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July 27, 2016
Ms. Kavita Kale
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-17999
Dear Ms. Kale:
Attached for electronic filing in the above-captioned matter is DTE Gas Company’s
Initial Brief. Also attached is a Proof of Service.
Very truly yours,
David S. Maquera
DSM/lah
Attachments
cc: Service List
DTE Gas Company
One Energy Plaza, 688 WCB
Detroit, MI 48226-1279
David S. Maquera (313) 235-3724
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-17999
schedules and rules governing the ) (Paperless e-file)
distribution and supply of natural gas, )
and for miscellaneous accounting authority. )
)
DTE GAS COMPANY’S INITIAL BRIEF
Dated: July 27, 2016
i
TABLE OF CONTENTS
I. HISTORY OF PROCEEDINGS. ................................................................................... 1
II. BACKGROUND AND SUMMARY OF MAJOR ISSUES. .......................................... 6
III. JURISDICTION, STANDARD OF REVIEW AND RATE SETTING LAW. ............. 10
A. Jurisdiction and Standard of Review. .................................................................. 10
B. Rate Setting Legal Requirements. ....................................................................... 11
IV. TEST YEAR. .............................................................................................................. 15
V. RATE BASE. .............................................................................................................. 15
A. Adjusted Total Rate Base .................................................................................... 16
B. Capital Expenditures. .......................................................................................... 16
VI. RATE OF RETURN. ................................................................................................... 18
A. Capital Structure. ................................................................................................ 19
B. Debt Cost Rates. ................................................................................................. 21
1. Long-Term Debt. .......................................................................................... 21
2. Short-Term Debt. .......................................................................................... 21
C. Return on Common Equity.................................................................................. 21
1. CAPM and ECAPM Estimates. ..................................................................... 23
2. DCF Estimates. ............................................................................................. 26
3. DTE Gas’s Relatively High Risk Justifies a Higher Return on Equity............ 27
4. Any Reduction of Equity in DTE Gas’s Capital Structure Would Require a
Higher Return on Equity. .............................................................................. 29
5. Summary and Recommendations Regarding DTE Gas’s Cost of Equity. ....... 30
D. Other Cost Rates. ................................................................................................ 30
E. Overall Rate of Return. ....................................................................................... 31
VII. ADJUSTED NET OPERATING INCOME AND OTHER REVENUE-RELATED
ISSUES. ...................................................................................................................... 31
A. Throughput. ........................................................................................................ 32
1. Weather Normalization. ................................................................................ 32
2. Customer Usage. ........................................................................................... 33
3. Exelon Energy Company (“Exelon”). ............................................................ 34
4. Cost of Gas. .................................................................................................. 35
5. End-Use Transportation (“EUT”). ................................................................. 36
ii
6. Long-Term Fixed-Price Contract Revenues. .................................................. 36
B. Midstream Revenue. ........................................................................................... 37
C. Other Operating Revenue. ................................................................................... 38
D. DTE Gas’s Operating and Maintenance (“O&M”), Administrative and General
(“A&G”), and Infrastructure Costs Are Reasonable to Maintain Safe and
Reliable Service. .............................................................................................. 38
1. O&M Expenses. ............................................................................................ 38
a. Inflation and 2015 Actuals. ...................................................................... 40
b. Shared Asset Rent Expense. .................................................................... 41
c. Injuries and Damages. ............................................................................. 42
d. Employee Benefits Expense. ................................................................... 42
e. ANR Alpena Transport Contract ............................................................. 59
f. Manufactured Gas Plant (“MGP”) Remediation Expenses....................... 60
g. O&M Expense Summary. ........................................................................ 62
2. Uncollectible Expense. .................................................................................. 62
E. Advanced Metering Infrastructure (“AMI”) Costs. .............................................. 63
F. Lost And Unaccounted For (“LAUF”) and Company Use (“CU”) Gas, and Gas-
In-Kind (“GIK”). ............................................................................................. 65
G. Depreciation and Amortization. .......................................................................... 67
H. Property and Other Taxes. ................................................................................... 68
I. Income Tax Expenses. ........................................................................................ 69
J. Revenue Decoupling Mechanism (“RDM”). ....................................................... 69
K. Infrastructure Recovery Mechanism (“IRM”)...................................................... 73
1. The Company’s Proposed New IRM Surcharge............................................. 74
2. Program spending flexibility ......................................................................... 75
3. Impacted Meters............................................................................................ 76
4. MRP Risk Ranking ....................................................................................... 77
5. MRP Spending Increase ................................................................................ 78
6. Meter Assembly Check Reporting Requirements .......................................... 79
L. Corrosion Work Order Backlog. ......................................................................... 79
M. Leak Backlog. ..................................................................................................... 80
N. Accounting Requests. ......................................................................................... 81
VIII. REVENUE DEFICIENCY AND REQUESTED RATE RELIEF. ............................... 82
iii
IX. RATE DESIGN AND TARIFF REVISIONS. ............................................................. 83
A. Allocation of Revenue Deficiency. ...................................................................... 83
B. Supplemental Utility Service Changes. ............................................................... 86
C. Tariff Changes for All Customers. ...................................................................... 87
D. Tariff Changes for Sales Rate Schedules. ............................................................ 88
1. Revised IRM. ................................................................................................ 88
2. Low Income Assistance Credit Pilot. ............................................................. 88
3. Rate Schedule AS.......................................................................................... 90
E. Tariff Changes for EUT and Choice Service. ...................................................... 90
1. Section E1.1. ................................................................................................. 90
2. Section E14. .................................................................................................. 92
F. Tariff Changes for Off-System Storage and Transportation Service. ................... 92
G. Tariff Changes for Gas Customer Choice Program. ............................................. 93
H. Proposed Monthly Customer Charges and Rate Schedule Economic Break Even
Points. .............................................................................................................. 94
X. REQUEST FOR RELIEF ............................................................................................ 96
1
I. 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”)
December 20, 2012 and April 16, 2013 Orders in Case No. U-16999. On December 18, 2015,
DTE Gas filed its Application, direct testimony, and exhibits with the Commission requesting to
raise revenues by approximately $182.9 million annually.1 By January 5, 2016, DTE Gas
published notice of its above request.2
On January 19, 2016, a pre-hearing conference was held by Administrative Law Judge
Mark E. Cummins (the “ALJ”) who granted petitions to intervene filed by the Association of
Businesses Advocating Tariff Equity (“ABATE”); ANR Pipeline Company (“ANR”); the
Michigan Attorney General (“AG”); and Detroit Thermal, LLC (“Detroit Thermal”). Staff also
participated at the pre-hearing conference and a case schedule was established (1T 6-11).
On May 11, 2016, DTE Gas filed the testimony and exhibits of Don M. Stanczak3
regarding the tariffs that DTE Gas proposed to self-implement pursuant to MCL 460.6a(1)4
1 See In re DTE Gas Co, MPSC Case No. U-17999, Application, Testimony, and Exhibits, Dkt. Nos. 1-22.
2 See In re DTE Gas Co, MPSC Case No. U-17999, Gas Service Area Notice, Dkt. No. 42.
3Mr. Stanczak is DTE Energy’s Vice President, Regulatory Affairs. He has a Bachelor of Science degree in
Business Administration, with a major in Finance, and a Master of Business Administration degree, with a major in
Accounting. He joined DTE Gas in 1983, and was promoted to positions of increasing responsibility. In his current
position, he is responsible for the development and implementation of regulatory strategy and administration for
both DTE Electric Company (“DTE Electric”) and DTE Gas (2T 61-62, 93-94).
4 On October 6, 2008, Act 286 amended MCL 460.6a to provide that a gas utility, such as DTE Gas, may self-
implement its requested rate increase if the Commission does not issue an order within 180 days after the utility files
its application for a rate increase, unless the Commission finds good cause to prevent or delay the utility from
implementing those rates. See MCL 460.6a(1).
2
beginning November 1, 2016.5 Mr. Stanczak supported DTE Gas’s proposal to self-implement a
$103 million rate increase. Mr. Stanczak further recommended that the rate increase be allocated
based on the rate design (self-implementation surcharge allocated based on the statutorily-
mandated equal percentage basis) reflected on Exhibit A-20 and included in DTE Gas’s tariff
pages contained in Exhibit A-21 (2T 70, 99-100).6 On June 9, 2016, the Commission issued an
Order stating that DTE Gas may not self-implement a rate increase prior to November 1, 2016.7
No party presented evidence suggesting that DTE Gas should not self-implement a rate
increase effective November 1, 2016, or that the rate increase should be less than DTE Gas
proposed. Accordingly, DTE Gas intends to self-implement its proposed rate increase as
indicated above.
DTE Gas sponsored the direct testimony and exhibits of 16 witnesses. Jennie A. Aud is
DTE Gas’s Director, Gas Control and Planning (qualifications and direct testimony at 2T 392-
417);8 George H. Chapel is DTE Gas’s Manager, Market Forecasting (qualifications and direct
testimony at 2T 531-79);9 Robert D. Feldmann is DTE Gas’s Director, Gas Sales and Marketing
5 See In re DTE Gas Co, MPSC Case No. U-17999, Testimony, and Exhibits, Dkt. No. 79.
6 Mr. Stanczak confirmed that DTE Gas’s decision to self-implement a $103 million rate increase does not imply
that the Company is lowering its total requested rate relief (2T 101).
7 See In re DTE Gas Co, MPSC Case No. U-17999, Order dated June 9, 2016, Dkt. No. 107.
8 Ms. Aud has a Bachelor of Science degree in Mechanical Engineering, and has worked for DTE Gas since 1994 in
positions of increasing responsibility. In her current position, she is responsible for the following functions: Gas
Control; Measurement and Control Maintenance; Gas Measurement; Gas Nomination Services; and Project
Planning and Asset Prioritization (2T 393-94).
9 Mr. Chapel has a Bachelor of Science degree in Mathematics. He is currently responsible for projecting DTE
Gas’s rate schedule customer growth/decline, and natural gas supply requirements, and provides gas demand
forecasts and analysis (2T 532-33).
3
(qualifications and direct testimony at 2T 582-654);10
Mark W. Heaphy is DTE Energy
Corporate Services LLC’s Manager of Tax Accounting (qualifications and direct testimony at 2T
365-75);11
Martin L. Heiser is a Consultant, Regulatory Economics in DTE Energy Corporate
Services LLC’s Regulatory Affairs organization (qualifications and direct testimony at 2T 322-
47);12
Robert J. Lee is DTE Gas’s Manager of Environmental Management and Resources
(qualifications and direct testimony at 2T 746-61);13
Alida D. Sandberg is DTE Gas’s Director,
Engineering Services (qualifications and direct testimony at 2T 673-732);14
Robert E. Sitkauskas
is DTE Energy Corporate Services LLC’s General Manager of the Advanced Metering
Infrastructure (“AMI”) group in the Major Enterprise Projects Organization (qualifications and
direct testimony at 2T 283-99);15
Kenneth L. Slater is the Manager of Revenue Requirements in
10 Mr. Feldmann has an Honors Bachelor of Commerce Degree and a Master of Business Administration degree. In
his current position, he is responsible for commercial and customer facing activities associated with the regulated
Mid-Stream business, EUT customers, Home Protection Plus (“HPP”), Residential New Market customer
enrollments, the organizations CNG business and the Gas Sales and Marketing function.(2T 583-84).
11 Mr. Heaphy has a Bachelor of Business Administration degree. In his present position, he is responsible for
overseeing accounting for income taxes and related financial reporting (2T 366). 12 Mr. Heiser has a Bachelor of Science degree in Civil Engineering and a Master’s degree in Business
Administration with a concentration in Finance. In his current position, he is responsible for performing cost of
service studies, revenue requirement studies, economic analyses, depreciation studies, and other short and long-term
financial evaluations. He is also responsible for performing embedded and marginal cost studies, and fully-allocated
class cost of service studies (2T 323-25).
13 Mr. Lee has a Bachelor of Science Degree in Geology and a Master of Science degree in Environmental
Geochemistry. In his current position, he manages DTE Gas’s remediation program and environmental efforts at the
former Manufactured Gas Plant (“MGP”) properties, including managing the expenses associated with the
investigation and remediation of the MGPs (2T 747-48). 14 Ms. Sandberg has a Bachelor of Science degree in Bioengineering and a Masters of Business Administration
degree with a concentration in Finance.. In her present position, she is responsible for the engineering activities for
DTE Gas, including corrosion control, codes and standards, gas laboratory services, transmission and distribution
engineering, and geology and reservoir engineering (2T 674-75).
15 Mr. Sitkauskas has a Bachelor of Business Administration degree and a Master of Business Administration
degree.. In his current position, he is responsible for the development, administration, and reporting of the AMI
project for DTE Electric and DTE Gas, including the negotiation and execution of the contract with the main project
vendor, Itron, Inc. (“Itron”) (2T 284-85).
4
DTE Energy Corporate Services LLC’s Regulatory Affairs organization (qualifications and
direct testimony at 2T 764-803);16
Edward J. Solomon is the Assistant Treasurer and Director of
Corporate Finance, Insurance and Development for DTE Energy and its subsidiaries, including
DTE Gas (qualifications and direct testimony at 2T 128-48);17
Jason E. Sparks is the DTE
Energy Corporate Services LLC’s Manager, Revenue Management Strategy (qualifications and
direct testimony at 2T 815-30);18
Mr. Stanczak (qualifications and direct testimony at 2T 60-91);
Renee M. Tomina is DTE Gas’s Director of Southeast Michigan Gas Operations (qualifications
and direct testimony at 2T 935-62);19
Theresa M. Uzenski is the Manager of Regulatory
Accounting for DTE Electric and DTE Gas (qualifications and direct testimony at 2T 451-509);20
Dr. Michael J. Vilbert is a principal in The Brattle Group, which is an economic, environmental
and management consulting firm (qualifications and direct testimony at 2T 173-225);21
and
16 Mr. Slater has a Bachelor of Science degree Business Administration with a concentration in Accounting. In his
present position, he is responsible for revenue requirement studies, depreciation rate studies, cost of service studies,
as well as regulatory analysis and research for both DTE Electric and DTE Gas (2T 765-66).
17 Mr. Solomon is a CPA and has a Bachelor of Business degree with a concentration in Accounting, and a Master of
Business Administration degree, with a focus in Finance and Corporate Strategy. In his current position, he is
responsible for assisting the Treasurer in managing the Company’s capital needs (2T 129-31).
18 Mr. Sparks has a Bachelor of Science degree in Business Administration, and a Master of Business
Administration degree. In his current position, he oversees the Company’s overall collections strategy, low-income
assistance programs, and reporting function (2T 816).
19 Ms. Tomina has a Bachelor degree in Electrical Engineering, with a concentration in Electronics, and a Master of
Science degree in Systems Engineering, with a concentration in Manufacturing Processes.. In her current position,
she is responsible for all areas of operations in Southeast Michigan including Field Service, Distribution, Construction Support and Drafting (2T 936-37).
20 Ms. Uzenski is a Certified Management Accountant and she has a Bachelor of Science degree in Accounting and
a Master of Business Administration degree with a concentration in Finance. She is presently responsible for the
development and management of regulatory accounting policies and practices, as well as supporting regulatory
filings (2T 452-53).
21 Dr. Vilbert has a Bachelor of Science degree and a Ph.D. in Finance. He has worked in the areas of cost of
capital, investment risk and related matters for many regulated and unregulated industries, and frequently testified or
filed cost of capital testimony in public utility proceedings (2T 175-77; Exhibit A-11, Schedule D5.13).
5
Jeffrey C. Wuepper is the Director of Compensation & Benefits for DTE Energy (qualifications
and direct testimony at 2T 851-910).22
On May 11, 2016, the Commission Staff and Intervenors filed their testimony although
neither ANR nor Detroit Thermal filed any testimony. Staff sponsored Ronald J. Ancona
(qualifications and direct testimony at 3T 1210-20); Catherine E. Cole (qualifications and direct
testimony at 3T 1125-39); Cynthia L. Creisher (qualifications and direct testimony at 3 T 1140-
65); Daniel J. Gottschalk (qualifications and direct testimony at 3T 1264-81); David W. Isakson
(qualifications and direct testimony at 3T 1245-54); Olumide Makinde (qualifications and direct
testimony at 3T 1236-44); Cody S. Mathews (qualifications and direct testimony at 3T 1166-75);
Kirk Megginson (qualifications and direct testimony at 3T 1176-1200); Robert F. Nichols II
(qualifications and direct testimony at 3T 1112-24); Nyrhe U. Royal (qualifications and direct
testimony at 3T 1221-35); and Brian Welke (qualifications and direct testimony at 3T 1201-
1209).
ABATE sponsored Nicholas Phillips, Jr. (qualifications and direct testimony at 2T 227-
46). The Attorney General sponsored Sebastian Coppola (qualifications and direct testimony at
3T 986-1072).
On June 8, 2016, DTE Gas filed the rebuttal testimony and exhibits of witnesses Aud (2T
418-23), Chapel (2T 573-79), Feldmann (2T 655-66), Heaphy (2T 376-80), Heiser (2T 348-53),
Sandberg (2T 733-43), Sitkauskas (2T 300-303), Slater (2T 804-12), Solomon (2T 149-51),
Sparks (2T 831-35), Stanczak (2T 103-109), Tomina (2T 963-65), Uzenski (2T 510-18), Mark L.
22 Mr. Wuepper has a Bachelor of Business Administration degree with a major in Accounting and a Master of
Business Administration degree with an emphasis in Finance. He currently has overall responsibility for the design,
implementation and administration of DTE Energy’s compensation policies and practices, including executive
compensation, and employee benefits (2T 852-53).
6
Vanderheuvel (2T 837-47),23
Vilbert (2T 226-58), and Wuepper (2T 911-32). On that same day,
ABATE filed the rebuttal testimony of witness Phillips (2T 47-54), and the Staff filed the
rebuttal testimony of witness Isakson (3T 1255-63).
Cross-examination and binding-in of testimony was held on June 21 and 24, 2016. The
record consists of 1,287 pages of transcript and 137 Exhibits.
II. BACKGROUND AND SUMMARY OF MAJOR ISSUES.
DTE Gas initially projected a revenue deficiency of approximately $182.9 million for the
projected test year (2T 68-69, 337, 347; Exhibit A-8, Schedule A1). DTE Gas requires rate relief
to primarily address the revenue requirement associated with increased investments made in net
plant and associated depreciation and property tax increases, lower energy usage, plus an
increase in O&M expense. This revenue deficiency also includes some Infrastructure Recovery
Mechanism (“IRM”) related capital investments (meter move out, cast iron replacement, and
pipeline integrity) made through 2016 in base rates. With the current $40.8 million IRM
surcharge ceasing and DTE Gas’s proposed new $8.6 million IRM surcharge beginning
simultaneously with new rates, the $182.9 million filed revenue shortfall would result in an
effective rate increase to customers of $150.7 million ($182.9 million less $40.8 million plus
$8.6 million) (2T 68-69).
DTE Gas continues to focus on efforts to control and, where possible, reduce costs,
through sustainable and ongoing continuous improvement efforts. These activities have allowed
the Company to partially mitigate the impact of increasing routine operating costs without
23
Mr. Vanderheuvel is the DTE Gas’s Director of Gas Operations - Construction. He has a Bachelor of Science
degree in Chemical Engineering, and has worked for the Company since 1996 in positions of increasing
responsibility. He is currently responsible for all construction activities associated with the Main Renewal and
Meter Move-Out programs. He is also responsible for customer-initiated construction, public improvement
construction, routine construction, and supplier performance management (2T 838).
7
reducing the quality of service to its customers (2T 66). The Commission’s original approval of
the IRM in Case No. U-16999 also allowed the Company to recover the cost of service for
approximately $150 million in capital expenditures during 2013 and 2014, thereby helping to
offset the need to file a general rate case (2T 66). The Company also initiated changes to its
Other Post-Employment Benefit (“OPEB”) obligation, thereby significantly lowering benefit
expense beginning in 2013 (2T 66).
Even with DTE Gas’s cost savings, the Company still faces a revenue deficiency of
approximately $182.9 million for the projected test year (2T 68-69, 98, 101, 337, 347; Exhibit A-
8, Schedule A1). DTE Gas’s proposed revenue increase is necessary to maintain the Company’s
financial health, ensure safe and reliable customer service, and continue to maintain the
Company’s gas distribution, transmission and storage infrastructure. Insufficient rate relief
could make it more difficult and expensive for DTE Gas to obtain the required financing on
favorable terms. The more dollars DTE Gas has to spend on financing costs, the less that will be
available for capital and maintenance programs. Inadequate capital and maintenance funding,
over time, would result in the deterioration of distribution, transmission, and storage
infrastructure, ultimately resulting in reduced system reliability (2T 66-67, 97).
DTE Gas also supports Michigan’s economy as a major employer and taxpayer in the
communities it serves. As Mr. Stanczak explained:
• “While I am aware of the impact that utility rate increases have on our
customers, I am similarly aware that our customers expect and deserve
safe and reliable service.”
• “The only way that DTE Gas can adequately provide the required service
levels that our customers desire and deserve is by being financially
healthy.”
• “Inadequate rates will likely result in higher financing costs and have a
significant negative impact on our ability to safely and adequately serve
8
our customers and maintain the integrity of our gas distribution,
transmission, and storage assets.”
• “DTE Gas has an important positive economic impact on the communities
it serves. DTE Gas is a large employer with over 1,600 employees
throughout the State of Michigan; and through the Pure Michigan
Business Connect campaign, the Company utilizes the services of
numerous local contractors and vendors.”
• “In the 2014 historical test year, DTE Gas paid over $46 million in
property taxes to Michigan communities.”
• “DTE Gas continues to make major capital investments in the
communities in which it serves and operates. Thus, DTE Gas supports
additional job growth opportunities and provides incremental tax revenue
for the communities it serves” (2T 66-68, 97-98).
DTE Gas is keenly aware of the economy’s effects on its customers, and therefore
continues to aggressively pursue opportunities to reduce costs and improve performance as much
as possible. The Company also continues to face considerable risks and cost pressures,
particularly due to the economic conditions in its service territory. The Company needs rate
relief to run a healthy utility business providing safe and reliable service to its customers (2T 66-
68).
Although DTE Gas initially projected a revenue deficiency of approximately $182.9
million for the projected test year (2T 68-69, 337, 347; Exhibit A-8, Schedule A1), Staff
recognized a smaller, but still considerable revenue deficiency, which Staff calculated as $122.9
million (3T 1117; Exhibit S-1, Revised Schedule A1). After reviewing Staff’s various positions,
DTE Gas adopts the following adjustments to its projected revenue deficiency:
(1) a $9.0 million increase in deferred taxes while debt and equity are each reduced by
$4.5 million for the impact of the December 2015 bonus depreciation extension (3T
1122);
9
(2) Staff’s long-term debt costs from 4.97% to 4.98% and short-term debt cost from
1.84% to 1.54% (3T 1184 and 1185);
(3) A reduction in working capital of $0.987 million for an update to the Regulatory
Asset Demolition Fee (3T 1120);
(4) A $0.428 million reduction to net plant to reflect an offset of $0.855 million for
non-municipal demo fees offset to construction (2T 513);
(5) A reduction in net plant of $1.7 million for the impact of corrected depreciation
rates on accumulated depreciation (3T 1118);
(6) Staff’s proposed increase to uncollectible expense of $1.0 million from $42.920
million to $43.979 million (3T 1205-1206, Exhibit S-3 Schedule C5 revised);
(7) Staff’s proposed $0.674 million increase to injuries and damages expense (3T 1206,
Exhibit S-3, Schedule C5 revised);
(8) Staff’s proposed reduction of $1.2 million related to shared asset rent expense (3T
1207 Exhibit S-3, Schedule C5 revised);
(9) Staff’s proposed adjustment to reduce O&M expense by $1.8 million for accrued
vacation expense (3T 1206-7 Exhibit S-3, Schedule C5 revised);
(10) Staff’s proposed $4.9 million reduction in O&M expense to reflect the impact of
using 2015 actual O&M expense and updated inflation rates (3T 1203-1204,
Exhibit S-3, Schedule C5 revised);
(11) A reduction in benefit expense of $0.795 million for Executive Supplemental
Retirement Plan (Exhibit A-10, Schedule C5.9);
10
(12) Staff’s proposed $3.4 million increase to depreciation expense to reflect a
correction of an error in the Company’s computation of depreciation expense (3T
1118); and
(13) Staff’s proposed reduction in demolition fee amortization expense of $0.7 million
based on updated estimates of municipal cut and caps (3T 1120).
Based upon adoption of these thirteen adjustments, DTE Gas supports an adjusted revenue
deficiency of approximately $177 million for the projected test year.24
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.
Const 1963, art 6, § 28 requires the Commission’s findings to “be supported by
competent, material and substantial evidence on the whole record.” 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 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
24 See Attachments A and B.
11
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).
In Kar v Hogan, 399 Mich 529, 539; 251 NW2d 77 (1976), our Supreme Court
explained:
“The 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 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) (holding that agency’s decision was not supported by
evidence that a reasonable person would consider adequate).
B. Rate Setting Legal Requirements.
All Commission decisions must be authorized by law, and the Commission’s findings of
fact must be supported by competent, material, and substantial evidence. Const 1963, art 6, § 28.
DTE Gas also 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
12
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.25
The Michigan Supreme Court has provided further guidance that the Commission must
use in setting DTE Gas’ 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 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.26
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).
25 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).
26
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).
13
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);
MCL 460.6h(1); 2008 PA 286; 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
admonished 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
14
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’ rates on past events.
In Michigan, our Supreme Court announced the retroactive ratemaking prohibition in
Michigan Bell Telephone Co v Public Service Comm, 315 Mich 533; 24 NW2d 200 (1946). The
Court used a statutory analysis, reasoning that the Commission has only limited statutory
authority, which does not include the authority to retroactively reduce rates. 315 Mich at 547.
Further, a lawfully-established rate remains in force until altered by a subsequently-established
lawful rate. 315 Mich 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.
In any event, “the 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
15
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 November 1, 2016 through October 31, 2017
(2T 68). Staff agrees (e.g., Exhibit S-1, Revised 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,27
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
December 31, 2014 as a point of departure, 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 $182.9 million (2T 68-69, 337, 347; Exhibit A-8, Schedule A1).28
In other words, DTE Gas essentially utilized the Commission’s prior methodology, which
produced the equivalent of a fully-projected test year.
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 initially filed Total Rate Base for the
27 MCL 460.6a(1) relevantly states: “A utility may use projected costs and revenues for a future consecutive 12-
month period in developing its regulated rates and charges.”
28
DTE Gas’ Revenue Deficiency of $182.9 million is based on a 13-month average Rate Base of $3,720 million,
adjusted NOI of $113.7 million, and an overall rate of return of 6.04%. The $3,720 million Total Rate Base is
detailed on Exhibit A-9, Schedule B1. The $113.7 million NOI is developed on Exhibit A-10, Schedule C1.1, and
summarized in an income statement format on Exhibit A-10, Schedule C1. The 6.04% overall rate of return is set
forth on Exhibit A-11, Schedule D1. (2T 337).
16
projected test year is $3.720 billion, which consists of $2.720 billion of Net Utility Plant and
$1.0 billion of Working Capital (2T 337; Exhibit A-9, 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) the reduction to capital for demolition fees from non-
municipal cut and caps (2T 513); 2) a $1.7 million adjustment to accumulated depreciation for
the $3.4 million correction to depreciation expense (3T 1118); and 3) the reduction in working
capital to reflect the updated estimate of the Regulatory Asset Demolition Fees (3T 1120; Exhibit
S-12.1). The first two adjustments reduce DTE Gas’s Net Plant from $2.720 billion to $2.718
billion and the third adjustment reduces Working Capital from $1.0 billion to $0.999 billion.
DTE Gas’s Total Rate Base as adjusted in this Brief for the projected period ending October 31,
2017 is reduced from $3.720 billion to $3.716 billion.
B. Capital Expenditures.
DTE Gas has made or will make $931.2 million of capital expenditures from the end of
the historical test year to the end of the projected test year (December 31, 2014 through October
31, 2017). These 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. DTE Gas further proposes to recover the revenue
requirement associated with $127.6 million of capital expenditures annually beginning January
1, 2017 through a new five year Infrastructure Recovery Mechanism (“IRM”) (2017 through
2021) surcharge, as further discussed in Section VII. K (2T 678; Exhibit A-9, Schedule B6, line
19). Exhibit A-9, Schedule B6.1 provides further detail regarding capital expenditures on routine
and other capital projects for 2015 through 2017, and new IRM investments for 2017 through
2021 (2T 679).
17
Routine capital spending supports distribution plant, transmission and storage
infrastructure, and general assets, which include vehicles, building improvements and computer
equipment. DTE Gas has made or will make $324.9 million of routine capital expenditures from
the end of the historical test year to the end of the projected test year (December 31, 2014
through October 31, 2017). (2T 680; Exhibit A-9, Schedule B6.1, line 5). Ms. Sandberg
explained and supported the routine capital expenditures required for distribution plant (2T 681-
87), transmission plant (2T 687-88), storage plant (2T 688-90), and general plant (2T 691-92).
Other capital projects are, for the most part, either new projects with no historical or
comparable spending levels, or are revenue generating or cost saving projects. DTE Gas has
made or will make $426.2 million of other capital expenditures from the end of the historical test
year to the end of the projected test year (December 31, 2014 through October 31, 2017). (2T
692-93; Exhibit A-9, Schedule B6.1, line 13). Ms. Sandberg explained and supported the other
capital expenditures required for new market attachments (2T 693-94), Advanced Metering
Infrastructure (“AMI”) (2T 694), the NEXUS pipeline project (2T 695-97), the Belle River
Compressor Project (2T 697-99), the Gordie Howe International Bridge (“GHIB”) (2T 699-700),
the Milford Junction Loop (2T 701-703), and the Revenue Protection Program (2T 703-704).
Ms. Aud further discussed the operational changes that DTE Gas is making to its storage
facilities (2T 411-16).
DTE Gas expects its 2015, 2016, and 2017 IRM capital expenditures to be $78.1 million,
$102.1 million and $127.6 million, respectively (2 T 705). The Company will spend $127.6
million annually from 2018 through 2021 (2 T 705). The Company has included all IRM capital
invested through December 31, 2016 in base rates (2 T 705). In Case No. U-16999, the
Commission approved a provision that all capital invested as part of IRM would be rolled into
18
rate base in the event DTE Gas filed a rate case (2 T 705). The treatment of IRM capital
expenditures for 2017 and beyond are discussed further in Section VII, K.
DTE Gas projects $201 million of capital expenditures from 2015 through October 31,
2017 related to upgrades to facilitate the transportation of NEXUS gas (2T 696; Exhibit A-9,
Schedule B6.1). However, customer rates will not be impacted in this proceeding by the
upgrades due to the Allowance for Funds Used During Construction (“AFUDC”) charges
incurred during construction. Furthermore, when placed into service, the revenue associated
with the NEXUS project will support the invested capital including accumulated AFUDC. Thus,
the cost of service associated with the NEXUS project will never be borne by DTE Gas retail
customers (2T 697).
VI. RATE OF RETURN.
DTE Gas originally requested a weighted after-tax rate of return of 6.04% (2T 337;
Exhibit A-11, Schedule D1). DTE Gas is now requesting a weighted after-tax rate of return of
6.02% resulting from the acceptance of the Staff’s lower cost of short-term debt of 1.54%,
Staff’s slightly higher cost of long-term debt of 1.98% and incorporating the impact of bonus
depreciation on deferred income taxes (Attachment A, page 4). Staff recommends a weighted
after-tax return of 5.73% (3T 1181; Exhibit S-4, Schedule D-1). Staff largely adopted the
Company’s projections, so the only remaining substantive issue affecting rate of return relates to
Staff’s understated Return on Equity (“ROE”). For the detailed reasons set forth below, the
Commission should adopt DTE Gas’s weighted after-tax rate of return of 6.02% as computed on
Attachment A, page 4.
19
A. Capital Structure.
DTE Gas needs to have a permanent capital structure consisting of 48% long-term debt
and 52% equity, which is consistent with the Company’s current and planned capital structure
(2T 133-36, 148; Exhibit A-11, Schedule D1). This 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. Particularly in economically-challenged areas like Michigan, a
company with an inadequate capital structure (too little equity compared to debt) might have
limited access to sources of capital. 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 (2T 136-39).
In establishing this target capital structure, DTE Gas considered several factors. One
factor is the risk appetite of the company’s shareholders, who must be compensated for higher
risk, but who also might find risk above a certain level to be intolerable. The appropriate capital
structure is also based on the risk inherent in the company’s line of business, the amount of
capital required to maintain the appropriate level of service to the company’s customers, the
general economic, financial and business environment existing at the time, and the certainty of
the company’s earnings, capital expenditure requirements and cash flow. A company with
20
higher business risk (including volatility and uncertainty of future cash flows)29
must reduce its
financial risk (by injecting more equity) in order to balance the overall risk (2T 138-42).
These risk factors, combined with Michigan’s economic situation,30
increase DTE Gas’s
business risk, and weigh in favor of a corresponding decrease in DTE Gas’s financial risk
through a higher percentage of equity in its capital structure (2T 138-42). Moreover, the utility
industry as a whole is at greater risk than in the past due to conservation initiatives, volatile
commodity prices, uncertain revenues from storage assets, increasing operating costs and
uncontrollable costs such as active employee and retiree healthcare (2T 142).
Based on the foregoing, DTE Gas needs a strong equity component of its capital structure
to maintain adequate access to capital at the lowest possible cost. DTE Gas continues to face
credit risk and challenges from Michigan’s economy, as well as significant ongoing and
emerging business challenges. Accordingly, DTE Gas’s weighted cost of capital should be
based on a capital structure consisting of a minimum of 52% equity, which is consistent with the
52% equity ratio in the historical period and the forecasted test period (2T 133-34, 148, 150-51;
Exhibit A-11, Schedule D1). Staff agrees with the Company’s recommended capital structure,
and calculated a long-term debt balance of $1.329, billion and common equity balance of $1.439
billion (3T 1184-85; Exhibit S4, Schedules D-2 and D-5). For the purpose of narrowing the
number of contested issues in this proceeding, the Company agrees to adopt the capital structure
changes proposed by Staff Witness Megginson as a result of reflecting the impact of the
extension of bonus depreciation (Attachment A, page 4). Accordingly, the Commission should
29
For DTE Gas, such uncertainty includes the risks of funding and recovering the costs of its utility operations.
Other challenges include the economic health in DTE Gas’s service territory; the condition and age of the gas
delivery system, and the potential for increases in commodity prices (2T 141).
30 The metropolitan Detroit and Michigan economies have been among the weakest economies in the United States
(2T 143).
21
also increase DTE Gas’ ROE from 10.5 % to 10.75%, as further discussed in Section VI. C
below.
B. Debt Cost Rates.
1. Long-Term Debt.
DTE Gas recommends a 4.97% weighted cost of long-term debt, which was determined
using the net proceeds method for each issue outstanding as of October 31, 2017, including the
financing cost of the new debt issues (2T 135, 144-45, 148; Exhibit A-11, Schedule D2). Staff
similarly recommends 4.98% (3T 1184-85; Exhibit S-4, Schedule D-1). No other party
addressed long-term debt. For the purpose of narrowing the number of contested issues in this
proceeding, the Company adopts Staff’s proposed cost of long-term debt of 4.98% (Attachment
A, page 4).
2. Short-Term Debt.
DTE Gas recommends a 1.84% cost of short-term debt (2T 135, 144, 146, 148; Exhibit
A-11, Schedule D3). Staff recommends a 1.54% cost of short-term debt using the same
methodology as the Company with an updated LIBOR (3T 1185-86; Exhibit S-4, Schedule D-1).
No other party addressed short-term debt. For the purpose of narrowing the number of contested
issues in this proceeding, the Company adopts Staff’s proposed cost of short-term debt of 1.54%
(Attachment A, page 4).
C. Return on Common Equity.
DTE Gas proposes a just and reasonable Return on Equity (“ROE”) for DTE Gas’
common equity capital of 10.75% as supported by the testimony of Dr. Vilbert. A 10.75% ROE
is at the upper end of Dr. Vilbert’s range of 10.0% to 11.0% because DTE Gas has greater-than-
average risk (2T 179, 208-209, 223-24). Dr. Vilbert’s recommended 10.75% ROE reflects
updated economic analyses based on economic data through April 30, 2016 (2T 231-34, 237).
22
Dr. Vilbert selected a sample of six regulated gas distribution companies in the same line
of business as DTE Gas (2T 204-206). He estimated the ROE for each company in his sample
using the risk positioning31
and Discounted Cash Flow (“DCF”) approaches.32
He then
combined the ROE estimates from both models with the market value capital structure
information and costs of debt and preferred stock for each sample company to compute each
company’s overall cost of capital (i.e., its after-tax weighted-average cost of capital, or
“ATWACC”) (2T 177, 209).33
This resulted in a sample average ATWACC for each cost of
equity estimation method. He reported the cost of equity consistent with the sample’s average
estimated ATWACC as if the sample’s average market-value capital structure had a 52% equity
ratio, which is consistent with DTE Gas’ requested capital structure in this case. The best
estimate for the range for the cost of equity for a gas distribution company of average business
risk and a capital structure with a 52 percent equity ratio is 10.0% to 11.0%; however, DTE Gas
has a higher risk than the average company in the sample because of economic conditions, as
well as Company-specific reasons. Thus, Dr. Vilbert’s recommended ROE of 10.75% is based
31 The risk positioning approach is sometimes called the risk premium approach, and consists of analyses using the
Capital Asset Pricing Model (“CAPM”) and the Empirical CAPM (“ECAPM”) (2T 177, 209).
32 Staff and the AG also used the risk premium method, which lacks a strong basis in financial theory. It also suffers
from a significant shortcoming because it assumes that the spread between the equity return and the bond yield will
remain unchanged, which is unlikely. Dr. Vilbert also expressed concerns about Mr. Coppola’s flawed application of the risk premium method (2T 251-52).
33 The ATWACC is calculated as the weighted average of the after-tax cost of debt capital and the cost of equity.
The ATWACC is commonly referred to as the weighted-average cost of capital (“WACC”) in financial textbooks,
and is a fundamental method used by financial economists to measure the cost of capital. A number of regulators in
the United States and around the world rely on the ATWACC to set rates. The ATWACC is important because it
allows an “apples to apples” comparison between the sample companies’ cost of capital estimates and the cost of
capital for DTE Electric by eliminating differences in financial risk due to differences in capital structure. The
ATWACC avoids inconsistencies that could arise from estimating the cost of equity for sample companies without
considering differences in financial risk inherent in each company’s capital structure (the higher the debt-to-equity
ratio, the higher the financial risk, and the higher the cost of equity) (2T 183-85, 255-58).
23
on the financial risk inherent in a 52% equity ratio for DTE Gas, the sample ATWACC
estimates, and the relative risk of DTE Gas compared to the sample (2T 179, 208-209, 223-24).
Simply put, capital structure affects financial risk (the higher the debt/equity ratio, the
higher the financial risk), which affects the estimated cost of equity (the higher the financial risk,
the higher the return needed to compensate shareholders for the risk). The ATWACC provides
an “apples-to-apples” comparison among the returns of sample companies with different capital
structures. The ATWACC is also well recognized in academic literature, and used extensively as
a standard methodology in finance. Failure to consider financial risk (risk shifted to equity
holders from the use of debt in a company’s capital structure) among the sample companies and
DTE Gas could lead to unjust and inappropriate ROE estimates (2T 184-85).
In contrast to Dr. Vilbert’s analysis and recommendation of 10.75%, Staff developed an
ROE range of 9.00% to 10.00% with a recommendation of 10.00% (3T 1197-98). The AG
recommended 9.75% (2T 1045, 1048, and 1058). Both the Staff and AG recommendations are
understated due to errors in methodology and adjustments. In addition, although the witnesses
suggest some recognition of DTE Gas’ risks, the uncertainty in the capital markets, the more
challenging Michigan economic environment, and the differences in financial risk for DTE Gas
as compared to sample companies justifies an increase in the recommended ROE for DTE Gas
relative to the sample companies (2T 179, 208-209, 223-24, 230-31, 233-34).
1. CAPM and ECAPM Estimates.
Dr. Vilbert developed risk positioning estimates based on the CAPM and on an empirical
approximation to the CAPM (“ECAPM”). The CAPM is based on the idea 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
24
additional return, or risk premium, required for bearing incremental risk using (a) a risk free rate,
(b) beta,34
and (c) a market risk premium (2T 177, 209-10).
As a proxy for the CAPM’s risk-free interest rate, Dr. Vilbert used the 2.7% yield on the
10-year U.S. Treasury bond forecasted by Blue Chip Economic Indicators to be in effect in 2016,
and adjusted it upward by 30 bps, which is his estimate of the representative maturity premium
for the 20-year over the 10-year Treasury bond (2T 210-11).35
Dr. Vilbert conducted analyses using 6.5%, 7.5% and 8.5% for the market risk premium
(“MRP”). He explained that he would typically view an MRP of 6.5% over the long-term bond
rate as reasonable, but current market conditions suggest a 7.5% or 8.5% value is more
appropriate at this time (2T 212-13, 230, 343-45). Dr. Vilbert used a 0.77 average beta reported
by Value Line (2T 214-15).
Staff developed a 6.30% MRP, which Dr. Vilbert explained was unreasonably low.
Regulatory cost of capital experts in the U.S. commonly base the MRP on the historical average
MRP going back to 1926, which is the first year when high quality data on market returns is
available. Currently, the long-term historical average is 7.0%. Mr. Coppola used an MRP
estimate of 7.0%, and Staff also did so in its work papers. The use of 6.5% and 7.5% remains
34 Dr. Vilbert explained that the basic idea behind beta is that risks that cannot be eliminated by diversification in
large portfolios matter more than those that can be eliminated by diversification. 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 average when the market fluctuates (2T 213). 35 Dr. Vilbert explained that long-term rates are the relevant benchmarks because short-term Treasury bill yields
have been driven down to artificially low levels by the Federal Reserve’s efforts to stimulate the economy. Risk
positioning estimates using short-term Treasury bill yields as the risk-free interest rate are sometimes less than the
company’s cost of debt, which is unreasonable because equity is always riskier than debt and requires a higher cost
of capital, since debt holders are paid before equity holders in the event of bankruptcy or financial distress (2T 211).
Dr. Vilbert would normally use the 15-day average yields on long-term (20-year) Treasury bonds, but he did not
believe that that the current yield on the long-term Treasury bond is a good estimate for the risk-free rate that will
prevail over the relevant time when DTE Gas’ rates go into effect (2T 210).
25
appropriate to address concerns about using more recent historical averages and the need to
address the current economic environment. The average beta in Staff’s proxy group is 0.77%.
Therefore, using an MRP in the 6.5% to 8.5% range (approximately 0.2 to 2.2 percentage points
higher than Staff’s 6.30%) would raise Staff’s CAPM cost of equity estimates by approximately
15-170 basis points. Mr. Coppola used the same sample, and therefore the same beta, as Dr.
Vilbert. Therefore, using an MRP in the 7.5% to 8.5% range, instead of his 7.0%, would raise
his CAPM cost of equity estimates by approximately 40-150 basis points. (2T 241-43).
Dr. Vilbert 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. Vilbert 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 (2T 215-16, 245-46; Exhibit A-29, Schedule V1).
Staff suggested that the use of adjusted beta in the CAPM is redundant with the
application of the ECAPM (3T 1194-95). Dr. Vilbert 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 (2T 230, 247-50).
Neither the AG nor Staff adjusted for this empirical observation. Had they recognized
and adjusted for this underestimation, then their ROE estimates would have been approximately
12.5 to 37.5 basis points higher (2T 250).
26
Dr. Vilbert’s CAPM analyses produced ROE estimates of 10.0% to 11.3%. His ECAPM
analyses produced ROE estimates of 10.2% to 11.5% at a 0.5% sensitivity, and 10.5% to 11.8%
at a 1.5% sensitivity. He explained, however, that the ECAPM numbers deserve more weight
than the CAPM numbers because the ECAPM adjusts for empirical findings. The results of
ECAPM Scenario 1 do not fully adjust for the still-elevated market risk premium in the capital
markets. Thus, the focus should be on ECAPM Scenario 2 and 3 results ranging from 10.8% to
11.8% (2T 219, 246).
2. DCF Estimates.
Dr. Vilbert 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 (2T 219). The
approach is widely accepted by regulatory commissions, and provides useful insight regarding
the cost of capital based on forward-looking metrics. The DCF method is particularly valuable
in the current economic environment because of the effects on the capital markets of the Federal
Reserve’s efforts to maintain interest rates at historically low levels, which bias the CAPM and
ECAPM estimates downward (2T 220-21).
In order to apply the DCF model, two components are required: (1) the forecasted
earnings growth rates; and (2) the long-term growth rate. Dr. Vilbert used earnings growth rates
from Bloomberg and Value Line for companies in the gas utility sample. He used the October
10, 2015 (the most recently available at time of filing) long-run GDP growth forecast from Blue
Chip Economic Indicators for the long-term growth rate. The corresponding ROE estimates are
12.3% for the single-stage model, and 9.9% for the multi-stage model (2T 221-23).
The AG and Staff used the single-stage 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 approximately 20-25 basis points. Staff’s calculation also
27
erroneously applied the previous quarter’s dividend rather than an estimate of the expected
quarterly dividend, and relied on overlapping growth rate estimates from reporting services (2T
238-40).36
3. DTE Gas’s Relatively High Risk Justifies a Higher Return on Equity.
Companies such as DTE Gas rely on investors in capital markets to support efficient
business operations. These investors have been dramatically affected by the financial crisis. An
investor will not make or maintain an investment unless it provides a return corresponding to its
risk. The higher the risk, the higher the required return. There have been material improvements
in the capital markets since the height of the financial crisis, but the economic situation in the
United States and much of the world remains uncertain, and investor risk aversion remains
elevated relative to pre-crisis periods. Thus, there is an increased cost of capital for all risky
investments, including regulated utilities (2T 177-79, 186-94, 231-34, 261, 269-70).
DTE Gas has not had a recent general rate case with a contested ROE issue. In DTE
Electric’s last general rate case, however, the ALJ recommended an ROE of 10.0%, in
accordance with Staff’s recommendation. The Commission instead set DTE Electric’s ROE at
10.3%, explaining in part that: “The Commission finds that an ROE of 10.3% will best achieve
the goals of providing appropriate compensation for risk, ensuring the financial soundness of the
business, and maintaining a strong ability to attract capital . . . DTE Electric has an ambitious
capital investment program, much of which is related to environmental and generation
expenditures that are unavoidable and are saddled with time requirements” (December 11, 2015
Order in Case No. U-17767, pp 54-55).
36 Mr. Coppola further acknowledged that prices of proxy companies had recently escalated, which depressed the
dividend yield (3T 1051), and that “a potential 10% correction in utility stock prices would produce a 0.40%
increase in the cost of capital under the DCF approach” (3T 1058).
28
In DTE Electric’s prior general rate case, the ALJ recommended an ROE of 10.15%,
which was the midpoint of Staff’s 9.85% to 10.35% range. The Commission instead set DTE
Electric’s ROE at 10.50%, explaining that the ALJ’s recommendation “underestimates to some
extent the company’s overall risk profile, and the Commission finds that balancing the interests
of the ratepayers in just and reasonable rates against the need for Detroit Edison to continue to
attract capital from the financial markets justifies setting its ROE at 10.50%” (October 20, 2011
Order in case No. U-16472, p 40). The Commission also previously recognized that “economic
conditions in Detroit Edison’s service territory remain uncertain . . . [and] the company’s risk
environment will continue to be challenging . . . .” (January 11, 2010 Opinion and Order in Case
No. U-15768, pp 20-21). Given current economic conditions and those expected for the
foreseeable future, it would be a mistake to reduce DTE Gas’ allowed ROE as Staff and the AG
suggest.37
In the current environment of low demand growth and falling natural gas consumption by
U.S. households, DTE Gas’ lack of a full weather normalization adjustment mechanism typical
to gas LDCs, places it at increased risk of under-recovering its cost of service relative to the
companies in Dr. Vilbert’s sample that benefit from such mechanisms (2T 206-207). DTE Gas
also faces revenue risk because its End Use Transportation (“EUT”) customers, which are its
largest commercial and industrial customers, have the ability to bypass DTE Gas and take
service directly from interstate pipeline companies (2T 207, 593, 596). Moreover, and in
addition to ongoing uncertainty in the capital markets (2T 177-79, 186-94), DTE Gas faces
increased risk of under-recovery due to Michigan’s economy, which is heavily dependent on the
37 Dr. Vilbert further noted that utility ROEs have decreased in recent years during a period of declining and low
interest rates, but interest rates are expected to rise, and DTE Gas’ ROE is being set on a forward-looking basis (2T
262-63). Also, Mr. Coppola’s suggestion that utilities with low authorized ROEs have been able to raise capital (3T
1059) neglects to consider the potentially onerous conditions that such utilities must face to do so (2T 236, 265).
29
auto industry. DTE Gas’s service territory is largely in Southeastern Michigan including Detroit,
which has a weak economy. Therefore, DTE Gas has higher-than-average business risk relative
to companies in Dr. Vilbert’s sample (2T 142-43, 206-208, 237).
Staff seemed to interpret credit ratings to indicate that DTE Gas’ equity is less risky than
the equity of the average proxy group company. However, Dr. Vilbert disagreed by explaining
that a credit rating is a measure of the default risk on a company’s debt. It measures the
company’s total risk and not its systemic or non-diversifiable risk, which is important to
shareholders (2T 231, 252-54).
Staff also misleadingly compared Moody’s corporate credit ratings for DTE Gas and the
proxy group (3T 1199). However, if Staff had looked at company/issuer ratings, then it would
have found that DTE Gas’ BBB+ company credit rating is actually one notch below the sample
average. Staff also inappropriately looked at senior secured credit ratings (which are issue-
specific for secured bonds that provide collateral to bondholders in the event of default; i.e., the
secured rating depends on what is used as security) instead of company/issuer credit ratings
(which are designed to reflect the company’s overall creditworthiness) (2T 253-54).
4. Any Reduction of Equity in DTE Gas’s Capital Structure Would Require a
Higher Return on Equity.
A company’s cost of equity and capital structure are inextricably intertwined because the
use of debt increases the company’s financial risk, which 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. Vilbert’s recommended ROE corresponds to a 52% equity ratio. If DTE
Gas has less equity, however (and a corresponding increase in both debt leverage as well as risk),
then DTE Gas’ ROE must increase to compensate for the increased risk (2T 140-41, 184-85).
30
Only Mr. Coppola disagreed with DTE Gas’ proposed 52% equity ratio (3T 1044), but his own
calculations show that the sample average equity ratio is 54% (Exhibit AG-28, page 1, line 7,
column (c)).
5. Summary and Recommendations Regarding DTE Gas’s Cost of Equity.
DTE Gas’s ECAPM numbers deserve more weight than the CAPM numbers because the
ECAPM adjusts for consistent empirical findings that the CAPM underestimates the cost of
capital for low-beta companies such as DTE Gas. The results of ECAPM Scenarios 2 and 3 are
more reliable than the results for Scenario 1 because Scenario 1 ignores the increased MRP
resulting from the ongoing uncertainty in the capital markets. For companies of comparable risk
to DTE Gas at a capital structure with approximately 52% equity, the cost of equity falls in the
range of 10.0% to 11.0%. DTE Gas has higher risk than the average sample company, so the
corresponding ROE estimate for DTE Gas is 10.75% (2T 223-24, 230-31, 237).
It is also important to maintain DTE Gas’ access to capital. Maintaining a solid credit
rating and outlook is one important aspect to maintaining access to capital. A reduction in the
allowed return on equity would signal a likely reduction in cash flow, and put downward
pressure on DTE Gas’ credit metrics. Maintaining a strong credit rating is particularly critical
during a period forecast to have substantial capital investment for infrastructure. In addition, one
can expect that the cost of capital will increase as the Federal Reserve continues to adjust its
monetary policy. Therefore, estimates at the upper end of the ROE range are more
representative of the cost of capital expected over the next three years (2T 224-25, 230-32).
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
31
capital rates of 4.98% and 10.75%. Deferred income taxes are at zero cost of capital (2T 334,
343-444; Exhibit A-11, Schedule D1, and Attachment A, page 4).
E. Overall Rate of Return.
DTE Gas’s initial sum of the weighted cost of the above-described capital components
resulted in a weighted, after-tax 6.04% overall rate of return (2T 337, 341; Exhibit A-11,
Schedule D1). Both Staff and DTE Gas agree that a 1.6464 revenue conversion factor is
appropriate for the projected period (2T 339; Exhibit A-10, Schedule C2 and Exhibit S-4,
Schedule D-1). The corresponding weighted pre-tax overall rate of return is 8.74% (Exhibit A-
11, Schedule D1). The corresponding weighted pre-tax rate of return used for the calculation of
the IRM surcharge is 11.59% (2T 344-45).
Notwithstanding DTE Gas’s initial sum resulting in a weighted, after-tax 6.04% overall
rate of return, for the purpose of narrowing the number of contested issues in this proceeding,
DTE Gas supports the use of the 6.02% overall rate of return in the derivation of its revenue
requirements, a corresponding weighted pre-tax overall rate of return of 8.70% and the use of the
11.59% pre-tax overall rate for the return in calculating the IRM surcharge (Attachment A, page
4). As discussed above, Staff’s weighted cost of capital of 5.73% is deficient due to the use of an
understated 10.0% return on equity.
VII. ADJUSTED NET OPERATING INCOME AND OTHER REVENUE-RELATED
ISSUES.
DTE Gas’s adjusted Net Operating Income (“NOI”) is projected to decline by $65.1
million from $178.8 million in the 2014 historical test year to $113.7 million in the projected test
year (2T 329, 333, 337, 483; Exhibit A-10, Schedule C1). DTE Gas’s NOI projected reduction
is primarily due to increased operating costs resulting from inflation, growth in net plant, and a
higher shared asset charge for new plant at DTE Electric. In addition, revenues are forecasted to
32
decrease due to the discontinuation of the current IRM surcharge, decreased sales, and lower
midstream revenues, as further discussed below (2T 483; Exhibit A-10, Schedule C1.1). Based
upon the NOI related adjustments discussed in Section II above, the Company agrees to adopt
those adjustments and update its projected test year NOI to approximately $116.1 million
(Attachment A, page 3).
A. Throughput.
Throughput represents the total gas sales and transportation volumes delivered to end-use
customers during the test period. DTE Gas projects 1,248,701 sales customers, 605 End Use
Transportation (“EUT”) customers, sales volumes of 147.1 billion cubic feet (“Bcf”), and
transportation volumes of 119.9 Bcf (3T 537, 543, 600; Exhibit A-12, Schedules E1, E8, and
E9).
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”)38
that occurred during that time period. Weather-normalized historical consumption is then used
to forecast future consumption (2T 539-40).
Mr. Chapel, the Company’s Manager, Market Forecasting, explained that in accordance
with the Commission’s Orders in Case Nos. U-15985 and U-16999, DTE Gas presented normal
HDDs based on 15-year normal weather calculated from 2000 through 2014 (updating the
Commission’s approved methodology to reflect the most recently completed calendar years) and
38
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 (2T 540).
33
that he also prepared a forecast using 30-year (1985 – 2014) weather normalization (2T 541;
Exhibit A-12, Schedules E6 and E7).
No party appears to support the use of 30-year weather normalization. Accordingly, the
Commission should approve the use of DTE Gas’s 15-year weather forecast methodology and
eliminate the requirement of the Company to perform 30-year weather normalization
calculations.
2. Customer Usage.
DTE Gas’s weather-normalized 2014 test period customer usage was approximately
161.0 Bcf. DTE Gas’s projected test period usage is 147.1 Bcf (2T 539, 543; Exhibit A-12,
Schedule E1, p 1, line 16). This 14.0 Bcf reduction is due to conservation and increasing gas
heating values, which is partially offset by gains in the number of customers (2T 543).39
Increasing heating values can lower consumption since less gas is needed to generate the
same heating requirements (2T 544). The Company’s system average heating value began
increasing in the middle of 2014 and the Company has projected that it will continue to do so
through the projected test year (2T 545-47, 553). Since ethane (with a higher heating value than
methane) is being left in the natural gas stream rather than being processed out, the Company is
receiving higher Btu content gas at some of its main pipeline interconnections: this raises the
Company’s overall system average heat content. Ethane prices are expected to remain low, so
there will continue to be an economic incentive to leave ethane in the natural gas stream, which
is expected to continue to increase the gas stream’s heat content (2T 547-53). The Company’s
system-weighted average heating value for the projected test period is 1,087 Btu/cf (2T 547,
554).
39 Mr. Chapel further discussed residential, commercial, and industrial sales forecasts (2T 554-65).
34
The AG asserts that the BTU content of gas stabilized at around 1,042 Btu/cf in the first
quarter of 2016 (3T 995). Staff similarly suggested that heating values have plateaued around
1,045 Btu/cf and should not be expected to significantly change in the near future, therefore Staff
recommends using 1,045 Btu/cf for the projected test year (3T 1218-19).40
Mr. Chapel disagreed based on the system average heating values for the first 4 months
of 2016: 1,045 Btu/cf (January), 1,046 Btu/cf (February), 1,047 Btu/cf (March), and 1,051
Btu/cf (April). All of these heating values are higher than Mr. Coppola’ suggested 1,042 Btu/cf.
In fact, the last three months are higher than Staff’s suggested 1,045 Btu/cf. Moreover, these
high and continually-increasing heating values show an upward trend rather than stabilization
(2T 575-76).
AG witness Mr. Coppola also inaccurately asserted that the Company’s EO forecast
assumptions are duplicative to the on-going overall rate of conservation (3T 996). Mr. Chapel
explained that the Company’s EO program has conservation goals that the Company expects to
achieve due to ongoing Company efforts to promote conservation. These goals are described in
the Company’s EO filings before the Commission and the forecasted conservation assumptions
are modeled in the forecast in this proceeding (2T 575-76).
3. Exelon Energy Company (“Exelon”).
Exelon customers (formerly served by DTE Gas) 41
are removed from the sales forecasts
because they receive all of their gas services from Exelon instead of DTE Gas (2T 566). DTE
40 The difference between DTE Gas’ and Staff’s system heating value is 3.8638%. Staff applied this percentage to
increase DTE Gas’ projected monthly sales volumes for all rate classes and EUT rate classes (3T 1227; Exhibit S-
10.1).
41 DTE Gas and Exelon entered into an easement agreement that grants Exelon a right to pipeline capacity on DTE
Gas’ distribution system, and thereby gives Exelon the ability to compete in the overlapping service territories of
DTE Gas and DTE Electric (2T 565-66). The Commission approved the easement agreement (February 14, 2001
Order Approving Special Contract in Case No. U-12825).
35
Gas projects $5.85 million of annual revenue (2T 485; Exhibit A-10, Schedule C3, column (d),
line 3). No parties opposed the Company’s projection of Exelon revenue.
4. Cost of Gas.
Mr. Chapel projected a $3.920/Mcf jurisdictional cost of gas for November 2016 through
March 2017, and a $3.605/Mcf jurisdictional cost of gas for April 2017 through October 2017.
This price bifurcation represents the projected jurisdictional rates in each of the GCR periods
covering the projected test year (2T 567).
Staff calculated $3.6089/Mcf as the average cost of gas for the projected test year, based
on the Company’s natural gas purchases, the portion of those purchases already at a fixed price
pursuant to the Company’s Commission-approved fixed-price plan, the Company’s projected
pipeline transportation costs (including fuel), and a five day average of the New York Mercantile
Exchange (“NYMEX”) strip taken from January 11 to 15, 2016 of $2.714/Dth (3T 1231-35;
Exhibit S-10.3 Revised).
Mr. Chapel explained that the Company’s direct case used the projected test year
(November 2016 through October 2017) NYMEX forward strip price on October 27, 2015 of
$2.846/Dth. The June 1, 2016 NYMEX settlement (the most recent NYMEX data available at
the time of rebuttal filing) shows the average NYMEX forward strip price for the projected test
year to be $2.959/Dth. The Company stands by the projected test year cost of gas as presented in
its direct case, even though the most recent test year NYMEX strip supports a higher cost of gas
(2T 577-79).
36
5. End-Use Transportation (“EUT”).
DTE Gas had 611 End-Use Transportation (“EUT”) customers42
and 124.6 Bcf of
volume in the 2014 historical test period. DTE Gas forecasts 605 customers and 119.9 Bcf in the
projected test period (2T 59-600; Exhibit A-12, Schedule E-8, column (c) and Schedule E-9,
column (h)). DTE Gas had $77.8 million of total EUT revenue in 2014, and projects $75.9
million of total EUT revenue in the projected test period (2T 600-601; Exhibit A-10, Schedule
C3.2, columns (b) and (c)).
Staff witness Ms. Royal agreed with the Company’s approach to projecting the sales
forecast and agreed with DTE Gas forecast of 605 EUT customers (3 T 1226; Exhibit S-6
Schedule F3). The only difference between Company and Staff’s EUT volume forecast is
related to the heating value (see Section VII A.2).
6. Long-Term Fixed-Price Contract Revenues.
DTE Gas has entered into long-term contracts, some of which are special contracts, with
customers that have minimum revenue commitment terms. DTE Gas’s projected test year
revenues do not include minimum revenue commitment revenues, since it is assumed that all
minimum commitment levels are achieved so no separate payments would be necessary under
the contracts. This is the same methodology that the Commission adopted in DTE Gas’s prior
rate cases (Case Nos. U-13898 and U-15985) and is consistent with the settlement that the
Commission approved in Case No. U-16999 (2T 602). No parties opposed the Company’s
position.
42 EUT customers are DTE Gas’ 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 (2T 593).
37
B. Midstream Revenue.
DTE Gas realizes Midstream revenue from selling storage and transportation services to
off-system customers.43
These sales maximize the utilization of DTE Gas’s utility assets and
help mitigate rate increases for all customers (2T 602-603). DTE Gas projects $74.4 million of
Midstream revenue, consisting of $35.0 million of storage revenue and $39.4 million of
transportation revenue (2T 606-607).
The Company’s proposed $35.0 million of storage revenue is based on 51.7 Bcf of
storage capacity. This includes $29.9 million of Contract Storage revenue and $5.2 million of
Park and Loan revenue (2T 609; Exhibit A-10, Schedule C3.3, column (f)).44
Contract Storage
revenue consists of 43.4 Bcf of capacity sold and under contract through March 31, 2017, and
28.6 Bcf of capacity sold and under contract through the remainder of the test period ($20.8
million in revenue), plus 8.4 Bcf of storage capacity to be sold for the 2016/17 storage cycle (i.e.,
starting April 1, 2016) and 14.7 Bcf of storage capacity to be sold for the 2017/18 storage cycle
(i.e., starting April 1, 2017), which are expected to contribute an additional $9.1 million of
revenue (2T 610). Park and Loan revenue is based on average annual revenue from 2011 through
2013 (2T 605-606, 614).
43 An off-system customer transports gas through the DTE Gas storage and transmission system to an off-system
location. These customers ultimately consume gas outside the DTE Gas service territory, in contrast to GCR sales,
GCC and EUT customers (“on-system customers”). (2T 603). DTE Gas provides transportation services to off-
system customers that want to transport gas across DTE Gas’ transportation system from a specified receipt point to
a different delivery point (2T 615).
44 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 period of time for ratable withdrawal over a different specified
period of time (2T 613). GIK is not collected because the GIK value is embedded in the Park and Loan service rate
(2T 615).
38
C. Other Operating Revenue.
DTE Gas’ other operating revenue is projected to be $92.8 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) other gas revenues, (7) gas-in-kind,
(8) Blue Lake investment income, (9) Vector lease interest, (10) Grantor Trust income, and (11)
short-term interest income (2TG 620-25; Exhibit A-10, Schedule C3).
DTE Gas disagrees with Staff’s proposal to increase miscellaneous revenues by $855,000
for non-municipal demolition fees. However, DTE Gas accepts Staff’s amount of $855,000, but
only if the fees are credited to plant as that is the most appropriate accounting treatment (2 T
513). Staff stated that if the Commission disagrees with Staff that miscellaneous revenue is the
right way to flow these revenues through, then Staff’s projected revenue should be applied to
plant-in-service as suggested by the Company (3 T 1242).
D. DTE Gas’s Operating and Maintenance (“O&M”), Administrative and General
(“A&G”), and Infrastructure Costs Are Reasonable to Maintain Safe and
Reliable Service.
1. O&M Expenses.
DTE Gas’s adjusted O&M expense was $341.4 million in 2014, and is projected to
increase to $389.9 million in the projected test period, which is a reasonable and prudent amount
that would provide the Company with the necessary resources to assure continued safe and
reliable service (2T 488-89; Exhibit A-10, Schedule C5, line 8, columns (f) and (l)). The major
categories of O&M expense, as reflected on Exhibit A-10, Schedule C5, are Natural Gas
Storage; Transmission; Distribution; Customer Service and Marketing; Administrative and
General; Pensions and Benefits; and AMI Savings (2T 489-90).
Although the Company’s initial filing supported an O&M expense of $389.9 million, the
Company adopts the following five O&M related adjustments: 1) Staff’s $4.9 million reduction
39
for 2015 update and Staff’s inflation; 2) decrease in share asset charge of $1.2 million, 3) Staff’s
increase to injuries and damages of $0.7 million, 4) elimination of Executive Supplemental
Retirement Plan expense of $0.8 million and 5) Staff’s reduction for accrued vacation expense of
$1.8 million. Accordingly, the Company is now supporting a total O&M expense amount of
$381.8 million (Attachment A, page 3).
Company witness Ms. Tomina explained and supported the O&M expenses for Natural
Gas Storage (2T 939-41; Exhibit A-10, Schedule C5.1), Transmission (2T 941-50; Exhibit A-10,
Schedule C5.2), and Distribution (2T 950-56; Exhibit A-10, Schedule C5.3) as reasonable and
necessary.
Company witness Mr. Sparks explained and supported the actual and projected O&M
expenses for the Customer Accounts, Customer Service and Marketing organizations as
reasonable and necessary (2T 817-23; Exhibit A-10, Schedule C5.4). These O&M expenses
(including rate case adjustments) were $84.536 million for the 2014 historical test period, and are
expected to increase to $87.882 million for the projected period ending October 31, 2017
(Exhibit A-10, Schedule C5.4, line 22). Mr. Sparks testified that the projected increase is based
only on inflation,45
and the projected O&M expenses are further supported by an “analysis of
past expenditures, and the projected resource requirements to meet the Company goals for
continued improvement in customer service” (2T 823).
Company witness Ms. Uzenski explained and supported the actual and projected O&M
expenses for the Administrative and General (“A&G”) category as reasonable and necessary (2T
490-96; Exhibit A-10, Schedule C5.5). She explained that many of these costs are charged to
45 The rate of inflation is the CPI of 0.2% for 2015, 1.8% for 2016, and 1.9% for the first 10 months of 2017 (2T
489, 822).
40
DTE Gas by the Corporate Staff Group (“CSG”), which is a shared services organization that
includes corporate staff functions. This business model provides efficiencies, cost savings, and
enhanced governance and internal controls (2T 490). Customers benefit from a leaner, more
efficient organization, and cost-effective processes. DTE Gas’ proposed CSG cost allocation
methodology is the same methodology that the Commission approved in the Company’s prior
general rate cases (Case Nos. U-13898 and U-15985), and DTE Electric’s last five general rate
cases (Case Nos. U-13808, U-15244, U-15768, U-16472, and U-17767) (2T 493). Total
adjusted historical O&M expense for A&G was $76.310 million, which is projected to increase
to $88.133 million in the projected test year (Exhibit A-10, Schedule C5.5, line 20, columns (f)
and (l)). The projected increase is based on inflation and other adjustments that Ms. Uzenski
explained (2T 494-96).
Company witness Mr. Sitkauskas explained and supported how Net O&M savings from
AMI are projected to be $3.6 million in the projected test year (Exhibit A-10, Schedule C5.6, line
9, column (h)), and are further discussed in Section VII. E. No intervenor disputed these
projected Net O&M Savings from AMI.
Company witness Mr. Wuepper supported projected employee benefits of $36.7 million
(Exhibit A-10 Schedule C5.9) and compensation expense as reasonable and valid (2 T 854) and
are discussed further in Section VII.D.1.d.
a. Inflation and 2015 Actuals.
The Company used a 2014 historical test-year. In contrast, Staff Witness Welke
essentially used 2015 as the Historical Test-Year. Staff’s use of a 2015 test year is the most
current actual O&M expense experience available. As such, using a 2015 historical test-year
O&M expense experience eliminates any forecasting inaccuracies that the Company
inadvertently made for 2015 (3T 1204).
41
Staff’s inflation adjustment is the result of using Staff’s proposed inflation of 1.45% and
2.57% versus the Company’s 1.80% and 2.30% for 2016 and 2017, respectively (3T 1204).
Since Staff’s numbers represent more current information, DTE Gas is reducing the Company’s
projected O&M expense by $4.9 million based on 2015 actual O&M and Staff’s inflation rates
(Attachment A, page 3).
AG witness Mr. Coppola proposed that no inflation should be applied to historical O&M
levels, claiming that “inflation has been negligible in recent months [and] the Company has
demonstrated the ability to reduce costs in prior years and also more recently from 2014 to 2015”
(3T 1013). However, Mr. Coppola provided no analytical basis for his conclusory assertion that
inflation has become “negligible,”46
and the Company has already included a $15.4 million
reduction in costs as a result of the normalization of 2014.
b. Shared Asset Rent Expense.
DTE Gas initially projected rent expense to be $33,682,000. However, the rent revenue
projected in DTE Electric’s concurrently pending general rate proceeding, Case No. U-18014, is
only $32,480,000. Therefore, Staff witness Welke proposed a $1.2 million reduction to shared
asset rent expense (3T 1207). In other words, Staff’s adjustment ties the rent expense projected
in this case with the rent revenue projected in the electric case (3T 1208). Although the
projected test years in the two rate cases are not the same 12 month periods, for the purpose of
narrowing the number of contested issues in this proceeding, the Company adopts Staff’s $1.2
million reduction to O&M expense relative to rent expense (Attachment A, page 3 and Section II
above).
46 “The party alleging a fact to be true should suffer the consequences of a failure to prove the truth of that
allegation.” Kar v Hogan, 399 Mich 529, 539; 251 NW2d 77 (1976).
42
c. Injuries and Damages.
Staff’s recommended Injuries and Damages expense adjustment of $0.674 million was
derived using a five-year average of Injuries and Damages expense. Staff’s methodology is the
same used by the Company. The Company used 2012 through 2014 actuals whereas Staff used
the more current 2013 through 2015 actual Injuries and Damages Expenses (3T 1206). For the
purpose of narrowing the number of contested issues in this proceeding, the Company adopts
Staff’s Injuries and Damage adjustment of $0.674 million (Attachment A, page 3 and Section II
above).
d. Employee Benefits Expense.
In its initial filing, DTE Gas supported $36.723 million of net O&M employee benefits
expense (2T 876; Exhibit A-10, Schedule C5.9, line 32, column (d)). As discussed in Section II
above, in this Brief, the Company is accepting certain O&M expense adjustments proposed by
Staff that impact employee benefit expense: 1) updating O&M expense using 2015 actuals and
more current inflation rates; 2) accrued vacation adjustment ($1.8 million); and 3) the
elimination of the executive supplemental retirement plan ($0.795 million) (Attachment A page
3). DTE Gas now supports $33.234 million for pension and benefits (Exhibit S-3 Schedule C5
Revised Staff’s). (Staff’s $32.589 plus $0.644 million for the Supplemental Retirement Plan
which the Company continues to support for inclusion in the rates set in this proceeding as
explained in Section 5d.)
43
1) Pension.
DTE Gas developed its projected pension costs based on the accounting requirements of
U.S. GAAP Accounting Standard Codification (“ASC”) 715-30 (“ASC 715-30”),47
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.
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 in the short run, the expected return is determined based on
long-term financial market expectations in order to avoid large swings in pension costs
based on short-term investment performance. DTE Gas’ estimated annual rate of return
was 7.75% for the historical period, and is assumed to be 7.75% in 2016 and 7.50% in
2017.
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 discount rates of 4.12% for the historical period, and 4.15% for
the projected period. Measuring the PBO as a present value at the beginning of the period
requires the accrual of an interest cost for the current period at a rate equal to the discount
rate. The discount rate of 4.95% for the historical period is based on the interest rate
47 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’ references to ASC 715-
30 are comparable to references to SFAS 87 in prior rate cases.
44
environment at the end of 2013, the prior fiscal year end, and projected benefit payments
from the pension plan matched against a yield curve of corporate bond rates, rated Aa or
higher, provided by DTE Gas’ independent actuarial firm, Aon Hewitt. The 4.15%
discount rate for the projected period reflects an expectation that high-quality corporate
bond interest rates at the end of 2015 and 2016 will remain essentially unchanged from
levels prevailing in August 2015.
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
estimates, differences arise whenever discount rates or actual asset returns differ from
long-range expectations (2T 855-57).
DTE Gas’s annual pension costs are expected to decrease by $7.8 million, from $21.6
million in the historical test period to $13.8 million in the projected period (Exhibit A-10,
Schedule C5.10), which after adjustments for the impact of the costs transferred and the portion
of pension costs capitalized, produces a projected pension expense of $10.2 million (2T 858-60).
Since the Commission previously excluded DTE Gas’s negative pension costs from its
revenue requirement in Case Nos. U-13898 and U-15985, the pension expense projected in this
case will be applied as a reduction to the accumulated regulatory liability, and it is not included
in the Company’s projected revenue requirement (2T 859-60).
45
2) Other Post-Employment Benefit (“OPEB”) Expenses.
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 to U.S. GAAP Accounting Standard Codification 715-60 (“ASC 715-
60”),48
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 (2T 860-62).
DTE Gas’s OPEB costs are projected to increase from a negative $32.0 million in the
historical test period to a negative $26.7 million in the projected period (Exhibit A-10, Schedule
C5.11), which after adjustments for the impact of the costs transferred and the portion of OPEB
costs capitalized, produces a projected OPEB expense of negative $17.4 million. DTE Gas’s
OPEB costs are negative in 2014 and the projected test period because in 2012 and 2013, the
Company implemented certain changes in the medical and related benefits that it provides to its
current and future retirees. These changes substantially reduced DTE Gas’s Accumulated Post-
Retirement Benefit Obligation (“APBO”). This decrease in APBO has been deferred, consistent
with ASC 715-60, as Prior Service Costs that are being amortized over four years, which is
consistent with participants in the plans being, on average, about 60% through the 10-year
vesting period (2T 862-65).
DTE Gas has externally funded its OPEB costs, and projects funding in accordance with
Case No. U-16999, as modified by funding of the New Hire Retirement Voluntary Employee
Beneficiary Association (“VEBA”). The Company proposes to defer the projected net negative
48 ASC 715-60 superseded SFAS 106, but did not change the underlying accounting standards. DTE Gas’
references to ASC 715-60 are comparable to references to SFAS 106 in prior rate cases.
46
$17.4 million OPEB expense to a regulatory liability (Exhibit A-10, Schedule C5.9, line 5), in
accordance with the Commission’s approval of a similar proposal by DTE Electric (December
11, 2015 Order in Case No. U-17767, p 69). Staff is not opposed to the Company’s use of the
OPEB deferral mechanism (3T 1121), and it was undisputed by any other party. Therefore, the
negative OPEB expense is not included in the Company’s proposed revenue requirement (2T 79-
82, 496-99, 865-66).
3) 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 $17.6 million in the historic
period, to $21.2 million in the projected period, based on projected annual healthcare inflation of
7.5% (2T 686; Exhibit A-10, Schedule C5.9).
AG witness Mr. Coppola suggested that the Company’s active health care costs should be
reduced by $2.8 million, reasoning that it is inappropriate to use Company health care consultant
Aon Hewitt’s 7.5% annual escalation rate for retirees less than 65 years old because: “It is a
known fact that health care costs are typically higher for older employees and retirees” (3T
1017). Mr. Coppola’s reasoning is unsound. The absolute level of healthcare costs is higher for
older employees and retirees than it is for active employees, but this is irrelevant to the year-to-
year rate of change, which is what is measured by the 7.5% annual escalation rate (2T 926-27).
AG witness Mr. Coppola suggested that the 7.5% annual escalation rate is unsupported,
but an age-stratified analysis of the claims incurred by the Company’s self-insured healthcare
plans demonstrates that the rate of change in healthcare costs for plan participants 50 to 65 years
old are no higher than for the general population, thereby refuting AG witness Coppola’s claim
that he 7.5% annual escalation rate is inappropriate (2T 927; Exhibit A-28, Schedule U1). The
7.5% annual escalation rate is also corroborated by two studies available in the public domain. A
47
PriceWaterhouse Coopers LLP (“PWC”) study projects healthcare cost increases in 2016 of
6.5%, and a Wells Fargo Insurance (“Wells Fargo”) study projects overall claims costs will
increase between 7.0% and 10.0%. The Company’s three primary managed healthcare providers
have similarly projected that overall active healthcare costs will increase, on average, 7.6% for
2016 (2T 928).
AG witness Mr. Coppola proposed a 2.5% annual escalation rate based on a simple three-
year average of increases in the Company’s active healthcare costs for 2013 through 2015 (3T
1018, the average is actually 2.6%, which Mr. Coppola presumably just rounded down). Mr.
Coppola’s methodology is unreliable, since changes in the Company’s active healthcare expense
have ranged from a 2.4% decrease in 2013 to a 10.4 % increase in 2014 (Exhibit A-28, Schedule
U2). Active healthcare costs have a predictable long-term trend, but short-term volatility.
Therefore, the 7.5% projected trend is a more reliable predictor of future expenses than Mr.
Coppola’s proposed short-term average (2T 929).
AG witness Mr. Coppola’s focus on short-term results is also misleading because the
Company has reduced its health care costs through aggressive plan-design enhancements and
improvements in the cost effectiveness of delivering benefits to its employees. The Company is
proud of its results, but these efforts tend to produce the most savings when they are
implemented. The lower costs provide a lower base for future cost increases, and then costs
resume increasing at the normal escalation rate. There is also a risk that active healthcare costs
could increase by more than 7.5% based on new government regulations. For example, new
regulations issued by the Equal Employment Opportunity Commission related to company
sponsored wellness programs could increase the Company’s cost by almost 2.0% when
implemented in 2017 (2T 932).
48
There is no sound basis to conclude that the Company’s future active health care costs
will increase by any less than the 7.5% forecasted by the Company’s health care consultant, Aon
Hewitt. Therefore, Mr. Coppola’s suggested reduction to the Company’s projected active health
care costs should be rejected (2T 930-32).
4) Non-Qualified Benefit Costs.
DTE Gas has four employee benefit programs that do not qualify for tax-advantaged
status under the Internal Revenue Code (“IRC”): the Executive Supplemental Retirement Plan
(“ESRP”), the Supplemental Retirement Plan (“SRP”), the Supplemental Savings Plan (“SSP”)
and the Deferred Compensation Plan (“DCP”). The Commission has found that SSP and DCP
expenses are appropriate for recovery, but has denied recovery of ESRP and SRP costs
(December 11, 2015 Order in Case No. U-17767, p 41; October 20, 2011 Order in Case No. U-
16472, pp 66-67).
Staff removed $1,439,000 related to Supplemental Executive Retirement Plan (“SERP”),
characterizing it as a “perquisite” that is only available to a select and already highly
compensated group of employees, and reasoning that the Commission has found that these
expenses are not “commensurate with the costs to ratepayers” (3T 1207). Staff presumably
intended to refer to the ESRP ($795,000) and SRP ($644,000), which totals $1,439,000. (Exhibit
A-10, Schedule C5.9)
DTE Gas acknowledges that the ESRP provides enhanced benefits to a select group of
employees. Therefore, the Company is not disputing the Staff’s proposed exclusion of $795,000
of ESRP expense. However, the SRP is different. The SRP provides the exact same benefits
provided to all other participants in the Company’s pension plans, so there are no incremental
costs of providing the SRP. The only reason that these benefits are provided through the SRP is
because of IRC provisions. It is just part of the total annual compensation that DTE Gas offers
49
to attract and retain key employees. Customers benefit from these employees working for DTE
Gas, and DTE Gas is entitled to recover its costs of compensating those employees. Since the
Company has shown that its total compensation practices are competitive, as demonstrated by
the fact that DTE’s target executive compensation is 7% less than the midpoint of its peer group,
there is no basis for the Commission to make a finding that a portion of the total compensation is
unreasonable (2T 871-75, 924-25).49
5) Incentive Compensation.
DTE Gas has incentive compensation programs for its executives and non-represented
employees that consist of both short-term (the Annual Incentive Plan or “AIP,” and Rewarding
Employees Plan or “REP”) and multiple year (Long Term Incentive Plan or “LTIP”) components
(2T 892). Mr. Wuepper 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
(2T 892-900; Exhibit A-17, Schedules J1, J2, J3, and J4 Revised). The Company’s overall
compensation policy is to provide total compensation that is competitive with its peer groups,
including incentive compensation. The Company’s incentive compensation programs for both
its executive and non-executive employees consist of short term incentive plans provided
through the AIP, applicable to executive level employees, and REP, available to all other non-
49 Const 1963, Art 6, § 28 requires the Commission’s findings to “be supported by competent, material and
substantial evidence on the whole record.” 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 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).
50
represented employees. In addition, the Company provides a multiple year incentive plan
delivered through the LTIP, which is generally available to managers and above (2T 876-81,
892).
The performance measures included within these plans include both operating and
financial metrics. The operating measures reflected in the short term incentive plans relate to
Customer Satisfaction, Employee Engagement and Operating Excellence, as appropriately
customized for the specific business units. Within Customer Satisfaction are measures related to
improving performance as measured by J.D. Power. Also included are measures related to
improving customer service and reducing complaints to the Commission. Employee
Engagement pertains to creating a highly motivated and productive workforce as well as
improvements related to workplace safety. Operating Excellence includes six measures. These
measures relate to reducing the number of gas leaks, reducing the elapsed time for the Company
to respond to customer calls regarding leaks, lowering lost and unaccounted for gas volumes,
improving gas compression reliability, enhancing gas damage prevention effectiveness and the
installation of additional remote control valves (2T 892-98, 921).
DTE Gas seeks to recover the $11.2 million normalized historical test period expense of
these plans, which excludes the incentive compensation expense allocated to the Company for
DTE Energy’s top five executives. The components of the Company’s normalized historical test
period expenses are reflected in the table below, as differentiated for the portion of such
expenses based on operating versus financial performance measures (2T 900, 923).
51
LTIP AIP REP Total
Operating $0.0 $1.0 $2.4 $3.5
Financial $3.5 $1.3 $2.9 $7.7
Total $3.5 $2.3 $5.4 $11.2
Staff proposed the exclusion of $7,745,000, representing the portion of the Company’s
incentive compensation expense related to financial measures (3T 1204-1205). Staff’s proposal
is based entirely on the Commission’s December 11, 2015 Order in Case No. U-17767 (DTE
Electric’s most recent general rate case), where the Commission approved a partial recovery of
costs attributable to operating but not financial measures, stating that:
“[I]n the immediate case, the Commission finds that DTE Electric provided
convincing evidence that the operating (non-financial) measures for the AIP and
REP provide appreciable benefits to customers, and meet the standard set forth in
the April 28, 2005 order in Case No. U-13898 (April 28 order) and the December
23, 2008 order in Case No. U-15244 (December 23 order) . . . [discussion of
evidence omitted].
“The Commission concludes that the benefits of the operating measures are
commensurate with the cost to ratepayers, and as a result, approves the portion of
the short-term incentive compensation plans attributable only to the operating
measures of customer satisfaction, employee engagement, and operating
excellence, for a total of $14.487 million. In regards to the financial measures of
the short-term incentive compensation plans, the Commission finds that there is
insufficient evidence to conclude at this time that the benefits to ratepayers are
significant and therefore, they are not approved in this proceeding.
“Similarly, regarding the LTIP, the Commission finds that the company failed to
demonstrate that the benefits to ratepayers are commensurate with the costs. The
LTIP is too closely tied to company earnings and cash flow requirements that
overwhelmingly benefit shareholders” (December 11 Order in Case No. U-17767,
pp 76-77).
DTE Gas certainly agrees with the Commission to the extent that it approved incentive
compensation cost recovery. However, just 20 days earlier, the Commission approved
Consumers Energy Company’s (“Consumers”) cost recovery for its employee incentive
52
compensation program (“EICP”), which is structured so that 50% of an employee’s incentive is
based on achievement of operational and performance measures, and the other 50% is based on
the achievement of financial measures (November 19, 2015 Order in Case No. U-17735, pp 73-
74, 78).
DTE Gas’ incentive compensation programs are similar to Consumers’ program (2T 885-
86). Therefore, it is inappropriate for the Commission to limit DTE’s incentive compensation
cost recovery to operating (non-financial) measures. The Commission did not draw such a
distinction in approving Consumers’ operating and financial incentive compensation cost
recovery.50
Staff witness Mr. Welke’s total exclusion of the incentive compensation expense related
to financial measures is also unjustified because it overlooks the cost/benefit analysis performed
by Mr. Wuepper related to the financial measures as reflected Exhibit A-17, Schedule J4
Revised. While the total net customer benefits were quantified to be $4.217 million, a portion of
those benefits related to the financial measures, as reflected in the table below.
50 DTE Gas has due process rights under the Fourteenth Amendment to the United States Constitution. Michigan’s
Constitution similarly provides DTE Gas with the right to fair and just treatment in MPSC proceedings: “No person
shall be compelled in any criminal case to be a witness against himself, nor be deprived of life, liberty or property,
without due process of law. The right of all individuals, firms, corporations and voluntary associations to fair and
just treatment in the course of legislative and executive investigations and hearings shall not be infringed.” Const
1963, art 1, § 17.
53
Total Incentive Plans
Expense Benefit Net
(000's Omitted)
DTE Gas Average Return on Equity 2015-
2017
170 (437) (267)
DTE Gas Operating Earnings
629 (1,619) (989)
DTE Gas Adjusted Cash Flow
1,942 (2,946) (1,004)
Total Related to DTE Gas Financial
Measures
2,741 (5,002) (2,261)
Total DTE Energy Shareholder Return vs.
Peer Group
1,989 0 1,989
DTE Energy Balance Sheet Health- FFO to
Debt
540 (1,078) (538)
DTE Energy Operating Earnings Per Share
1,628 0 1,628
Total DTE Energy Financial Measures
4,157 (1,078) 3,079
Total Incentive Compensation Related to
Financial Measures
6,898 (6,080) 818
Although the total customer benefits of the financial measures were slightly less than the
related incentive compensation expense, the customer benefits derived from financial measures
related explicitly to DTE Gas were almost twice as large as the related incentive compensation
expense. While the precise measure of customer benefits of the DTE Energy financial measures
related to total return to shareholders and operating earnings per share escape quantification,
there can be little doubt that customers benefit from DTE Energy being financially healthy with
access to the capital markets. Since the customer benefits of the financial measures offset almost
90% of the related incentive compensation expense, it is unreasonable to conclude that 100% of
the incentive compensation expense related to the financial measures should be excluded from
54
the Company’s revenue requirements (2T 914-16).
Recovery of all requested incentive compensation expense is fully justified because even
the portion of the variable compensation tied to financial metrics does not simply benefit
shareholders as reflected in the table above. Instead, customers benefit from incentive
compensation measures that focus on earnings and cash flow because the ability to exceed the
annual goals is dependent on the Company realizing productivity enhancements and cost
savings, which allows the Company to postpone rate increases and produces lower revenue
requirements when rate increases become unavoidable. Proof of the benefits of the cost and
productivity focus provided by the use of earnings and cash flow measures is provided in the fact
that the Company’s O&M expenses have increased by dramatically less than inflation over the
last five years. Indeed, the Company’s projected O&M expense as filed for the projected test
year is $24.3 million less than it would have been if the Company’s O&M expense increased by
the rate of inflation since 2005. DTE Gas’s financial performance also directly affects its ability
to raise capital, as well as the cost of capital, that it needs to fund its operations.51
Accordingly,
the costs of encouraging managers and employees to provide excellent customer service with an
eye on the financial bottom line is fully justified (2T 887-88, 905).
AG witness Mr. Coppola proposed the complete elimination of incentive compensation
expense, asserting that the Commission reached “incorrect” conclusions in Case Nos. U-17767
and U-17735 (3T 1026-27).52
Mr. Coppola’s views are not aligned with the Commission’s
51 A direct measure of customer benefits from DTE Gas achieving its cash flow performance goals is represented by
the avoided interest costs from the Company maintaining its existing debt ratings (2T 903-904; Exhibit A-17,
Schedule J4 Revised).
52 Mr. Coppola incorrectly suggested a disallowance of $11.381 million, apparently based on his erroneous
calculation of the impact of inflation on incentive compensation expense (2T 916-17). His alternative proposal is to
only include the short-term incentive compensation expense related to operating measures, which he computed to be
45% of the total short-term incentive compensation expense, or $3.5 million (2T 1027-28).
55
recognition that incentive compensation costs are recoverable and also the need for Commission
decisions to be based on the record.53
DTE Gas’s full incentive compensation cost recovery is fully supported by the record in
this case (2T 886-91, 902-10). DTE Gas provided an in-depth cost/benefit analysis
demonstrating a $4.2 million net customer benefit ($14.6 million total customer benefits minus
$10.4 million total incentive plan costs (2T 904, 922; Exhibit A-17, Schedule J4 Revised, line
55).54
AG witness Mr. Coppola suggested that the Company’s incentive compensation plans are
too heavily skewed toward measures that directly benefit shareholders and not customers (3T
1022). Instead, the proportion of incentive compensation related to financial measures reflects a
carefully-constructed mix of short and long-term incentive compensation vehicles designed to
motivate performance on both an annual as well as a multi-year basis. The benefits of these
financial measures are reflected on Exhibit A-17, Schedule J4 Revised (2T 914-16, 918-20).55
It is also important to recognize that certain metrics can provide benefits to customers,
while evading specific quantification. There can be little doubt that customers benefit from DTE
53 In addition to Case Nos. U-17767 and U-17735, see for example Case No. U-15244, where the Commission
disallowed the proposed recovery, but also stated that it “strongly encourages Detroit Edison to continue refining its
incentive compensation program for submission in a future rate proceeding” demonstrating the Commission’s belief
in the value of such compensation programs and suggesting that improvements would merit cost recovery
(December 23, 2008 Opinion and Order in Case No. U-15244, p. 38). In Case No. U-16472, the Commission again
denied recovery as not sufficiently supported, but stated that it “nevertheless encourages the company, in future rate
case filings, to provide more detail regarding its incentive program and better support for the assumptions
contained in its benefit/cost analysis” (October 20, 2011 Order in Case No. U-16472, p 68).
54
Staff’s proposed financial-measures disallowance also included $757,000 related to Restricted Stock grants under
the LTIP. It is not proper to characterize the LTIP expense for Restricted Stock as being related to financial
measures, since the quantity of Restricted Stock is not variable based on either the Company’s financial or operating
metrics. The Restricted Stock is a valuable tool for retaining employees. The only contingency is that the employee
forfeits the stock if he or she leaves the Company other than through retirement or death. Since the $784,000 is not
variable, it is also not included in the cost/benefit analysis on Exhibit A-17, Schedule J4 Revised (2T 901, 913).
55 Measurable customer benefits would still exceed expense even if the Commission adopts the Staff’s O&M
expense updated for 2015 (2T 923).
56
Energy being financially healthy with access to capital markets. Similarly, an emphasis among
the Company’s leadership and employees on improving the experiences that customers have with
the Company results in significant non-quantifiable benefits to both customers and the
Commission (2T 903, 906, 916).
AG witness Mr. Coppola also criticized the savings associated with operating measures,
suggesting without reasoning or support that: “Clearly [the Employee Engagement and Lost and
Unaccounted for Gas] metrics involve employee and shareholder satisfaction” (3T 1025). Mr.
Coppola seems to have ignored that lower levels of Lost and Unaccounted for Gas result in cost
savings that are passed on to customers (2T 906). Further, Mr. Coppola has apparently confused
employee engagement with employee satisfaction. The Employee Engagement measure has a
demonstrable relationship to productivity, safety, and absenteeism, which directly affect the
Company’s costs and the efficiency of customer interactions with Company employees. Indeed,
the savings associated with the achievement of Target level performance related to the Employee
Engagement as measured by Gallup employee surveys are estimated to be $3.6 million (2T 907).
AG witness Mr. Coppola is similarly inaccurate in suggesting that the Company is
performing poorly on the Customer Satisfaction metric (3T 1025). He neglected to recognize
that improved customer service has value to customers, as well as the Commission and its Staff,
although that value evades specific quantification. (2T 908-9, 920-22). Moreover, the aggregate
benefits far exceed the incentive compensation plan expense. This record evidence demonstrates
that on a cost/benefit basis, DTE Gas’ incentive compensation plan provides benefits to
customers that far outweigh the expense. Therefore, the Commission should allow DTE Gas’
recovery of these reasonably and prudently-incurred costs (2T 909).
57
Incentive compensation programs are an increasingly prevalent practice among the vast
majority of energy companies.56
Therefore, DTE Gas must also offer incentive compensation
opportunities to be competitive with other employers in attracting and retaining talented and
qualified employees (2T 877).
The record further demonstrates that DTE Gas’s incentive compensation programs allow
the Company to attract and retain a highly skilled workforce at a reasonable cost relative to its
peer companies. There is no evidence from any party that the total annual compensation of DTE
Gas’ employees is unreasonable or imprudent. Further, the focus on the variable portion of total
compensation is also inappropriate because DTE Gas’ 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’ total
annual compensation package, which is comparable to other companies competing for the same
employees. Indeed, based on an analysis of executive incentive compensation by AON Hewitt,
DTE’s target incentive compensation is 22% less than the midpoint of its peers (2T 891, 914).
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, or provide incentives for its employees to engage in activities that benefit customers
because total compensation would be substantially less than the peer companies, as reflected in
the chart below which demonstrates the critical role that short and long term compensation
programs play in the Company’s total compensation practices (2T 891).
56 A 2012 WorldatWork and Vivient Consulting study indicates that in 2011, 95% of companies had short-term
incentive programs and 61% had long-term incentive programs, up from 79% and 35%, respectively, in 2007 (2T
890).
58
Customers benefit every day from employees who have the requisite skills and
experience to ensure the delivery of 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 (2T 878, 880, 889-90, 914).
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 reduce or eliminate
the variable element of compensation, as the Staff and the AG’s testimony suggest, then DTE
Gas would need to provide a commensurate increase in base pay in order to attract and retain a
highly-skilled workforce. This increase in base pay 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 (2T 877-78, 880). Moreover, paying compensation solely in
salary would diminish the motivational incentives for employees to provide superior service to
59
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 service-based industry like the utility industry. Incentive
compensation is an essential component of DTE Gas’s total compensation package in light of the
Company’s need to provide adequate total compensation while driving 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 (2T 878, 880, 890).
DTE Gas has demonstrated in detail that the customer benefits of its incentive
compensation plans significantly outweigh their costs, that the total compensation is reasonable
based on comparison to its peers, and that there is no valid reason to reduce or disallow the
Company’s requested cost recovery. Therefore, the Commission should approve DTE Gas’
request to include the incentive compensation expense in the revenue requirement adopted in this
case.
e. ANR Alpena Transport Contract
ANR Alpena Transport Contract No. 122065 differs from the Alpena transport contract
that existed when the Commission approved the settlement in Case No. U-16999. In fact, the
initial Alpena transport contract that existed when the Commission approved the settlement in
Case No. U-16999 has expired. The new contract has an additional 30,000 Dth/day of summer
capacity, and the primary receipt point has been changed to the Alliance Pipeline interconnect
with ANR. The O&M costs during the historical test period under the prior contract were
approximately $1.4 million. The total projected costs under the new contract are approximately
60
$2.9 million. Of this $1.5 million increase, $1.3 million is attributable to the 30,000 Dth/day
increase in summer capacity and projected gas purchase receipts from the Alliance interconnect
(2T 568-69; Exhibit A-10, Schedule C5.2, line 9, column (j)).
DTE Gas sought to recover these incremental costs, which are not incurred for system
integration, but are instead incurred for transporting purchased gas supplies, in its 2015-16 GCR
plan (Case No. U-17691), 2013-14 GCR reconciliation (Case No. U-17131-R), and 2014-15
GCR reconciliation (Case No. U-17332-R) (2T 569-571). The Attorney General opposed the
Company’s requested GCR recovery of these costs, arguing that all of the costs under the ANR
Alpena Transport Contract (in effect when the U-16999 settlement was executed, and as
amended), including costs that are incurred for transporting purchase gas supplies instead of
system integration, are to be in O&M and recovered in base rates. The Commission recently
agreed with the Attorney General (June 9, 2016 Order in Case No. U-17131-R, pp 14-16, 17).
DTE Gas has filed a petition for rehearing in Case No. U-17131-R explaining the
unintended consequences of the Commission’s decision and the ratemaking principles that
support a different result. If the Commission maintains its agreement with the AG’s position,
however, then the Commission should correspondingly adopt the Company’s O&M placeholder
in this case (which the Company would abandon if the Commission agrees with the Company’s
proposed GCR recovery). Otherwise, there appears to be no opposition to the Company’s
inclusion in the projected test year revenue requirements attributable to the 30,000 Dth/day
increase in summer capacity and transportation commodity and fuel costs associated with the
projected gas purchase receipts from the Alliance interconnect (2T 571).
f. 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
61
must take appropriate action.57
DTE Gas is the current owner or operator of all or a portion of
the former MGP sites listed on Exhibit A-10, Schedule C13, p 1. DTE Gas has the responsibility
for 15 former MGP sites, and 9 former holder sites (2T 750; Exhibit A-10, Schedule C13, p 2
provides detail on the remediation status of each site).58
DTE Gas works closely with the
Michigan Department of Environmental Quality (“MDEQ”), which is responsible to oversee and
coordinate all activities required under the NREPA (2T 752-53).
DTE Gas incurred costs of approximately $70.8 million from 1984 through September
2015 for the prudent and reasonable costs of investigation and remediation of the MGP sites (2T
759; Exhibit A-10, Schedule C13, p 3). Expenditures incurred prior to March 2004 were
addressed in Case No. U-13898. Expenditures from March 2004 through August 2009 were
addressed in Case No. U-15985. Expenditures from September 2009 through June 2012 were
addressed in Case No. U-16999. DTE Gas has a balance of $0 from the deferred environmental
proceeds. DTE Gas requests approval of the expenses and an additional recovery of $21.2
million (net of insurance) for MGP expenditures from July 2012 through September 2015 (2T
759; Exhibit A-10, Schedule C13, p. 4). These costs are unavoidable and relate to DTE Gas’
responsible actions to investigate and remediate MGP sites in a cost effective manner and were
undisputed by any other party. Thus, the expenditures are reasonable and prudent and should
be recovered (2T 759-61).
57 From the early 1800’s until the 1950’s, manufactured gas plants, which produced gas from coal, were widely used
for lighting and heating. The plants rapidly disappeared when natural gas pipelines were constructed since they
could not compete with less expensive natural gas. The manufacturing of gas created soil and ground water
contamination that are not acceptable under current State and Federal environmental laws and require remediation to
an exposure level consistent with environmental standards (2T 750-51; Exhibit A-10, Schedule C13, p 1 provides
additional information on DTE Gas’ former MGP sites).
58 Under the prior law, DTE Gas was responsible for the investigation and cleanup of three additional sites. DTE
Gas successfully obtained the State’s concurrence that it is not liable for the three sites under the new Part 201
regulations. A holder site is a location where gas was stored prior to distribution to customers (2T 755-56, 760).
62
g. O&M Expense Summary.
The Company’s initial filing supported an O&M expense of $389.9 million. However, as
noted above, the Company adopts the following five O&M related adjustments: 1) Staff’s $4.9
million reduction for 2015 update and Staff’s inflation; 2) decrease in share asset charge of $1.2
million, 3) Staff’s increase to injuries and damages of $0.7 million, 4) elimination of Executive
Supplemental Retirement Plan expense of $0.8 million and 5) Staff’s reduction for accrued
vacation expense of $1.8 million. Accordingly, the Company is now supporting a total O&M
expense amount of $381.8 million (Attachment A, page 3).
2. Uncollectible Expense.
Uncollectible expense is the expense that is recorded in the income statement to reflect
the portion of accounts receivable (“AR”) that is considered to be uncollectible (2T 823). DTE
Gas’ uncollectible expense is driven by continued economic challenges throughout the
Company’s service territory due to relatively high unemployment rates and rising poverty. The
Federal energy assistance budget was also reduced by 30% from 2009 through 2014 (2T 825).
DTE Gas has worked proactively to control uncollectible expense, and projected $43.0
million of uncollectible expense based on a three-year average of actual uncollectible expense,
normalized for a one-time receipt of $2.4 million of proceeds from a debt sale in 2014 (Exhibit
A-10, Schedule C5.7). The $43.0 million projection reflects the Company’s plans to continue its
efforts to sustain its results in uncollectible expense, despite continuing economic challenges for
many of its customers (2T 825-26). Staff calculated uncollectible expense using the same
methodology, but with more recent data (3T 1206). DTE Gas accepts the Staff’s proposed
amount of $44.0 million (Exhibit S-3, Schedule C5 revised, Attachment A page 3).
63
E. Advanced Metering Infrastructure (“AMI”) Costs.
The Commission previously rejected the AG’s suggestion that it lacked authority to
approve DTE Gas’s proposal to implement an Advanced Metering Infrastructure (“AMI”)
program, but added: “However, credible evidence offered by MichCon in its future rate cases
that the benefits to ratepayers of an AMI program actually outweigh the program’s costs will be
required to achieve this Commission’s authorization of the recovery of such costs” (June 3, 2010
Opinion and Order in Case No. U-15985, p 16). The Commission has also repeatedly approved
funding for DTE Electric’s AMI program, and recently found that it has “thoroughly vetted the
underlying benefit/cost analyses, and the AMI program itself, and will not revisit those issues”
(December 11, 2015 Order in Case No. U-17767, p 34).
Accordingly, Company witness Mr. Sitkauskas provided a brief background on AMI
efforts at DTE Gas and DTE Electric (2T 286-90),59
explained the major benefits to DTE Gas
customers (2T 290-91), and provided a detailed cost/benefit analysis (2T 294-95). Company
witness Mr. Sitkauskas explained the four line items constituting AMI capital expenditures
(Meters, PMO, IT, and Corporate Overhead), and supported DTE Gas’s recovery (2T 92-94;
Exhibit A-9, Schedule B6.6). AMI’s O&M expenses consist of module and information
technology expenses associated with installing AMI. These expenses are partially offset by
O&M savings, the majority of which relate to meter reading expenses (2T 293; Exhibit A-10,
Schedule C5.6).
59 The pilot program to install AMI meters began in the fall of 2008. As of October 2015, the Company had installed
over 2.1 million electric meters, 518,000 AMI gas modules, and 240,000 AMR gas only modules for a total of over
2.8 million endpoints, or 74% of the Company’s planned meters. By the end of 2015, the Company expects to have
installed 544,000 gas AMI modules, 250,000 gas AMR modules, and 2,187,500 electric AMI meters, comprising
about 77% of the total project, with the electric and gas installations expected to be completed in 2016 and 2017 (2T
288-89).
64
Exhibit A-15, Schedule H1 provides the cost/benefit analysis of the full deployment of
AMI throughout DTE Gas’ and DTE Electric’s service territories (2T 294). The cost/benefit
analysis demonstrates that the benefits to customers of an AMI program outweigh the costs. The
Present Value of Revenue Requirement (“PVRR”)60
of $42.6 million for DTE Gas’ AMI
program affirms that the benefits of the program exceed the incremental cost to customers to
implement the program (2T 299; Exhibit A-15, Schedule H2, line 22, column(d)). Mr.
Sitkauskas concluded by summarizing the cost/benefit analysis of the AMI project, and
supporting the AMI project as a reasonable and prudent use of utility resources as follows:
“Based on the successful results of the company’s AMI pilot program and net cost
benefits shown above, along with numerous direct customer benefits and future
customer benefits, both DTE Gas and DTE Electric are convinced that the AMI
investment continues to be a reasonable and prudent use of utility resources” (2T
299).
Staff recommended that the Company provide annual smart grid reporting metrics
identified in Exhibit S-9.0 (3T 1173). The majority of the 43 metrics listed in Exhibit S-9.0
transcend well beyond specific DTE Gas reporting, and include items for DTE Electric and
Customer Service. DTE Gas agrees with Staff’s recommendation in the spirit of unified smart
grid reporting, and recommends that these items be joined and not company specific. The
individual metrics should also be reviewed at the time of each report for clarity, and to
determine whether they should continue to be reported (2T 302).
60 The PVRR metric is a standard measure used to evaluate investments in the regulated utility industry, and was
adopted following the Staff’s expression of concern with DTE Electric’s use of a Net Present Value (“NPV”) metric
in Case No. U-16472. The PVRR is the discounted value of the stream of annual revenue requirements resulting
from capital expenditures and related expenses.
65
F. Lost And Unaccounted For (“LAUF”) and Company Use (“CU”) Gas, and Gas-
In-Kind (“GIK”).
DTE Gas supports 6,645 MMcf of Lost And Unaccounted For (“LAUF”)61
gas for the
projected test period, based on a five-year (September 1, 2010 to August 31, 2015) average, in
accordance with the methodology adopted in DTE Gas’ last three contested rate cases (Case Nos.
U-10150, U-13898, U-15985), and which the Staff supported in settled Case No. U-16999 (2T
400; Exhibit A-12, Schedule E11). Staff agrees (Exhibit S-14, Revised Schedule E10).
DTE Gas supports the utilization of 2,500 MMcf of Company Use (“CU”)62
gas in the
projected test period to operate its system and to support the deliveries of the natural gas
requirements of its customers, which is reasonably consistent with the actual CU level during the
2014 historical test year (2T 405; Exhibit A-12, Schedule E13). The only change proposed by
the Company relates to the increasing Btu heating value content of gas deliveries and receipts.
Since the Btu content is expected to be higher, less natural gas volume will be required to operate
DTE Gas’ compression and other equipment. Accordingly, the historical 2014 CU volume was
lowered by 156 MMcf, thereby resulting in the CU volume of 2,500 MMcf for the projected test
year (2T 405-406). Staff adjusted the CU volume upward by 3.8638% based on the Staff’s
disagreement with the Company about the heat content of gas (3T 1250). DTE Gas disagrees as
discussed in Section VII. A. 2 regarding customer usage.
61 LAUF represents the difference between booked sources of gas and booked disposition of gas. LAUF gas is
comprised of transmission system losses (metering) and distribution system losses (theft, metering and leaks). DTE
Gas calculates a monthly 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 (2T 396-99, 587).
62 CU volume is predominantly related to fuel used to operate and maintain DTE Gas’ transmission and storage
facilities. CU volume includes, among other things, fuel use for compressors, gas processing at storage fields and
gate station heaters (2T 405).
66
DTE Gas supports: (1) reducing the Company’s current, authorized gas-in-kind
(“GIK”)63
rate of 1.116% applicable to the largest volume end-use transportation (“EUT”)
customers (rate schedule XXLT transport customers) to 1.00%; (2), reducing the 1.63% GIK rate
for off-system service rates to 1.00%; and (3) reducing the GIK rate applicable to EUT service
rates ST, LT, and XLT (the base EUT group) from 1.66% to 1.41%. (2T 590-91, 612, 640, 651,
800-801; Exhibit A-12, Schedule E17, line (18), columns (d), (f) and (g)).
These reductions are appropriate because, from a cost-causation standpoint, transmission
system losses and distribution system losses occur on different parts of DTE Gas’ system, which
are used in different proportions by the Company’s various classes of customers. All DTE Gas
customers use the primary transmission system, so they should share in the cost associated with
transmission pipeline losses. In contrast, DTE Gas’ off-system storage and transportation
customers (“off-system customers”) and largest volume EUT customers (XXLT transport
customers) are extensive users of DTE Gas’ transmission system, with little or no utilization of
the distribution system. DTE Gas is able to determine the losses that occur on its transmission
system separately from the losses that occur on the distribution system. Accordingly, off-system
transporters and certain EUT rate classes should provide a lower contribution toward the
recovery of LAUF gas than the average recovery needed from all other rate classes (2T 400-403,
406-407).
Transmission losses are 0.27% (Exhibit A-12, Schedule E14, line 7, column (d)). CU
volumes are 0.57% (Exhibit A-12, Schedule E-17, line 15). The sum of these costs supports a
GIK rate of 0.84% for all off-system users and XXLT customers (2T 404, 408-409, 588-89).
63 GIK is gas (expressed as a percentage of throughput) that is supplied by customers to offset CU gas, and it also
includes LAUF gas (2T 587).
67
DTE Gas recommends 1.00% GIK rates, however, because they: (1) support the current off-
system and EUT competitive business environment without additional risk to load and revenue
loss, and (2) provide a contribution to the recovery of LAUF gas for all other rate classes,
including Commission-approved special contracts at GIK rates less than the 0.84% calculation
(2T 590; Exhibit A-12, Schedule E17, lines (18) and (21), columns (e) and (f)). The 1.00% GIK
rate fairly and equitably covers the actual cost of providing service, will provide a 0.16% subsidy
to DTE Gas distribution customers, and is required to make DTE Gas storage competitive with
other market area storage providers and thereby better optimize DTE Gas storage (2T 612-13,
618).
DTE Gas recommends a 0.25% GIK rate reduction (from 1.66% to 1.41%) for the base
EUT group (rates ST, LT, and XLT) because on average over the last five years, actual primary
transmission losses are averaging about 0.25% less than the actual loss rate that was occurring
when the Commission approved the Company’s 1.66% GIK rate in Case No. U-15985. This rate
is appropriate because the base EUT group uses the Company’s distribution system to some
extent, so that group should contribute to the recovery of distribution losses (2T 590-91).
Sales rate customers should pay the equivalent of 4.14% GIK in base rates. 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 and U-15985), and is consistent with the
settlement that the Commission approved in Case No. U-16999 (2T 591-92).
G. Depreciation and Amortization.
DTE Gas initially projected $117.2 million for Depreciation and Amortization expense
(Exhibit A-10 2nd
revised Schedule C6). In this Brief, the Company is accepting the Staff’s
increase in depreciation expense of $3.4 million to correct an error in the Company’s originally
68
filed depreciation expense (3T 1119). The Company is also accepting Staff’s reduction to
demolition fee amortization expense of $0.713 million to reflect the updated estimate of
municipal cut and caps. (3T 1120). Based on these adjustments, the Company now supports a
Depreciation and Amortization expense of $119.9 million instead of its initial projected expense
of $117.2 million.
H. Property and Other Taxes.
DTE Gas projects a $72.2 million Property and Other Tax Expense for the projected test
year (Exhibit A-10, Schedule C1.1, column (i), line 16). This expense consists of property taxes,
payroll taxes, other tax expense, and the MPSC assessment fees as shown on Exhibit A-10,
Schedule C7 (2T 371).
Staff proposed a $6,431,000 property tax expense reduction. Staff suggested that the
Combined Average Growth Rate (“CAGR”) in property tax expense has been 3.69% year over
year from 2011 through 2015. Staff indicated that it calculated its proposed reduction by
applying that CAGR to the Company’s 2015 actual property tax expense (3T 1208).
Company witness Mr. Heaphy explained that Staff’s proposed reduction should be
rejected because the amounts used to calculate the CAGR represent Taxes Other Than Income
Taxes, which includes property taxes, but also includes payroll taxes, MPSC assessments, sales
and use tax, and other miscellaneous taxes. The CAGR method also incorrectly assumes
uniform increases in property taxes, but the actual change in property taxes varies from year to
year. The CAGR methodology does not accurately forecast property tax expense because it does
not take into account the variability in actual property tax expense, which is determined by the
level of net capital additions and type of assets placed in service and retired (2T 377-78; Exhibit
A-24, Schedule Q1).
69
I. Income Tax Expenses.
Company witness Mr. Heaphy explained that DTE Gas projects a $8.2 million federal
income tax (“FIT”) expense for the projected test year, based on a 35% FIT rate (2T 368, 372;
Exhibit A-10, Schedule C1.1, line 16). DTE Gas projects a $4.6 million Michigan Corporate
Income Tax (“MCIT”) expense, based on a 6.00% MCIT rate (2T 368, 373; Exhibit A-10,
Schedule C9, line 16). DTE Gas also projects a $0.382 million municipal income tax expense,
based on a 0.5592% composite municipal income tax rate (2T 368, 373-74; Exhibit A-10,
Schedule C10, line 13). The Section II adjustments accepted by the Company in this Brief result
in an increase to total income tax expense (Federal, State and Local) of $1.9 million for revised
total income tax expense amount of $15.1 million (Attachment A, page 3).
J. Revenue Decoupling Mechanism (“RDM”).
The Commission approved DTE Gas’s current RDM in the December 20, 2012 Order
Approving Partial Settlement Agreement in Case No. U-16999. The RDM is a “simple revenue
tracker” that is limited by a revenue cap set at 150% of the legislated Energy Optimization
(“EO”) 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, such that 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 (2T 71-72).
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,
70
surcharges and customer charges). DTE Gas’s only proposed change is to remove the RDM
revenue cap (2T 72).
It is appropriate to remove the RDM revenue cap because over the last 18 months, DTE
Gas has experienced continual increases in the Company’s system-average heating value of the
gas it delivers to customers. This continual increase in heating value has resulted in lower
average use per customer64
that would likely not be captured by the current RDM due to the
revenue cap. DTE Gas’s forecasted heating value in this case65
mitigates a certain amount of this
volatility, but only an RDM without a revenue cap would fully mitigate future volatility in
heating value. Therefore, the optimal method to mitigate risk is to adopt both DTE Gas’s
forecasted system average heating value and proposed IRM with no revenue cap (2T 72-75).
There could be significant impacts on DTE Gas and its customers if the Commission does
not approve these proposals. The nature of DTE Gas’s business requires continual investments
and maintenance of the Company’s gas system to reliably and effectively serve customers. A
significant proportion of DTE Gas’s costs are fixed, since the distribution cost of natural gas
does not change dramatically with changes in customer consumption. DTE Gas currently
recovers much of these fixed costs through volumetric usage charges, so DTE Gas’s ability to
recover its fixed costs declines when customer consumption declines. Without the forecasted
system average heating value and proposed IRM with no revenue cap, DTE Gas may be unable
to fully recover its revenue losses with corresponding limits to the Company’s ability to provide
the service level expected by customers (2T 74).
64
Increasing heating values tend to lower consumption, since less gas is needed to generate the same heating
requirements (2T 73, 544. See also Section VII. A. 2 regarding Customer Usage).
65 The Company’s system-weighted average heating value for the projected test period is 1,087 Btu/cf (2T 73, 547,
554).
71
The first reconciliation period would begin November 1, 2017, which is the first month
following the end of the projected test year.66
The reconciliation would be filed three months
after the end of the reconciliation period, consistent with the current process. The RDM would
terminate when DTE Gas implements new rates either through self-implementation or by
Commission order approving new rates based on an updated test year (2T 75-76).
Staff indicated that it “agrees with the Company’s proposed RDM with the exception of
the proposed system average heating value, sales forecast, commencement of the reconciliation
period, and the removal of the revenue caps in place with the current RDM” (3T 1277). Mr.
Coppola opposed removal of the RDM revenue caps, and questioned the Company’s forecasted
change in BTU content of gas, and the expected change in sales due to that higher BTU content
(3T 1007-1008).
Company witness Mr. Stanczak responded by pointing out that the expected BTU content
of gas and related sales forecast are not components of the RDM. Instead, they are key variables
relative to the operation of the RDM. The uncertainty regarding BTU content supports the
Company’s proposed changes to the RDM (2T 105).
Staff suggested that BTU content is similar to weather, and variability is a traditional risk
borne by the utility (2T 1278). Sales changes due to weather, however, are fully normalized
before the RDM’s operation. As Company witness Mr. Stanczak discussed, Staff’s suggestion
that large sales changes due to BTU content (those that are beyond the RDM revenue caps)
should be borne by the Company is not how weather has traditionally been addressed through the
RDM’s operation (3T 106).
66 This timing assumes that the Commission adopts the Company’s sales forecast, which reflects the higher heating
value content of gas. If the Commission instead uses a higher sales forecast, then the new RDM without a revenue
cap should be implemented concurrent with the implementation of new rates in this case (2T 75, 118-19).
72
AG witness Mr. Coppola suggested that if the increasing BTU “problem becomes severe,
the Company always has the option to file a rate case to request relief” (3T 1008). This option is
of course possible, but not legally necessary,67
nor is it desirable in light of the inefficiencies and
regulatory burdens of otherwise-avoidable rate cases. The Commission has repeatedly
authorized reconciliation mechanisms for cost or revenue items that are expected to vary widely
in the future, thereby deferring the need for incremental rate relief. As Company witness Mr.
Stanczak aptly pointed out, sales volatility due to potential BTU changes is an appropriate item
to capture through the RDM’s operation (3T 107). Mr. Coppola’s suggested administrative
burden of additional rate case filings can and should be avoided with the Company’s proposed
RDM.
67 Section 89(6) of 2008 PA 295, MCL 460.1089(6) 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 optimization
programs to implement a symmetrical revenue decoupling true-up mechanism that adjusts for sales volumes 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 optimization programs are administered by the provider or an independent
energy optimization 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”).
73
K. Infrastructure Recovery Mechanism (“IRM”).
The Commission approved DTE Gas’s IRM for the recovery of 2013-17 capital
investments in the Meter Move Out Program (“MMO”),68
the Main Renewal Program
(“MRP”),69
as well as incremental capital for main renewal beyond the level that the
Commission approved in Case No. U-16407 (incremental MRP), and for Pipeline Integrity
(“PI”).70
(April 16, 2016 Order in Case No. U-16999). The Court of Appeals affirmed. In re
Application of Michigan Consolidated Gas Company to increase rates, unpublished opinion per
curiam of the Court of Appeals, issued December 11, 2014 (Docket Nos. 316141 and 316263).
The Commission later approved additional infrastructure investments as part of an expanded
IRM for 2016 and 2017 (November 23, 2015 Opinion and Order in Case No. U-17701).
The capital expenditures used to calculate the IRM surcharge are made on a calendar year
basis. The IRM surcharge is calculated on a calendar year basis for each year of the five-year
investment period based on the cumulative cost of service associated with the incremental capital
investment, and allocated to each rate schedule. IRM capital spending is reconciled annually,
and if required, the IRM surcharges are adjusted for any underspend with the next scheduled
increase in July of each year. All capital invested as part of the IRM is rolled into rate base, and
recovery would continue through base rates when DTE Gas files a general rate case. The IRM
surcharge would expire when new rates are set by Commission order (2T 76-77, 705).
68 The Commission approved the MMO in its September 13, 2011 Opinion and Order and November 10, 2011 Order
Granting Clarification in Case No. U-16451. Ms. Sandberg discussed DTE Gas’ existing and proposed MMO
program (2T 722-24).
69 The Commission approved the MRP in its September 13, 2011 Order in Case No. U-16407. Ms. Sandberg
discussed DTE Gas’ existing and proposed MRP program (2T 724-32).
70 Ms. Sandberg discussed DTE Gas’ existing and proposed PI program (2T 708-22).
74
1. The Company’s Proposed New IRM Surcharge.
DTE Gas proposes to establish a new IRM surcharge that is consistent with the currently-
approved IRM surcharge. A new IRM surcharge would begin on January 1, 2017 to recover the
cost of service associated with invested IRM capital (the MRP, MMO and PI programs) made on
a calendar year basis for the five-year period of 2017 through 2021. It will be administratively
simpler to include all invested capital through December 31, 2016 in rate base in this case, and
begin the new IRM surcharge simultaneous with the invested IRM capital beginning January 1,
2017. Accordingly, DTE Gas has included all invested capital through December 31, 2016
(which includes the first two months of the projected test period) in rate base in this case, and all
IRM capital beginning January 1, 2017 in the new IRM surcharge (2T 77-78, 503-504, 507, 679,
705, 719, 723, 725-26).71
DTE Gas proposes that the new IRM surcharge will be calculated for each year of the
five-year investment period based on the cumulative cost of service associated with the MMO,
MRP and PI capital investment,72
allocated to each rate schedule (see Section IX. D. 1 regarding
IRM rates), and adjusted for any underspend.73
The new IRM surcharge would start on January
71 If the Commission does not approve DTE Gas’ proposed IRM, then all invested IRM capital through October 31,
2017 should be incorporated into the projected test year in this case (2T 77).
72 Exhibit A-18, Schedule K1, page 1 identifies the annual incremental Revenue Requirements / Cost of Service for
2017 through 2021 relating to MMO capital costs associated with the IRM (2T 343).
Exhibit A-18, Schedule K2, page 1 identifies the annual incremental Revenue Requirements / Cost of Service for 2017 through 2021 relating to MRP capital costs associated with the IRM (2T 343-44).
73 DTE Gas expects to invest $78.1 million in 2015, $102.1 million in 2016, and $127.6 million annually ($22.7 for
MMO, $93.8 for MRP, and $11.1 for PI) in 2017 through 2021. The annual capital spending by MMO, MRP and PI
component for the IRM is included on Exhibit A-9, Schedule B6.2 (2T 505, 705, 719, 723, 725).
Exhibit A-18, Schedule K6 calculates DTE Gas’ proposed customers’ monthly charge reduction of $0.0132 for
every $1 million of IRM capital costs that DTE gas underspends. This calculation is consistent with the
methodology that the Commission approved in Case No. U-16999. There is no adjustment mechanism for DTE Gas
overspending, so there will be no recovery of such costs until a subsequent rate case (2T 345-46, 505-506).
75
1, 2017, to recover the cost of service associated with the IRM capital invested during the 2017
calendar year. In subsequent years, DTE Gas will update the IRM surcharge on July 1 of each
year to recover the cost of service on the incremental IRM capital invested from that calendar
year.74
DTE Gas chose July 1 as the start date for the annual surcharge update beginning in year
two of the new IRM because July 1 matches the current IRM’s review and implementation
process. DTE Gas intends to file a reconciliation case by the last day in February of each year to
reconcile the prior year’s investments. This filing date would allow up to a four month review of
the prior year’s reconciliation before implementing the new surcharge on July 1. The IRM
surcharge would cease when new base rates were implemented in the Company’s next general
rate case. At that time, 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. In future rate
cases, DTE Gas may propose to implement an updated IRM to address recovery of future
infrastructure investment. Absent a rate case, the IRM surcharge would continue at the final rate
established after the fifth year of the program (capturing all invested capital through December
31, 2021). This continuing IRM may allow DTE Gas to avoid filing a rate case until other cost
increases result in a need for rate relief (2T 78-79, 504, 507-508, 704-705).
2. Program spending flexibility
Staff generally supports DTE Gas’ level of capital expenditures for PI (3T 1154-55),
MMO (3T 1161) and MRP (3T 1163-64). DTE Gas also requests an increase in spending
flexibility among the IRM programs. Adjusted expenditures will be included in the IRM
reconciliation, subject to not exceeding the cap of $102.1 million in 2016, and $127.6 million in
2017 through 2021 (3T 706-707).
74 For example, the updated IRM surcharge beginning on July 1, 2018 will recover the cost of service for all new
IRM capital for calendar year 2018, and the invested IRM capital from 2017 (2T 78).
76
3. Impacted Meters
Staff suggested that DTE Gas should be “expected to impact 229,750 inside meters [over
the period of 2012 to 2021] through the MMO, MRP, and other routine programs as outlined in
the plan proposed and approved in Case No. U-16451” (3T 1160). DTE Gas disagrees. Based
on the program design and the Company’s historical performance, DTE Gas does not believe it is
feasible to relocate 229,750 inside meters during the ten-year period. Staff’s proposed target is
based on the original estimate of inside meters DTE Gas thought it could remediate in Case No.
U-16451 (3T 1158), but Staff acknowledges that the MMO was modified in Case No. U-16999
to target both inside and outside meters (3T 1155). DTE Gas now estimates that construction
activities (MMO, MRP, and routine) may impact 229,750 inside and outside meters combined
(not 229,750 inside meters as Staff suggests) during the 2012 to 2021 timeframe, subject to the
amount of service line work required, and the demand for routine construction activities (2T 839-
41, 844).
Staff acknowledged that DTE Gas exceeded its four-year (2012 to 2015) plan for MMO
meters impacted by 2,373 meters in total (3T 1157). Going forward, the variability in the
concentration of inside meters75
and the actual work required at each site (e.g., a move-out, with
or without a service line renewal, required service line work on an inside meter, or a cut and
cap)76
will determine the actual number of meters impacted by MMO each year (2T 841). MRP
targets poor performing main. Meter relocation and remediation are tertiary considerations with
highly variable results that do not support meter relocation targets (2T 841-42). Routine
75
The concentration of inside meters (percentage of inside meters as compared to total meters) has declined over the
years as DTE Gas has expanded its MMO program (2T 843).
76 The percentage of cut and caps has declined over the years. As the cut and cap rate decreases for inside meters,
higher cost and labor intensive service line renewals reduce the number of inside and outside meters that can be
relocated within the stablished spending levels (2T 843-44).
77
construction similarly does not support any meter relocation target. Routine construction is
driven by customers, required by regulation, or emergent (pipeline related emergencies), and in
all cases performed in accordance with Company standards. The Company has no control over
the number of inside meters relocated or cut and capped during routine construction activities.
Variable costs (such as municipal permitting fees and imposed restoration requirements) are also
beyond the Company’s control. Therefore, any inside meter projections are just estimates (2T
842, 845). There is no reason to implement compliance targets when it is well recognized that
the number of meters affected will vary over time because of the inherent design and nature of
the work that is performed (2T 845).
Staff also suggested revising the MMO reporting requirements to provide a plan amount
of inside meters to be impacted by MRP and routine construction for the next calendar year that
supports meeting the Staff’s suggested 10-year goal of 229,750 inside meters impacted (3T
1160). DTE Gas does not object to showing cumulative progress in remediating inside meters
overall, but the Company has concerns with providing a plan amount of inside meters to be
impacted by activities that are not designed to remediate inside meters as a primary objective.
DTE Gas cannot control or predict with a high degree of certainty the number of inside meters
that will be impacted by routine construction (which is performed in response to customer
demand, regulations, and/or pipeline related emergencies) or the MRP risk model (which
annually identifies the highest-risk segments for renewal, with differing inside meter
concentrations). Therefore, any reporting requirement should recognize that the number of
inside meters impacted by MRP and routine activities will vary annually (2T 839, 845-46).
4. MRP Risk Ranking
AG witness Mr. Coppola suggested that DTE Gas often does not replace higher priority
and riskier main segments first (3T 1034). The suggestion is inaccurate because it is based on
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one point in time. As indicated above, the MRP risk model annually identifies the highest-risk
segments for renewal. As inputs change, so do risk rankings. DTE Gas is committed to renewing
15 miles of the highest risk segments each year, which may include adjacent pipe segments with
lower risk rankings to reduce the complexity of the work. For efficiency, the remainder of the
renewal occurs in large grid areas containing relatively high-risk segments (2T 839, 846).
AG witness Mr. Coppola suggested a concern that DTE Gas has not had an outside
technical expert on cast iron and steel pipe assist the Company in assessing the mains to be
replaced through the MRP (3T 1034). This is not a valid concern because the Company’s own
experienced and dedicated engineers have expertise to assess the condition of the remaining
miles of pipe to be replaced, and determine the renewal priorities to assure a safe and reliable gas
distribution system (2T 839, 846).
5. MRP Spending Increase
AG witness Mr. Coppola suggested that no new information has been presented to justify
an increase in MRP spending since Case No. U-17701 (3T 1035). To the contrary, the Company
has demonstrated its ability to scale-up internal resources along with planning, design and supply
chain activities in order to sufficiently renew larger grids of poor performing main in a cost-
effective manner. Since the filing of Case No. U-17701, DTE Gas has successfully completed
76 miles of planned main renewal in 2015, including a pilot of the Modified Grid Approach.
Design and construction resources are prepared to complete additional main renewals beyond the
spending levels and associated mileage ordered in Case No. U-17701. Additional MRP
expenditures are warranted to address: (1) continued reduction of the risk of major leak
incidents; (2) reduction in volume of future main leaks, and (3) improved overall reliability of
the distribution system (2T 839, 846-47).
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6. Meter Assembly Check Reporting Requirements
Staff recommended that the Commission require DTE Gas to file with Staff monthly
Meter Assembly Check (“MAC”) progress reports including data consistent with that presented
on page 3 of Exhibit S-7.9 (3T 1161). DTE Gas disagrees because it will continue to provide
updates each fall at the DTE Gas Company Annual Operations Update meeting in Lansing. DTE
Gas can also provide an update each spring at the Codes and Standards Annual Communications
forum at the Allen Road Station. This semi-annual reporting will satisfy communications needs.
The Staff’s proposed monthly formal filing requirement will not improve DTE Gas performance,
and should not be adopted (2T 965).
L. Corrosion Work Order Backlog.
Ordering paragraph K 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 corrosion problems. By the time of the filing of its next general
rate case, the company shall incorporate its corrosion data into the Geographic
Information System.”
In accordance with these directives, Ms. Sandberg testified that DTE Gas’ corrosion work
order (“CWO”) backlog declined from 1,757 in 2009, to 129 at year-end 2010, to 1 at year-end
2011. As of January 31, 2012, the Company had zero overdue CWOs. DTE Gas also had a zero
backlog of CWOs at the start of 2015. As of October 11, 2015, DTE Gas was nearly 94%
complete on planned CWOs, and was on track to maintain a zero backlog at the start of 2016.
DTE Gas also incorporated its corrosion data into the Graphical Information System (GSI/ESRI).
(2T 684-86).
Going forward, DTE Gas plans to continue utilizing its proven and successful
remediation plan to maintain zero CWOs as detailed in Exhibit A-19, Schedule L1, MPSC
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Corrosion Update – 2015 CWO Status and Plan. Also, since DTE Gas is already providing
CWO backlog information to the Staff semi-annually and the Company has demonstrated its
commitment in meeting and sustaining the requirements outlined in ordering paragraph K of the
Commission’s June 3, 2010 Opinion and Order in Case No. U-15985, the Company requests that
the Commission eliminate the semi-annual reporting requirements and future rate case filing
requirements (2T 686-87). Staff agrees (3T 1147).
M. 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.”
Ordering paragraph N further stated:
In its next general rate case, Michigan Consolidated Gas Company shall provide
information addressing the capital expenditure amount required for continuing
and completing improvements to its natural gas system, and shall file a report
analyzing the effectiveness of its capital expenditures during the previous 12
months in preventing leaks.”
In accordance with these directives, Ms. Tomina testified that DTE Gas started 2014 with
a leak backlog of 2,698, and remediated 16,541 leaks out of approximately 17,949 new incoming
leaks, resulting in a year-end balance of 4,106, with capital expenditures of $6.3 million. For
2015, DTE Gas projects that it will remediate 16,980 leaks out of approximately 14,874 new
incoming leaks, resulting in a year-end balance of 2,000, with capital expenditures of $6.9
million. For 2016, DTE Gas projects that it will remediate 16,188 leaks out of approximately
16,188 new incoming leaks, resulting in a year-end balance of 2,000, with capital expenditures of
$6.6 million. Exhibit A-19, Schedule L2, August 2015 Leak Inventory Compliance Filing,
provides additional detail on incoming leaks and remediation (2T 957-58).
81
Going forward, DTE Gas’ IRM will, in the long term, significantly reduce the amount of
poor performing main, including cast iron main, thus helping to reduce leak issues. Also, since
DTE Gas is already providing Leak Backlog information to the Staff in semi-annual meetings,
March and December, the Company requests that the Commission eliminate the filing
requirement and related annual reporting requirements set forth in ordering paragraph L of the
Commission’s June 3, 2010 Opinion and Order in Case No. U-15985 (2T 958-59).
Staff recommends that in lieu of a semi-annual reporting requirement, the Company
should be required to submit an annual report consistent with the midyear Leak Backlog report,
which specifically includes pending leak data through July 31 and December 31 of each year (3T
1150). DTE Gas disagrees because it already provides this information to Staff at its semi-
annual meetings, and intends to continue providing this information at the meetings. The formal
filing requirement serves no purpose and will not improve DTE Gas performance. Therefore, the
requirement should be removed completely (2T 964).
N. Accounting Requests.
DTE Gas requests accounting authority for the deferral of negative OPEB costs to a
regulatory liability, in accordance with the Commission’s recent approval of DTE Electric’s
similar request (December 11, 2015 Order in Case No. U-17767, p 68), and as further discussed
in Section VII.D.1.d.1. Staff is not opposed to the Company’s use of the OPEB deferral
mechanism (3T 1121). No other party expressed opposition.
DTE Gas also requests accounting authority concerning the treatment for the re-
measurement of deferred tax balances arising from the change in the City of Detroit corporate
tax rate from 1% to 2% effective January 1, 2012, in accordance with the Commission’s recent
approval of DTE Electric’s similar request (December 11, 2015 Order in Case No. U-17767, p
87). The Company requests that the Commission approve full normalization ratemaking for the
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law change over a period reasonably related to the reversal of the underlying book tax basis
differences consistent with the Commission’s February 15, 2012 Order in Case No. U-16864,
and the long-standing Commission income tax policy of full normalization as established in Case
No. U-10083 (2T 374-75).
DTE Gas also requests accounting authority concerning the depreciation period for
certain computer hardware. The current eight-year depreciation period is still appropriate for
large corporate installations such as servers, but is not the best estimate for smaller devices that
generally are replaced after about five years. DTE Gas proposes a new temporary account that
would allow for a five-year depreciation period. The temporary account would be used for
desktop and laptop computers, tablets, and other low-cost computer hardware that are not
expected to be in service beyond the five-year life. The proposal would not affect depreciation
expense in this case. The temporary account would be used until the Commission reviews
depreciation rates for computer hardware and sets new rates in the next DTE Gas depreciation
case (3T 508-509).
VIII. REVENUE DEFICIENCY AND REQUESTED RATE RELIEF.
DTE Gas initially requested approximately $182.9 million of rate relief for the projected
test year (2T 68-69, 337, 347; Exhibit A-8, Schedule A1). Staff suggested a revenue deficiency
of $122.9 million (3T 1117; Exhibit S-1, Revised Schedule A1). DTE Gas accepts some of
Staff’s adjustments, but Staff’s position still understates DTE Gas’ revenue deficiency by
approximately $54 million for the projected test year, and does not recognize the circumstances
under which DTE Gas must operate. Attachments A and B summarize DTE Gas’s computation
of its updated revenue deficiency, starting with the Company’s filed position of $182.9 million
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and adjusted by thirteen adjustments proposed by Staff, as discussed throughout this Brief. DTE
Gas requests that the Commission approve approximately $177 million in rate relief.
IX. RATE DESIGN AND TARIFF REVISIONS.
A. Allocation of Revenue Deficiency.
Company witness Mr. Slater supported DTE Gas’ cost of service studies (“COSS”) for
the 2014 historical test year (Exhibit A-6, Schedule F6.1) and the projected test period (Exhibit
A-13, Schedule F1.1) (2T 771). 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 for storage costs (2T 775-76).
ABATE witness Mr. Phillips proposed to use just the peak day demand method to
allocate fixed related delivery system costs in place of the A&P method (2T 30, 35-36). DTE
Gas disagrees because the Commission has consistently approved the use of the A&P method
since December 1988 in DTE Gas (then MichCon) general rate Case No. U-8812 (2T 811-12).
Staff similarly opposes ABATE’s proposal, adding further discussion reflecting its support for
the continued use of the A&P method (3T 1256-63).
For the historical test year, Company witness Mr. Slater used the January design peak day
requirement of 2.25 Bcf from DTE Gas’ GCR Plan Case No. U-17131 (2T 416-17, 776-77). The
use of a design peak day is well established, but in DTE Gas’ last contested general rate case, the
Commission invited all parties to present their positions on the use of a design or actual peak day
(June 3, 2010 Opinion and Order in Case No. U-15985, pp 90-91). DTE Gas’ last general rate
case was settled except for the IRM issue (December 20, 2012 Order in Case No. U-16999).
84
Therefore, Mr. Slater further explained why it is better to use a design peak day rather than an
historic peak day for cost allocation (2T 777-79).
The Company’s revenue requirement is allocated to its customer classes using twenty-
two allocation factors that reflect each class’s share of cost responsibility (2T 772-73). Nearly
all of the allocation methods in DTE Gas’ COSS for the projected test period (Exhibit A-13,
Schedule F1.1) are the same as those approved in Case No. U-15985; however, that ordered
COSS removed the costs initially allocated to Dearborn Industrial Generation, LLC (“DIG”) for
the distribution mains plant cost and distribution operating expenses, and reassigned them to the
remaining transportation classes (ST, LT, and XLT).
DTE Gas proposes two modifications. First, all Rate Schedule XXLT customers,
including DIG, are connected directly to the Company’s transmission system or to a high-
pressure system that is connected directly to the Company’s transmission system. Therefore,
they should only be allocated transmission system costs, and they should not be allocated any of
the distribution mains plant costs and distribution operating expenses. None of these costs were
allocated to DIG in the Case No. U-15985 ordered COSS. DTE Gas’ extension of this treatment
to all Schedule XXLT customers treats similarly-situated customers consistently and without
discrimination. Second, DTE Gas allocated the distribution mains plant costs and distribution
operating expenses to all non-XXLT rate classes (not just to other transportation classes) since
they are not transportation specific. DTE Gas made these proposals in Case No. U-16999 and
Staff agreed (2T 630-31, 780-82; Exhibit A-13, Schedule F1.1, pp 1-4).
Staff further suggested in Case No. U-16999 that distribution mains plant related
Construction Work in Progress (“CWIP”), Accumulated Depreciation, and Depreciation expense
should also not be allocated to rate Schedules XXLT and DIG. DTE Gas agrees with this
85
consistent cost treatment, so Mr. Slater separately broke out these costs, and allocated them on
the same basis as distribution mains plant costs (2T 780, 782-83).
DTE Gas proposes to allocate uncollectible expense based on net write-offs caused by
each rate schedule, in accordance with the Commission’s recent approval of this methodology to
allocate DTE Electric’s uncollectible expense (2T 784-85). ABATE agrees (2T 31-32). Staff
instead proposed to allocate uncollectible expense based on total cost of service including cost of
gas, suggesting that uncollectibles “are simply a cost of doing business” and that it is “impossible
to know whether uncollectibles are even correlated with net write-offs” (3T 1252).
Company witness Mr. Sparks responded by explaining how uncollectible expense is
calculated based on net write-offs, and by demonstrating that uncollectible expense in year one
has been reasonably correlated to net write-off amounts in year two for each of the last three
years (2T 833). Mr. Slater further explained that Staff’s reasoning is circular and cannot support
a decision by the Commission (2T 811).
The Commission also considered Staff’s position and instead adopted DTE Electric’s
proposal (like DTE Gas’ present proposal) to allocate uncollectibles based on net write-offs. The
Commission found DTE Electric’s proposal “to be reasonable and better reflective of the cost of
service. It is appropriate and consistent with regulatory ratemaking principles to directly assign
such costs to the class that caused the costs” (June 15 Order in Case No. U-17689, p 27). The
Commission also recently declined to revisit the issue (December 11, 2015 Order in Case No. U-
17767, p 114).
Exhibit A-13, Schedule F3 calculates current and proposed revenues by rate schedule.
Exhibit A-13, Schedule F4 calculates typical bills for each gas sales rate under DTE Gas’ current
and proposed rates (2T 781). Exhibit A-14, Schedule G-1 identifies projected gas transportation
86
system costs used in developing DTE Gas’ proposed cost-based rate for off-system or third-party
shippers who transport gas on DTE Gas’ gas transportation system (2T 792-93). Exhibit A-18,
Schedule K3 calculates the monthly per-meter charge for each rate schedule for the years 2017
through 2021 relating to DTE Gas’ IRM (2T 794-96).
B. Supplemental Utility Service Changes.
As described in Section A of the Company’s tariff, DTE Gas charges customers to “cut
and cap” a gas line service when requested by the customer or for the purpose of demolition.
DTE Gas proposes to modify the tariff to exempt government-requested cut and cap services
from the charge. This modification will help facilitate blight-related demolition in an effort to
reduce safety concerns, reduce theft, and support economic development in local communities
for the benefit of all customers. Helping to facilitate the demolition of blighted properties also
supports the Commission’s recently-modified gas safety rules, as adopted in Case No. U-17462,
regarding the discontinuation of inactive service lines (R 460.20332). (2T 83).
The Commission approved DTE Electric’s accounting request to record a regulatory asset
for demolition-related cut and cap fees (December 22, 2015 Order Approving Application in
Case No. U-17991). DTE Gas has included the regulatory asset in this case, and proposes to
amortize the regulatory asset over a two-year period effective with its inclusion in base rates (2T
84, 479).
Staff proposed that future cut and cap fees charged to non-municipal customers continue
to be recorded as miscellaneous revenue, and that an estimate of those revenues of $855,000
should be included in the projected test period (3T 1242). DTE Gas agrees that $855,000 is a
reasonable estimate for fees to be charged to non-municipal customers, but the fees should not be
recorded as revenue. A credit to plant is the appropriate accounting treatment because the related
87
cost of demolition work is charged as a removal cost within net plant. Specifically, the credit
should be recorded to accumulated depreciation to offset costs for removal work (2T 511, 513).
C. Tariff Changes for All Customers.
DTE Gas proposes changes to its tariff pages under Section C of its rate book (2T 796-
97; Exhibit A-13, Schedule F5 (summary of proposed tariff changes); Exhibit A-13, Schedule
F5.1 (revised tariff pages)). DTE Gas proposes to:
(1) Change Sections C3.1.H and C3.2.J Penalties for Unauthorized Use to reflect one
calculation methodology for all unauthorized use penalties across the Company’s entire rate
book. DTE Gas proposes that the penalty charge currently defined in Gas Customer Choice
Program, Section F, of the Company’s gas rate book, using the highest price reported in the
midpoint column of the Daily Price Survey, be adopted as the common basis of all unauthorized
gas use penalties in Section C, Section E, and Section F of the Company’s rate book. This will
provide consistency and clarity, as well as adequately protect both the Company and its
customers (2T 633, 635-37, 796).
(2) Change Section C11.1.B pertaining to account aggregation by modifying the
contiguous facility provision, which is a long-standing service characteristic for the largest
customers receiving service under the Company’s Rate Schedules S (School rate), GS-2 (large
volume sales rate), and the EUT rates. The Company’s rate book provides that contiguous
facilities include buildings or parts of buildings, separated by a public street or ally “but not
including a limited-access highway” that . . . are exclusively occupied and used by Customer as a
unitary enterprise at one location and under one management. DTE Gas proposes to eliminate the
“but not including a limited-access highway” provision because it provides no operational
purpose for the Company, and limits a very small number of customers from the benefits of
aggregation (2T 633, 635-38, 796-97).
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(3) Update the Customer Attachment Program tariff to reflect revised percentages for
DTE Gas’ Carrying Cost Rate (proposed as 11.59%) under Section 8.9.B(1) and Discount Rate
(proposed as 7.98%) under Section 8.9B(6) (2T 796-97).
D. Tariff Changes for Sales Rate Schedules.
DTE Gas proposes the following changes under Section D of its rate book.
1. Revised IRM.
As discussed in Section VII. K.1 above, the revised IRM will allow DTE Gas to recover
its capital spending costs for MRP, MMO and Pipeline Integrity over the next five years, and
continuing at the year five level, subject to reconciliation, absent another rate case. Beginning
January 1, 2017, and each July 1, beginning July 1, 2018, a monthly charge will be implemented
for each rate schedule as indicated on Sheet No. D-2.01, subject to annual reconciliations (2T
797-98). Exhibit A-18, Schedule K3, page 6 displays the proposed IRM monthly charges for
each customer class from 2017 through 2021 (2T 793).
ABATE witness Mr. Phillips indicated a concern that DTE Gas is proposing to change
the allocation of IRM costs, and charge large transportation customers significantly more (2T
42). To the contrary, DTE Gas is only proposing to change the maximum monthly charge (2T
794). The maximum monthly charge does not affect the allocation of IRM costs; however, the
current $500 maximum monthly charge shifts costs onto other rate schedules. DTE Gas’s
proposal would reduce this cost shifting (2T 795, 812). Staff indicated agreement with the
Company, and that it “would consider removing the cap on the charge entirely to avoid subsidies
between rate schedules” (3T 1281).
2. Low Income Assistance Credit Pilot.
DTE Gas proposes a Low Income Assistance Credit Pilot Rate to replace the existing
Residential Income Assistance (“RIA”) credit available to Residential Service Rate A customers.
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The proposed pilot will provide meaningful assistance to eligible low income customers by
making their bills more affordable through a $30.00 monthly bill credit, rather than the current
$10.50 RIA monthly credit. The pilot tariff’s participation will be capped at 42,000 customers,
and will require the same amount of ratepayer funding as the RIA program requires (2T 83, 799,
828-30).
Staff proposed that the Company auto-enroll 20,000 randomly-selected RIA customers in
the pilot (3T 1277), and that the total number of RIA and Low Income Assistance Credit Pilot
customers be set at 100,000 (3T 1274). DTE Gas disagrees with the Staff’s proposed restrictions
on customer participation. The Staff’s proposed $11.25 RIA would provide only a negligible
amount of energy assistance to the Company’s most vulnerable customers. In contrast, the Low
Income Assistance Credit Pilot’s $30.00 monthly bill credit will provide energy assistance that
will be more effective in helping the most vulnerable customers manage their gas bills and
prevent service disconnections (2T 834).
DTE Gas also disagrees with the Staff’s proposal to randomly enroll customers in the
Low Income Assistance Credit Pilot. In addition to the energy assistance benefits discussed
above, the Company’s Customer Advocacy team will refer customers in the pilot to the
Company’s agency partners for self-sufficiency services (as resources will allow). Customers
that participate in self-sufficiency services are far more likely to succeed in addressing any areas
of need if they are actively engaged in the process, especially at the onset. In contrast, randomly
enrolling customers in the pilot would not promote customer engagement in self-sufficiency
services. It would be preferable for the Company and its agency partners to proactively work
with customers to enroll them in the pilot on a first come – first served basis as part of a broader
plan to assist the customers’ overall needs (2T 835).
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3. Rate Schedule AS.
DTE Gas proposes to eliminate the Low Income Senior Citizen Service Rate Schedule
AS because it was originally designed to protect low income senior citizens from shutoff during
the winter, but it is now redundant and no longer offers any additional benefit. The shutoff
provisions relating to these customers are now embedded into the State of Michigan’s Customer
Standards and Billing Practices for Electric and Gas Residential Service indexed in Section B of
the Company’s rate book (2T 638-39, 799). Staff agrees with the elimination of rate schedule AS
(2T 1244).
E. Tariff Changes for EUT and Choice Service.
DTE Gas proposes several changes under Sections E1 through E14 of its rate book.
These changes are discussed below in no particular order of importance.
1. Section E1.1.
An Operational Flow Order (“OFO”) is a directive that DTE Gas issues requiring gas
shippers to deliver a pre-specified quantity of flowing gas supply onto the DTE Gas system. An
OFO is issued to alleviate conditions that, in the sole judgment of the Company, jeopardize the
safe operations or integrity of the Company’s system. DTE Gas does not propose to change its
operational handling of an OFO, but the Company does propose to clarify its current OFO tariff
language (2T 409-10).
During the record setting “polar vortex” winter of 2013-14, DTE Gas experienced system
operating conditions that threatened the integrity of the Company’s system, and caused DTE Gas
to evaluate when and how an OFO should be implemented (2T 410-11, 641). Accordingly, DTE
Gas proposes to clarify and introduce definitions to better clarify for EUT customers their
requirements if DTE Gas implements an OFO. An OFO would be specifically defined to state
that an OFO will be issued to alleviate conditions that, in the sole judgment of the Company,
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jeopardize the operations or integrity of the Company’s system. The proposed definition would
further explain that an OFO, when implemented by the Company, requires that EUT customers
nominate and deliver specified quantities of flowing natural gas supply. The Company will
direct customers to nominate and deliver a maximum daily quantity of gas supply (OFODQ
Max), or a minimum daily quantity of gas supply (OFODQ Min), (both of these terms would
also be defined in Section E1.1 for clarity), or a quantity specified in a contract between the
Company and a customer (2T 640-43, 800).
DTE Gas also proposes additional OFO definition clarifications describing how an OFO
may be implemented, including: (1) an OFO that is applicable to all customers; (2) an OFO to
customers within an affected region; (3) an OFO applicable to specific large customers; (4)
restrictions to a customer with special operating conditions; and (5) direction to deliver gas to
points specified by the utility. These additional clarifications are appropriate because if an
operating constraint or emergency is limited to a specific region or delivery points on the
Company’s system, then it would not be appropriate to burden customers with OFO
requirements where those customers are not having an adverse effect on the Company’s system
(2T 643-44).
DTE Gas also proposes to change Section E4.5, Notice of Operational Flow Order, to
clarify that the Company may implement an OFO during constrained operational conditions and
emergency situations, and replace the reference that an OFO invokes daily balancing on all
customers with a provision stating that, unless specified otherwise in the contract between the
customer and the Company, an OFO invokes the requirement a that customers deliver at least the
OFODQ Min or no more than the OFODQ Max. For clarity, DTE Gas also moved the penalty
charge provision and description from Section E4.5 to Section E14, where the Company
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proposes to locate all penalty charge descriptions applicable to EUT customers (2T 640, 644-45,
800).
2. Section E14.
DTE Gas proposes to clarify Section E14, Unauthorized Gas Usage, by establishing four
subsections describing the four unauthorized gas usage specifications where a customer is using
the Company’s system in non-compliance. As discussed above with regard to Section C of the
Company’s rate book, the Company proposes to apply all unauthorized use penalties using one
calculation methodology for consistency across the Company’s entire rate book. DTE Gas
proposes that the penalty charge currently defined in Gas Customer Choice Program, Section F,
of the Company’s gas rate book, using the highest price reported in the midpoint column of the
Daily Price Survey, be adopted as the common basis of all unauthorized gas use penalties in
Section C, Section E, and Section F of the Company’s rate book. This will provide consistency
and clarity, as well as adequately protect both the Company and its customers. DTE Gas also
proposes two corrections with regard to Load Balancing Storage and Charges (2T 640, 645-50,
800).
DTE Gas also proposes to lower the GIK rate applicable to EUT service rates ST, LT,
and XLT from 1.66% to 1.41%, and the 1.116% GIK rate applicable to rate schedule XXLT to
1.00% (2T 640, 651, 800-801).
Staff proposes to add language to provision “C” stating that “any gas imbalance charged
under this provision cannot be considered under provision A” (2T 1280). DTE does not believe
that this addition is necessary, but does not object to including Staff’s proposed language (2T
660).
F. Tariff Changes for Off-System Storage and Transportation Service.
DTE Gas proposes to following changes under Sections E15 through E28 of its rate book:
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(1) Clarify and introduce definitions under Section E15.1 for Maximum Daily
Injection Quantity (“MDIQ”), Maximum Daily Withdrawal Quantity (“MDWQ”), and
Maximum Storage Quantity (“MSQ”); and delete the definition for Operational Flow Order as it
does not apply to Midstream customers;
(2) Clarify verbiage in Sections E15.9, E15.10, E15.11 and E28 to align with
definitions in Section E15.1;
(3) Remove Section E18.5, Notice of Operational Flow Order, as it does not pertain
to Off-System customers;
(4) Change capitalization in Section E21 to reflect that Unauthorized Gas Usage
Charge is a defined term;
(5) Clarify the Company’s language regarding penalties for unauthorized gas usage
for TOS-F, TOS-I, CS-F and CS-1 services (Sections E25, E26, E27 and E28), and align that
language with the common calculation methodology for all unauthorized gas use penalties
discussed above;
(6) Lower the GIK rate applicable to off-system storage and transportation customers
to 1.00% under Sections E25, E26, E27 and E28; and
(7) Increase the TOS-F (Section E25) and TOS-I (Section E26) not to exceed rate
from$0.269 per MMBtu to $0.375 per MMBtu (2T 652-54, 801-802).
G. Tariff Changes for Gas Customer Choice Program.
DTE Gas made only minor changes for clarification purposes to Section F1.10 of the
General Provision of the Company’s Gas Choice Program tariff. The section aligns unauthorized
use penalties as discussed above, and the changes are non-substantive to reflect changes in Gas
Daily (2T 651-52, 803).
94
H. Proposed Monthly Customer Charges and Rate Schedule Economic Break Even
Points.
DTE Gas proposes a $15.00 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 remains at $590.00. The Rate S monthly service charge is $250.00. The
monthly customer charges for EUT Rates ST, LT, XLT, and XXLT are $2,200.00, $4,200.00,
$16,000.00, and $135,000.00, respectively (2T 628-29; Exhibit A-13, Schedule F2).
Staff calculated monthly customer charges of $11.27 (rounded to $11.25) for Rate A,
$50.96 for Rate 2A, and $36.24 for Rate Schedule GS-1/GS-2 (3T 1251; Exhibit S-6, Schedule
F1 Revised, line 20). Staff reasoned that customer charges must only include expenses
associated with the attachment of customers to the Company’s system, which Staff proposed to
limit to costs associated with metering, the service lateral, and customer billing, based on the
Commission’s January 18, 1974 Order in Case No. U-4331 (3T 1250-51).
DTE Gas disagrees because since 1974, cost of service rate design theory has moved
toward use of the Straight Fixed Variable (“SFV”) rate design, under which all fixed costs are
collected through fixed charges. In 1992, FERC Order 636 required all natural gas pipelines to
adopt SFV. The Company’s proposed fixed charges reflect a gradual movement towards the
establishment of a fixed rate that approximates non-volumetric charges that are attributable to
serving customers (2T 806-807).
Staff only used its calculated monthly customer charge for Rate A ($11.27, rounded to
$11.25 per month), and otherwise used the same charge ($11.25 per month) for Rate 2A Meter
95
Class I (which is consistent with past practice), and $31.00 per month for Rate 2A Meter Class 2
and Rate GS-1 (3T 1269; Exhibit S-6, Schedule F-3 Revised, p 1).
DTE Gas disagrees with Staff’s proposed $31.00 per month customer charge because a
monthly customer charge for Rates 2A Meter Class II and GS-1 of at least $40.00 is supported
by multiple sources. DTE Gas’ testimony and exhibits support $40.00 (2T 628-29; Exhibit A-
13, Schedule F2). Exhibit S-6, Schedule F1 Revised, line 20 supports $50.96 for Rate 2A, and
$36.24 for Rate Schedule GS-1. The SFV rate design supports $201.68 for Rate 2A, and
$140.80 for Rate Schedule GS-1). Thus, the Commission should adopt the Company’s filed
monthly charges (2T 808-809).
It is important to have competitive XLT and XXLT rates because they apply to very large
EUT customers. These are sophisticated energy users with opportunities to bypass DTE Gas’
system and obtain their gas supply directly from federally-regulated interstate pipelines. The
XXLT rate was originally approved in Case No. U-15985, and is consistent with the settlement
that the Commission approved in Case No. U-16999. The XXLT rate is based primarily on
transmission system costs, and is designed to retain the very largest commercial and industrial
customers that would otherwise bypass DTE Gas’ system (2T 596-99).
The XXLT rate was successful in returning and retaining one of DTE Gas’ largest (12
Bcf load) customer from interstate pipeline bypass to DTE Gas’ system; however, economic
incentives and regulatory risk and uncertainties remain significant factors in retaining existing
customers and competing for additional potential customers. Therefore, it is extremely important
for the Commission to continue the XXLT rate design methodology with a high monthly
customer charge, a low unit transportation rate, and a competitive overall rate structure. The
economic break-even point should be 3.6 Bcf, which marks a natural break between current XLT
96
and XXLT customers, and will prevent rate switching by the Company’s largest customers. The
XXLT rate (including the DIG rate class) should also not be allocated any of the distribution
mains plant cost or distribution operating expenses, as discussed above (2T 629-31, 780-82).
The minimum optional rate under rate schedules ST and LT should remain at $0.23 per
Mcf. The minimum option rate under rate schedules XLT and XXLT should remain at $0.18 per
Mcf and $0.05 per Mcf, respectively (2T 631-32; Exhibit A-13, Schedule F2, page 3). The
maximum optional rate for rates ST, LT and XLT should set by calculating the difference
between the minimum optional rate for each of the rate schedules and the approved cost of
service rate and adding that difference to the cost of service rates to determine the maximum
rates. The maximum rate for XXLT should be set equal to the maximum rate calculated for Rate
XLT. The maximum optional rate is 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 (2T 631-32).
X. REQUEST FOR RELIEF
DTE Gas respectfully requests that the Commission issue its final order:
A. Granting DTE Gas’ 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 $177.0 million, based
on a November 1, 2016 through October 31, 2017 test year, effective as soon as possible after
November 1, 2016;
B. Approving recovery of DTE Gas’ new rates effective no later than December 17,
2016, in the manner described in the Company’s Application, testimony, exhibits, and this Brief
including Attachments A and B;
97
C. Acknowledging that DTE Gas has satisfied all of the directives of the
Commission’s Order in Case No. U-15985, which were required components of the Company’s
next general rate cases;
D. Approving the Company’s recovery of the requested infrastructure-related capital
and the associated IRM;
E. Approving the Company’s proposal 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), albeit with the sole modification of
removing the RDM revenue cap;
F. Approving expense for 30,000 Dth/day incremental summer capacity as O&M to
be recovered through base rates if, and only if, the Commission determines that such expense
may not be recovered as GCR booked cost of gas;
G. Approving the Company’s proposal to amend certain customer rate schedules and
proposed tariff changes;
H. Approving recovery of the Company’s incentive compensation programs;
I. Authorizing implementation of DTE Gas’s proposed accounting changes as
described in the Company’s Application, testimony, exhibits, and this Brief;
J. Approving the remainder of DTE Gas’s miscellaneous proposals as set forth in
the Company’s Application, testimony, exhibits and this Brief including Attachments A and B;
and
98
K. Granting such other lawful relief that the Commission deems reasonable and
appropriate.
Dated: July 27, 2016
Respectfully submitted,
DTE GAS COMPANY
Legal Department
By:_________________________________
Attorneys for Applicant
Michael J. Solo (P57092)
Richard P. Middleton (P41278)
Jon P. Christinidis (P47352)
David S. Maquera (P66228)
Andrea E. Hayden (P71976)
One Energy Plaza, 688 WCB
Detroit, Michigan 48226
(313) 235-3724
DTE Gas Company MPSC Case No. U-17999
Computation of Revenue Deficiency Initial Brief
for the 12 Month Period Ended October 31, 2017 Attachment A
($000) Page 1 of 4
(a) (b) (c) (d)
U-17999
Line U-17999 Initial
No. Description Filed Adjustments Brief Position
1 Rate Base 3,719,566$ (3,131)$ 3,716,435$
2
3 Adjusted Net Operating Income 113,669 2,428 116,097
4
5 Rate of Return 6.04% -0.028% 6.02%
6
7 Income Requirements 224,776 (1,225) 223,551
8
9 Income Deficiency (Sufficiency) 111,107 (3,653) 107,454
10
11 Revenue Conversion Factor 1.6464 1.6464
1213 Revenue Deficiency (Sufficiency) 182,927$ (6,014)$ 176,913$
DTE Gas Company MPSC Case No. U-17999
Rate Base - Average Net Plant Initial Brief
for the 12 Month Period Ended October 31, 2017 Attachment A
($000) Page 2 of 4
(a) (b) (c) (d)
U-17999
Line U-17999 Initial
No. Description Filed Adjustments Brief Position
1 Plant in Service 4,603,545$ (428)$ (1) 4,603,118$
2 Plant Held for Future Use 0 0
3 Construction Work in Progress 241,807 241,807
4 Total Utility Plant 4,845,352 (428) 4,844,925
5
6 Less: Depreciation Reserve 2,164,856 1,717 (2) 2,166,573
7
8 Net Utility Plant 2,680,496 (2,144) 2,678,352
9
10 Net Capital Lease Property 0 0
11 Gas Stored Underground - non-current 39,339 39,339
12
13 Total Utility Property and Plant 2,719,835 (2,144) 2,717,691
14
15 Less: Capital Lease Obligations 0 0
16
17 Net Plant 2,719,835 (2,144) 2,717,691
18
19 Allowance for Working Capital 999,731 (987) (3) 998,744
20
21
22 Rate Base 3,719,566$ (3,131)$ 3,716,435$
NOTE (1): Adjustment to rate base is 50% of the capital spend change to reflect simple average
Non-muni demo fees offset to capital (855)$ (428)
(2): Adjustment to depreciation reserve is 50% of the $3.4M correction to depreciation expense
(3): Adjustment to reflect adjustment for update reg asset demo fee (Exhibit S-12.1)
DTE Gas Company MPSC Case No. U-17999
Adjusted Net Operating Income Initial Brief
for the 12 Month Period Ended October 31, 2017 Attachment A
($000) Page 3 of 4
(a) (b) (c) (d)
U-17999
Line U-17999 Initial
No. Description Filed Adjustments Brief Position
Net Operating Income
Operating Revenues
1 Distribution Revenues 607,610$ 607,610$
2 Third Party Transportation & Storage 74,421 74,421
3 Other Revenues 92,769 92,769
4 Net Margin 774,800 0 774,800
5
6 Operating Expenses
7 Operations and Maintenance Expenses (1) 389,899 (8,062) 381,837
8 Company Use & Lost Gas 34,929 34,929
9 Gas Uncollectibles 42,962 1,017 43,979
10 Depreciation and Amortization (2) 117,202 2,720 119,922
11 Property and Other Taxes 72,177 72,177
12 Total Operating Expenses 657,169 (4,325) 652,844
13
14 Operating Income 117,631 4,325 121,956
15
16 Other Operating Income Adjustments
17 Allow. For Funds Used During Constr 10,806 10,806
18 Amortization of Loss on Reacquired Debt (1,585) (1,585)
19 Total Operating Income Adjustments 9,221 0 9,221
20
21 PreTax Net Operating Income 126,852$ 4,325$ 131,177$
22
23 Income Taxes (Federal State & Local) 13,183 1,897 15,080
24
25 Net Operating Income 113,669$ 2,428$ 116,097$
(1) O&M detail
- 2015 update and Staff's inflation Exh S-3 C5 Revised (4,930)
- Rents Exh S-3 C5 Revised (1,202)
- Injuries and Damages Exh S-3 C5 Revised 674
- Executive Supplemental Retirement Plan Exh A-10, C5-9 (795)
- Accrued vacation Exh S-3 C5 Revised (1,809)
(8,062)$
(2) Depreciation detail
- Correction of depreciation rates Exh S-12.1 3,433
- Reduction of demolition amortization Exh S-12.1 (713)
2,720$
DTE Gas Company MPSC Case No. U-17999
Computation of Revenue Deficiency Initial Brief
Rate of Return Summary for October 31, 2017 Attachment A
Based on Average Rate Base Page 4 of 4
Line Amount Weighted Weighted
No. ($000) Percent Cost % Cost % (1) Cost %
U-17999 Filed (Test Period Average Basis)
1 Long-Term Debt 1,333,778$ 48.03% 35.83% 4.972% 2.3883% 1.78% 1.0000 1.78%
2 Preferred Stock 0 0.00% 0.00% 0.000% 0.0000% 0.00% 0.00%
3 Common Shareholders' Equity 1,443,268 51.97% 38.77% 10.750% 5.5868% 4.17% 1.6460 6.86%
4 Total 2,777,046 100.00% 7.9751%
5
6 Short-Term Debt 137,815 3.70% 1.842% 0.07% 1.0000 0.07%
7
8 Customer Deposit 8,918 0.24% 7.000% 0.02% 1.0000 0.02%
9
10 Other Interest Bearing Accounts 3,869 0.10% 1.842% 0.00% 1.0000 0.00%
11
12 Job Development - ITC - Debt 1,495 0.04% 4.972% 0.00% 1.0000 0.00%
13 Job Development - ITC Equity 1,618 0.04% 10.750% 0.00% 1.6460 0.01%
14 Total Job Development - ITC 3,113
15
16 Deferred Income Taxes (Net) 791,814 21.27% 0.000% 0.00% 0.00%
17
18 Total 3,722,575 100.00% 6.04% 8.74%
19
U-17999 Initial Brief (Test Period Average Basis)
20 Long-Term Debt 1,329,379$ (1) 48.02% 35.71% 4.980% (2) 2.391% 1.7784% 100.00% 1.78%
21 Preferred Stock 0 0.00% 0.00% 0.000% 0.000% 0.0000% 0.00% 0.00%
22 Common Shareholders' Equity 1,438,768 (1) 51.98% 38.65% 10.750% 5.588% 4.1547% 1.6460 6.84%
23 Total 2,768,147 100.00% 7.979%
24
25 Short-Term Debt 137,815 3.70% 1.540% (3) 0.0570% 100.00% 0.06%
26
27 Customer Deposit 8,918 0.24% 7.000% 0.02% 1.0000 0.02%
28
29 Other Interest Bearing Accounts 3,869 0.10% 1.540% 0.00% 1.0000 0.00%
30
31 Job Development - ITC - Debt 1,495 0.04% 4.980% 0.0020% 100.00% 0.00%
32 Job Development - ITC Equity 1,618 0.04% 10.750% 0.0047% 1.6460 0.01%
33 Total Job Development - ITC 3,113
34
35 Deferred Income Taxes (Net) 800,814 (1) 21.51% 0.000% 0.0000% 0.00%
36
37 Total 3,722,676 100.00% 6.02% 8.70%
(1) 3 T 1183 - 1185, Exhibit S-4, Schedule D-1, column (b)
(2) 3 T 1184, Exhibit S-4, Schedule D-1, line 1, column (e)
(3) 3 T 1185, Exhibit S-4, Schedule D-1, line 5, column (e)
Description
DTE Gas Company MPSC Case No. U-17999
Revenue Requirement Adjustments to Company's Filing Initial Brief
for the 12 Month Period Ended October 31, 2017 Attachment B
($000) Page 1 of 1
(a) (b) (c)
Line RevenueNo. Description Source Deficiency
(Pre Tax Amts)1 Company's Filed Position Exhibit A-8 Sch A-1 182,927$
23 Adjustments to Revenue Deficiency:
4
5 Capital Structure
6 - Bonus Depreciation (1) (1,100)
7 - Debt cost rate adjustment (2) (316)
8
9 Rate Base10 Rate Base Changes
11 Working Capital - Reg Asset Demo Fee Attachment A page 2 (987) (86)
12 Net Plant - Non-municipal demo fees offset to construction Attachment A page 2 (428) (37)
13 Net Plant - Impact of corrected depreciation rates on Accum Depr. Attachment A page 2 (1,717) (150)
14 (3,131) 15 Operations and Maintenance Expenses
16 - 2015 update and Staff's inflation rate Exh S-3 C5 Revised (4,930)
17 - Rents Exh S-3 C5 Revised (1,202)
18 - Injuries and Damages Exh S-3 C5 Revised 674
19 - Executive Supplemental Retirement Plan Exh A-10, C5.9 (795)
20 - Accrued vacation Exh S-3 C5 Revised (1,809)
21
22 - Uncollectible Expense Exh S-3 C5 Revised 1,017
2324 Depreciation and Amortization
25 - Corrected depreciation rates S-3 C1.1 3,433
26 - Demo Fee Amortization Exhibit S-12.1 (713)
27 Total Adjustments to Company's Initial Revenue Deficiency Line 6 through Line 26 (6,014)$
28
29 Company's Brief Position Line 1 + Line 27 176,913$
(1) Exhibit S-12.2
(2) Original Rate Base X (new % Long Term Debt + % JDITC) X Change in Long Term Interest Rate +
Original Rate Base X % Short Term Debt X Change in Short Term Debt Interest Rate
= 3,719,566 X (35.71% + .04%) X (4.98% - 4.972%) + 3,719,566 X 3.7% X (1.54%-1.842%)
= 101 - 416 = (316)
STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
In the matter of the application of )
DTE GAS COMPANY for authority to )
to increase its rates, amend its rate )
schedules and rules governing the ) Case No. U-17999
distribution and supply of natural gas, )
and for miscellaneous accounting authority )
)
PROOF OF SERVICE
STATE OF MICHIGAN )
) ss.
COUNTY OF WAYNE )
TANYA MARIA CARR, being duly sworn, deposes and says that on the 27th
day of
July, 2016, she served a copy of DTE Gas Company’s Initial Brief, via electronic mail upon the
persons listed on the attached service list.
TANYA MARIA CARR
Subscribed and sworn to before
me this 27th day of July, 2016
___________________________
Lorri A. Hanner, Notary Public
Wayne County, Michigan
My Commission Expires: 4-20-2020
Acting in Wayne County
SERVICE LIST MPSC CASE NO. U-17999
ADMINISTRATIVE LAW JUDGE Mark E. Cummins 7109 W. Saginaw Hwy. Lansing, MI 48917 [email protected] ABATE Robert A. W. Strong 151 S. Old Woodward Avenue Suite 200 Birmingham, MI 48009 [email protected] Michael J. Pattwell Sean P. Gallagher Clark Hill, PLC 212 East Grand River Avenue Lansing, MI 48906 [email protected] [email protected] Nicholas Phillips Jr. Brubaker & Associates, Inc. 16690 Swingly Ridge Road, Suite 140 Chesterfield, MO 63141-2000 [email protected] ANR PIPELINE COMPANY Timothy J. Lundgren Varnum Law 201 N. Washington Square Suite 910 Lansing, MI 48933 [email protected] CO-COUNSEL FOR ANR Howard Nelson Francesca Ciliberti-Ayres Mike VanNordenm Greenburg Traurig, LLP 2101 L Street N.W., Suite 1000 Washington, D.C. 20037 [email protected] [email protected] [email protected]
ATTORNEY GENERAL (ENRA) Celeste R. Gill John A. Janiszewski G. Mennen Williams Bldg. 525 W. Ottawa Street, 6th Floor P.O. Box 30755 Lansing, MI 48909 [email protected] [email protected] Sebastian Coppola, President Corporate Analytics 5928 Southgate Rd. Rochester, MI 48306 [email protected] MPSC STAFF ATTORNEYS Meredith R. Beidler Graham Filler Spencer A. Sattler Amit T. Singh 7109 West Saginaw Hwy, 3rd Floor Lansing, MI 48917 [email protected] [email protected] [email protected] [email protected] DETROIT THERMAL, LLC Matthew M. Peck Arthur J. LeVasseur Fischer Franklin & Ford Attorneys for Detroit Thermal, LLC 500 Griswold Street, Suite 3500 Detroit, MI 48226-3808 [email protected] [email protected]
