate

of return used for the calculation of the IRM surcharge was 9.12% (1390, 1392; Exhibit A-18,

Schedules H1 and H3).

VII. ADJUSTED NET OPERATING INCOME AND OTHER REVENUE-RELATED ISSUES.

DTE Gas’s adjusted Net Operating Income (NOI) is projected to decline by $68.0 million

from $238.0 million in the 2019 historical test year to $170.0 million in the projected test year (5T

357; Exhibit A-13, Schedule C1, line 17). DTE Gas’s projected NOI reduction is primarily due to

increased operating costs partially offset by increased revenues. The increase in costs reflects

growth in plant, increased O&M, and higher depreciation rates. Operating revenues reflect

increased distribution and off-system revenues, partially offset by the discontinuation of the IRM

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surcharge and other lower revenues, as further discussed below (5T 357; Exhibit A-13, Schedule

C1).

A. Throughput

Throughput represents the total gas sales and transportation volumes delivered to end-use

customers during the test period. DTE Gas projects 1,311,592 sales customers, 563 End Use

Transportation (EUT) customers, sales volumes of 151.9 billion cubic feet (Bcf), and

transportation volumes of 146.2 Bcf (5T 429, 806, 808; Exhibit A-15, Schedules E1.1, E6, and

E7).

1. Weather Normalization.

Weather is one of the primary determinants of natural gas consumption. Weather

normalization adjusts actual consumption from a past period to eliminate the impact of warmer or

colder than normal weather (temperatures, measured in Heating Degree Days or “HDDs”)30 that

occurred during that time period. Weather-normalized historical consumption is then used to

forecast future consumption (5T 809–10).

Mr. Chapel, the Company’s Manager, Market Forecasting, explained that in accordance

with the Commission’s Orders in Case Nos. U-15985, U-16999, U-17999, U-18999, and U-20640,

DTE Gas presented normal HDDs based on 15-year normal weather calculated from 2006 through

2020 (updating the Commission’s approved methodology to reflect the most recently completed

calendar years). (5T 810–11; Exhibit A-15, Schedule E5).

30 A HDD is a measure of how temperature relates to natural gas usage for heating purposes; HDDs give an indication of a customer’s likelihood of turning on their furnace to heat their home or facility. Basically, the greater the HDDs, the greater the heating demand (5T 809).

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2. Customer Usage.

DTE Gas’s weather-normalized 2020 customer usage was approximately 153.6 Bcf. DTE

Gas’s projected test year usage is 151.9 Bcf (5T 811, Exhibit A-15, Schedule E1, p 1). This

reduction is due to reductions in usage per customer, driven by the Company’s Energy Waste

Reduction (EWR) program, and further impacts observed and projected due to the ongoing

COVID-19 situation (5T 810–11).31

AG witness Coppola claimed that the effects of COVID-19 on forecasted sales is not

reasonable or supported by recent data, and “the evidence now shows that any previous impact on

sales has begun to reverse and will likely disappear by 2022, as residential and commercial

customers return to normal routines” (5T 1723). Mr. Chapel responded by explaining that Mr.

Coppola did his analysis on total volumetric sales figures, but actual customer behavior must

properly be viewed on a per-customer basis.32 The Company made its COVID-19 economic

adjustments on its usage factors (i.e., usage per customer), not on its overall sales figures (5T 838).

All of the Company’s GCR/GCC/Aggregate customers have lower normalized consumption on a

per-customer basis from 2019 into 2021 (5T 842).33

31 Mr. Chapel further discussed residential, commercial, and industrial sales forecasts (5T 816–23, 828–31), and COVID-19 impacts (5T 823–25) 32 Mr. Coppola criticized the Company for allegedly providing only a “limited amount of information from September 2015 to April 2021” in discovery (5T 1722). Mr. Chapel explained that the criticism is unjustified because the AG’s discovery sought a specific analysis that the Company does not do in the general course of its business. The Company provided data that should have been sufficient for Mr. Coppola to perform his own analysis. When he indicated that he could not do so, the Company went “above and beyond” what is required by creating the analysis and providing it to him (5T 836–37; Exhibit A-34, Schedule X1). 33 From 2019 to 2021, there were customer average energy consumption reductions of 2.8% for Rate A (residential), 8.6% for Rate GS-1 (commercial and small industrial), 0.8% for Rate S (school), 14.1% for rate 2A I (multi-metered residential), 1.2% for Rate 2A I (multi-metered residential), and 62.4% for Rate GS-2 (commercial and small industrial). (5T 838–42).

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Mr. Coppola proposed a 7,225 MMcf sales increase (corresponding to a $25,700,107

revenue increase) based simply on removing all of the COVID-19 sales adjustments for 2021

(4,812 Mcf) and 2022 (2,413 MMcf). (5T 1725). Mr. Chapel explained that the Company already

properly anticipates 2,399 MMcf (4,812 minus 2,413) to return to sales service by 2022. In other

words, the Company’s total expected 2020 volume reduction due to COVID-19 was 4,812 MMcf.

The Company then expected 2,399 MMcf of that COVID-19 reduction to return in 2021 so that

the 2021 total volume reduction was only 2,413 MMcf. The AG’s recommendation incorrectly

double counts this reduction and is grossly overstated; it should be rejected (5T 842–43).

Mr. Coppola further suggested that the Company’s GS-1 sales are understated by 395,068

Mcf (corresponding to a $1,379,143 revenue increase) due to 12 former EUT customers that have

recently moved to service under rate schedule GS-1 (5T 1725–26). Mr. Chapel explained that the

AG’s proposal should be rejected because the twelve customers used approximately 400,000 Mcf

per year as EUT customers (an average of 33,333 Mcf per customer). If they expected to continue

using gas at this level, then they would not have converted to GS-1 service because it would have

been uneconomic to do so. Since these customers have chosen to take GS-1 service, it is reasonable

to assume that they will, in aggregate, more closely assume usage characteristics of a typical GS-

1 customer (5T 843).

Increasing heating values, measured in terms of Btu per cubic feet (Btu/cf), can lower

consumption because less gas is needed to generate the same heating requirements. The

Company’s system average heating value began increasing in August of 2014, and reached 1,064

Btu/cf in June of 2019, but seems to have stabilized recently. The Company’s system-weighted

average heating value for the projected test period is 1,057 Btu/cf. No adjustments have been made

to the usage factors in this case due to heating value (5T 814–16).

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3. Exelon Energy Company (Exelon)

Exelon customers (formerly served by DTE Gas) 34 are removed from the sales forecasts

because they receive all of their gas services from Exelon instead of DTE Gas (5T 832). DTE Gas

projects $7.9 million of annual revenue from the Exelon agreement (5T 359; Exhibit A-13,

Schedule C3, column (d), line 3). There appears to be no opposition to the Company’s projection

of Exelon revenue.

4. Cost of Gas.

Mr. Chapel projected a $2.9479 per Mcf jurisdictional cost of gas for the 2022 projected

test year (5T 833).

5. End-Use Transportation (EUT).

DTE Gas had 573 End-Use Transportation (EUT) customers35 and 156.8 Bcf of volume in

the 2019 historical test year. DTE Gas forecasts 563 customers and 146.2 Bcf in the projected test

year (5T 429; Exhibit A-15, Schedules E6 and E7). DTE Gas had $87.4 million of total EUT

revenue in 2019, and projects $101.3 million (at current rates) of total EUT revenue in the projected

test year (5T 434; Exhibit A-13, Schedule C3.2, columns (b) and (c)).36

Staff’s “recommended level of EUT gas volumes in 2022 amounts to 149,300 MMcf, an

increase of 3,080 MMcf or 2.1% over the Company’s projections and is the result of adjustments

34 DTE Gas and Exelon entered into an easement agreement that grants Exelon a right to pipeline capacity on DTE Gas’s distribution system, and thereby gives Exelon the ability to compete in the overlapping service territories of DTE Gas and DTE Electric. The Commission approved the easement agreement (February 14, 2001 Order Approving Special Contract in Case No. U-12825). 35 EUT customers are DTE Gas’s largest volume Commercial and Industrial (C&I) customers who purchase their gas supplies from a third-party supplier, and then contract with DTE Gas to transport and load balance their gas supplies on the DTE Gas system for delivery to the customers’ facilities (5T 425).

36 AK Steel and Ford Rouge will be returned to cost-based rates by the projected test year, so DTE Gas is not again seeking to recover a transportation rate discount (there will be no discount to recover), but the Company might again seek to recover such a discount in a future case.

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to rate schedules ST, LT and XLT as shown in Exhibit S-13” (5T 1988). Staff’s reasoning is

unclear. Staff “found the Company’s EUT customer count forecast reasonable and fit with

historical trends” (5T 1987) and for “rate class XXLT, Staff is not proposing any adjustment to

forecasted volumes” (5T 1988). Staff then stated: “For every other EUT rate schedule however,

Staff found the forecasted changes in gas demand were not easily explained by EWR measures

and/or changes in the number of customers taking service from DTE, and thus found an adjustment

to be reasonable” (5T 1988).

The Company assumes that Staff’s indicated concern relates to Mr. Decker’s direct

testimony explaining, for brevity, only five of the largest drivers, which contributed 4.3 Bcf to the

Company’s projected 9 Bcf decrease in EUT volumes for the projected test year (5T 433–34;

Exhibit A-15, Schedule E7, line 6, pg. 2 (Net impact of customer operational volume increases

and decreases)). Therefore, Mr. Decker’s rebuttal testimony provided additional detail, pointing

out that the 9 Bcf reduction is the sum of variances among 526 customers, and was calculated

using the same volume adjustment methodology that the Company used in Case Nos. U-18999

and U-20642. Following the five previously explained adjustments (equating to 4.3 Bcf), the next

largest ten customer adjustments make up an additional 2.5 Bcf (see the table at 5T 474). Those

two groups collectively cover 75% of the 9 Bcf. Of the remaining 511 adjustments, 100 are volume

increases (5T 473–74).

The Company also disagrees with Staff’s proposal to increase EUT volumes by 3,080

MMcf because Staff did not explain the methodology that it used to arrive at this recommendation.

In contrast, the Company’s EUT forecast was created using the most recent 12-month data

available when this case was prepared, adjusted for known and measurable changes, which is an

appropriate methodology that has been approved in previous cases (5T 430, 474–75).

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AG witness Coppola proposed to increase EUT volumes by a total of 7.33 Bcf based on

three adjustments. First, he recommended a 1,747 MMcf (1.7 Bcf) increase in power generation

volumes based on his use of a three-year average of consumption instead of the Company’s five-

year average (5T 1729). The Company stands by its power generation forecast, which is based on

the Commission-approved five-year average methodology (5T 479). The issue was litigated

extensively in Case No. U-18999, where the Commission found “that DTE Gas’ five-year

historical period best represents the company’s average gas use. While the Attorney General’s

three-year historical period captures an apparent uptrend in gas use, it does not account for

variances in Michigan weather, which may be warmer or colder than is typical and may influence

customer gas use” (September 13, 2018 Order in Case No. U-18999, p 63).

Second, the AG proposed to increase EUT volumes by 4.7 Bcf, suggesting that the

Company did not properly explain this matter (5T 1730–31). The Company disagrees,

incorporating its response to Staff above (further explaining the 4.7 Bcf of the 9 Bcf volume

adjustment).

Third, the AG proposed to increase EUT volumes by 880 MMcf based on the complete

rejection of EUT volumes being reduced by EUT customers participating in the Commission-

approved Energy Waste Reduction (EWR) program (5T 1732). The Company disagrees because

it files, and the Commission reviews, EWR results annually. For reference, in 2020, the C&I EWR

gas savings totaled 1,108 MMcf. The Company’s 1% factor applied to the rate ST and rate LT

volumes totals 880 MMcf. Staff used the same methodology (5T 1988), and it is well supported

(5T 480). The Commission also previously found that “the Attorney General did not provide a

basis for rejecting the EWR volume reduction” (September 13, 2018 Order in Case No. U-18999,

p 64).

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B. Midstream Revenue

DTE Gas realizes Midstream revenue from selling storage and transportation services to

off-system customers.37 These sales maximize the utilization of DTE Gas’s rate base assets and

help mitigate rate increases (5T 437). DTE Gas projects $101.0 million of Midstream revenue,

consisting of $31.6 million of storage revenue and $69.4 million of transportation revenue (5T

438–39, 447).

The Company’s proposed $31.6 million of storage revenue is based on 62.5 Bcf of storage

capacity. This includes $28.0 million of Contract Storage revenue, and $3.6 million of Park and

Loan revenue (5T 439–40, 445; Exhibit A-13, Schedule C3.3, lines 1-3, column (d)).38 Contract

Storage revenue consists of 29.8 Bcf of capacity sold and under contract through the test period

($17.7 million in revenue), plus 13.3 Bcf of storage capacity to be sold for the 2021/22 storage

cycle (i.e., starting April 1, 2021) and 19.4 Bcf of storage capacity to be sold for the 2022/23

storage cycle (i.e., starting April 1, 2022), which are expected to contribute an additional $10.3

million of revenue (5T 443; Exhibit A-13, Schedule C3.3, line 1, column (d)). Park and Loan

revenue is based on a three-year average of annual revenue from 2017 through 2019, which is the

same methodology that was used in the U-20642 settlement (5T 445).

Midstream projects $69.4 million of transportation revenue for the projected test period,

consisting of $60.4 million in Off-System Transportation revenue and $9.0 million in Exchange

revenue. Exchange revenue is based on a three-year average of annual revenue from 2017 through

37 An off-system customer transports gas through the DTE Gas storage and transmission system from a specified receipt point to an off-system delivery point. These customers ultimately consume gas outside the DTE Gas service territory, in contrast to GCR, GCC and EUT customers (“on-system customers”). (5T 434). 38 Park and Loan services enable DTE Gas to optimize the amount of revenue from its storage complex. The services consist of ratable injection over a specified time period, for ratable withdrawal over a different specified time period (5T 445). GIK is not collected because the GIK value is embedded in the Park and Loan service rate (5T 446).

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2019, which is the same methodology that was used in the U-20642 settlement (5T 447, 450–51;

Exhibit A-13, Schedule C3.3, lines 6, 7, and 8, column (d)).

AG witness Coppola proposed to increase Midstream revenue by $5,311,000 based on

three adjustments. First, the AG increased Contract Storage revenue by basing it on a three-year

average of revenue (5T 1734). The Company disagrees. It is not appropriate to use historical

averages to forecast Contract Storage revenue because the rate is based on forward markets, not

historical pricing. The Company properly calculated Contract Storage revenue by adding the

revenue associated with capacity under contract plus the forecasted revenue from unsold capacity

at market rates (5T 443, 481).

The AG also proposed to increase revenue from Park and Loan and Exchange services

based on a three-year average of 2018-2020 (5T 1734). Historical averages are appropriate for

these items as indicated above (5T 445, 450–51), but the appropriate methodology (used in Case

Nos. U-18999 and U-20642) is to use the historical test period (2019 in this case) as the last year

in the average. The AG’s 2018-2020 average is also inconsistent with the use of a 2017-2019

historical average to forecast storage cycling and Off-System Transportation volumes. The AG

also appears to have inappropriately cherry-picked years to calculate the highest result for these

items.39 Therefore, AG’s forecasting methodology is inappropriate, and the AG’s resulting

calculations should be rejected (5T 481–82).

C. Other Operating Revenue

DTE Gas’s other operating revenue is projected to be $119.0 million, consisting of (1) late

payment/NSF revenue, (2) appliance service programs, (3) miscellaneous service revenue, (4) gas

choice supplier revenues, (5) rent from gas property, (6) inter-department rent, (7) other gas

39 The AG accepted the Company’s forecast for Off-System Transportation, which is higher than the result would be if the AG used her own methodology (5T 482).

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revenues, (8) gas-in-kind, (9) Blue Lake investment income, (10) Vector Lease interest, and (11)

Grantor Trust income (5T 362–63, 451–57; Exhibit A-13, Schedule C3, line 21).

AG witness Coppola proposed a $6.6 million increase in operating revenue based on using

2020 to calculate revenues and expenses from appliance service programs, and his disagreement

with the Company that 2020 involved unusual circumstances (5T 1735–36). The Company

disagrees. Adopting 2019 historical test period revenues and costs is consistent with the Orders in

Case Nos. U-17999 and U-18999, and the settlements in Case Nos. U-16999 and U-20642. There

were also a lower number of repair visits in 2020, specifically at the peak of Covid-19. During this

time, several HPP services were postponed and only critical work was performed (No-Heats, Hot

Water Tanks, and Air Conditioners) and service to other appliances was phased in over time.

Therefore, 2019 more accurately reflects a normal operating year than 2020 (5T 483).

D. Operating and Maintenance (O&M) Expenses

DTE Gas’s adjusted O&M expense was $432.8 million in 2019, and is projected to increase

by $90.8 million to $523.5 million in the 2022 projected test year, which is a reasonable and

prudent amount that would provide the Company with the necessary resources to assure continued

safe and reliable service (5T 363; Exhibit A-13, Schedule C5, line 8, columns (g), (h), (i) and (j)).

The major categories of O&M expense, as reflected on Exhibit A-13, Schedule C5, are Natural

Gas Storage; Transmission; Distribution; Customer Service; Marketing; Administrative and

General; and Pensions and Benefits. The increase in O&M expense is due primarily to inflation,

increased transmission fees, right-of-way maintenance, records remediation work, increased

merchant fees, customer experience expenses, higher benefits expense, and increased shared asset

fees from DTE Electric (5T 363).

Although the Company’s initial filing supported an O&M expense of $523.5 million, the

Company adopts the following O&M related adjustments:

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O&M Adjustments In millions Uncollectible Expense ($ 2.4) Transmission Right of way ( 2.0) TCARP Demand Charge ( 11.6) Shared Assets Customer Service ( 0.8) Shared Assets Other than Customer Service ( 0.8) Total O&M Adjustments ($17.6)

Accordingly, the Company is now supporting a total O&M expense amount of $505.9 million

(Attachment A, page 3 ).

1. Inflation

The Company used a 2019 historical test-year, with inflation of 2.8% for 2020,

2.9% for 2021, and 3.0% for 2022 (5T 364; Exhibit A-13, Schedule C12). The inflation factor is

a weighted rate based on using the CPI-Urban projected indexes as of September 2020 through the

end of the projected test period for non-labor costs, and expected wage increases for labor costs

(5T 364). Mr. Cooper further explained that he conservatively estimated annual wage increases of

3.0% for 2020, 2021, and 2022, based largely on mandatory base pay increases and progression

increases set forth in the Company’s collective bargaining agreements with labor unions

representing DTE Gas employees (5T 875). There is no evidence that DTE Gas can avoid paying

wage increases as set forth above, and any proposal that DTE Gas should do so threatens an illegal

result. DTE Gas cannot violate its Collective Bargaining Agreements, and the Commission has no

authority to become involved in, let alone dictate results for, collective bargaining.40 Therefore,

the Commission should approve DTE Gas’s proposed composite inflation rate.

40 The Commission has no common law powers, but instead possesses only the limited authority that the Legislature conferred upon it. Consumers Power Co v Public Service Comm, 460 Mich 148, 155; 596 NW2d 126 (1999); Mason Co Civil Research Council v Mason Co, 343 Mich 313, 326-27; 72 NW2d 292 (1955).

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AG witness Mr. Coppola proposed to disallow all inflation, characterizing projected

inflation as a self-fulfilling prophecy, and further asserting that the Company was able to offset

inflation in the past, so the Company should be able to also do so in the future (5T 1748–49). The

Company disagrees. Mr. Telang explained that Mr. Coppola ignored that labor cost increases are

largely driven by the Company’s collective bargaining agreements, as discussed above. The

Company has experienced and will continue to experience inflationary pressures, so Mr. Coppola’s

unfounded and unreasonable proposal should be rejected (5T 1325–26). The Commission also

previously rejected similar arguments by the AG (May 2, 2019 Order in Case No. U-20162, pp

73-74; September 13, 2018 Order in Case No. U-18999, p 75; January 31, 2017 Order in Case No.

U-18014, p 72).

2. Storage, Transmission, and Distribution O&M Expenses.

Company witness Mark Johnson explained and supported O&M expenses of $14.1 million

for Natural Gas Storage (5T 937–40; Exhibit A-13, Schedule C5.1, column (l), line 22), $89.6

million for Transmission (5T 937, 940–56; Exhibit A-13, Schedule C5.2, column (l), line 22), and

$132.4 million for Distribution (5T 937, 957–67; Exhibit A-13, Schedule C5.3, column (l), line

22) as reasonable and necessary.

a. TCARP

DTE Gas originally requested to recover $11.6 million for TCARP transmission fees (5T

948; Exhibit A-13, Schedule C5.2, line 9, column (j)). Staff recommended a complete $11,625,000

disallowance for all transmission fees relating to DTE Michigan Lateral Company (DMLC) and

Saginaw Bay services for the TCARP, reasoning that they are speculative due to DMLC’s pending

Act 9 case (Case No. U-20894), but indicated that it would consider revising the recommendation

to include six months of TCARP costs ($5.86 million, based on a revised in-service date of July 1,

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2022) if the Commission approves DMLC’s Act 9 application prior to the conclusion of this Case

No. U-20940 (5T 1970–72).

On July 27, 2021, the Commission entered an order in Case No. U-21102 authorizing the

Company to record a regulatory asset in account 182.3, Other Regulatory Assets, for expenses

associated with TCARP beginning with the first payment to DTE Michigan Lateral Company and

Saginaw Bay Pipeline Company through no later than the date the Company implements new rates

in its next general rate case and authorizing the Company to amortize the regulatory asset over a

three-year period beginning on the effective date of its inclusion in base rates. In conjunction with

the approval of this deferral, DTE Gas removes $11.6 million of O&M expenses related to the

TCARP transmission fees from its revenue requirement request in this case (5T 1323–24).

b. Transmission Integrity Management Program (TIMP)

The Transmission Integrity Management Program (TIMP) is a federally mandated program

(49 CFR, part 192, subpart O) to identify and mitigate risks to transmission pipeline systems (5T

946). The Company forecasts $19.2 million of TIMP Pipeline Integrity expenses for the projected

test year. AG witness Coppola proposed a recovery of $12.6 million, which is the average of 2018-

2020 actual TIMP Pipeline Integrity expenses (a $6.6 million disallowance from the Company’s

requested $19.1 million recovery). (5T 1755).

The Company disagrees because regulations require operators to assess pipelines generally

every seven years, and there are several factors that cause expenses to vary from year to year for

assessments and remediation, including: (1) the number of pipelines being assessed based on

assessment requirements for those pipelines; (2) the Company is increasing the number of

pipelines being assessed due to the In Line Inspection (ILI) Expansion program; (3) the length and

diameter of the pipelines being assessed; (4) the type of assessment being conducted, either Direct

Assessment (DA) or ILI; (5) the type and number of tools utilized to perform the assessment (5T

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989); Mr. Johnson added that the AG’s proposed use of an historical average is inappropriate to

predict the amount and type of remediation, which is based on the assessments, and a significant

expense for TIMP Pipeline Integrity (5T 989–90).

c. Maximum Allowable Operating Pressure (MOAP) Records Remediation

The projected test period O&M cost for Maximum Allowable Operating Pressure (MAOP)

records remediation is $5.9 million (5T 948). DTE Gas implemented a MAOP records review

program in 2012 in response to an Advisory Bulletin from the PHMSA. The PHMSA issued a

final rule on October 1, 2019, with an effective date of July 1, 2020. Based on this rule, the

Company will begin to address MAOP reconfirmation for pipelines that do not have Traceable,

Verifiable and Complete (TVC) records starting in 2021, so an increase in O&M funding is

required (5T 951; Exhibit A-13, Schedule C5.16, line 5).

AG witness Coppola proposed to disallow $2.95 million (half the cost), stating that the

Company “should be responsible for at least 50% of the costs to remediate its records” (5T 1759).

The Company recognizes its responsibility for maintaining records to ensure the safety and

reliability of its system; however, the AG neglects that industry record-keeping requirements have

changed. Following the 2010 San Bruno incident (where one of the key findings was that the utility

did not have adequate records), in 2011 and 2012 the PHMSA released Advisory Bulletins (ADB

2011-01 and ADB 2012-06) that introduced the concept of TVC records. The PHMSA, industry

organizations, and utilities spent the next eight years developing additional requirements to ensure

operators could support the MAOP of their pipelines by having TVC records. On July 1, 2020, the

MOAP Reconfirmation rules went into effect, requiring operators to have an MAOP

Reconfirmation plan by July 1, 2021, and remediate records defects by 2035 (5T 991, 1266–67).

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The AG’s proposed disallowance is inappropriate because records gaps are an industry

issue, as reflected by the PHMSA introducing a new TVC concept and then working eight more

years with the industry before issuing its final rules. Those rules also reflect the magnitude of the

endeavor by giving operators fifteen years to remediate their records defects. Therefore, the

Company should recover the full $5.9 million of expenditures that are required to comply with this

regulation, and which are also vital to ensuring the safety and reliability of its system (5T 992,

1267–68).

d. Pipeline Safety Management System (PSMS)

DTE Gas requests $2.0 million of O&M expense for Pipeline Safety Management Systems

(PSMS). (5T 948; Exhibit A-13, Schedule C5.2, line 10, column (j)).

AG witness Coppola proposed a $1.0 million disallowance, reasoning that the Company

spent less in 2020 than it forecasted in Case No. U-20640, and that the forecasted 2021 O&M

expense from Case No. U-20642 ($1.0 million) should be used here for 2022 (5T 1760).

The Company disagrees because implementation of a PSMS at DTE Gas is vital to

improving pipeline safety. PSMS is also an American Petroleum recommended practice supported

by the American Gas Association and by the Commission in its 2019 State Energy Assessment

Report. Due to the Covid-19 pandemic, DTE Gas spent less related to PSMS in 2020 than

originally planned, but those items are moving forward in 2021 and will continue to increase in

2022 with the establishment of new initiatives and required ongoing support.41 Therefore, DTE

Gas’s request for $2.0 million of O&M expense should be fully approved (5T 993).

41 Mr. Johnson further clarified historical spending by explaining that PSMS costs were incurred in 2019, but they were included in the Codes and Standards O&M expenses, because at that time PSMS was not identified as a separate group (5T 993–94; Exhibit A-32, Schedule V3).

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e. Meter Abnormal Operating Condition (AOC) Initiative

DTE Gas requests $1.5 million of O&M expense recovery in the projected test year for the

Meter Abnormal Operating Condition (AOC) Initiative (5T 966–67; Exhibit A-13, Schedule

C5.16, line 13).

AG witness Coppola proposed a full $1.5 million disallowance, reasoning that AOCs “have

existed before” and that the Company did not justify its proposed spending increase over historical

levels (5T 1760–61).

The Company disagrees. Mr. Johnson explained that the proposed increase in expenditures

is justified because improvements in training and meter data integrity have led to an increase in

the number of AOC meters requiring remediation identified annually. Through these

improvements, 127% more Meter AOCs were identified in 2018-2020, on average, each year

compared to 2015-2017 (Exhibit A-32, Schedule V3). Meter AOCs typically are added to the

backlog after two years, so this increase in AOC identification starting in 2018 will impact the

backlog in 2020 to 2022. DTE Gas expects to continue to identify Meter AOCs at this increased

rate. In addition to these increased identification levels, remediation of AOCs is required by the

Michigan Gas Safety Code, and is otherwise important to ensuring that the Company’s system can

continue to provide safe and reliable service to customers. Therefore, the Company’s request is

justified and should be fully approved (5T 967, 996).

3. Customer Service O&M Expenses.

Company witness Mr. Campbell explained and supported the actual and projected O&M

expenses for the Customer Service organizations as reasonable and necessary (5T 785–94; Exhibit

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A-13, Schedule C5.4).42 These O&M expenses (including rate case adjustments) were $59 million

for the 2019 historical test year, and are expected to increase to $73 million for the projected test

year (5T 785–86, 792–94; Exhibit A-13, Schedule C5.4). Mr. Campbell discussed the work

activities performed in 2019 (5T 786–91) and testified that the projected O&M increase is based

on known and measurable adjustments including inflation of $4.7 million for 2020-2022,43

Customer Records and Collection Expenses of $4.5 million, and Customer Collection-Merchant

Fees of $4.4 million (5T 792–94).

a. Meter Reading

The Company’s request includes $5,349,000 for nine Meter Read employees (Exhibit A-

13, Schedule C5.4, line 4, column (l)).

Staff proposed a $1,603,493 disallowance (eight of the nine employees), reasoning that the

Company has reported only one employee in its Smart Grid Metrics Reports (5T 1899–1902).

The Company disagrees because the employee referenced in the Smart Grid Metric Reports

is a union employee who actually reads meters. The other eight employees are non-represented

employees who perform back office, customer service, and meter analysis functions. The

Company’s requested O&M cost recovery is for the whole Meter Read Staff (nine total employees)

needed to support all meter reads coming into the system for AMI, AMR, and non-AMI. Therefore,

Staff’s proposed disallowance was based on a misperception, and the Company should recover the

full amount for its nine employees (5T 985–87; Exhibit A-32, Schedule V1).

42 The Customer Service organizations are Customer Care, Customer Billing, Revenue Management and Protection (RM&P), Customer Service Operations, Exceptions Management, and Customer Service Transformation / Digital Experience. These organizations are responsible for billing, customer contact, and payment acceptance, and the Company has taken unprecedented steps to deliver customer support during the COVID-19 pandemic (5T 782–85). 43 The rate of inflation is 2.8% for 2020, 2.9% for 2021, and 3.0% for 2022 (5T 364; Exhibit A-13, Schedule C12).

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AG witness Coppola proposed a $1,637,620 disallowance for Meter Read O&M expense,

reasoning that there is a 54% decrease in the number of meters requiring manual reading between

2019 and 2022, and simplistically calculating a cost decrease of 27% (half of 54%). (5T 1763–64).

The Company disagrees. In addition to the discussion about Meter Read O&M costs above,

Mr. Johnson explained that the Company’ small projected increase in Meter Read O&M expense

from 2019 through 2022 is justified due to a 25% increase in contract rates for contract meter

readers and geography, which causes increased distance between manual meter read sites, so there

are fewer meters read per hour, as explained previously in direct testimony and in response to

discovery (5T 980; Exhibit A-32, Schedule V2). Therefore, the Company’s O&M cost projection

is reasonable and to be expected, and it should be fully approved (5T 987–88).

b. Customer Service Representatives (CSRs)

The Customer Records and Collection Expenses include $3.8 million for Customer

Experience, which is driven by wages for Customer Service Representatives (CSRs). (5T 792–93).

AG witness Coppola proposed to disallow $3,115,000 for 120 CSRs who he suggested are

unjustified in light of the Company’s proposed digital enhancements (5T 1770).

Mr. Campbell explained that the AG’s proposal should be rejected because it conflates two

different things. The longer-term (beyond the test year) goal of digital enhancements is to reduce

call volume and improve the Call Center’s average speed to answer. Call Center staffing is driven

primarily by average handle time (AHT) and call volume. Changes to call handling requirements,

and the need for continuous training and development are driving the need to increase staffing

levels. Since the start of the COVID pandemic, the Call Center has had a heightened focus on

exercising special care for the Company’s most vulnerable customers. DTE has experienced

approximately a 174 second AHT increase in calls that involve low-income customers because,

for example, it takes extra time for CSRs to explain specialized COVID payment plans, and

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properly pre-screen and advise customers regarding requirements for agency resources. The net

impact of these activities requires 120 additional CSRs to maintain best practice levels (5T 796–

98).

c. Merchant Fees

Witness Burns explained that merchant fees are the costs associated with processing debit

and credit card payments. Provision 14 of the U-20640 settlement reflects the parties’ agreement

that “recovery of merchant fees will be as proposed by DTE Gas for residential customers, and

recovery of merchant fees will be limited to only those business customers whose aggregate bill is

less than $75,000 per year.” DTE Gas supports the continued inclusion of merchant fees in the

Company’s rates in accordance with the U-20640 settlement and in alignment with DTE Electric,

as reflected in the Commission’s Orders in Case Nos. U-20162 and U-20561 (5T 646–48).

DTE Gas seeks recovery of $11.11 million of merchant fees in the projected test year

(Exhibit A-13, Schedule C.5.8, p 1, column (g), line 5). This forecast was developed by applying

the three-year average merchant fees growth rate that DTE Gas experienced from 2017 through

2019 to the actual merchant fee expense incurred in 2019. Limiting the use of credit and debit

cards, as indicated above, reduces merchant fees by $2.53 million (5T 648–49).

AG witness Coppola proposed to reduce the Company’s merchant fee recovery to $7.523

million (5T 1769). Mr. Burns explained that the AG’s proposal should be rejected because it only

accounts for annual growth from 2019 to 2020. DTE Gas used a three-year historical growth rate

to forecast the projected test years to avoid anomalies from any specific year (such as 2020, which

was impacted by the pandemic). (5T 652).

Mr. Coppola’s reasoning is also flawed. He stated: “As more and more customers pay their

bill with a credit card there are fewer customers who will make use of credit cards to pay their gas

bills. This is basic logic. The 2020 actual data supports this conclusion” (5T 1768). Mr. Coppola

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inaccurately assumed that merchant fees are directly related to the number of customers paying

their bill with a credit or debit card. Mr. Coppola cites no evidence to support this conclusion.

Instead, merchant fees are driven primarily by the volume of payment transactions and the rate of

fees being charged by the various credit and debit card companies and banking institutions.

Therefore, the merchant fee forecast is based on the growth in actual transaction fees assessed to

DTE annually (5T 652).

4. Marketing, and Administrative and General O&M Expenses.

Company witness Mr. Decker explained and supported $49.4 million of projected O&M

expenses for Marketing as reasonable and necessary (5T 469; Exhibit A-13, Schedule C5.5).

Company witness Ms. Uzenski explained and supported historical and projected O&M

expenses for the Administrative and General (A&G) category as reasonable and necessary (5T

364–69; Exhibit A-13, Schedule C5.6, column (l)). She explained that many of these costs are

charged to DTE Gas by the Corporate Staff Group (CSG), which is a shared services organization

that includes corporate staff functions. This business model, since the merger of Detroit Edison

and MichCon in 2001, provides efficiencies, cost savings, and enhanced governance and internal

controls (5T 364–65). Customers benefit from a leaner, more efficient organization, and cost-

effective processes. DTE Gas’s proposed CSG cost allocation methodology is the same

methodology that the Commission approved in prior general rate cases for DTE Gas and DTE

Electric (5T 366–68). Total adjusted historical O&M expense for A&G was $106.6 million, which

is projected to increase to $124.1 million in the projected test year (Exhibit A-13, Schedule C5.6,

line 20, columns (f) and (l)). The projected increase is based on inflation and other adjustments

that Ms. Uzenski explained (48-49).

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a. Injuries and Damages

The A&G category includes an Injuries and Damages expense projection of $6,824,000 for

the projected test year (Exhibit A-13, Schedule C5.6. line8, column(l)).

Staff proposed a $622,000 decrease for insurance rebates, dividends and refunds collected

by the Company (5T 2003, 2005).

Ms. Uzenski disagreed, explaining that the Company forecasted Injuries and Damages

expense using an average of the actual cost reflected in account 925. These actual amounts already

include reductions for rebates, dividends, and refunds of $438,000 in the five-year average. The

remaining $184,000 of Staff’s proposed reduction relates to Property Insurance in account 924.

The Company’s projection for Property Insurance was based on the 2019 historical amount,

adjusted for inflation, and already included a credit of $163,000 for rebates/refunds. Therefore,

Staff’s proposed reduction should be rejected as duplicative of credits that the Company has

already reflected (5T 382–83, 386–87).

b. Rent Expense for Shared Assets and Related Information Technology (IT) O&M Costs

The A&G category also includes a rents expense projection for the cost to DTE Gas for its

proportionate use of certain assets, including buildings, facilities and IT systems (“Shared Asset

Charge”), which are owned by DTE Electric of $47,830,000 for the projected test year (Exhibit A-

13, Schedule C5.6, line 15, column (l)). The Shared Asset charge represents an intercompany

billing for the cost of jointly used assets such as buildings and IT systems.44

44 The Company’s IT group is a Shared Services organization. IT assets that are not unique to DTE Gas (for example, email, servers, and networks) are part of the shared asset cost system, and span across the IT Investment portfolios. The costs of services are billed to DTE Gas and other affiliates based on the level of service provided to each entity. DTE Gas currently pays approximately 21% of all shared asset costs. The shared asset charge is recorded as O&M at DTE Gas, and there is a corresponding O&M offset at DTE Electric (5T 709, 1116–17; Exhibit A-13, Schedule C5.14, columns (f)-(h)).

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DTE Electric and DTE Gas utilize and share certain assets to provide better service to

customers at lower cost. By sharing assets, DTE Electric and DTE Gas leverage economies of

scale by utilizing common assets to serve customers of both utilities, thus creating efficiencies and

lowering costs to customers. The sharing of assets allows DTE Electric and DTE Gas to provide

similar services to customers without having redundant assets, systems and employee resources.

The Shared Asset charge to DTE Gas was first introduced by the Company and approved by the

Commission in DTE Gas Rate Case No. U-13898, filed in 2003 and included in subsequent rate

cases (See e.g., U-17999 December 9, 2016 Order at p.33 adjusting the Shared Asset rent expense

by $1.2 million; U-18999 September 13, 2018 Order at pp. 81-82 approving a $10.9 million

increase in the shared asset charge (referred to as the capital usage charge)).45 The alternative

approach would require each utility to implement and maintain its own IT systems, buildings, etc.,

each with its own set of capital and human resources and at a higher cost to customers.

i. Shared Asset Charge - Existing Assets

A significant portion of the Company’s projected Shared Asset charge is related to

“Existing Assets” costs associated with projects that were previously approved in past DTE

Electric or DTE Gas rate cases. In the last DTE Gas rate case to receive a Commission Order

outside of settlement (U-18999), the Commission approved a $10.9 million increase in the Shared

Asset charge (previously referred to as the Capital Usage Charge) bringing the total charge to

$35.5 million. (See Commission Order in Case No. U-18999 dated September 13, 2018 at p.81

and the Company’s Hearing Exhibit A-13, Schedule C5.6 line 15 in U-18999). Actual costs

charged to DTE Gas in 2019 were $37.2 million. (Exhibit A-13, Schedule C5.12, line 5.)

45 The Company also discussed the Shared Asset charge in Case Nos. U-15985 (See Direct Testimony of Peter Rynearson), U-16999, and U-20642, however, there is no mention of the charge in the U-15985 Order. Case Nos. U-16999 and U-20642 were resolved in settlement.

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Staff recommends disallowance of rents expense (an O&M cost) associated with the

Existing Assets bucket of $20,923,000 (5T 1925). Staff reasoned that since project detail is not

maintained, “any information regarding the projected project cost and depreciable life can only be

based on information available at the project’s start” (5T 1921). Staff then concluded that “there

is no way to examine the reasonableness and prudency of the investments within the Existing

Assets bucket” (5T 1921).

The Company disagrees as Staff’s position has three key flaws.

First, Staff is attempting to re-litigate capital expenditures that the Commission previously

approved in past DTE Electric rate cases (Case Nos. U-20162 and U-20561). The capital

expenditures previously approved by the Commission represent the rent expense associated with

the Existing Assets bucket. Continuing to require project level cost detail after the project costs

have already been approved is contrary to fundamental regulatory law and practice. While res

judicata and collateral estoppel do not apply to Commission proceedings in the pure sense, issues

fully decided in earlier MPSC proceedings need not be relitigated in later proceedings unless a

party presents new evidence or shows by changed circumstances that the earlier result is

unreasonable. Application of Consumers Energy Co, 291 Mich App 106, 122; 804 NW2d 574

(2010). To have the same proofs, exhibits, and testimony repeated would be a waste of the

Commission's resources. Pennwalt Corp v Public Service Comm, 166 Mich App 1, 11; 420 NW2d

156 (1988).

Similarly, in ABATE v Public Service Comm, 208 Mich App 248, 261; 527 NW2d 533

(1995) the Attorney General argued that Consumers Energy should not recover expenses

associated with a construction project that was never placed in service. The Court found that AG’s

arguments were inconsistent with the prudent investment test under which the end result of a

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utility's efforts do not determine how much is recoverable. Utilities are compensated for prudent

investments at their actual costs when made regardless of whether the investments are deemed

necessary or beneficial in hindsight.

In this case, Staff has presented no changed circumstances or shown that the Commission’s

earlier decision was unreasonable. As noted above, the Commission has approved the capital costs

for these projects in DTE Electric’s prior rate cases as well as DTE Gas’s Shared Asset portion in

prior DTE Gas rate cases. Re-litigating the reasonableness of the projects at this stage, without

any changed circumstances or a showing that the projects are unreasonable, is contrary to

established law and regulatory practice. Such a practice would also create a duplicative

burdensome requirement (5T 388).

Second, DTE Gas is required to follow the Federal Energy Regulatory Commission’s

Uniform System of Accounts (USofA), which it did in this case with respect to the Shared Asset

capital investments. Staff did not recognize that the accounting guidance under the USofA,

requires capital assets in the Plant Ledger to be accounted for by Plant account instead of by

Project. DTE Gas (and DTE Electric) has consistently applied these guidelines to all of its capital

expenditures (5T 389), not just IT or Shared Asset capital.

The Court of Appeals has frequently recognized the importance of the Commission

following consistent accounting practices.

• In Attorney General v Public Service Comm, 262 Mich App 649; 686 NW2d 804

(2004), the Court affirmed the Commission’s approval of a utility’s deferral and

amortization because “it is consistent with established and accepted regulatory

principles… Each amortization process is consistent with accepted regulatory and

accounting principles.” 262 Mich App at 658-59.

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• Attorney General v Public Service Comm, 215 Mich App 356, 365; 546 NW2d 266

(1996) the Court affirmed the Commission’s decision, which was supported by a

DTE witness who “testified that standard accounting principles or standards require

that a net gain or loss on a futures contract be recorded as a ‘cost’ of the gas

purchased pursuant to the contract”.

• ABATE v Public Service Comm, 208 Mich App 248, 261; 527 NW2d 533 (1995)

the Court of Appeals affirmed the Commission’s approval of construction costs that

were capitalized and amortized according to accepted accounting and regulatory

practices.

• Application of Michigan Consolidated Gas Company, 304 Mich App 155, 172-73;

850 NW2d 569 (2014) the Court reversed an attempt to re-price gas purchases that

were made in accordance with a prior pricing methodology.

With respect to the Existing Assets projects, the Companies follow a uniform and well-

established system of accounting. For all DTE Electric and DTE Gas projects (not just those at

issue in the Shared Asset charge), once a project is placed into service, the total cost of the project

is reclassified from construction work in progress into specific plant asset accounts within the

Company’s plant ledger. This process is called unitization. Tracking by project level ceases, and

accounting and depreciation by plant account begins (5T 388–89). After explaining accounting

details and providing an example, Ms. Uzenski testified that the distinction between projects and

plant assets is important because it impacts how costs are reflected and approved in rate cases. The

beginning balance of plant in service for rate cases is the accumulation of all projects to date, less

retirements, categorized by plant type at a point in time, which in this case is December 31, 2019.

The plant in service beginning balance is delineated by plant type (e.g., distribution, transmission),

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not by every historical project that resulted in additions to those plant types. To determine plant in

service in rate base, the rate case model starts with existing plant balances and calculates changes

to those balances based on capital expenditures supported in the Company’s filing. The same logic

applies for determining the balance and projected changes to that balance for shared assets, which

are a subset of DTE Electric’s plant in service (5T 390–91). In sum, DTE Electric and DTE Gas

follow the same USofA accounting guidelines and apply the same accounting methodologies to

the Shared Assets as they have to all capital assets for decades.

Third, Staff’s indicated concern that the Existing Asset bucket might contain projects that

were abandoned or cancelled or remain in the balance after being retired is unwarranted and there

is simply no basis in the record to support this assertion. The Company prudently tracks its costs

in accordance with FERC’s USofA standards. USofA definition of account 101 Plant in service

states: “This account shall include the original cost of gas plant, included in accounts 301 to 399

prescribed herein, owned and used by the utility in its operations, and having an expectation of life

in service of more than one year from date of installation.” (emphasis added) The standards do not

require project level cost detail.

As indicated above, the Existing Asset bucket reflects unitized asset balances in the

Company’s plant ledger. Projects that were abandoned or canceled will not be in the plant ledger

because they would have been written off from construction work in progress to expense instead

of being unitized. The fixed asset subledger reflects only those assets that are in-service and

excludes historical assets that have been retired This process is consistent with USofA Plant

Instruction 10 B(2) which states: “When a retirement unit is retired from electric plant, with or

without replacement, the book cost thereof shall be credited to the electric plant account in which

it is included…”) (5T 388, 393).

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In addition, a disallowance associated with the Existing Assets not only impacts DTE Gas,

but will also result in rate impacts to DTE Electric without notice and hearing under MCL 460.6a.

DTE Electric’s approved rates in Case No. U- 20561 included a revenue credit of $35.1 million

from DTE Gas. The Shared Asset charge is an annual amount paid to DTE Electric, hence a $20

million disallowance in DTE Gas’s portion of the Shared Asset charge would unlawfully remove

a $20 million credit to DTE Electric that was previously accounted for in DTE Electric’s last rate

case (U-20561) and reflected in its current rates. The loss of this credit would result in a downward

adjustment in DTE Electric’s rates without proper notice and hearing or adequate due process.46

In summary, the Commission should treat the Existing Asset bucket of shared assets in the

same manner as other plant in service. Additionally, the shared asset revenue from most of the

Existing Asset bucket is already reflected as a reduction in DTE Electric’s current base rates.

Therefore, and as further discussed above, Staff’s proposed $20.9 million disallowance should be

rejected (5T 393–94).

ii. Information Technology (IT) O&M Related to Existing Assets

IT O&M costs are part of DTE gas’s historical expenses plus inflation and are embedded

in A&G expenses (5T 394; Exhibit A-13, Schedule C5.6).

Staff proposed an $11.3 million disallowance by reasoning that if the cost of existing assets

underlying rent expense of $20.9 million is disallowed, then the related IT O&M should be

disallowed (5T 1924). Staff’s proposal to defund over 50% of existing IT operations for DTE Gas

should be rejected as it results in a proposed disallowance of over $30 million associated with

46 DTE Gas has due process rights under the Fourteenth Amendment to the United States Constitution. See also Gonzales v United States, 348 US 407, 415; 75 S Ct 409; 99 L Ed 467 (1955).

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assets and associated O&M that have already been approved in both DTE Gas’s and DTE

Electric’s past rate cases.

In the past, the Commission has opined that adjustments to historical test year O&M should

be unusual and infrequent. In the context of the utility’s proposal to adjust historical O&M, the

Commission has stated:

The Commission again takes this opportunity to state its preference for a historically based test year adjusted for known and measurable changes. A properly adjusted historical test year provides a firm, prudent, and practical basis for setting appropriate rates for the future period. Moreover, as was done with the Staff’s approach in this case, the historically based test year may include, when shown to be appropriate, adjustments for items that are substantial, reasonably likely to occur, and largely beyond the control of the utility. By separately setting forth such adjustments (with full justification and explanation), their appropriateness can be evaluated by the Commission on a case-by-case basis. In the Commission’s view, these additional adjustments must be unusual, and should only occur infrequently. (See Order dated April 28, 2005 in Case No. U-13898 at p.7)

Here, the Company has provided substantial evidence to support the ongoing operation of the IT

projects that were previously approved and put in service under past orders from the Commission.

Any proposed modification to historic O&M must provide full justification and explanation on the

record. Staff’s proposal to adjust historical O&M simply utilizes a mathematical formula to cut

O&M expenses by an amount proportional to their proposed Shared Asset disallowance. This

approach assumes without justification that the Company will no longer operate or maintain the

projects/assets that were put in place, that are currently operating, and for which capital dollars

have already been spent. There is simply no support in the record to employ such a measure.

In addition to the discussion above regarding shared asset costs, Ms. Uzenski explained

that disallowing one half of current O&M expense is unreasonable because it would require layoffs

and other draconian measures. Staff’s proposal is also imprudent because it would prevent the

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Company from performing its basic and critical IT operations that are necessary to ensure the

continued safe and reliable operation of DTE Gas’s business (5T 387, 394–95).

iii. Shared Asset Charge – Net Increase Due to New Assets

DTE Gas originally supported Rent Expense of $47.8 million (Exhibit A-13, Schedule

C5.6, column (l), line 15) which reflects a net increase in the Shared Asset charge of $9.7 million

from the 2019 historical period. Exhibit A-13, Schedule C5.12 summarizes the changes in the

Shared Asset charge from 2019 to 2022. The increase consists of a $16.7 million increase in the

Shared Asset charge related to new IT projects as well as $0.9 million related to buildings,

furniture and equipment. A list of projects underlying this increase in the Shared Asset charge is

provided on Exhibit A-13, Schedules C5.13, C5.13.1, C5.14, and C5.15 (5T 369). This increase

is offset by the impact of existing assets as of 12/31/19 that will be retiring for a net decrease of

$9.6 million. Cost drivers were also updated to align the allocation of assets with the allocation of

the labor using those assets, resulting in an increase of approximately $1.6 million in the allocation

to DTE Gas (5T 370).

As indicated above, the primary increase to the Shared Asset charge is due to new IT

investments that DTE Gas and DTE Electric share. DTE Gas’s IT investment spending is part of

the DTE IT Five-year Plan for 2021-2025, which was filed on March 22, 2021 in Case No. U-

20561 (660–62, 1299). In DTE Electric’s last general rate case, the Commission recognized that

using actual historical costs to support investment recovery involves regulatory lag and

uncertainty. Therefore, the Commission offered DTE Electric the option to develop an IT plan

modeled from the Company’s distribution planning effort (May 8, 2020 Order in Case No. U-

20561, p 152) as follows:

The plan would strategically and holistically assess IT needs, solutions, risk management, security, and decision-making approaches to support the utility’s customer, business, and operational functions going forward….

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The Commission envisions the plan would describe the IT system needs and strategic goals over a suitable timeframe that considers not only immediate needs to replace legacy systems but also longer term integration and compatibility between systems and support for the company’s strategic vision for the utility’s business. [May 8, 2020 Order in Case No. U-20561, pp 152-53.] As part of the U-20642 settlement, DTE Gas agreed to participate with DTE Electric in

meeting with Staff and other stakeholders regarding an IT plan. The IT Plan represents DTE’s

strategy to leverage and deploy affordable IT assets over the next five years. It also provides

valuable context to see how specific IT investments align with long-term planning (5T 661).

Included in the plan are the results of a three-year IT spend benchmark against 21 other utility

companies in the United States including peers in size and geography. The focus of the benchmark

was on the amount of IT spend as a percentage of overall Company revenue covering 2017, 2018,

and 2019. The DTE Enterprise compares favorably, placing in the first quartile in lowest spend as

a percentage of revenue. (See Case No. U-20561 Five-Year Plan p.134)

To continue moving forward with needed IT investments, DTE Gas presented details

regarding DTE Electric IT capital expenditures through the end of the projected test year

(December 31, 2022) and which make up a significant portion of the increased Shared Asset

charge. 47, 48, 49 This presentation is necessary and appropriate because no record data exists

47 In DTE Gas’s original filing, Witness Busby supports $233.5 million of projects with Shared Asset costs from January of 2020 through December of 2022 (Exhibit A-13, Schedule C5.13). There are 95 projects that contribute to the Enterprise IT Shared Asset charge breakdown (Exhibit A-13, Schedule C5.13.1). There are 48 Corporate IT projects and 22 Customer IT projects above $250,000. Of those, 18 Corporate IT and 6 Customer IT projects have not been previously discussed in an electric rate case (see Exhibit A-13, Schedule C5.13 regarding projects that have been discussed previously). (5T 710–11). 48 Witness Busby supported the projects underlying the Company’s $11.7 million O&M incremental increase in Shared Asset charges from 2019 levels (Exhibit A-13, Schedule C5.13, column (h), line 10). This includes DTE Gas’s portion of Enterprise-wide projects, and 22 projects specific to Customer Service (Customer Portfolio) focused on underlying technical support (5T 709; Exhibit A-13, Schedule C5.14). 49 Witness Pizzuti described the Company’s efforts to create Distinctive Service Excellence for its customers (5T 1104–13), and to transform the customer experience through targeted investments in the Customer IT Portfolio, which

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regarding these IT-related Shared Asset investments since DTE Electric’s last rate case (No. U-

20561, which was filed in July 2019 and resulted in a May 8, 2020 Order). DTE Electric’s planned

and actual IT expenditures, and therefore DTE Gas’s Shared Asset Charges, have increased since

the U-20561 test period (which ended April 30, 2021). DTE Gas’s rates should be set based on

DTE Gas’s projected test year (January 1, 2022 through December 31, 2022), and not based on

DTE Electric’s last rate case, with different historical and projected test years (5T 1300–1301).

Due to changes made in response to Staff and intervenor positions, DTE Gas’s revised

request for Rent Expense is $46.194 million. This represents the Company’s original request of

$47.830 million less $0.792 million concession by Witness Busby and $0.844 million concessions

by Witness Pizzuti. This equates to a net increase of $8.0 million from the 2019 historical period.

Staff’s proposed disallowances related to missing final business cases

Staff proposed a $792,000 disallowance in Shared Asset costs for 16 IT projects that do

not have final business cases. While DTE Gas believes that it has articulated extensive support for

these projects through testimony and exhibits, the Company appreciates Staff’s concerns, and is

no longer seeking recovery in this case for the 16 projects with shared asset costs of $792,000

(reflected in Table 2 at 5T 756). The Company will seek recovery in a future proceeding (5T 755–

756).

Similarly, with regard to Customer IT projects, Staff identified 13 projects with 2022

capital spend for which the Company did not provide business case summaries, with a

corresponding disallowance of $955,000 (5T 1928; Exhibit S-11.28). Again, while the Company

includes all IT investments that improve customer operations and that enhance customer interactions and the customer experience (5T 1104, 1113–19). There are 28 projects in the Customer IT Portfolio totaling $86.3 million of capital investments in the historical ($7.9 million), bridge ($41.0 million) and test-year period ($37.6 million) in the Regulatory/Compliance, IT Enhancements, and Strategic categories. The associated test year shared asset cost to DTE Gas is $5.1 million (5T 1116–17; Exhibit A-13, Schedule C5.14, column (h), line 8

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believes that the costs were fully supported, it appreciates Staff’s concerns, and is no longer

seeking recovery in this case for 11 of these projects with shared asset costs of $816,000 (reflected

in Exhibit A-13, Schedule C5.14). The Company will seek recovery in a future proceeding (5T

755–56, 1167). The Company has, however, completed business cases for the remaining two

projects (Enhanced Training Environments and Speech Analytics). The Company has also clearly

articulated the benefits of these projects (5T 1337, 1149), and provided the associated business

case executive summaries (Exhibit A-27, Schedule Q1). The full business cases (Exhibit A-27,

Schedules Q3 and Q4) provide a summary of the most recently updated cost estimates and project

objectives, including a $640,000 reduction in total estimated capital costs for the two projects (as

compared to Exhibit A-13, Schedule C5.14). Accordingly, the Company’s original request for

shared asset cost recovery is reduced from $139,000 to $111,000 for the remaining two projects

(5T 1165–66). This results in $844,000 ($816,000 + $28,000) total concessions related to the 13

projects identified by Staff.

Staff’s proposed disallowances related to variances between cost estimates

Staff proposed a $600,193 disallowance of Shared Asset costs in the 2022 test year based

on the variance between the projected cost estimates in the executive summary and projected

capital expenditure for 21 projects. Staff used the minimum cost reflected in each of the exhibits

(5T 1931–33). The Company disagrees because the business cases provided in workpapers and

their corresponding executive summaries were specifically utilized throughout the investment

planning process and were requested by Staff in Case No. U-20162. The information was provided

with the understanding that Staff wanted as much point-in-time information as possible. The

business cases were not updated as the projects progressed, but the Company was able to present

more refined cost estimates through Exhibit A-12, Schedules B5.5 and B5.4.1, and Exhibit A-13,

Schedules C5.13 and C5.13.1 (5T 753–54). Also, for three projects (reflected on Table 1 at 5T

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755), Staff improperly proposed a disallowance based on a suggested variance in cost projections

that does not exist (5T 754).

Similarly, with regard to Customer IT projects, Staff identified 11 projects for which capital

spend in Exhibit A-13, Schedule C.14 did not exactly match Exhibit A-22, Schedule L1. Staff took

the minimum cost reflected in each of those exhibits, resulting in a proposed disallowance of

$367,976 (Exhibit S-11.31). As indicated above, the Company disagrees because the estimates

were prepared at different points in time. Staff’s minimalization methodology disregards the

different types of data provided and is contrary to the understanding underlying the provision of

early point-in-time data. The 2020 and 2021 capital amounts shown in Exhibit A-22, Schedule L1

reflect the capital estimates at the time the business cases were completed, and which were not

updated as the projects progressed. Exhibit A-13, Schedule C5.14 reflects what was at that time

(when DTE Gas filed this case) the most recent assessment of capital costs. DTE Gas continues to

seek recovery of the shared asset costs reflected in Exhibit A-13, Schedule C5.14 for the 11

projects (5T 753–54, 1167; the 11 projects are summarized in Table 2 at 1168). There are, however,

three projects that do not yet have completed 2022 business cases (the Customer Closed Loop

Expansion, Qualtrics Expansion, and Regulatory Reserve projects). As indicated above, the

Company is no longer seeking recovery in this case for any projects without completed business

cases. Therefore, the Company continues to request recovery of only the $1,009,000 in 2022

shared asset costs associated with the actual 2020 and forecasted 2021 capital spend for those three

projects (5T 1168).

Ms. Pizzuti further explained that the Digital Experience Group (DEG) was formed in 2020

to identify, develop, and implement improvements in the self-service voice and digital channels.

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The original 2020 business case estimated the cost of two product teams at $3.0 million capital.50

As the work of the teams progressed, however, it was recognized that additional funding would be

necessary to manage the desired scope and realize the full potential of the teams which required

the $5.0 million in capital to support this project, as reflected in Exhibit A-13, Schedule C5.14,

column (c), row 30 (5T 1140–43, 1169).

AG’s proposed disallowances

AG witness Coppola proposed a $1,248,000 O&M disallowance for seven Shared IT

projects (5T 1787). The AG proposed a $290,000 disallowance for the Automated Application

Monitoring Project and a $239,000 disallowance for the Customer Legacy Application Health

Project, reasoning that they were not adequately justified (5T 1784-1785). The Company disagrees

because Mr. Busby discussed the need for these projects, provided business outcomes, benefits

and additional cost details in his direct and rebuttal testimony.

The AG proposed a $33,000 disallowance for the Hybris Application Health Project,

reasoning that this project is not part of the Company’s scope of providing natural gas delivery

service (5T 1785). The Company disagrees because the Hybris solution is an e-commerce delivery

platform that allows the company to design and deliver various products and offerings. This

platform provides the ability to create marketing campaigns and online microsites as well as to

manage product and program enrollments. This project supports the regular maintenance required

to support daily operations and the effective delivery of service to our customers. (5T 741).

The AG proposed a $58,000 disallowance for the Cloud Center of Excellence Project and

a $144,000 disallowance for the Private Cloud Transformation Project (shown on Exhibit A-13,

50 Staff also reflected the business case capital estimate as $1.0 million due to low image resolution of the business case executive summary in Exhibit A-22, Schedule L1. The original business case capital estimate was $3.0 million as shown by Exhibit A-27, Schedule Q1 (fully legible version of the 2020 DEG business case summary) and Exhibit A-27, Schedule Q2 (full business case). (5T 1169).

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Schedule C5.13.1, lines 58 and 104), reasoning that the “Company has not made a sound economic

case that the shift to more cloud computing is justified” (5T 1786). The Company disagrees. Mr.

Busby explained that the projects align with the technology and cloud adoption principles outlined

in the DTE Five-Year IT Plan (see section 4.B, pages 22-24). The Cloud Center of Excellence

Project supports the growth in cloud utilization reflected across IT investment from 2019-2022

and beyond, as DTE currently expects a growth of 75%-100% in cloud utilization. The Company

uses Private Cloud on Premise solutions for (1) core and critical business functions, (2) data

sensitivity, and (3) NERC, SOX and PCI compliance. The expected efficiency and security

benefits further justify the projects (5T 726, 735–36, 771–73).

Finally, the AG proposed a $356,000 disallowance for the SuccessFactors Program

(shown on Exhibit A-13, Schedule C5.13.1, line 17), reasoning that the project has not been

adequately justified (1783). The Company disagrees. Mr. Busby explained that this is an ongoing,

multi-year program that was previously authorized in Case No. U-20162. Implementing the

planned additional SuccessFactors integrations and modules will improve payroll accuracy, reduce

pay inflation and erroneous conditions, improve supervisor time savings, reduce controllable

overtime, and reduce unplanned absences (5T 714–15, 773–74).

AG witness Coppola also proposed a $2,871,000 disallowance for 9 of the 28 Customer IT

projects that Ms. Pizzuti supported originally (5T 1782). Five of those projects do not have

completed business cases, so the Company is no longer seeking recovery in this case, as indicated

above. The Company continues to seek shared asset cost recovery for the remaining four projects,

two of which are further discussed below (5T 1170). (These projects were included in Staff’s list

of projects with no business case which the Company has conceded. Therefore, no additional

adjustment is needed in Brief.)

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Mr. Coppola did not dispute the merits or forecasted customer benefits of the IVR Natural

Language/Virtual Assistant project (which Mr. Coppola referenced as IVR Virtual Assistants), or

the DEG and Digital Transactional Experience projects (which Mr. Coppola grouped together as

the Digital Transactions and Experience Group). Instead, his reason for proposed disallowances

was that the projects should pay for themselves (5T 1780–81). The AG’s reasoning is inconsistent

with regulated, cost-of-service ratemaking, which does not dismiss recovery of capital invested in

a particular year because there could be operational savings in a subsequent year. Therefore, the

Company continues to seek full recovery of the $228,000 and $1,241,000 in shared asset costs that

the AG proposed to disallow for these projects (5T 1170–71).

Lastly, there are five Customer IT projects included in Exhibit A-13, Schedule C5.14 that

have been reprioritized and deferred to a later year as part of the Company’s ongoing planning and

budgeting process.51 Therefore, the Company is no longer seeking recovery of the associated

Shared Asset Cost, but will file for recovery in a future case (5T 1171). (These projects were

included in Staff’s list of projects with no business case which the Company has conceded.

Therefore, no additional adjustment is needed in Brief.)

c. Contingency

Staff “recommends a disallowance of $224 for Regulatory Commission Expenses and

$409,615 for Administrative and General salaries. This yields a total O&M disallowance of

$409,839 for the inclusion of contingency in the rate case” (5T 1898).

The Company disagrees. There is no contingency in O&M expenses. Staff’s proposed

O&M disallowance appears to be a penalty because the Company requested some contingency

51 The five projects are: (1) CRM Customer Profile & Preference; (2) Customer Profile & Preference: (3) Messaging Engine: (4) Outbound Notifications; and (5) Social Technologies (5T 1172).

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recovery for capital expenditures (5T 997. See also section V. B. 5). The Commission should

decline to impose such a penalty because no legal authority exists to support such action.52 In

addition to being unsupported by law, Staff’s reasoning (that the Company should not have

requested contingency recovery in this case because the Commission rejected similar requests in

past cases) is unsound and contrary to established regulatory practice. Parties often re-present

arguments that have not been adopted in past cases. The Commission may reach a different

decision based on changes in the law and/or the record in a particular case.53 Here, DTE Gas

modified its position on contingency from its last case, and has thoroughly supported its request

for limited recovery. In response to feedback from the Commission, DTE Gas eliminated

contingency from routine capital projects. Large capital projects managed by DTE Energy’s Major

Enterprise Projects (MEP) include contingency, however, because these projects tend to be larger

in scope, complexity, and duration. These projects are the TCARP, Van Born Project, Fort St Main

52 The Commission has no common law powers, but only possesses the limited authority that the Legislature conferred upon it. Consumers Power Co v Public Service Comm, 460 Mich 148, 155; 596 NW2d 126 (1999). The MPSC is an “administrative body created by statute and the warrant for the exercise of all its power and authority must be found in statutory enactments.” Union Carbide v Public Service Comm, 431 Mich 135, 146; 428 NW2d 322 (1988); Sparta Foundry Co v Public Utilities Comm, 275 Mich 562, 564; 267 NW 736 (1936). The MPSC’s authority must be conferred by clear and unmistakable statutory language, and a doubtful power does not exist. Mason Co Civil Research Council v Mason Co, 343 Mich 313, 326-27; 72 NW2d 292 (1955). The MPSC cannot expand its jurisdiction through its own acts or assumption of authority. Ram Broadcasting v Public Service Comm, 113 Mich App 79, 92; 317 NW2d 295 (1982). See also, Coffman v State Bd of Examiners, 331 Mich 582, 589; 50 NW2d 322 (1951) ("an administrative agency may not, under the guise of its rule-making power, abridge or enlarge its authority or exceed the powers given to it by statute, the source of its power"); GF Redmond & Co v Michigan Securities Comm, 222 Mich 1, 5; 192 NW 688 (1923). The Commission cannot re-write the Legislature’s language to include new or different provisions. Hanson v Mecosta Co Rd Comm, 465 Mich 492, 501-503; 638 NW2d 396 (2002). If an MPSC order conflicts with a statute, the order is void. Manufacturers Nat’l Bank v DNR, 420 Mich 128, 146; 362 NW2d 572 (1984). Our Supreme Court recently reaffirmed that “agencies cannot exercise legislative power by creating law or changing the laws enacted by the Legislature.” In re Complaint of Rovas Against SBC Michigan, 482 Mich 90, 98; 754 NW2d 259 (2008) (Emphasis added). 53 As discussed in section III. A, all Commission decisions must be authorized by law, and the Commission’s findings must “be supported by competent, material and substantial evidence on the whole record.” Const 1963, art 6, § 28.

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Phase III, and Grosse Ile System Supply. It is expected that undefined costs will arise above the

best forecast for the project, so contingency costs are a necessary part of budgeting for overall

project costs. Therefore, DTE Gas should recover the $13.0 million of capital contingency that it

is projecting to incur from the end of the historical test year to the end of the projected test year

(December 31, 2019 through December 31, 2022) for those four projects (5T 1200–1203, 1243–

44, 1294–95; Exhibit A-12, Schedule B5.10).

It would be unlawful and unreasonable to selectively punish DTE Gas alone for seeking

this relief (5T 997).54 Staff asserts: “It is not reasonable and prudent to have ratepayers bear the

costs of the Company’s contingency request when the Company understands that the Commission

will reject it” (5T 1897). The Company disagrees and believes that the Commission should approve

its lawful and reasonable request, as discussed above.

Staff’s methodology for determining the amount of its proposed disallowance is not

supported by the record in this case. Staff simply calculated a percentage rate of contingency for

capital expenditures (0.93%) and multiplied it by the total amount of DTE Gas O&M

Administrative and General salaries ($43.9 million) to arrive at a theoretical imputed disallowance

of approximately $410,000 (5T 1897). Staff’s calculation assumes that it took a percentage of time

to compute the contingency costs proposed in this case, and any time associated with preparing

such costs should not be approved. Mr. Johnson explained that DTE Gas utilized salaried employee

time to prepare its contingency request, and it was prepared during the normal budget process. No

additional employees were hired, nor was overtime expense incurred to perform any of the work.

54 Moreover, ratemaking is a legislative, rather than judicial, function so res judicata and collateral estoppel cannot apply in the pure sense, although issues fully decided in earlier MPSC proceedings need not be relitigated in later proceedings unless a party presents new evidence or shows by changed circumstances that the earlier result is unreasonable. Application of Consumers Energy Co, 291 Mich App 106, 122; 804 NW2d 574 (2010); Pennwalt Corp v Public Service Comm, 166 Mich App 1, 420 NW2d 156 (1988)

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Also, prior to beginning any work on capital project plans, employees were instructed to omit any

contingency from their project plans. Salaried employee compensation does not change based on

the amount of time spent working on a rate case, including contingency. Additional costs for

contingency preparation would have accrued only if a contractor service had been utilized or

additional personnel were hired, neither of which happened. The vast majority of incremental time

spent on contingency has been to address Staff’s concerns and data requests (5T 997–98).

As with Staff’s proposals regarding contingency in capital expenditures (see section V. B.

5), Staff’s additional proposals here also threaten to violate fundamental constitutional rights.55

DTE Gas has a fundamental right to seek relief from the Commission.56 The right to petition

extends to all departments of government, including administrative agencies.57 DTE Gas’s status

as a privately-owned and government-regulated company does not preclude its assertion of First

Amendment rights.58 It is inappropriate for Staff to attempt to foreclose DTE Gas from asking the

Commission to decide an issue.59

55 DTE Gas raises constitutional issues to preserve them for the record. Wikman v Novi, 413 Mich 617, 646-47; 322 NW2d 103 (1982) (“an agency exercising quasi-judicial power does not undertake the determination of constitutional questions”). 56 The First Amendment to the United States Constitution relevantly provides: “Congress shall make no law . . . abridging . . . the right of the people . . . to petition the Government for a redress of grievances.” The First Amendment is applicable to the State of Michigan and its political subdivisions by operation of the Fourteenth Amendment. Gault v City of Battle Creek, 73 F Supp 2d 811, 814 (WD Mich, 1999). Michigan’s Constitution similarly provides: “The people have the right peaceably to assemble, to consult for the common good, to instruct their representatives and to petition the government for redress of grievances.” Const 1963, art 1, § 3. 57 California Motor Transport Co v Trucking Unlimited, 404 US 508, 510; 92 S Ct 609; 30 L Ed 2d 642 (1972). 58 Consolidated Edison Co of New York v Public Service Comm of New York, 447 US 530, 533-34; 100 S Ct 2326; 65 L Ed 2d 319 (1980) (holding that the New York Public Service Commission’s suppression of bill inserts discussing public issues directly infringed the freedom of speech protected by the First and Fourteenth Amendments). 59 Baker Driveway Co, Inc. v Bankhead Enterprises, Inc, 478 F Supp 857, 859 (ED Mich, 1979) (“Our system of government places a high value on the freedom of the public to petition the government, and such activity will not be curtailed without some extraordinary showing of abuse”).

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The Commission must also hear the issues and receive the information that DTE Gas offers

so that the Commission can carry out its regulatory duties.60 Staff’s proposal to restrict

development of the record threatens to impede the Commission’s decision-making ability, contrary

to Const 1963, art 6, § 28’s requirement that the Commission’s findings be “supported by

competent, material and substantial evidence on the whole record.” (Emphasis added).

It is also axiomatic that decisions regarding what proposals DTE Gas will make are the

prerogative of the Company’s management.61 DTE Gas cannot lawfully be forced to alter its

proposals to conform to the Staff’s (or anybody else’s) point of view.62

5. Employee Benefits Expenses

Company witness Mr. Cooper supported projected employee pensions and benefits of

$44.3 million, which after adjustments for the portion transferred and capitalized, and the

elimination of costs allocated to the Company’s separate surcharge program, yields $40.0 million

for the projected test year (5T 851, 874; Exhibit A-13, Schedule C5.9).

a. Pension.

DTE Gas has two qualified pension plans, which are the Union Plan (for eligible employees

covered by collective bargaining agreements) and the Non-Union Plan (for eligible employees not

covered by collective bargaining agreements). Exhibit A-13, Schedule C5.10 reflects the sum of

pension costs from these two plans. The Company developed its projected pension costs based on

60 Eastern Railroad Presidents Conference v Noerr Motor Freight, Inc, 365 US 127, 137; 81 S Ct 523; 5 L Ed 2d 464 (1961) (“In a representative democracy such as this, these branches of government act on behalf of the people and, to a very large extent, the whole concept of representation depends on the ability of the people to make their wishes known to their representatives”). 61 Detroit Edison Co v Public Service Comm, 221 Mich App 370, 387-88; 562 NW2d 224 (1997). 62 Pacific Gas and Electric Co v Public Utilities Comm of California, 475 US 1, 9-16; 106 S Ct 903; 89 L Ed 2d 1 (1986) (holding that California Public Utilities Commission order that utility place third-party’s newsletter in its billing envelopes violated the First Amendment by forcing the utility to alter its speech to conform with an agenda that the utility did not set).

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the accounting requirements of the Financial Accounting Standard Board’s Accounting Standard

Codification section 715-30 (ASC 715-30),63 under which there are four components of pension

costs, as described below:

Service cost: This represents the pension benefits earned by active employees during the

current period on a present value basis. It is based on actuarial assumptions including

current and projected salaries, expected employee turnover, and life expectancy.

Interest cost: The interest cost recognized in the current period is the increase in the

Projected Benefit Obligation (PBO) due to the passage of time. The PBO is the actuarial

present value of benefits attributable to the pension benefit formula discounted back to

current dollars at a discount rate selected at each prior year end. A 3.28% discount rate was

applied in determining the PBO at the end of the historical period for the Non-Union Plan.

A 3.42% discount rate was applied in determining the PBO at the end of the historical

period for the Union Plan. The discount rates used in determining interest costs and service

costs during the projected period reflect the assumption that high-quality corporate bond

interest rates at the end of 2021 will remain essentially unchanged from levels prevailing

in December 2019.

Expected return on assets: This is an estimate of the expected investment return on assets

invested in the pension trusts for the current period. While actual year-to-year investment

returns can vary significantly, the expected return is determined based on long-term

financial market expectations in order to avoid large swings in pension costs based on

63 ASC 715-30 superseded Statement of Financial Accounting Standards Number 87, Employer’s Accounting for Pensions (SFAS 87), but did not change the underlying accounting standards. DTE Gas’s references to ASC 715-30 are comparable to references to SFAS 87 in prior rate cases.

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short-term investment performance. DTE Gas’s estimated annual rate of return was 7.30%

for the 2019 historical period and is assumed to be 7.10% in the 2022 projected period.

Amortizations: In addition to these current period costs, pension costs also include the

effect of the delayed recognition of prior costs. This includes prior service costs and

unrecognized gains and losses. Prior service costs arise from pension plan changes that

will affect future economic benefits for employees. Unrecognized gains and losses are

changes in the amount of either the PBO or plan assets resulting from actual experience in

a given year that is different from that assumed in the actuarial assumptions for the year.

Most notably, since discount rates and return on asset assumptions are based on point-in-

time measurements or long-term estimates, differences arise whenever discount rates

change, or actual asset returns differ from long-range expectations (5T 852–55).

DTE Gas’s annual pension costs are expected to decrease from $8.1 million in the historical

test period to negative $9.8 million in the projected period, which after adjustment for the portion

of pension costs capitalized, produces a projected negative pension expense of $5.4 million (5T

856–57; Exhibit A-13, Schedule C5.10, lines 10 and 16).

Since the Commission previously excluded DTE Gas’s negative pension costs from its

revenue requirement in Case No. U-13898, the Company has been accruing a regulatory liability

for negative pension expense. The Company proposes to continue deferring the projected negative

pension expense to the accumulated regulatory liability, as discussed in section VIII. G

(Accounting Requests). Therefore, the negative pension expense projected in this case is not

included in the Company’s projected revenue requirement (5T 856–57).

b. Other Post-Employment Benefit (OPEB) Expense.

DTE Gas’s OPEB costs are related to the provision of retiree medical, dental, prescription

drug, and life insurance benefits. DTE Gas’s projected OPEB expenses are determined pursuant

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to Accounting Standard Codification section 715-60 (ASC 715-60),64 which parallels ASC 715-

30, reflecting the cost of benefits earned by employees during the year, the expected return on

assets invested to meet the future liabilities, the interest cost on the accrued liability, and the

amortization of unrecognized gains and losses (5T 857–58).

DTE Gas’s OPEB costs are projected to decrease from a negative $18.9 million in the

historical test period (excluding a charge relating to income taxes) to a negative $25.3 million in

the projected period, which after adjustments for the impact of the costs transferred and the portion

of OPEB costs capitalized, produces a projected OPEB expense of negative $13.3 million (5T 859;

Exhibit A-13, Schedule C5.11, lines 12 and 19).

The Commission previously approved the Company proposal to defer negative OPEB

expense to a regulatory liability. As discussed in section VIII. G (Accounting Requests), the

Company proposes to continue to defer the net negative OPEB expense to a regulatory liability.

Therefore, the negative OPEB expense is not included in the Company’s proposed revenue

requirement, and there is no obligation for the Company to externally fund its OPEB liability (5T

860).

c. Active Employee Benefits.

DTE Gas incurs substantial costs to provide benefits to its active employees. These costs

largely concern health care and are projected to increase from $17.0 million in the historic test

year, to $21.4 million in the projected test year. This increase reflects (1) the normalization of the

historical Active Healthcare costs to reflect an historic average of constant dollar costs and thereby

64 ASC 715-60 superseded SFAS 106, but did not change the underlying accounting standards. DTE Gas’s references to ASC 715-60 are comparable to references to SFAS 106 in prior rate cases.

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establish a sound starting point, and (2) annual escalations for the adjusted medical plan trend of

5.7% in 2020, and 5.2% in 2021, and 4.7% in 2022 (5T 862; Exhibit A-13, Schedule C5.9).

AG witness Coppola proposed to reject the normalization adjustment, and to instead

escalate actual 2019 Active Healthcare expense by the average annual increase in costs per

employee from 2015 through 2019. The combined effect is a proposed $2.8 million reduction from

$21.4 million to $18.6 million (5T 1765–66).

The AG’s proposal should be rejected. Mr. Coppola mischaracterized the Company’s

Constant Dollar normalization adjustment as “simply compounding inflationary increases on top

of inflationary increases . . . [in a] brazen attempt to inflate forecasted O&M expense” (5T 1765).

To the contrary, Mr. Cooper explained that the year-to-year volatility of actual Active Healthcare

costs (which is largely driven by the Company’s self-insurance of healthcare benefits, and changes

in utilization) makes any historical period expense potentially unreliable as a starting point to

project costs. The $1.402 million constant dollar normalization adjustment to the Company’s

actual 2019 Active Healthcare costs is designed to eliminate this volatility and reduce the risk of

selecting an unrepresentative starting point. The only means of producing a starting point for

Active Healthcare that is normalized for changes in utilization is to develop an historical average

that neutralizes the change in price levels (5T 863–67, 914–15). As described by Mr. Cooper, the

use of a historical average for volatile costs is a routine practice by the Commission. For example,

an historical average of Lost and Unaccounted for Gas volumes is used to project Lost and

Unaccounted for Gas and the historical average of the ratio uncollectibles to revenue are used to

project uncollectible costs.

Mr. Coppola incorrectly described the adjustment’s mechanics as “compounding

inflationary increases.” Instead, the mechanics (reflected on Exhibit A-13, Schedule C5.9.3)

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merely adjust the Company’s historical Active Healthcare costs for each of the years 2015 through

2018 for the actual increases in medical costs as measured by PwC65 to make each year’s Active

Healthcare costs comparable to 2019. The five-year average of these price-level adjusted Active

Healthcare costs is then used to adjust the 2019 actual Active Healthcare costs to a more

representative level. By analogy, the Constant Dollar approach is similar to the conversion of

historical nominal prices into real prices because the value of a dollar changes over time due to

inflation (5T 915–16. See also the May 8, 2020 Order in Case No. U-20561, rejecting the AG’s

exception to the use of a constant-dollar denomination for emergent replacement expenditures).

Mr. Cooper further explained that annual unadjusted medical trend factors of 6.2% for

2020, 2021, and 2022 are based on projections for healthcare trends provided by the healthcare

experts at Aon, as reflected on Exhibit A-13, Schedule C5.9.1. 66 Aon’s trend factors are not

adjusted for the impact of COVID-19, and are corroborated by a study by PwC’s Health Research

Institute (reflected on Exhibit A-13, Schedule C5.9.2, page 3), which projects that medical costs

will increase by 6.0% in 2020, with a range of 4.0% to 10.0% in 2021, based on alternative

COVID-19 scenarios (5T 868).

In contrast to this well-supported analysis, Mr. Coppola apparently just used the total

change in Active Healthcare costs per employee between 2015 and 2019 of 12.2% and divided by

4 to produce an average annual increase of about 3%. This is inappropriate due to the volatility in

Active Healthcare costs, as discussed above, and because his sample size is too small to reliably

predict the future. Moreover, Mr. Coppola proposed a four-year average of years 2015 through

2019 but provided no rationale for selecting those years. Because of the high volatility and

65 Also commonly known as Pricewaterhouse Coopers LLP. 66Aon first develops an Allowed Trend, which represents a consensus expectation for medical and prescription drug costs. The Allowed Trend is then adjusted for the Company’s average fixed plan design leveraging to develop the future Medical Plan Trend, which is the basis for the Company’s projected active healthcare costs (5T 867–68).

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relatively few data points, the period selected can dramatically change the result. For example, a

three-year average of years ending in 2019 would produce an average annual rate of 5.2%, but a

five-year average of years ending in 2019 would produce an average annual rate of 1.3%.

Moreover, DTE Gas’s actual Active Healthcare costs increased by 9.0% in 2020, which further

buttresses the inherent year-to-year volatility in the Company’s Active Healthcare costs (5T917).

A far preferable alternative to Mr. Coppola’s mechanistic retrospective analysis of the

Company’s Active Healthcare costs is to escalate normalized historical costs by the medical trend

rates prepared by Aon (reflected in Exhibit A-13, Schedule C5.9.1), which are based on national

information, which Aon deems more credible than a single company’s experience, and reflect

consensus expectations of both Aon’s internal experts and other external resources. These trend

rates are then adjusted by the expected savings from the Company’s Wellness Program (0.5% in

2020, 1.0% in 2021, and 1.5% in 2022) to the adjusted numbers indicated above (5.7% in 2020,

5.2% in 2021, and 4.7% in 2022), which is a compound annual growth rate of 5.2% between 2019

and 2022 (5T 867, 917–18).

d. Other Employee Benefit Costs.

The Company’s Other Employee Benefits expense is expected to decrease from $6.5

million in the historic test year to $4.4 million in the projected test year (Exhibit A-9, Schedule

C5.9, line 26). These costs include a variety of other benefits including Accrued Vacation,

Supplemental Severance Plan costs, Long-Term Disability claims, costs associated with the

Affordable Care Act (ACA), the Company’s Wellness Program, as well as the Supplemental

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Savings Plan and Deferred Compensation Plan, and are supported in Mr. Cooper’s testimony (5T

869–74).67

AG witness Coppola proposed a $0.7 million disallowance for the Supplemental Severance

Plan (SSevP) expense, claiming that the SSevP should be a DTE Energy corporate expense due to

the acquisition of MCN Energy Group (5T 1766–67).

Mr. Cooper explained several reasons that the AG’s proposal should be rejected. First,

there is no merit in Mr. Coppola’s speculation that the Company delayed adopting the SSevP for

accounting reasons. Instead, the SSevP was adopted in response to fairness concerns expressed by

DTE Energy employees and provides benefits to eligible former MCN non-represented employees

(still covered under MCN’s traditional pension plan) that are comparable to what those employees

would receive if they were covered by DTE Energy’s traditional pension plan. Second, Mr.

Coppola does not dispute the reasonableness of the benefits provided. Third, even if one accepts

Mr. Coppola’s assertion that the SSevP is related to the merger, the merger produced substantial

cost savings that flowed through to customers, as the Commission previously recognized in its

Order in Case No. U-13898. Finally, the SSevP was adopted in 2016, and its expenses were

included and unopposed in general rate cases for DTE Gas (Case No. U-18999) and DTE Electric

(Case Nos. U-18255 and U-20561). Mr. Coppola proposed a similar disallowance in DTE Electric

Case No. U-20162, but the Commission did not adopt it. Therefore, Mr. Coppola’s proposed

disallowance should be rejected (5T 920–22).

67 DTE Gas also offers an Executive Supplemental Retirement Plan (ESRP) and a Supplemental Retirement Plan (SRP) but does not seek any recovery for them in this case (5T 873).

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6. Employee Compensation.

DTE Gas has incentive compensation programs for both its executive and non-executive

employees, which consist of short-term incentive plans provided through the Annual Incentive

Plan (AIP), applicable to executive level employees, and Rewarding Employees Plan (REP),

available to all other non-represented employees. In addition, the Company provides a multiple

year incentive plan delivered through the Long-Term Incentive Plan (LTIP), which is generally

available to managers and above, and up to 10% of other non-represented employees. Mr. Cooper

provided a detailed description of the design and mechanics of these plans, including the metrics

used to track Company performance, the method for setting Company performance level targets,

and the conditions for payment of incentive compensation (5T 890–99; Exhibit A-19, Schedules

I3 through I5).

DTE Gas seeks to recover the $17.0 million net projected test period expense of these plans,

which excludes the incentive compensation expense allocated to the Company for DTE Energy's

top five executives (5T 885; Exhibit A-3, Schedule C5.16). The components of these expenses

are reflected in the table below, as differentiated for the portion of such expenses based on

operating versus financial performance measures (5T 900).

LTIP AIP REP Total

Operating $0 $1.277 $4.009 $5.286

Financial $6.162 $1.277 $4.493 $11.732

Total $6.162 $2.553 $8.302 $17.018

DTE Gas’s proposal to include incentive compensation expense related to both the

operating and financial measures is fully supported by the record in this case as DTE Gas provided

an in-depth cost/benefit analysis demonstrating a $6.8 million net customer benefit ($23.8 million

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total customer benefits minus $17.0 million total incentive plan cost) (5T 902; Exhibit A-29,

Schedule I6).

It is also important to recognize that certain metrics can provide benefits to customers,

while evading specific quantification. There can be little doubt that an emphasis among the

Company’s leadership and employees on improving customers’ satisfaction and certain safety-

related measures results in significant non-quantifiable benefits to both customers and the

Commission (5T 902).

Staff proposed to exclude $11,732,000, representing incentive compensation expense

related to financial measures, indicating that it understood recent decisions by the Commission to

have established a “policy” of excluding financial performance measures from the revenue

requirement (5T 2036). To the contrary, the Commission has based its decisions on the evidence

(e.g., April 17, 2018 Order in Case No. U-18255, p 49) and has expressly recognized that “each

case must be evaluated on the record in that case” (January 31, 2017 Order in Case No. U-18014,

p 85). 68 Thus, financial measures have not been, and cannot lawfully be, categorically disallowed

as Staff suggests.69 The Commission’s older orders also recognize that incentive compensation is

recoverable based on the type of programs that DTE Gas has developed and the type of evidentiary

record that DTE Gas has presented in this case.70

68 The Commission also approved Consumers Energy Company’s (Consumers) cost recovery for its employee incentive compensation program (EICP), which was structured with 50% of an employee’s incentive based on achievement of operational and performance measures, and the other 50% based on the achievement of financial measures (November 19, 2015 Order in Case No. U-17735, pp 73-74, 78). 69 Michigan’s Constitution requires the Commission’s findings to “be supported by competent, material and substantial evidence on the whole record.” Const 1963, art 6, § 28. The APA similarly precludes the Commission from making decisions based on non-record materials. MCL 24.276. 70 The Commission long ago recognized that: “Executive bonuses have often been viewed as an appropriate cost of operating a utility” (October 28, 1993 Opinion and Order in Case Nos. U-10149 and U-10150, p 57 (rejecting the ALJ’s total exclusion recommendation; adopting Staff’s 50/50 sharing proposal; and advising DTE Gas that “future

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Absent a demonstration that the Company’s total compensation is excessive (which nobody

claims), there is no legitimate basis for disallowing any portion of that compensation, regardless

of the method used to determine the compensation (5T 928). DTE Gas performed an analysis of

virtually all incumbent salaries as of December 31, 2019, showing that DTE’s compensation

practices are comparable with market medians. Exhibit A-19, Schedule I1 reflects a summary of

the market median for all DTE Gas positions for which corresponding positions have been

identified, other than employees covered by collective bargaining agreements (5T 881). Exhibit

A-19, Schedule I1 demonstrates that for all positions with incumbents on December 31, 2019 with

available position matches, the weighted average of the annual base compensation was essentially

equal to the average of mean market base compensation (within 0.1%), and the total cash

compensation was 0.3% less than the average of mean market for total cash compensation (5T

882). An independent expert on compensation, Aon, reviewed the methodology used by DTE Gas,

and concluded that the Company deployed best practices in sourcing the market pay data and

developing estimated market values (5T 884; Exhibit A-19, Schedule I2). This analysis of existing

salaries as well as total cash compensation demonstrates that the Company’s compensation

policies and practices are reasonable compared to the comparative markets (5T 882–84, 927).

Incentive compensation programs are also an increasingly prevalent practice among the

vast majority of companies.71 Therefore, DTE Gas also must offer incentive compensation

opportunities to be competitive with other employers in attracting and retaining talented and

qualified employees.

approval of an incentive bonus plan like this requires a showing that it will not result in excessive costs and that the benefits to the utility’s ratepayers will be commensurate with those costs”). 71 A 2018 WorldatWork and Deloitte Consulting LLP study indicates that in 2018, 98.5% of companies had short-term incentive programs and 90.6% had long-term incentive programs. Moreover, a 2018 study by Aon of U.S. Salary Increases shows that 90% of Power and Gas Service providers utilized broad-based incentive compensation programs (5T 889).

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The focus on the variable portion of total compensation is also inappropriate because DTE

Gas’s incentive programs are not additional compensation over and above what other companies

pay for similar jobs. Instead, DTE Gas’s incentive compensation programs are one of two

components that make up DTE Gas’s total annual compensation package, which is comparable to

other companies competing for the same employees. Without the incentive compensation

programs, total cash compensation for Company employees would be 12% less than the market

medians, as reflected on Exhibit A-19, Schedule I1, and total compensation for Company

executives would be 70% less than market. Without the prospect of total annual compensation

equal to the fixed plus the variable compensation components, DTE Gas would not be able to

attract and retain a highly skilled workforce because total compensation would be substantially

less than the peer companies. Incentive compensation is a reasonable, prudent, and necessary cost

of doing business, so DTE Gas should be able to fully recover that cost (5T 886).

ABATE witness LaConte similarly proposed an $11.7 million disallowance of incentive

compensation expense relating to financial measures (5T 195). AG witness Coppola proposed the

complete elimination of incentive compensation expense related to financial measures ($12.9

million), plus 80% of incentive compensation expense related to operating measures ($4.2 million)

for a total disallowance of $17.1 million (5T 1792–94). Like Staff, the ABATE’s and AG’s

proposed exclusion of financial measures is based on a broad policy viewpoint that these measures

benefit only shareholders and not customers (5T 195, 238–39, 1789–90). In addition to the

discussion above, this ignores the customer benefits related to the maintenance of the Company’s

current debt ratings and the related avoided interest costs and the operating and capital cost savings

from an organizational emphasis on operating efficiencies that produce improved earnings and

cash flow (5T 923).

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Customers also benefit every day from employees who have the requisite skills and

experience to ensure the delivery of safe, reliable, and high-quality customer service. DTE Gas’s

compensation philosophy and framework benefits all customers by providing a high level of

service at competitive costs, with properly-compensated employees having an at-risk element of

compensation that provides incentives for safe, reliable, and efficient utility service that benefits

every customer (5T 877, 888–89, 902–903).

Mr. Coppola proposed to exclude 80% of incentive compensation expense relating to

operating measures, asserting that the remaining “20% represents the percentage of performance

measures that have been achieved at target level or higher over the past five years from 2016 to

2020” (5T 1793). Mr. Cooper explained that Mr. Coppola’s analysis is flawed for two reasons.

First, Exhibit AG-72 only reflects performance above Target and Below Maximum and ignores

performance at Maximum. Correcting for the omission of performance levels at Maximum

increases the number of measures at Target or Above to about 50%, as reflected on Exhibit A-25,

Schedule O-1 (5T 924).

Mr. Coppola also failed to recognize that while certain measures may produce results less

than Target, other measures can produce results greater than Target. There are also various

gradients of performance above and below Target.72 Exhibit A-25, Schedule O-2 reflects the

overall performance in operating measures, recognizing the gradients of performance rather than

Mr. Coppola’s simplistic and misleading binary approach (either the target was met, or not). From

2016 through 2020, the weighted performance was 93.7% for the AIP and 83.8% for the REP of

operating Targets, for an overall average of 88.7% (5T 925).

72 Under the AIP, payouts range from 25% for Threshold performance to 175% for Maximum performance, whereas under the REP payouts range from 50% for Threshold performance and 150% for Maximum performance.

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The Commission previously relied on similar evidence to reject less-extreme versions of

the same argument that the AG repeats in this case. The Commission rejected the AG’s proposed

40% disallowance of expenses relating to operating measures in DTE Gas’s last fully-litigated rate

case, finding that “DTE gas presented persuasive evidence that its annual overall average

performance in operating measures for AIP and REP was 90.1% (September 13, 2018 Order in

Case No. U-18999, p 68). The Commission similarly authorized DTE Electric’s recovery of

incentive compensation relating to operating measures, explaining in part: “The Commission notes

that DTE Electric provided evidence showing that the company has achieved performance targets

for AIP at an average of 96.3% and for REP at an average of 82.8%, from 2012 to 2016. (7T 837).

When looking at historical performance over a longer period, the Attorney General’s

recommendation that 50% should be disallowed is simply not supported” (April 18, 2018 Order in

Case No. U-18255, p 49). See also, May 2, 2019 Order in Case No. U-10162, p 93.

It is also important to keep in mind that DTE Gas’s incentive compensation programs allow

the Company to provide a lower level of base pay. If DTE Gas were to eliminate the variable

element of compensation, then DTE Gas would need to provide a commensurate increase in base

pay to attract and retain a highly skilled workforce. This would increase the cost of employee

benefits, such as 401(k) matching contributions, life insurance, and disability insurance, which are

tied solely to base salaries (5T 876–77, 879). Moreover, paying compensation solely in salary

would diminish the motivational incentives for employees to provide superior service to customers

and other constituencies that DTE Gas serves. Annual incentives ensure that employees have an

element of at-risk compensation that allows DTE Gas to differentiate pay partly based on

performance and allocate compensation to those employees that are most deserving. Incentive-

based compensation is an important tool to drive performance improvement, particularly in a

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service-based industry like the utility industry. Incentive compensation is an essential component

of DTE Gas’s total compensation package, considering the Company’s need to provide adequate

total compensation and to drive performance that ultimately benefits customers. Therefore, the

Commission should recognize that variable compensation is a cost-effective component of total

compensation, and allow DTE Gas’s requested recovery (5T 879, 888–89).

DTE Gas has demonstrated in detail that its incentive compensation plans have customer

benefits that significantly outweigh their costs, that its total compensation is reasonable compared

to its peers, and that there is no valid reason to disallow the Company’s requested cost recovery.

Therefore, based on the evidence in this record the Commission should approve DTE Gas’s request

to fully include the Company’s incentive compensation expense (except for the top five DTE

Energy executives) in the revenue requirement adopted in this case (5T 908–09).

E. Manufactured Gas Plant (MGP) Remediation Expenses

Part 201 of the Michigan Natural Resources and Environmental Protection Act (NREPA)

requires that a current owner or operator of a facility for which the owner is liable must take

appropriate action (5T 1041). DTE Gas is the current owner or operator of former Manufactured

Gas Plant (“MGP”) sites listed on Exhibit A-13, Schedule C13, p 1 (5T 1042). DTE Gas has the

responsibility for 14 former MGP sites, and 9 former holder sites (5T 1045–46).

DTE Gas incurred costs of approximately $106.1 million from 1984 through October 2020

for the prudent and reasonable costs of investigation and remediation of the MGP sites (5T 1048;

Exhibit A-13, Schedule C13, p 3). Most of those costs were addressed in prior general rate cases.

DTE Gas requests approval and recovery of $2.7 million (offset by a $2.0 million Station

A settlement payment for a net total of $0.7 million) for MGP expenses incurred from August

2019 through October 2020. These costs are unavoidable and relate to DTE Gas’s responsible

actions to investigate and remediate MGP sites in a cost-effective manner and were undisputed by

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any other party. Thus, the expenditures are reasonable and prudent and should be recovered (5T

1048–49, 1053; Exhibit A-13, Schedule C13, p. 4). Staff similarly “recommends the Commission

approve and allow recovery of $0.7 million for the time period August 2019 through October 2020

as reasonably and prudently incurred” (5T 2018).

Going forward, DTE Gas estimates that it incurs approximately $314,000 per year of non-

incremental recurring costs for routine monitoring and reporting, and other operations and

maintenance (O&M) activities. Based on feedback from Staff in Case No. U-20642, the Company

plans to remove these costs from the MGP regulatory asset and manage them under O&M starting

in October 2021. DTE Gas will also transition from utilizing third-party analytical laboratories to

DTE Electric’s analytical laboratory, which is estimated to shift approximately $130,000 of future

laboratory costs to annual recurring O&M costs (5T 1051–53; Exhibit A-13, Schedule C5.6, p 1).

F. Uncollectible Expense

Uncollectible expense is recorded in the income statement to reflect the portion of accounts

receivable (AR) that is considered uncollectible (5T 1017–19). DTE Gas projected $40.2 million

of uncollectible expense in direct testimony based on 2019 historical expense of $37.8 million,73

plus deferred COVID UCX amortization of $2.4 million ($11.9 million/5 years). (5T 1019–20;

Exhibit A-13, Schedule C5.7.0). DTE Gas continues to support the $37.8 million projection

excluding the estimate for deferred COVID UCX amortization of $2.4 million.

Staff proposed a $6,491,000 downward adjustment (from $40.2 million to $33,706,000)

(5T 2007). AG witness Coppola proposed a $4,341,00 reduction to $35,877,000 (5T 1743). Both

proposals are based on using the cash-basis method for estimating uncollectible expense. Ms.

Johnson explained that the cash-basis method should not be used to estimate uncollectible expense

73 DTE Gas used 2019 as the basis for the forecast because uncollectible expense was abnormally high in 2018, and the three-year (2016, 2017, 2019) average is not indicative of recent collection performance and activities (5T 1020).

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because it is inconsistent with how expense is recorded and with how other costs and revenues are

calculated for both MPSC reporting and for ratemaking. The estimation of future expenses should

be consistent with the practice used to record the actual expenses to ensure recovery of the

Company’s reasonable and prudent costs. An average of the amounts charged to account 904

provides such consistency. The cash-basis method also does not factor in special circumstances

that are accounted for under the accrual method (for example, delaying write-offs that are being

disputed or negotiated, and the temporary suspension of disconnects during 2020 due to the

pandemic). (5T 1024).

If the cash-basis method is to be used (which it should not be), then two flaws should at

least be corrected: (1) direct charges relating to the Company’s forgiveness match to low-income

customers must be included in uncollectible expense, and (2) the write-off ratio should be applied

to proposed revenue instead of present revenue to align the historical write-offs as a percentage of

historical revenue with projected revenue. This would result in an uncollectible expense of $36.6

million, an increase of $2.9 million to Staff’s projection, and $0.7 million to the AG’s projection

(5T 1025–26).

G. Lost And Unaccounted For (LAUF) and Company Use (CU) Gas, and Gas-In-Kind (GIK)

DTE Gas supports 4.6 Bcf of Lost And Unaccounted For (LAUF)74 gas for the projected

test period, based on a five-year (January 1, 2015 to December 31, 2019) average, in accordance

with the methodology adopted in DTE Gas’s last five contested rate cases (Case Nos. U-10150,

U-13898, U-15985, U-17999, and U-18999). (5T 508; Exhibit A-15, Schedule E9).

74 LAUF represents the difference between booked sources of gas and booked disposition of gas. Contributors to LAUF gas are (1) metering inaccuracy, (2) leaks and theft, and (3) other metering and billing issues. DTE Gas calculates a monthly gain (or loss) estimate for its three categories of LAUF gas (Transmission, Leaks, and Theft and Other) and has taken initiatives to control and reduce LAUF gas in each of these areas (5T 505–08).

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DTE Gas supports the utilization of 4.7 Bcf of Company Use (CU)75 gas in the projected

test period to operate its system and to support natural gas delivery requirements of its customers.

(5T 514; Exhibit A-15, Schedule E11).

DTE Gas recommends maintaining the Company’s current gas-in-kind (GIK)76 rates,

which were approved in Case No. U-18999, of: 1.00% applicable to the largest volume end-use

transportation (EUT) customers (rate schedule XXLT transport customers); (2), 1.00% for off-

system service rates; and (3) 1.41% for EUT service rates ST, LT, and XLT (the base EUT group).

(5T 424, 444, 449; Exhibit A-15, Schedule E14, line (18), columns (d), (e) and (f)). These rates

are appropriate because (1) the rates support the current off-system and end-use transportation

competitive business environment without additional risk to load and revenue loss, and (2) the

rates provide a contribution to the recovery of LAUF for all other rate classes including

Commission-approved special contracts (5T 424–25).

GCR/GCC sales rate customers should pay the equivalent of 1.95% GIK in base rates (5T

425; Exhibit A-15, Schedule E14, line 17, column (c)). In each of the special contracts not covered

by a tariff GIK percentage, the Company used the GIK percentage in the special contracts

previously approved by the Commission. This is the same methodology that was used in prior

DTE Gas rate cases (U-13898, U-15985, U-16999 Settlement, U-17999), and is consistent with

the Orders in Case Nos. U-18999 and U-20642 (5T 425).

75 CU volume is predominantly related to fuel used to operate and maintain DTE Gas’s transmission and storage facilities. CU volume includes, among other things, fuel use for compressors, gas processing at storage fields, and gate station heaters (5T 513). 76 GIK is gas (expressed as a percentage of throughput) that is supplied by customers to offset CU gas, and it also includes LAUF gas (5T 423).

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H. Depreciation and Amortization

DTE Gas projects $185.6 million for Depreciation and Amortization expense (Exhibit A-

13, Schedule C1, line 10, column (e)). The $44.0 million increase over the 2019 historical period

consists of $11 million relating to increased depreciation rates, plus $37 million from growth in

plant-in-services balances, partially offset by $4 million of reductions related to intangible plant

and regulatory liabilities (5T 374–75).

I. Property and Other Taxes

DTE Gas seeks to recover $89.7 million of property tax expense for the projected test

period (5T 1556; Exhibit A-13, Schedule C1, column (e), line 11).77

DTE Gas projects a $16.6 million Other Tax Expense for the projected test year (Exhibit

A-13, Schedule C1, column (e), line 12). This expense consists of payroll taxes ($13.1 million)

and Public Utility Assessment fees ($3.5 million) as shown on Exhibit A-13, Schedule C7 (5T

1557).

J. Income Tax Expenses

DTE Gas seeks to recover $19.2 million of total income tax expense for the projected test

year (Exhibit A-13, Schedule A-13, Schedule C1, lines 13 and 14). This consists of $9.4 million

of federal income tax (FIT) expense (5T 1557; Exhibit A-13, Schedule C1, line 14), $9.2 million

of Michigan Corporate Income Tax (MCIT) expense (5T 1557–59; Exhibit A-13, Schedule C9,

line 15), and of $0.6 million municipal income tax expense (5T 1560; Exhibit A-13, Schedule C10,

line 13).

VIII. OTHER ISSUES.

77 Property tax expense is the amount of property taxes deducted for book purposes. Property tax liability is the amount of property taxes payable to local governments. The Company expenses its property tax liability over a two-year period, with the liability of each year being expensed 39% the current year and 61% the subsequent year. This two-year allocation methodology has been used for many years, and is generally based on the fiscal years of the various taxing jurisdictions to which property taxes are paid (5T 1550, 1554, 1556).

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A. Revenue Decoupling Mechanism (RDM)

The Commission approved DTE Gas’s current RDM in the August 20, 2020 Order in Case

No. U-20642. The RDM is a “simple revenue tracker” that is limited by a revenue cap set at 150%

of the legislated Energy Waste Reduction (EWR) targets, resulting in a current RDM cap of 2.25%.

Large general service customers (General Service Rate GS-2) and End-User Transportation (EUT)

customers are excluded from the RDM calculation, so GS-2 and EUT customers are not subject to

RDM surcharges and do not receive RDM credits. The calculation of any revenue shortfall or

excess is determined on a rate schedule basis, and any resulting customer credit or surcharge is

also determined on a rate schedule basis (5T 1303–1304).

DTE Gas proposes to continue the currently approved RDM as a “simple revenue tracker”

that reconciles distribution revenue (excluding GCR revenues, surcharges, and customer charges),

with actual weather-normalized distribution revenue (excluding GCR revenues, surcharges, and

customer charges). With respect to the first annual reconciliation period, the qualifying revenue

shortfall, by rate schedule, should be capped at 1.125% of the rate case qualifying revenue. With

respect to the second and succeeding reconciliation periods, the qualifying revenue shortfall, by

rate schedule, should be capped at 2.25% of the rate case qualifying revenue (5T 1304–05).

The first reconciliation period would begin January 1, 2023, which is the first month

following the end of the projected test year. Reconciliations would be filed annually, beginning

three months after the end of the first reconciliation period, consistent with the current process.

The RDM would terminate when DTE Gas implements new rates by receiving a Commission order

approving new rates based on an updated test year (5T 1304–05). Staff supported the Company’s

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RDM proposal and recommended that the Commission approve it (5T 1844–45). Accordingly,

DTE Gas’s proposed RDM should be approved. 78

B. Infrastructure Recovery Mechanism (IRM)

The August 20, 2020 Order in Case No. U-20642 approved a settlement that allows DTE

Gas’s IRM to recover the predetermined incremental revenue requirement for infrastructure capital

investments in the Company’s (1) Main Renewal Program (MRP), (2) Meter Move Out Program

(MMO), (3) Meter Assembly Check Meter Move-out Program (MAC MMO), and (4) Pipeline

Integrity Program (PI) for each year in the 2021-2025 period. The IRM surcharge is calculated on

a calendar-year basis for each year of the five-year investment period. IRM capital spending is

reconciled annually, and if required, the IRM surcharges are adjusted in July of each year. The

current IRM surcharge will terminate with the last billing cycle in December 2021, in conjunction

78 Section 89(5) of 2008 PA 295, as amended by 2016 PA 342, MCL 460.1089(5) broadly authorizes RDMs, and directs the Commission to give deference to the utility’s proposal: “The commission shall authorize a natural gas provider that spends a minimum of 0.5% of total natural gas retail sales revenues, including natural gas commodity costs, in a year on commission-approved energy waste reduction programs to implement a symmetrical revenue decoupling true-up mechanism that adjusts for sales that are above or below the projected levels that were used to determine the revenue requirement authorized in the natural gas provider’s most recent rate case. In determining the symmetrical revenue decoupling true-up mechanism utilized for each provider, the commission shall give deference to the proposed mechanism submitted by the provider. The commission may approve an alternative mechanism if the commission determines that the alternative mechanism is reasonable and prudent. The commission shall authorize the natural gas provider to decouple rates regardless of whether the natural gas provider’s energy waste reduction programs are administered by the provider or an independent energy waste reduction program administrator under section 91.” The statute must be applied as written. Elozovic v Ford Motor Co, 472 Mich 408, 421-22, 425; 697 NW2d 851 (2005) (“The text must prevail. . . . The Legislature is held to what it said. It is not for us to rework the statute. Our duty is to interpret the statute as written”); Di Benedetto v West Shore Hosp, 461 Mich 394, 402; 605 NW2d 300 (2000) (“we presume that the Legislature intended the meaning it clearly expressed - no further judicial construction is required or permitted, and the statute must be enforced as written”); Hanson v Mecosta Co Road Comm’rs, 465 Mich 492, 504; 638 NW2d 326 (2002); Lorencz v Ford Motor Co, 439 Mich 370, 376; 483 NW2d 844 (1992): Ambs v Kalamazoo County Road Comm, 255 Mich App 637, 650; 662 NW2d 424 (2003) (“where the language of a statute is clear, it is not the role of the judiciary to second-guess a legislative policy choice; a court’s constitutional obligation is to interpret, not rewrite, the law”). The term “shall” denotes a mandatory duty imposed by the Legislature, and excludes the idea of administrative discretion. Macomb Co Rd Comm’n v Fisher, 170 Mich App 697, 700; 428 NW2d 744 (1988); Southfield Twp v Drainage Bd, 357 Mich 59, 76-77; 97 NW2d 281 (1959) (“the word ‘shall’ is mandatory and imperative and, when used in a command to a public official, it excludes the idea of discretion”).

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with the implementation of new rates pursuant to a Commission order in this case. All capital

invested as part of the IRM through December 2021 will be rolled into rate base, and recovery will

continue through base rates (5T 116–97, 1305–06).

DTE Gas proposes to continue the IRM with one adjustment, which is to combine the

financial aspects of the MRP and MMO programs into a single Gas Renewal Program (GRP). This

proposal is based on DTE Gas’s experience and will produce operational and financial efficiencies

and greater customer satisfaction. This change would align the program expenditure accounting

with the planning and performance of the GRP activities. This change would not result in any

changes in mileage or meter targets, or combined investment (5T 1306, 1333–38).79 Staff

supported the Company’s proposal (5T 1829).

DTE Gas proposes to recover the incremental revenue requirement associated with the

IRM (the GRP, MAC MMO, and PI programs) for the five-year period of 2022 through 2026

through new IRM surcharges that would be allocated by rate class on a fixed schedule, and adjusted

for any underspending (5T 1074–75, 1082, 1306–1307, 1334; Exhibit A-18, Schedule H3; see

section X. D. 1 regarding IRM rates). 80 DTE Gas intends to continue filing reconciliation cases

by March 31 of each year to reconcile the prior year’s investments. The IRM surcharge would

cease when new base rates are implemented in the Company’s next general rate case. At that time,

79 If the Commission approves DTE Gas’s proposal, no capital expenditure flexibility will be needed. If not, the Company will need the same flexibility it has required in past cases, which is up to 3.2 % of the total IRM capital expenditures, or $9.2 million ($287.2 million * 0.032). (5T 1365–66). 80 If the Company’s proposal to combine the MMO and MRP programs into the GRP is approved, any expenditures below those used to set the IRM surcharges, either in total or for any program, will result in an adjustment to the surcharge as calculated on Exhibit A-18, Schedule H6. There is no adjustment mechanism for DTE Gas overspending, so there will be no recovery of such costs until a subsequent rate case (5T 1307–08). If the Company’s GRP proposal is not approved, then expenditures above or below levels used to calculate the IRM surcharges will be treated as they have in all IRM programs since first approved in Case No. U-16999, with underspending resulting in a decrease to the IRM surcharge as calculated on Exhibit A-18, Schedule H5 (5T 1308–09).

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all capital invested as part of the IRM would be rolled into rate base, and recovery would continue

through base rates as part of a general rate case filing. Absent a rate case, the IRM surcharge would

continue at the December 2026 level, adjusted for any reductions from the last reconciliation filing

(5T 1307, 1365–66).

The IRM has been repeatedly reaffirmed, and it should be modified and continued as

indicated above. The discussion below further describes the IRM’s components. Exhibit A-12,

Schedule B5.5 Revised (DTE Gas Highest Cost Top 25 Capital projects), pages 27-40, provides

project level detail for IRM projects with expenditures large enough to fall within DTE Gas’s

highest cost projects (5T 1197). 81

1. Gas Renewal Program (GRP - combined MRP and MMO).

Ms. Tomina discussed the GRP (5T 1337–41) and supported DTE Gas’s proposed GRP

capital expenditures and scope through 2026 (5T 1341–42). She also identified several initiatives

that DTE Gas has deployed to gain efficiencies and reduce cost, which have resulted in

approximately $25 million in savings from 2018 to 2020 (5T 1342–43).

2. Meter Assembly Check Meter Move-out (MAC MMO) Program.

The MAC MMO program targets relocation of inside meters that have an overdue MAC

inspection. This program targets 8,000 inside meters annually, prioritized based on the date of the last

MAC inspection, the density of inside meters, the existing type of main, and coordination with GRP

project selection (5T 1343–44).

DTE Gas’s only proposed change is to increase MAC MMO capital expenditures by $4.5

million from U-20642 levels, to $21 million beginning January 1, 2021. This proposal is driven by

81 These projects include Powers – Iron River 8” and 10” ILI Expansion, Northeast Belt 24” ILI Expansion, Columbus 16” Storage Header Pipeline ILI Expansion, Great Lakes Petoskey 10” ILI Expansion, Great Lakes Gaylord 12” ILI Expansion, Loreed Ludington 16” Pipe Replacement, Coolidge Expansion Project, and Three Mile Road Renovation Project (5T 1197–98).

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two factors. First, increased costs of internal labor. DTE hired 33 Maintenance Fitter Apprentices to

support the program approved in Case No. U-18999. They are now trained and fully qualified,

resulting in $2.2 million of increased labor costs (5T 1344–45). The second factor is the new Cross

Bore Inspection requirement. When relocating inside meters outside, DTE Gas also renews and

upgrades the existing service line using a bore machine to install the new service underground. This

presents the possibility of cross-boring (inadvertently passing through) existing sewer lines and

laterals, which could lead to problems (a plumber working on a sewer line could puncture a gas line).

Post-construction sewer camera inspections will cost approximately $2.3 million annually (5T 1345–

46).

The MAC MMO program is making substantial progress in eliminating overdue MACs.

The MAC backlog was 106,445 on January 1, 2019. DTE Gas removed 42,072 expired MACs

from the backlog and 17,889 MACs expired in 2019, resulting in a 2019 year-end backlog of

82,272 (24,173 net decrease). For 2021, DTE Gas forecasts that it will remove 51,223 expired

MACs from the backlog and an additional 32,223 MACs will expire, resulting in a year-end

backlog of 40,000 (19,000 net decrease). (5T 973–74; Exhibit A-20, Schedule J2).

After the MAC backlog has been eliminated, the Company proposes to continue the MAC

MMO program (relocating 8,000 meters annually) to prevent new overdue MACs. DTE Gas

continues to project that it will have the vast majority of its inside meters moved out by 2028.

When meter move out is complete, both the MMO and MAC MMO programs will terminate (5T

1347–48; Exhibit A-12, Schedule B-6.3)

3. Pipeline Integrity (PI) Program.

DTE Gas’s PI program manages and ensures the integrity of the gas transmission system

as prescribed by Subpart O of the Michigan Gas Safety Standards (MGSS), Pipeline Integrity

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Management (5T 1348). Ms. Tomina explained and supported capital expenditures for four of the

PI program’s five 82 sub-programs: (1) In-Line-Inspection (ILI) Expansion (5T 1348, 1350–53);

(2) Remote Control Valves (5T 1348, 1353–55); (3) Maximum Allowable Operation Pressure

(MAOP) Records Review (5T 1348, 1355–58); and (4) Records Management System

Development (5T 1348, 1358–60).

Ms. Tomina also explained that DTE Gas is implementing a new probabilistic risk model

to enable risk comparisons and prioritize system investments in accordance with the December 9,

2016 Order in Case No. U-17999, p 53, and September 11, 2019 Michigan Statewide Energy

Assessment (SEA) final report, section 9.3.1.2. (5T 1360–61)

DTE Gas is not proposing any changes to the PI program included in the IRM. The

Commission authorized $11.1 million in annual PI IRM expenditures in Case No. U-18999,

beginning January 1, 2019. The Company has incurred, and will incur, additional expenditures,

but expects PI capital expenditures to return to normal levels after 2021, so the Company is not

requesting an increase for PI work in the proposed IRM. The Company has included all PI IRM

invested through December 31, 2020, plus an additional non-IRM $3.4 million of PI expenditures

through September 30, 2022 in base rates. The new IRM surcharge includes $11.1 million of PI

capital expenditures, consistent with the amount authorized in Case No. U-18999 (5T 1362–65).

Five PI projects have expenditures large enough to be included in DTE Gas’s highest cost

projects and are supported in detail in Exhibit A-12, Schedule B5.5 Revised (5T 1363). AG witness

Coppola proposed disallowances of $3,839,000 in 2020, and $786,000 in 2021 for the Northeast

Beltline ILI Expansion Project, claiming that there was a “cost overrun of . . . more than 400% of

82 Pipeline Integrity Assessments is an O&M expense that is discussed in section VII. D. 2 (5T 1348–50)

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the original project estimate, and that “something fundamentally wrong occurred with this project

that rises to the level of imprudent behavior” (5T 1665–66).

The construction of pig trap launchers and receivers to inspect more of DTE’s High

Consequence areas with ILI tools is important to ensure public safety and reliable service to

customers. The AG’s criticisms are overstated and based on the incorrect premise that the total

project cost is $5,767,022. Instead, the project began in 2018, and $5,767,022 is the total project

cost for 2020-2022. The original budget was $6,655,461, not $1,142,000 as calculated by Mr.

Coppola (5T 1369–70; Exhibit A-12, Schedule B5.5, p 29).

It is true that the project is over budget (by 67%, not 400%); however, the original project

cost estimate included the assumption that the final installed pig trap receiver product would be

fairly typical. Ann Arbor Township then made significant changes to the final site design through

design, construction, and permitting requirements with costs totaling $3,271,941. These Ann

Arbor Township specific requirements are not typical of any other jurisdiction where DTE Gas

has implemented the ILI expansion program. Although the money was not included in the original

estimate, the money was spent prudently to construct the pig receiver site in compliance with the

Township’s particular requirements (5T 1370–71).

Mr. Coppola’s suggestion that cost overruns should not occur if the Company “coordinates

closely with the municipality before starting construction of the project” (5T 1665) is misplaced

and unsupported in this context. DTE Gas did coordinate with the municipality, as outlined above,

which resulted in previously unanticipated requirements being identified before construction

began. DTE Gas did not miss an opportunity or do anything else that could be considered

imprudent. Instead, the project cost increased due to timely coordination with the municipality,

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and the municipality’s unique local requirements. Therefore, the entire project cost should be

approved (5T 1372).

C. Leak Backlog

Ordering paragraph L of the Commission’s June 3, 2010 Opinion and Order in Case No.

U-15985 relevantly stated:

“In each subsequent general rate case, Michigan Consolidated Gas Company shall file information addressing the capital expenditures associated with, and progress made in, reducing the backlog of leaks.”

In accordance with this directive, witness Mark Johnson testified that DTE Gas started

2019 with a leak backlog of 586 and remediated 7,122 leaks out of approximately 7,082 new

incoming leaks, resulting in a year-end balance of 546, with capital expenditures of $4.7 million.

For 2020, due to operational constraints from the COVID-19 pandemic, DTE Gas projects that it

will remediate 6,479 leaks out of approximately 8,333 new incoming leaks, resulting in a year-end

balance of 2,400, with capital expenditures of $4.0 million. For 2021, DTE Gas projects that it

will remediate 10,411 leaks out of approximately 9,475 new incoming leaks, resulting in a year-

end balance of 1,464, with capital expenditures of $8.2 million. Exhibit A-20, Schedule J1,

October 2020 Leak Remediation Plan, provides additional detail on incoming leaks and

remediation. Going forward, DTE Gas’s IRM will, in the long term, significantly reduce the

amount of poor performing main, including cast iron main, thus helping to reduce leak issues (5T

974–75).

D. Research and Development Cost Recovery

The Commission has approved past requests for R&D support. In Case No. U-14561, the

Commission found:

In summary, the Commission determines that an LDC may seek recovery of R&D expenses through a general rate case proceeding. For purposes of providing guidance to LDCs, the Commission is persuaded that a request for recovery of R&D

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expenses at up to $0.0174/Mcf is reasonable at this time. The Commission further notes that, as typical in a general rate case proceeding, the Commission will assess the reasonableness and prudence of the funding whenever the LDC seeks recovery for R&D expenses. An LDC shall be permitted to select the R&D organizations and projects that it deems worthy of support, and the R&D expenses shall be tracked in account 930.2 of the USOA. Finally, the Commission determines that any excess R&D amounts recovered in one year may be carried forward for spending on R&D projects during the following year. [December 21, 2006 Order in Case No. U-14651, p 5.] The Commission also previously approved DTE Gas’s request to recover $350,000 per

year for membership dues in the GTI Utilization Technology Development (GTI-UTD) program,

which focuses on efficient end-use technologies that are fueled by natural gas (September 13, 2018

Order in Case No. U-18999, p 96). DTE Gas makes two additional proposals in this case.

First, DTE Gas proposes to fund research and development (R&D) that focuses on critical

distribution system safety methods and pipeline integrity by again working with the GTI, which

will manage R&D through the national, industry-led consortia, Operations Technology

Development (GTI-OTD). The GTI-OTD program focuses on ensuring that natural gas is

delivered in the most safe, reliable, and environmentally-responsible manner (5T 967–68).

Membership in the GTI-OTD costs $600,000 per year, which is approximately $0.00443

per Mcf, or $0.50 per meter per year (5T 971–72; Exhibit A-13, Schedule C5.6, page 1, column

(j), line 14). This cost is justified because DTE Gas and its customers would benefit from the GTI-

OTD program’s body of knowledge in natural gas technologies and be able to leverage R&D

dollars with 25 other utility companies, as well as with federal and state funding mechanisms.

Customers would benefit from new technologies that would enhance safety, improve reliability

and integrity, develop new leak detection technologies while reducing methane emissions, and

support other areas critical to natural gas delivery (5T 969–70). DTE Gas would join the GTI-OTD

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promptly following an Order in this case authorizing the Company to recover its R&D expenses

(5T 973).

DTE Gas also proposes that it be allowed to recover natural gas technology R&D expenses

aimed at advancing technologies associated with decarbonization activities by becoming a member

of the Low Carbon Resource Initiative (LCRI). The LCRI is a joint effort between the Electric

Power Research Institute (EPRI) and the GTI aimed at accelerating the development and

demonstration of low and zero-carbon energy technologies for large-scale deployment across the

energy economy. DTE Gas and its customers would benefit primarily from the Company’s ability

to leverage its commitment through this industry-wide collaborative, as well as through support

from governmental, non-governmental, and academic entities to inform the Company’s

decarbonization strategy with economically viable and sustainable options (5T 464–65, 475).

DTE Gas requests to recover $300,000 per year for the years it participates in the LCRI,

beginning in 2021 when it joined the LCRI. 83 This amount, combined with $350,000 of GTI-UTD

expenses approved in Case No. U-18999, and $600,000 of Gas GTI-OTD expenses discussed

above, produces a total DTE Gas requested R&D recovery of $1,250,000 which is significantly

less than the $0.0174/Mcf approved in Case No. U-14651. DTE Gas also properly (1) makes its

requests to recover R&D costs in this general rate case proceeding, (2) selected reputable R&D

organizations focused on natural gas decarbonization technologies; and (3) would track its R&D

expenses in Account 930.2 of the USOA (5T 468, 972–73).

Staff recommended a $300,00 disallowance for R&D expenses associated with the LCRI,

suggesting it would benefit shareholders, but it is not clear how customers would benefit (5T 2026–

83 This is the fixed fee for a gas utility included with a combination utility. The annual commitment is $850,000 per year for DTE Energy as a whole (DTE Electric and DTE Gas). DTE Electric is currently evaluating joining the collaborative (5T 467). .

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27). The Company disagrees. In addition to the discussion above, Mr. Decker explained that over

the past six months, LCRI’s concrete goals and objectives have evolved with the assistance of 46

global partners, including over 25 utilities. LCRI’s core focus aimed at three critical areas

including: (1) reviewing multiple options and solutions to establish viable low-carbon pathways,

(2) advancing those technologies for hard-to-decarbonize areas of the energy economy, and (3)

developing affordable, reliable, and resilient integrated energy systems for the future (5T 476;

Exhibit A-23, Schedule Y1) will provide the Company with extensive technical knowledge to use

when deploying advanced decarbonization technologies over the coming years.

Joining the LCRI will specifically benefit customers by greatly assisting the Company’s

decarbonization efforts for customers in a cost-effective manner. The cost of production and

implementation for advanced technologies must be reduced to minimize the impact on customer

rates, and to ensure appropriate adoption for a future carbon-neutral environment (as reflected, for

example, by the Governor’s Executive Directive 2020-10, moving Michigan toward full carbon

neutrality by 2050). These advanced technologies such as Hydrogen present a significant cost

premium today to other energy alternatives such as fossil gas. LCRI research will help to advance

technologies to be more affordable for customers in the future. Cost reductions in technologies

(driven by LCRI efforts) will lead to substantial savings in future long-term costs to produce and

implement the technologies across the Company’s customer base. Thus, Staff’s concern has been

addressed, and there is no sound basis for any disallowance. Customers will benefit from LCRI

membership because the LCRI will drive down technology-related costs, leading to lower costs

for customers in the future (5T 476–78).

For all the above reasons, DTE Gas’s R&D proposals should be approved.

E. Demand Response (DR)

Paragraph 6 of the U-20642 settlement provides:

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The Parties agree that DTE Gas will launch a Demand Response (DR) Pilot in the winter of 2021. In connection with this Pilot, DTE Gas will hold a conference with interested parties to share existing proposals, discuss refinement of the proposals, and agree on a process to effectuate the DR Pilot. DTE Gas will also defer costs associated with pilot implementation up to $4.0 million over the bridge and test periods and through the end of the pilot program period as a regulatory asset subject to a reasonableness and prudency review for recovery in a future proceeding. Accordingly, DTE Gas has not included DR costs in its revenue requirement in this case.

On November 16, 2020, DTE Gas held a DR collaborative where it provided an overview of the

program it plans to launch and requested feedback from the participants. DTE Gas planned to

begin enrollment in its pilot in the second quarter of 2021 (5T 1309).

F. Advanced Metering Infrastructure (AMI) Benefits Reporting

DTE Gas and DTE Electric are nearing the end of their process of installing Advanced

Metering Infrastructure (AMI) meters (also known as “smart meters”) to provide various benefits

as compared to obsolete electromechanical (or “analog”) meters. The Commission has repeatedly

approved AMI funding and rejected AMI challenges. See, for example, December 11, 2015 Order

in Case No. U-17767, p 34 (finding that it has “thoroughly vetted the underlying benefit/cost

analyses, and the AMI program itself, and will not revisit those issues”), aff’d In re Application of

DTE Electric Company to Increase Rates, unpublished opinion per curiam of the Court of Appeals,

issued October 25, 2018 (Docket No. 338378), lv den 931 NW2d 334 (2019), recon den 935 NW2d

346 (November 26, 2019).84

The Commission previously directed: “In its next general rate case, DTE Gas Company

shall provide an annualized and monetized advanced metering infrastructure benefit projection”

84 See for further example, In re Application of DTE Electric Company to Increase Rates, unpublished opinion per curiam of the Court of Appeals, issued April 2, 2020 (Docket No. 344811; affirming Case No. U-18255), lv den March 30, 2021); In re Application of DTE Electric Company to Increase Rates, unpublished opinion per curiam of the Court of Appeals, issued February 25, 2021 (Docket Nos. 349924 and 350008; affirming Case No. U-20162).

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(September 13, 2019 Order in Case No. U-18999, p 126, ordering paragraph D). Paragraph 15.f of

the U-20642 settlement further provides:

AMI benefits: Update the information to provide actual historical realized AMI benefits as an exhibit in the Company’s next rate case, explain where the benefits have occurred, provide forecasted AMI benefits for past and future years, and quantify calculation methods (consistent with the Commission’s May 8, 2020 order in MPSC Case No. U-20561).

Accordingly, Company witness Mark Johnson sponsored Exhibit A-21, Schedule K1

(complies with the U-18999 Order by calculating DTE Gas AMI financial benefits, by year

through 2025, with $12 million of benefits for the 2022 projected test year) and Exhibit A-21,

Schedule K2 (complies with the U-20642 settlement by providing detailed historical realized DTE

Gas AMI financial benefits and projected benefits). (5T 978–79). Mr. Johnson also recounted the

major benefits of AMI to customers (5T 977–78) and discussed the realized benefits as displayed

in Exhibit A-21, Schedule K2 (5T 979–82).

G. Accounting Requests

DTE Gas requests confirmation that capitalizable implementation costs related to cloud

computing should continue to be recorded in Plant in Service. Ms. Uzenski explained that the

FASB issued Accounting Standards Update (ASU) 2018-15, Accounting for Implementation

Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. The ASU is effective

January 1, 2020 and is consistent with the Company’s existing policy for cloud service

implementation costs in terms of capital or expense treatment; however, the ASU requires

classification of any deferred costs in Other Assets (like prepayments) instead of Plant in Service.

Since the implementation costs at issue must be classified in Other Assets for SEC reporting, the

Company requests the Commission’s approval to record the deferred costs in Property Plant and

Equipment (PP&E) and recognize the expense as amortization for MPSC reporting, consistent

with current practice (5T 378–79).

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DTE Gas also proposes a Low-Income Mechanism to record a regulatory asset or liability

for the difference between actual LIA and RIA credits issued and the amount in rates. DTE Gas

requests approval to use account 182.3 (Other Regulatory Assets) and account 254 (Other

Regulatory Credits) to record the balances resulting from this proposed true-up mechanism (5T

360–61). As discussed in section X. D. 2 , DTE Gas’s proposal should be approved because it will

allow the Company to serve more customers who qualify for energy assistance. This proposal also

aligns with the Commission’s regulatory asset treatment for the enrollment of additional DTE

Electric customers (May 8, 2020 Order in Case No. U-20561, p 239). (5T 1013–15, 1032, 1310).

DTE Gas requests continued deferral of pension and OPEB expense. The Commission

approved the deferral of pension expense (U-20642 settlement, provision 8) in addition to the

Company’s previously-approved practice of deferring negative OPEB expense to a regulatory

liability (December 9, 2016 Order in Case No. U-17999, p 68). While the forecasted pension

expense is a negative $5.4 million for the projected period, the Company proposes to continue the

deferral of its actual pension expense (5T 371–72, 379; Exhibit A-13, Schedule C5.10, column

(d)). DTE Gas similarly proposes to continue the existing deferral of its actual OPEB expense,

which is currently projected to be negative $13.3 million expense (5T 371–72, 379; Exhibit A-13,

Schedule C5.11, line 20). No party has opposed the Company’s requests.

In its original filing, DTE Gas proposed an Uncollectible Expense True-up Mechanism

(UETM) to address the challenges in forecasting uncollectible expense during the pandemic. DTE

Gas withdraws this proposal and is no longer seeking a UETM in this filing.

DTE Gas requests a Shared Asset Deferral Mechanism (SADM) that would protect both

the Company and its customers where DTE Gas’s rates are based, in part, on the costs of shared

IT projects that might not be yet be approved in a DTE Electric rate case or otherwise implemented

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at DTE Electric due to the delay in timing of when DTE Electric files its rate case as compared

with DTE Gas.85 The SADM would operate like the Program Evaluation and Review Committee

(PERC) mechanism that the Commission approved for DTE Electric (January 31, 2017 Order in

Case No. U-18014, p 74). The proposed mechanism would defer any amounts charged by DTE

Electric above or below the base Shared Asset Charge used to calculate the revenue requirement

in this case. In a future case, DTE Gas would amortize the deferred amount, plus carrying charges,

into O&M over a five-year period (5T 370, 1295).

To implement the SADM, DTE Gas requests to use account 182.3 (Other Regulatory

Assets) to defer expense incurred above the base, and account 254 (Other Regulatory Liabilities)

for any difference between actual expense in account 931 (Rents) and the base, if actual expenses

are lower than the base. The impact to O&M would be recorded to account 931 (Rents). For

example, if the Shared asset cost is lower than the amount in base rates, then there would be a debit

to Rent Expense and a credit to Other Regulatory Liabilities (5T 371, 379).

Staff recommended that the Commission reject the proposed SADM, suggesting that it is

unnecessary because Staff is not proposing a synchronization adjustment (5T 1996). To the

contrary, the lack of synchronization is why DTE Gas does need a SADM. Otherwise, there is a

subsidy because either (1) one utility’s customers are subsidizing the other utility’s customers, or

(2) DTE shareholders are subsidizing the difference (5T 1318). This subsidization has occurred in

DTE Gas’s and DTE Electric’s most recent rate cases. It is improper to penalize either DTE Gas

customers or shareholders for the use of shared assets, particularly since DTE Gas and DTE

85 Basically, DTE Gas pays O&M charges to use a portion of DTE Electric’s capital projects. The IT capital projects underlying the Shared Asset charge are discussed in section V. B. 3. The O&M effects are further discussed in section VII. D. 3.

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Electric use shared assets to provide affordable service to customers, who benefit from the

efficiency of this process (5T 1319–20).86

Mr. Telang further explained that Staff provided three criteria for regulatory asset

consideration: (1) materiality, (2) uncertainty of amounts, and (3) lack of control by the company

(Exhibit A-36, Schedule Z1, Staff response to DTE Gas discovery). DTE Gas’s Shared Asset

charge meets all three criteria: (1) Staff recommended significant adjustments to DTE Gas’s

forecasted Shared asset expense in both Case No. U-20642 and this case, (2) DTE Gas is not certain

of the amounts it will be charged or what will be included in DTE Electric’s rates, and (3) DTE

Gas has only limited control over Shared asset projects that get approved at DTE Electric (5T

1321–22)

Customers would benefit from the proposed SADM because the ability to defer costs for

potential later recovery could allow DTE Gas to delay the need for new rates. Customers would

also be protected because if the Shared Asset charge is less than the amount approved in rates, then

these amounts would be returned to customers. Either way, the proposed mechanism would

provide more equitable treatment of costs that the Commission ultimately deems reasonable and

prudent (5T 1298, 1322).

Finally, DTE Gas requests to continue the authorized accounting for the IRM (5T 376–77,

379; Paragraph 13 of the Case No. U-20642 settlement relevantly states: “The parties agree that

the IRM structure that was approved by the Commission in Case No. U-18999 will continue”).

86 In addition to this DTE Gas case, DTE Electric might file a general rate case before the end of this year, involving the same issues outlined above. Therefore, at a minimum, DTE Gas should be allowed to record a regulatory asset (beginning in the month DTE Electric implements new rates, and continuing until DTE Gas implements new rates) for the difference between the revenue credit used to calculate DTE Electric’s new rates, and the Shared Asset charge currently reflected in DTE Gas’s rates (5T 1321).

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IX. REVENUE DEFICIENCY AND REQUESTED RATE RELIEF.

DTE Gas initially requested approximately $195 million of rate relief for the projected test

year (5T 1385, 1394–95; Exhibit A-11, Schedule A1). Attachments A and B summarize DTE

Gas’s computation of its updated revenue deficiency, starting with the Company’s filed position

of $195 million and adjusted by $18 million adjustments proposed by Staff and Intervenors, as

discussed throughout this Brief. DTE Gas requests that the Commission approve

approximately $177 million in rate relief.

X. RATE DESIGN AND TARIFF REVISIONS.

A. Allocation of Revenue Deficiency

Company witness Mr. Maroun supported DTE Gas’s cost of service study (COSS) for the

projected test year (5T 1061; Exhibit A-16, Schedule F1.1). The Company’s rate design reflects

the Commission’s long-standing approval of two demand/capacity allocation methods, which are

the Average and Peak (A&P) method for functionalized transportation costs and non-customer

related distribution costs; and a blended method (50% cost allocation on the Peak method and 50%

cost allocation on the percentage of storage capacity) for storage costs (5T 1065–67).

MPLP witness Phillips “recommend[ed] that a peak day demand allocation methodology

be used in place of DTE’s proposed demand and throughput . . . As an alternative solution, the

‘75/25’ method is far superior, stable and more equitable form of cost allocation than DTE’s

current A&P method” (4T 67). Mr. Maroun disagreed, noting that the Commission has consistently

approved the use of the A&P method since December 1988 in DTE Gas’s general rate case U-

8812 (5T 1097). Staff also “continues to support the A&P method as the most appropriate allocator

of distribution costs” (5T 2084).

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For the projected test year COSS, Mr. Maroun used the January design peak day

requirement of 2.59 Bcf from DTE Gas’s GCR Plan Case No. U-20816. The design peak day

methodology remains the most appropriate method for cost-of-service allocation (5T 516–17,

1067–68). In further response to Detroit Thermal witness Pucak’s suggestion that DTE Gas should

consider alternative means to calculate the XXLT class’s peak day demand (5T 1622), Mr. Maroun

explained that it would be incorrect to use XXLT demand from a different time period such as the

summer months because the design peak day is defined as the consumption expected on a day with

an average temperature of minus 6 degrees Fahrenheit (5T 1095–96).

The Company’s revenue requirement is allocated to its customer classes using twenty-four

allocation factors that reflect each class’s share of cost responsibility, and that are generally the

result of longstanding practice (5T 1063; Exhibit A-16, Schedule F1.2). Since the transportation

rate discount for AK Steel and Ford Rouge is being eliminated (as discussed in section VII. A. 5),

the discount allocator has also been eliminated (5T 1068). Also, since the special contract with

Dearborn Industrial Group, LLC (DIG) expires prior to the beginning of the projected test year,

the contract is no longer accounted for as a separate class; instead, Exhibits A-16, Schedules F1.1

and F1.2 have been modified to include DIG with the XXLT class. This modification does not

shift any costs to other rate classes (5T 1076). Merchant fees are assigned directly to rate classes

consistent with the methodology that the Company used in Case No. U-20642. The allocation

methods used in the proposed COSS are the same as those approved in Case No. U-20642 (5T

1069).

Exhibit A-16, Schedule F3 calculates current and proposed revenues by rate schedule.

Exhibit A-16, Schedule F4 compares typical bills for each gas sales rate under DTE Gas’s current

and proposed rates (5T 1071). Exhibit A-16, Schedule F6 identifies projected gas transportation

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system costs used in developing DTE Gas’s proposed rate for off-system or third-party shippers

who transport gas on DTE Gas’ gas transportation system (5T 1073). Exhibit A-18, Schedule H4

calculates the proposed monthly per-meter charge for each rate schedule for the years 2022 through

2026 relating to DTE Gas’s IRM (5T 1074–75).

MPLP witness Phillips asserted that DTE Gas “erroneously allocates a category of cost

identified as distribution-other to Rate XXLT. Rate XXLT is a transmission/high pressure rate and

this allocation is inappropriate” (5T 67). To the contrary, the “distribution plant-other” costs

(shown in Exhibit A-16, Schedule F1.1 page 3, line 4) contain facility-related costs that are used

by all distribution-served customers. A portion of XXLT volumes are taken at the distribution

level, so it is appropriate to allocate these costs to the XXLT class. The Commission has also

approved the allocation of these costs to the XXLT class in all recent DTE Gas cases since at least

Case No. U-15985 (5T 1096–97).

ABATE witness Pollock proposed that the Commission require the Company to develop

peak day demands by service level in its next general rate case (5T 275). Mr. Maroun disagreed

because the proposal is burdensome and unnecessary. The Company does not have the necessary

information readily available to develop peak day demands by service level, and it would take a

substantial amount of time and analysis to prepare such information. The development of peak day

demands by service level is also unnecessary to calculate EUT rates under the long-standing

volumetric EUT rate structure (5T 1091).

Witness Pucak proposed capping the rate design adjustment credit to the XXLT class at $5

million (5T 1621). Mr. Maroun disagreed because rate design adjustments are a necessary tool to

achieve the economic breakevens between EUT classes. An artificial cap would constrain the

calculation and prevent the Company from achieving breakevens. Changes to the target breakeven

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points could then make it economical for EUT customers to move between customer classes. The

resulting customer migration would cause the Company unjust and unreasonable financial harm

by preventing collection of the full revenue requirement for each EUT class (5T 1093). Mr. Decker

further explained why it is important for the Company to retain its break-even points between

various rates (5T 459–60).

Mr. Pucak also recommended amending the Weighted Customers allocator (#5) so that the

weighted average installed meter cost for EUT customers reflects the costs shown in a model

provided by DTE Gas (5T 1621). Mr. Maroun disagreed because the recommendation ignores that

some EUT customers have multiple meters. He explained that the referenced model shows many

more EUT meters than EUT customers. It was necessary for Mr. Maroun to calculate the

installation cost per EUT meter. Therefore, the allocator should continue to be calculated using the

Company’s methodology (5T 1094).

Mr. Maroun further explained that the Company should continue to use the same weighting

factor in Weighted Customer allocator #5 for both customer-related expenses and plant. The

Commission has approved the Weighted Customer allocation methodology in all recent DTE Gas

rate cases since at least Case No. U-15985. This allocator is appropriate because it recognizes

differences in the level of service provided to certain rate classes (5T 1094).

Mr. Pucak suggested that XLT and XXLT customers are allocated an excessive amount of

customer service and meter reading expenses using the existing weighting factors in allocator #5

(5T 1615). To the contrary, in total XLT and XXLT customers are only allocated $70,000 out of

a total of $54.6 million (0.0127%) for meter reading and customer records expense (Exhibit A-16,

Schedule F1.1, page 2, lines 7-8). It would be excessive and unnecessary to require the calculation

of a separate weighting factor for a relatively small amount (5T 1095).

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Mr. Pucak recommended removing any cost allocation to EUT customers related to the

Low-Income Assistance Pilot program (5T 1622). Mr. Maroun disagreed because the Commission

has consistently approved the COSS+COG allocator (#20) in DTE Gas rate cases to allocate Low-

Income Assistance Pilot program costs to all classes since at least Case No. U-17999 (5T 1095).

Staff proposed allocating uncollectible expense using allocation #20 (Cost of service plus

Cost of Gas) instead of allocator #21 (Net Write-Offs). (5T 2081, 2099). Mr. Maroun disagreed,

noting that the Commission previously agreed with the Company that using Net Write-Offs is the

proper method to allocate uncollectibles. The Commission explained in part that: “It is appropriate

and consistent with regulatory ratemaking principles to directly assign such costs to the class that

caused the costs” (December 9, 2016 Order in Case No. U-17999, p 57, quoting June 15, 2015

Order in Case No. U-17689, p 27). Staff has presented no evidence that its proposed allocation

method is correlated to causation of uncollectible expenses. Therefore, the Commission should

continue to use the current methodology because it reflects cost causation better than Staff’s

proposal (5T 1098).

B. High-pressure and low-pressure distribution main plant, and volume-by-type studies

Paragraph 18 of the U-20642 settlement states: “For the next rate case, DTE Gas will

perform a study on splitting out high-pressure and low-pressure distribution system costs. In

addition, DTE Gas will review how direct-served transmission volumes are determined and

classified to all rate schedules.” Accordingly, DTE Gas submitted the following supplemental

studies:

1. High-Low Mains Study #1; determine the percentage split of distribution-main plant

(account 376) through year-end 2019 between high-pressure (100 psig or greater) and low-

pressure (less than 100 psig); and

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2. Volume by Type Study #2; Calculate the percentage split of 2019 volumes by delivery type

between low-pressure, high-pressure, and transmission for every rate class.

Company witness Mr. Maroun summarized the results of the studies and discussed how

the studies were prepared. He also noted that two minor data issues that were discovered in

preparing study 1, but the cost effect was so minor that no revisions were made (5T 1077–80).

Staff proposed that the Commission require DTE Gas to provide Alternative COS Study 2

in addition to the Company’s main COSS in future rate cases (5T 2102). Mr. Maroun disagreed

because performing this study requires considerable time and resources, and there has been no

determination that this new allocation method would better align cost causation with cost

allocation for all rate classes (5T 1099).

ABATE witness Pollock proposed to classify 40% of the costs of low-pressure distribution

mains as customer-related (5T 285). If the Commission approves that proposal, then the

Commission should also include those costs in the monthly service charge because that charge is

designed to recover the customer-related direct costs associated with connecting customers to the

gas system (5T 1091).

C. Tariff Changes for All Customers

DTE Gas proposes the following changes to its tariff pages under Section C of its rate book

(5T 462, 1080–81; Exhibit A-16, Schedule F5 (summary of proposed tariff changes); Exhibit A-

16, Schedule F5.1 (revised tariff pages)):

(1) Section C1.9A(3); Revise the age of an eligible senior citizen customer to 65 under

(Alternative Shut Off Protection Program for Low-Income and Senior Citizen Customers), to align

with the Customer standards and billing Practices for Electric and Natural Gas Service (5T 1080).

141

(2) Section C8.9B(1) and (6); Revise the Customer Attachment Program (CAP)

Carrying Cost Rate and Discount Rate to reflect revised percentages based on the Commission’s

final order in this case (5T 1080–81).

D. Tariff Changes for Sales Rate Schedules

DTE Gas proposes the following changes under Section D of its rate book, in addition to

reflecting the Company’s proposed monthly customer charges and distribution charges for each

rate schedule.

1. Revised IRM.

As discussed in Section VIII. B. above, the revised IRM will allow DTE Gas to recover its

incremental revenue requirement associated with the GRP (combined MRP and MMO), MAC

MMO, and PI programs for the five-year period of 2022 through 2026, absent another rate case.

The revenue requirement for all three IRM components (reflected on Exhibit A-18, Schedules H1,

H2 and H3) is allocated according to the methodology approved in Case No. U-20642. Exhibit A-

18, Schedule H4, page 6 summarizes the proposed monthly IRM charges by rate schedule by year

(5T 1074–75, 1390–93).

Beginning January 1, 2022, a monthly charge will be implemented for each rate schedule,

as shown on proposed Sheet No. D-2.01, Section D2.2 of the Company’s rate book, and subject to

possible adjustments based on a continuation of the current annual reconciliation process. If the

annual reconciliation determines that an adjustment to rates is necessary, then a revised Sheet No.

D-2.01 will be filed reflecting the adjustment (5T 1082, 1306–1307). Exhibit A-18, Schedule H6

calculates a $0.0105 decrease in customers’ monthly charges for every $1 million of IRM capital

underspending, consistent with the methodology approved in Case No. U-17999 and subsequent

cases (5T 1393).

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2. Low-Income Energy Assistance.

DTE Gas’s energy assistance programs are designed to gradually reduce customer arrears

to the Company, while encouraging and supporting good payment habits, reducing consumption,

and maintaining active service. These programs are more important than ever during the COVID-

19 pandemic,87 with the continuing long-term goal of helping low-income customers achieve self-

sufficiency (5T 1010–11).

Paragraph 3 of the U-20642 settlement authorized 33,000 customers for the Low-Income

Self-Sufficiency Program (LSP), which provides a $30.00 per month credit for qualifying low-

income customers; and 70,000 customers for the Residential Income Assistance (RIA) program,

which offers low-income gas customers a monthly bill credit equal to the monthly customer

charge, currently $12.25 per month (5T 1011–12).

DTE Gas proposes to increase LIA participation from 33,000 customers to 45,000

customers due to the increased enrollment of LSP and Non-LSP customers. Additionally, there is

opportunity for over 60,000 RIA customers with active arrears to benefit from greater energy

assistance. The proposed increase is also appropriate because the LIA credit continues to be

important because many of DTE Gas’s low-income customers continue to struggle to pay their

utility bills, and the credit provides meaningful assistance to help make utility bills more affordable

for these customers (5T 1013–14, 1310).

Staff appropriately recognized that linking LSP with LIA gives high-risk customers a better

chance at self-sufficiency, but disagreed with the Company’s proposal, raising concerns about data

reporting, and inaccurately characterizing the proposal as a new approach (5T 2051–52, 2054).

Ms. Johnson addressed Staff’s concerns about reporting methodologies (5T 1026–27; Exhibit A-

87 The Company also established the Keys of Service Excellence (Safe, Caring, Dependable, and Efficient) as guiding principles, and initiated several low-income programs in response to the COVID-19 pandemic (5T 1004–10).

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32, Schedule V1), and explained that the Company has previously maintained that pairing the LIA

credit with the LSP program is the most effective way to assist the most vulnerable customers. See

also the September 13, 2018 Order in Case No. U-18999, pp 108-109. Thus, as customers enroll

in LSP they are also enrolled in LIA. The current 2021-2022 LSP forecast calls for 3,000 new LSP

customers. There are also 4,000 current LSP customers who do not receive the LIA credit. Adding

these groups to the current enrollment of 38,000 yields 45,000 LIA customers. Therefore, the

Company’s proposal should be approved (5T 1028–29).

DTE Gas also proposes a deferral that will allow the Company to serve more customers

who qualify for energy assistance. As discussed in section VIII. G (Accounting Requests), DTE

Gas proposes a Low-Income Mechanism to account for any LIA and RIA credits provided to

customers above or below the total LIA/RIA funding amounts approved in this case as a regulatory

asset or liability to be recognized in a subsequent period. This proposal also aligns with the

Commission’s regulatory asset treatment for the enrollment of additional DTE Electric customers

(May 8, 2020 Order in Case No. U-20561, p 239). The proposed Low-Income Mechanism also

addresses any concerns Staff might have about the Company over-projecting customer counts (5T

360–61, 1013–15, 1032, 1310).

DTE Gas proposes the following rate book changes relating to low-income energy

assistance:

1. Combine and eliminate duplicative language by adding a “Low Income Energy

Assistance Programs” section containing all common program features and prefacing

the individual program details;

2. Increase maximum income qualifications to 200% of Federal Poverty Level (FPL) from

150% of FPL. This would allow alignment of customers who participate in MI Bridge,

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which includes customers up to 200% of FPL. Staff opposed this proposal because

MCL 460.11(8) defines “eligible low-income customer” as having household income

that does not exceed 150% of the FPL, and to wait until the effectiveness of the pilot

approved in Case No. U-20929 has been proven (5T 2052–53). Ms. Johnson explained

that the statutory limitation only applies for state or federal funding. The Company

defines low income as customers at or below 200% FPL, and the Staff and Commission

have accepted this position for low-income programs not utilizing state or federal

assistance. Also, the U-20929 Payment Stability Pilot (PSP) is limited to 2,000

customers, while there are currently 60,000 gas customers identified in the Company’s

system between 151% and 200% FPL who could benefit from receiving the RIA or

LIA credit. (5T 1030). Staff also “recognizes that individuals at 150%-200% FPL may

need some level of assistance” (5T 2053). Therefore, the Company’s proposal should

be approved.

3. Clarify that the credits will be distributed at the Company’s discretion;

4. Add low-income self-attestation for LIA;

5. Update the RIA to $14.70 per month, which is the amount that DTE Gas proposes as

the monthly customer charge;

6. Increase the number of LIA customers from 33,000 to 45,000, as discussed above;

7. Clarify that assistance credits are applied in the same manner as the customer charge;

and

8. Remove requirement of RIA enrollment to qualify for LIA enrollment (5T 1015–16,

1082–83).

E. Tariff Changes for EUT Service

DTE Gas proposes the following changes under Sections E1 through E14 of its rate book.

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(1) Reflect the Company’s proposed Monthly Service Charges and Transportation

Charges for each EUT rate schedule in Section E14 (5T 463, 1083).

(2) Retain the 1.41% GIK rate applicable to EUT service rates ST, LT, and XLT, and

the 1.00% GIK rate applicable to rate schedule XXLT (5T 424, 444, 449, 463, 1084).

ABATE witness Pollock suggested that the four existing EUT rate classes should be

replaced with three rates based only on the level of service that the customer takes from the

Company, which are: (1) direct-served transmission, (2) high-pressure distribution, and (3) low-

pressure distribution (5T 264, 270–71, 285). The Company disagrees. Mr. Decker outlined some

obvious high-level issues with the proposal, including: (1) most customers only have one level of

service available in their vicinity so they would have only one EUT rate choice regardless of

volume, as such costs for a small ST customer burning 20,000 Mcf/year on a high-pressure

distribution system would go up more than 145% with ABATE’s proposed High Pressure rate

compared to the Company’s proposed ST rates in this case, (2) changing the rate structure would

be disruptive and punitive to customers who made siting decisions based on the current structure,

(3) over 40 EUT customers currently take more than one level of service under the same account,

(4) some EUT customers taking service directly from the transmission system use other parts of

the system, and (5) the proposal would significantly impact many customers that are not

represented in this case (5T 484–85).

Mr. Pollock further proposed that DTE Gas should be required to develop the information

to transform the current commodity-based EUT delivery charges into demand-based EUT charges

by service level in its next rate case (5T 285). DTE Gas disagrees because the effort to perform

such a task would be unduly burdensome. Significant investments in both time and EUT metering

146

upgrades across the Company’s service territory would likely be required to accurately provide

data to comply with the proposal (5T 486).

Detroit Thermal witness Pucak proposed to reduce the GIK rate to EUT customers to

0.54% (5T 1617). The Company disagrees because the existing GIK rates support the current off-

system and EUT competitive business environment without additional risk to load and revenue

loss. Other interstate pipelines also charge similar GIK rates, so the Company is competitive with

these other options (5T 424, 486).

Mr. Pucak further suggested that EUT customers should not be allocated any capital costs

associated with new customer attachments (5T 1621). The Company disagrees for two reasons.

First, new customer attachment capital includes capital to attach new EUT customers. Attaching

these new EUT customers adds gas to the overall EUT volumes, thereby spreading costs

attributable to EUT customers across higher volumes. Second, adding new residential and

commercial customers has kept overall gas demand from these customers flat despite declining

usage per customer, and likely prevented EUT customers from having to carry higher costs.

Therefore, EUT customers benefit from adding customers (5T 486–87).

Energy Michigan witness Wilken proposed that the EWR charge should be shown as a

separate line item on customers’ bills (4T 133–034. The Company did and would still do so but

cannot due to MCL 460.1089(2) (“Charges under this subsection [regarding EWR] may be

itemized on utility bills but shall not be itemized on or after January 1, 2021”). (5T 487–88).

Mr. Wilken further suggested that DTE Gas’s meter reading practices are inconsistent and

unpredictable, and made recommendations for EUT customers to avoid penalties (4T 137–45).

Mr. Decker responded by outlining billing considerations that the Company follows, and practices

for gas brokers to avoid a penalty in potentially challenging months. Other than these steps that

147

the Company is already taking, the Company does not agree with Mr. Wilkin’s recommendations

regarding meter reading (5T 488–89).

Mr. Wilken agreed that the concept of Operational Flow Orders invoking OFODQ Min

obligations is “a reasonable strategy for responding to real physical challenges that may arise on

the utility’s system” (4T 135).88 He suggested two scenarios, however, where if the Company

called an Operational Flow Order and invoked OFODO, it could cause issues with some

customers. He also proposed changing DTE Gas’s tariff language to deal with these two scenarios

(4T 135–37).

Mr. Decker responded by explaining that Mr. Wilken’s points are purely hypothetical. The

Company has never called an Operational Flow Order and invoked an OFODQ Min. Also, for Mr.

Wilken’s first scenario (involving seasonal customers), known highly-seasonal customers (such as

an asphalt plant with no winter use) are set up in the Company’s nomination system with Seasonal

MDQ’s, so in the hypothetical situation where the Company invokes OFODO Min in January, that

customer (with a zero MDQ at that time) would not be required to flow any gas and would not be

negatively affected. The Company understands that there could be a potential negative impact to

a customer in the second scenario (customer already voluntarily curtailing gas-burning operations

due to market pricing), but the reality is that the Operational Flow Order is the last step prior to

level 3 Curtailment, so action may be necessary to save the system. Therefore, Energy Michigan’s

proposed changes to tariff language should be rejected as unnecessary and inappropriate (5T 491–

92).

88 There are three levels of severe gas operations. Level 2 is called Operational Flow Order, which may occur when the Company is experiencing significant constrained operating conditions or an emergency. Depending on the circumstances, the Company could invoke a OFODQ Min, which would require customers to nominate and deliver a minimum daily quantity of gas supply (5T 490).

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F. Tariff Changes for Off-System Storage and Transportation Service

DTE Gas proposes to increase the TOS-F (Section E25) and TOS-I (Section E26) not-to-

exceed rate from $0.3537 per MMBTU to $0.5278 per MMBtu (5T 483, 1084; Exhibit A-16,

Schedule F6).

G. Proposed Monthly Customer Charges and Rate Schedule Economic Break-Even Points

DTE Gas proposes a $14.40 monthly customer charge for residential Rate A. To maintain

historical consistency, the same charge should apply to the Rate 2A-Meter Class 1, and the monthly

customer charge for Rate 2A-Meter Class II and Rate GS-1 should be set at $40.00. DTE Gas

established the monthly customer charges for the remaining rate schedules by using the economic

break even points and proposed Rate GS-1 monthly customer charge. The Rate GS-2 monthly

service charge is $750.00. The Rate S monthly service charge is $225.00. The monthly customer

charges for EUT Rates ST, LT, XLT, and XXLT are $2,750.00, $7,500.00, $18,000.00, and

$175,000.00, respectively (5T 458–59; Exhibit A-16, Schedule F2).

AG witness Coppola recommended that the Commission instead either maintain the current

residential (Rate A and 2A-1) monthly charge of $12.25, and the current Rate GS-1 charge of

$32.00, or limit the increases to no more than $1.00, to $13.25 and $33.00 (5T 1797–98) Mr.

Maroun disagreed because the AG’s proposal is arbitrary and unsupported by cost-based

calculations. In contrast, the Company’s proposal follows the Commission’s guidance regarding

the calculation of cost-based charges as well as accepted regulatory practice as reflected in the

NARUC Gas Rate Design Manual (5T 1089–90).

DTE Gas proposes the following economic break-even points between the various rate

schedules:

GS-1 to GS-2 14,000 Mcf per year

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GS-1 to S 2,183 Mcf per year

GS-1 to ST 14,500 Mcf per year

ST to LT 100,000 Mcf per year

LT to XLT 700,000 Mcf per year

XLT to XXLT 3.5 Bcf per year (5T 460).

The Commission has historically approved a cost-based transportation charge for each of

the EUT rate schedules. The Commission has also historically approved a minimum and maximum

transportation charge for each of the EUT rate schedules and defined them as optional rates in the

Company’s rate book. The minimum optional rate under rate schedules ST and LT should remain

at $0.23 per Mcf. The minimum optional rate under rate schedules XLT and XXLT should remain

at $0.18 per Mcf and $0.05 per Mcf, respectively (5T 461; Exhibit A-16, Schedule F2, page 3).

The maximum optional rate for rate schedules ST, LT and XLT should be set by calculating

the difference between the minimum optional rate for each of the rate schedules and the approved

cost of service rate, and then adding that difference to the cost-of-service rates to determine the

maximum rates. The maximum rate for rate schedule XXLT should be set equal to the maximum

rate calculated for rate schedule XLT. It is important to set the maximum optional rates at the

proposed levels because the maximum optional rate is sometimes used in negotiations with a

customer to facilitate paying a portion of the cost of extending gas facilities to the customer,

benefitting both DTE Gas and the customer (5T 461–62).

XI. REQUEST FOR RELIEF

DTE Gas respectfully requests that the Commission issue its final order:

A. Granting DTE Gas’s request for final rate relief, as further supported and explained

in its Application, testimony, exhibits, and this brief (including Attachments A and B) approving

rates that will recover the Company’s revenue deficiency of approximately $177 million, based on

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a January 1, 2022 through December 31, 2022 test year, effective as soon as possible on or after

January 1, 2022;

B. Approving recovery of DTE Gas’s new rates effective no later than January 1, 2022,

in the manner described in the Company’s Application, testimony, exhibits, and this Brief

including Attachments A and B;

C. Acknowledging that DTE Gas has satisfied all of the directives of the

Commission’s Order in Case No. U-20642, which were required components of the Company’s

next general rate case;

D. Approving the Company’s recovery of the requested infrastructure-related capital

and the associated Infrastructure Recovery Mechanism (IRM);

E. Approving the Company’s capital structure and return on investment;

F. Approving the Company’s recovery of projected Manufactured Gas Plant (MGP)

expenses;

G. Approving continuation of and changes to the Company’s Low-Income Assistance

credit pilot and Residential Income Assistance Service Provision credit, including regulatory asset

and liability treatment for low-income assistance customer credits applied greater or less than those

approved in rates;

H. Approving the Company’s proposal for a Shared Asset Deferral Mechanism

(SADM);

I. Approving the Company’s proposal to amend certain customer rate schedules and

proposed tariff changes;

J. Authorizing implementation of DTE Gas’s proposed accounting changes as

described in the Company’s Application, testimony, exhibits, and this Brief;

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K. Approving the remainder of DTE Gas’s miscellaneous proposals, and rejecting

other parties’ additional or inconsistent proposals, as set forth in the Company’s Application,

testimony, exhibits and this Brief including Attachments A and B; and

L. Granting such other lawful relief that the Commission deems reasonable and

appropriate.

Dated: August 5, 2021

Respectfully submitted, DTE GAS COMPANY By:_________________________________

Paula Johnson-Bacon (P55862) Andrea Hayden (P71976) Lauren D. Donofrio (P66026) Jon P. Christinidis (P47352) David S. Maquera (P66228) General Counsel – DTE Gas Company One Energy Plaza, 1635 WCB Detroit, Michigan 48226 (313) 235-7052

DTE Gas Company MPSC Case No. U-20940Computation of Revenue Deficiency Initial Brief

Projected 12 Month Period Ending December 31, 2022 Attachment A($000) Page 1 of 4

(a) (a) (b) (c) (d)

U-20940Line U-20940 InitialNo. Description Source Filed Adjustments Brief Position

1 Rate Base Attach A, Page 2 5,610,642$ (359)$ 5,610,283$

2 Adjusted Net Operating Income Attach A, Page 3 169,973 13,031 183,004

3 Rate of Return Attach A, Page 4 5.59% 0.00% 5.59%

4 Income Requirements 313,781 (20) 313,761

5 Income Deficiency (Sufficiency) 143,808 (13,051) 130,757

6 Revenue Conversion Factor Exh, A-13, Sch. C2 1.3547 - 1.3547

7 Revenue Deficiency (Sufficiency) 194,817$ (17,681)$ 177,136$

DTE Gas Company MPSC Case No. U-20940Rate Base - Average Net Plant Initial Brief

For the 13-Month Average Period Ending 12/31/2022 Attachment A($000) Page 2 of 4

(a) (b) (c) (d)

U-20642Line U-20940 InitialNo. Description Filed Adjustments Brief Position

1 Plant in Service 6,847,233$ (364)$ (1) 6,846,870$ 2 Plant Held for Future Use 0 03 Construction Work in Progress 222,707 222,7074 Total Utility Plant 7,069,941 (364) 7,069,57756 Less: Depreciation Reserve 2,523,891 (5) (2) 2,523,88678 Net Utility Plant 4,546,050 (359) 4,545,691910 Net Capital Lease Property 0 011 Gas Stored Underground - non-current 35,303 35,3031213 Total Utility Property and Plant 4,581,353 (359) 4,580,9941415 Less: Capital Lease Obligations 0 01617 Net Plant 4,581,353 (359) 4,580,9941819 Allowance for Working Capital 1,029,290 1,029,290202122 Rate Base 5,610,642$ (359)$ 5,610,283$

Note: Test Year Impact of Demand Response capital adjustmentsNet Cap Ex, Increase/(Decrease) (728) Plant Adjustment, Increase/(Decrease) (364) (1)Accumulated Depreciation, Increase/(Decrease) (5) (2)Net Rate Base, Increase/(Decrease) (359) Depreciation Expense, Increase/(Decrease) (10) General Plant Composite Depeciation Rate 2.68%

Conceded Amount PTY Average CitationService Rnwl PPE/Vehicle Rental (PTY) (278) (139) 5T 1837-1839Gas Information Technology (PTY) (450) (225) (3)

(728) (364)

Depreciation Expense, Increase/(Decrease) (10)

Accumulated Depreciation, Increase/(Decrease) (5)

(3) Amount discussed on Initial Brief section V(A)(3)

DTE Gas Company MPSC Case No. U-20940Adjusted Net Operating Income Initial Brief

Projected 12 Month Period Ending December 31, 2022 Attachment A($000) Page 3 of 4

(a) (b) (c) (d)

U-20940Line U-20940 InitialNo. Description Filed Adjustments Brief Position

Net Operating Income

Operating Revenues 1 Distribution Revenues 849,564$ 849,564$ 2 Third Party Transportation & Storage 100,963 100,963 3 Other Revenues 118,964 118,9644 Net Margin 1,069,492 0 1,069,49256 Operating Expenses7 Operations and Maintenance Expenses 523,525 (17,646) (1) 505,8798 Company Use & Lost Gas 27,373 27,3739 Gas Uncollectibles 40,198 40,19810 Depreciation and Amortization 185,598 (10) (2) 185,58811 Property and Other Taxes 106,307 106,30712 Total Operating Expenses 883,001 (17,656) 865,3461314 Operating Income 186,490 17,656 204,1461516 Other Operating Income Adjustments17 Allow. For Funds Used During Constr 4,384 4,38418 Amortization of Loss on Reacquired Debt (1,350) (1,350)19 Other (Income)/Deductions (389) (389)20 Total Operating Income Adjustments 2,646 0 2,6462122 PreTax Net Operating Income 189,136$ 17,656$ 206,792$ 2324 Federal Income Tax 9,787 3,466 13,25325 State and Local Income Taxes 9,376 1,158 10,5342627 Net Operating Income 169,973$ 13,031$ 183,004$

(1) O&M- Uncollectible Expense (2,385) 5T 1739- Transmission Right of Way (2,000) 5T 1754- TCARP Demand Charge (11,625) 5T 1970- Shared Assets - Customer Service (844) 5T 1167- Shared Assets - Other (792) 5T 756

(17,646)

(2) Depreciation and Amortization (10) Att. A pg 2

DTE Gas Company MPSC Case No. U-20940Rate of Return Summary Initial Brief

Projected 12 Month Period Ending December 31, 2022 Attachment ABased on Average Rate Base Page 4 of 4($000)

Line Amount Weighted WeightedNo. ($000) Percent Cost % Cost % (1) Cost %

U-20940 Filed (Test Period Average Basis)1 Long-Term Debt 2,075,774$ 48.10% 37.00% 3.968% 1.909% 1.47% 1.0000 1.47%2 Preferred Stock 0 0.00% 0.00% 0.000% 0.000% 0.00% 0.00%3 Common Shareholders' Equity 2,239,744 51.90% 39.92% 10.250% 5.320% 4.09% 1.3547 5.54%4 Total 4,315,518 100.00% 7.228%56 Short-Term Debt 194,565 3.47% 0.945% 0.03% 1.0000 0.03%78 Other Interest Bearing Accounts 0 0.00% 0.945% 0.00% 1.0000 0.00%9

10 Job Development - ITC - Debt 0 0.00% 3.968% 0.00% 1.0000 0.00%11 Job Development - ITC Equity 0 0.00% 10.250% 0.00% 1.3547 0.00%12 Total Job Development - ITC 01314 Deferred Income Taxes (Net) 1,100,559 19.62% 0.000% 0.00% 0.00%1516 Total 5,610,642 100.00% 5.59% 7.04%17

U-20940 Initial Brief (Test Period Average Basis)18 Long-Term Debt 2,075,774$ 48.10% 37.00% 3.968% 1.909% 1.47% 1.0000 1.47%19 Preferred Stock 0 0.00% 0.00% 0.000% 0.000% 0.00% 0.00%20 Common Shareholders' Equity 2,239,744 51.90% 39.92% 10.250% 5.320% 4.09% 1.3547 5.54%21 Total 4,315,518 100.00% 7.228%2223 Short-Term Debt 194,565 3.47% 0.945% 0.03% 1.0000 0.03%2425 Other Interest Bearing Accounts 0 0.00% 0.945% 0.00% 1.0000 0.00%2627 Job Development - ITC - Debt 0 0.00% 3.968% 0.00% 1.0000 0.00%28 Job Development - ITC Equity 0 0.00% 10.250% 0.00% 1.3547 0.00%29 Total Job Development - ITC 03031 Deferred Income Taxes (Net) 1,100,559 19.62% 0.000% 0.0000% 0.00%3233 Total 5,610,642 100.00% 5.59% 7.04%

Description

DTE Gas Company MPSC Case No. U-20940Revenue Requirement Adjustments to Company's Filing Initial Brief

Projected 12 Month Period Ending December 31, 2022 Attachment B($000) Page 1 of 1

(a) (b) (c)

Line RevenueNo. Description Source Deficiency

(Pre Tax Amts)1 Company's Filed Position Exhibit A-11 Sch A-1 194,817$ 23 Adjustments to Revenue Deficiency:45 Rate Base6 Rate Base (1) Changes7 - Net Rate Base, Increase/(Decrease) Attachment A page 2 (359) (25) 89 (359) 10 Operations and Maintenance Expenses11 - Uncollectible Expense Attachment A page 3 (2,385) 12 - Transmission Right of Way Attachment A page 3 (2,000) 13 - TCARP Demand Charge Attachment A page 3 (11,625) 14 - Shared Assets - Customer Service Attachment A page 3 (844) 15 - Shared Assets - Other Attachment A page 3 (792) 161718 Depreciation and Amortization19 - Depreciation Expense, Increase/(Decrease) Attachment A page 3 (10) 2021

22 Total Adjustments to Company's Initial Revenue Deficiency Line 6 through Line 26 (17,681)$

23

24 Company's Brief Position Line 1 + Line 27 177,136$

(1) Rate Base Change multiplied by pre-tax return 7.04% (Attachment A page 4)

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the application of ) DTE GAS COMPANY for authority ) to increase its rates, amend its rate ) schedules and rules governing the ) Case No. U-20940 distribution and supply of natural gas, ) and for miscellaneous accounting authority ) )

PROOF OF SERVICE

STATE OF MICHIGAN ) ) ss. COUNTY OF WAYNE ) ESTELLA R. BRANSON states that on August 5, 2021, she served a copy of DTE Gas

Company’s Initial Brief in the above caption matter, via electronic mail upon the persons listed on

the attached service list.

______ ESTELLA R. BRANSON

SERVICE LIST MPSC CASE NO. U-20940

Page 1 of 2

ADMINISTRATIVE LAW JUDGE Honorable Sally Wallace 7109 West Saginaw Hwy Lansing, MI 48917 [email protected] ABATE Michael J. Pattwell Clark Hill, PLC 212 East César E. Chávez Avenue Lansing, MI 48906 [email protected] Stephen A. Campbell Clark Hill, PLC 500 Woodward Avenue, Ste. 3500 Detroit, MI 48226 [email protected] ATTORNEY GENERAL (ENRA) Joel King Michael E. Moody 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] CITIZENS UTILITY BOARD OF MICHIGAN John R. Liskey John R Liskey Attorney At Law PLLC 921 N. Washington Avenue Lansing, MI 48906 [email protected]

DEARBORN INDUSTRIAL GENERATION, L.L.C. Sean P. Gallagher Gallagher Law 321 West Lake Lansing Road East Lansing, Michigan 48823 [email protected] DETROIT THERMAL, LLC; VICINITY ENERGY GRAND RAPIDS LLC Arthur J. Levasseur Fischer Franklin & Ford 24725 W. 12 Mile Road Southfield, MI 48034 [email protected] ENERGY MICHIGAN, INC.; VERSO CORPORATION Timothy J. Lundgren Laura A. Chappelle Potomac Law Group 120 N. Washington Square, Suite 300 Lansing, MI 48933 [email protected] [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]

mailto:[email protected]












SERVICE LIST MPSC CASE NO. U-20940

Page 2 of 2

MPSC STAFF ATTORNEYS Heather M.S. Durian Michael J. Orris Daniel E. Sonneveldt Monica M. Stephens Public Service Division 7109 West Saginaw Hwy, 3rd Floor Lansing, MI 48917 [email protected] [email protected] [email protected] [email protected] RESIDENTIAL CUSTOMER GROUP Don L. Keskey Brian W. Coyer University Office Place 333 Albert Avenue, Suite 425 East Lansing, MI 48823 [email protected] [email protected]







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