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

Andrea Hayden
(313) 235-3813
andrea.hayden@dteenergy.com

March 25, 2019
Ms. Kavita Kale
Executive Secretary
Michigan Public Service Commission
7109 West Saginaw Highway
Lansing, Michigan 48917
Re:

In the matter of the Application of DTE Electric Company for authority
to increase its rates, amend its rate schedules and rules governing the
distribution and supply of electric energy, and for miscellaneous
accounting authority.
MPSC Case No. U-20162

Dear Ms. Kale:
Attached for electronic filing in the above-captioned matter is DTE Electric Company’s
Exceptions to the Proposal for Decision. Also attached is a Proof of Service.
Very truly yours,

Andrea
Hayden
Andrea Hayden
AH/lah
Enc.
cc:
Service List

Digitally signed by
Andrea Hayden
Date: 2019.03.25
16:02:16 -04'00'

 STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the application of
DTE ELECTRIC COMPANY
for Authority to increase its rates, amend
its rate schedules and rules governing the
distribution and supply of electric energy,
and for miscellaneous accounting authority

)
)
)
)
)
)
)

DTE ELECTRIC COMPANY’S EXCEPTIONS
TO THE PROPOSAL FOR DECISION

Dated: March 25, 2019

Case No. U-20162
(Paperless e-file)

 TABLE OF CONTENTS
I. INTRODUCTION.................................................................................................................1
II. DTE ELECTRIC HAS A $248.6 MILLION REVENUE DEFICIENCY. ..............................2
III. DTE ELECTRIC’S RATE BASE IS $17,152,348,000. .........................................................2
A. The Company’s Fossil Generation capital expenditures are reasonable and prudent and
should be approved. .........................................................................................................3
1. The Commission should fully approve DTE Electric’s Monroe Fly Ash Project
Capital Expenditures. ............................................................................................... 3
2. The Commission should approve DTE Electric’s capital contingency for the new
combined cycle gas turbine (“CCGT”) plant. ........................................................... 4
3. The Commission should fully approve DTE Electric’s capital and O&M
expenditures for River Rouge Unit 3. ....................................................................... 5
4. The Commission should approve the Ford combined heat and power (“CHP”)
plant ................................................................................................................... 15
B. The Commission should approve DTE Electric’s Distribution Operations capital
expenditures. ................................................................................................................. 18
1. The PFD’s proposed 2018 disallowance should be rejected. ................................... 19
2. The PFD’s proposed disallowances for the four months ending April 30, 2019, and
the Test Year should be rejected............................................................................. 20
3. DTE Electric appropriately based its projected DO Capital Expenditures upon its
Five-Year Plan. ...................................................................................................... 23
4. There is no need to revise rate case filing requirements. ......................................... 24
C. The Company’s Demand Side Management (“DSM”) programs are reasonable and prudent
and should be approved. ................................................................................................ 25
D. The Company’s information technology capital expenditures are necessary to support
utility operations and customer service and should be approved. .................................... 28
E. The PFD’s proposed IT reporting requirements should be refined. ................................. 34
F. The PFD’s proposed disallowance for Corporate Staff Group capital expenditures should
be rejected. .................................................................................................................... 35
IV. RATE OF RETURN ........................................................................................................... 36
A. DTE Electric should have a weighted after-tax rate of return of 5.72%. ......................... 36
1. The Company’s proposed capital structure would allow it to maintain adequate
access to capital at the lowest reasonable cost and should be approved. .................. 37
2. The Company’s proposed return on common equity is reasonable and necessary
given the economic and financial environments. .................................................... 43
i.

Recent and continuing changes in economic conditions, increasing business
risk, and the TCJA’s negative effects on credit metrics justify increasing
DTE Electric’s ROE. .......................................................................................... 45

i

 ii. Any reduction of equity in DTE Electric’s capital structure would require a
higher return on equity. ...................................................................................... 49
iii. Summary and Recommendations Regarding DTE Electric’s Cost of Equity. ...... 49
V. DTE ELECTRIC’S ADJUSTED NET OPERATING INCOME AND REVENUE
DEFICIENCY SHOULD BE ADOPTED............................................................................ 50
A. The Company’s operating and maintenance (“O&M”) expenses are reasonable and prudent
and should be approved. ................................................................................................ 50
1. DTE Electric’s Inflation on O&M Expense is reasonable and prudent and fully
supported. .............................................................................................................. 50
2. Distribution Operations O&M expenses. ................................................................ 52
i.

The Company’s Enhanced Tree Trimming Program (“ETTP”) and surge
funding are reasonable and prudent and will provide significant benefits to
customers. .......................................................................................................... 52

ii. The PFD adopted Staff’s modification, which is generally aligned with the
Company’s goals, but will increase the surge duration and prolong the
recognition of long-term benefits. ...................................................................... 54
3. Customer Service O&M Expenses – meter reading expenses. ................................ 58
4. The Company’s projected uncollectible expense is accurate, reasonable, and should
be approved. .......................................................................................................... 59
i.

The Company’s calculation methodology should continue to be used. ................ 59

ii. DTE Electric’s proposed returned check charge should be approved. ................. 60
5. Employee pension and benefits expense. ................................................................ 61
6. Employee compensation. ....................................................................................... 61
7. Edison Electric Institute Dues ................................................................................ 68
8. Weekend Flex and Fixed Bill O&M expense ......................................................... 69
B. Depreciation and Amortization. ..................................................................................... 69
C. Federal Income Tax Expenses........................................................................................ 70
D. Allowance for funds used during construction (AFUDC) and Other Operating Income
Adjustments................................................................................................................... 70
E. Charging Forward.......................................................................................................... 71
1. The PFD’s recommendation to allow site hosts to charge by the kilowatt-hour should
be rejected. ............................................................................................................ 71
2. The PFD’s proposed regulatory asset treatment and amortization would cause the
Company to lose recovery of deferred costs that are amortized without the expense
being included in the revenue requirement ............................................................. 75
3. Staff’s proposed regulatory asset treatment for O&M costs should be rejected and
O&M should be recovered as base O&M. .............................................................. 78

ii

 4. Additional pilot elements should be rejected, so there is no need to increase the
Charging Forward budget; however, any increase in program cost must have a
corresponding cost recovery. .................................................................................. 78
5. The Company has already addressed the request to “file a rate that addresses the
issue of demand charges” by offering its D3 General Services rate......................... 82
6. The PFD’s DCFC charging recommendation should be clarified. ........................... 83
F. Infrastructure Recovery Mechanism (“IRM”). ............................................................... 84
G. The nuclear surcharge should be increased, but the PDF’s recommendation for an updated
decommissioning cost study should be rejected. ............................................................ 92
VI. THE COMMISSION SHOULD ADOPT DTE ELECTRIC’S COST ALLOCATION
AND RATE DESIGN PROPOSALS................................................................................... 95
A. There is no valid basis to revisit production cost allocation. ........................................... 95
B. DTE Electric’s proposed capacity charge revenue requirement should be approved. ...... 97
C. DTE Electric’s residential and commercial secondary monthly service charges should be
adopted.99
D. DTE Electric’s primary service charge should be maintained. ...................................... 102
E. DTE Electric’s Weekend Flex and Fixed Bill Pilots should be approved. ..................... 103
1. The Fixed Bill pilot should be adopted. ................................................................ 104
2. The Weekend Flex pilot should be approved. ....................................................... 107
F. DTE Electric’s Primary Rate Design Proposals. ........................................................... 108
1. The Company’s proposed voltage level energy discounts and voltage level demand
adjustments reflect the proper allocation of costs of service. ................................ 108
i.

Energy-based voltage level discounts. .............................................................. 109

ii. Demand based voltage level discounts. ............................................................ 110
iii. Non-Capacity demand voltage level discounts.................................................. 113
2. Allocation of Capacity Costs to Rider 3 and Generation Reservation Fee. ............ 114
i.

Rider 3 Cost Allocation. ................................................................................... 114

ii. Generation Reservation Fee. ............................................................................ 119
3. Rate D1 Time of Use rate design (summer on-peak non-capacity charges). .......... 122
i.

The Commission should reverse its prior ruling. ............................................... 122

ii. The PFD/Staff’s recommendation that the Company explore shadow billing
should be rejected. ........................................................................................... 123
iii. The PFD’s recommendations to study alternative rate structures should be
rejected. ........................................................................................................... 124
iv. The Company’s “Recommended Plan” to TOU rate implementation should
be adopted. ....................................................................................................... 126

iii

 G. DTE Electric’s Distributed Generation (“DG”) program tariff (Rider 18) is reasonable,
equitable and consistent with MCL 460.6a(14) and should be approved....................... 128
1. The Inflow/Outflow tariff is the appropriate basis for the Company’s proposed DG
tariff (Rider 18). ................................................................................................... 129
2. The System Access Contribution (“SAC”) Charge is cost-based, equitable, nondiscriminatory and should be approved. ............................................................... 130
i.

Without the SAC, the Company would not recover the full cost of DG
customers’ distribution infrastructure use. ........................................................ 131

ii. The SAC is cost-based. .................................................................................... 135
iii. The SAC is not discriminatory. ........................................................................ 137
iv. DG customers are not comparable to customers who reduce consumption
through energy efficiency or demand response measures. ................................. 137
3. Michigan Law sets the requirements for the outflow credit. ................................. 138
4. LMP is the appropriate choice for the outflow credit. ........................................... 145
5. DTE Electric’s proposal to limit the existing Standard Contract Rider DG to nonrenewable generation should be approved. ........................................................... 151
6. Transition from Rider 16 to Rider 18. .................................................................. 153
H. Retail Access Service Rider (RASR) changes. ............................................................. 154
VII.

REQUEST FOR RELIEF .................................................................................... 155

iv

 I.

INTRODUCTION
On March 6, 2019, the Administrative Law Judge (the “ALJ”) issued a Proposal for

Decision (“PFD”). DTE Electric Company (“DTE Electric,” or the “Company”) agrees with the
PFD’s recommended disposition of some issues. However, the Company believes that other
recommendations are based on incorrect or inapplicable analyses, or foundations that do not exist
in the evidentiary record as required by the Michigan Administrative Procedures Act (“APA”),
and, therefore, submits these exceptions. 1
DTE Electric attempts to be succinct in light of the Commission’s knowledge and prior
decisions. Further support for DTE Electric’s positions and the reasons for those positions may
be found in DTE Electric’s Initial Brief and Reply Brief (including Attachments to those briefs),
as well as DTE Electric’s Application (including Attachments), testimony and exhibits, all of
which are incorporated by reference in these exceptions. For consistency and ease of reference,
the discussion is presented largely in the order that matters arise in the PFD, and related matters
are addressed collectively in the most relevant or logically-sequential context.
It is also important to note that changing one matter can result in corresponding changes to
other matters as numbers flow through calculations (for example, the inflation rate affects a
number of calculations). Lack of a discussion by DTE Electric to separately address every issue
suggested by or consequence resulting from the PFD should not be deemed to constitute an
agreement by DTE Electric. DTE Electric, of course, maintains all of its appellate rights.

See MCL 24.285, which states in pertinent part that: “A decision or order shall not be made except upon consideration
of the record as a whole or a portion of the record as may be cited by any party to the proceeding and as supported by
and in accordance with the competent, material, and substantial evidence.”
1

1

 II.

DTE ELECTRIC HAS A $248.6 MILLION REVENUE DEFICIENCY.
DTE Electric initially requested a jurisdictional rate increase of approximately $328.4

million; however, after reviewing Staff’s and intervenors’ positions, and considering the
Commission’s December 6, 2018 Order in Case No. U-18150, DTE Electric made eight
adjustments in its Initial Brief (listed as items a – h on page 1 of that Brief) and made additional
adjustments in its Reply Brief, 2 which resulted in a revenue deficiency of approximately $248.6

million for the projected test year (DTE Electric Reply Brief Attachments A and B).
The PFD recommended a $261,904,000 revenue deficiency including the elimination of
the “Credit A” credit approved in Case No. U-20105, which is a $113,667,000 revenue deficiency
without consideration of that credit elimination (PFD, pp 223, 301 as corrected by Errata,
Attachment A to PFD). For clarity and consistency, the Company’s discussion will focus on the
PFD’s proposed $113,667,000 deficiency. Attachments A and B to these Exceptions reconcile the
PFD’s $113,667,000 revenue deficiency to the Company’s fully-supported revenue deficiency of
$248.6 million.
III.

DTE ELECTRIC’S RATE BASE IS $17,152,348,000.
DTE Electric’s initially-filed rate base was $17,172,558,000, which the Company adjusted

to $17,152,348,000 (DTE Electric Reply Brief Attachment A, page 2). Staff recommended a rate
base of $17,051,324,000, consisting of $15,572,916,000 of Net Plant and $1,478,408,000 of
Working Capital (Staff Initial Brief, pp 4-7; and Appendix B). The Attorney General suggested a
$394.8 million reduction in rate base, based on various recommendations reflected on Exhibit AG23 (AG Initial Brief, pp 74-75).

The additional adjustments include accepting Staff’s $4.3 million working capital adjustment related to the active
healthcare credit regulatory liability; Staff’s $900,000 adjustment to revenues associated with the reduction in the
number of RIA customers; and $89,000 decrease to depreciation expense related to the HQ Energy Center.
2

2

 The ALJ agreed with the Staff and AG on a number of issues and recommended a total rate
base of $16,999,569,000 (PFD, pp 106; Attachment B to PFD). DTE Electric takes exception and
maintains that its Rate Base for the projected period ending April 30, 2020 is $17,152,348,000.
A.

The Company’s Fossil Generation capital expenditures are reasonable
and prudent and should be approved.

DTE Electric has a two-tiered maintenance and capital expenditure allocation strategy that
is based on the anticipated retirement dates of its coal-fired generating units. Belle River and
Monroe are the Company’s Tier 1 coal-fired units with the greatest long-term value to customers.
The remainder of the coal-fired units (St. Clair, River Rouge, and Trenton Channel) are Tier 2 (4T
517, 573). There are different operating performance metric targets that drive the capital and O&M
expenditures for each tier of units. Investments in Tier 1 coal units are designed to achieve first
quartile reliability performance as measured by random outage factor (“ROF”). Investments in
Tier 2 units are limited to those required to maintain safe and environmentally-compliant
operations until the units are retired (4T 516-17, 524, 531, 537, 573-74).
1. The Commission should fully approve DTE Electric’s Monroe Fly Ash
Project Capital Expenditures.
The PFD agreed with the Staff and AG’s suggested $34 million disallowance ($9.433
million in the 16-month bridge period, and $24.667 million in the projected test year) for the
Monroe Fly Ash Processing project (Exhibit A-12, Schedule B5.1, page 2, line 6).3 (PFD, pp 3637). DTE Electric takes exception. Although Staff indicated that it was concerned that “the
Company has neither full budgetary approval or a contract for construction of the project” (8T
4190), Staff also recognized that “this project could result in value for both the Company and its

The PFD rejected the AG’s proposed disallowance relating to Monroe Power Plant Fly Ash projects based on
speculation that the EPA might reconsider and revise the Effluent Limitations Guidelines (“ELG”). (PFD, pp 36-37).
3

3

 ratepayers and reduce the impact of the Company’s generation fleet on the environment” (8T
4191). Company witness Mr. Paul similarly explained that the project is reasonable and prudent
because it will provide economic benefits to customers by lowering PSCR costs, as well as
environmental benefits through reduction of solid waste (4T 600).4 Additionally, DTE Electric has
received internal project approval and has completed benchmarking and conceptual design of the
project. (4T 600) Therefore, the PFD’s proposed $34 million disallowance should be rejected.
2. The Commission should approve DTE Electric’s capital contingency for
the new combined cycle gas turbine (“CCGT”) plant.
Non-routine capital investments also include construction costs for the new combined cycle
gas turbine (“CCGT”) plant. The Commission granted three certificates of need (“CONs”) for a
1,100 MW CCGT plant, which is needed due to DTE Electric’s pending retirement of Tier 2 coalfired generating units (April 27, 2018 Opinion and Order in Case No. U-18419). The PFD agreed
with the Staff and AG’s proposal to disallow $10.5 million of CCGT capital expenditures
(contained within Exhibit A-12, Schedule B5.1, page 2, line 30) because they were classified as
contingency (PFD, p 31).
The Company disagrees. Ordering paragraph D at page 126 of the April 27, 2018 Opinion
and Order in Case No. U-18419 states: “Pursuant to MVL 460.6s(6), the Commission approves
$951.8 million for the construction of the natural gas combustion turbine electric generation
facilities. This amount includes $934 million for power island equipment and engineering,
procurement and construction costs and $17.8 million for contingency costs. Only actual amounts
incurred up to $951.8 million shall be recoverable through rates.” Mr. Paul explained that because

Mr. Paul’s testimony and exhibit regarding unforeseen projects that recently materialized was struck, but the record
was preserved through an offer of proof (4T 492-94) and the Company maintains its positions as previously set forth
in its filed response and on the hearing record.
4

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 the Company is only requesting to recover approximately two-thirds of the total pre-approved
project costs (approximately $650 million) in this case, it would be premature to disallow a portion
of the approved funding particularly considering that the Company has not exceeded the cost
approval provided for in the U-18419 Order. (4T 597-98)
3. The Commission should fully approve DTE Electric’s capital and O&M
expenditures for River Rouge Unit 3.
The PFD recommends disallowance of capital and O&M expenditures for Rouge Unit 3.
The ALJ summarized her decision as follows:
This PFD finds that the previously deferred capital costs, totaling $8.45
million, that were expended through December 31, 2018, were minimal,
reasonably incurred, and should be recovered in rates in the instant proceeding.
While issue about the economic operation of RR 3 were raised in the company’s
previous three rate cases, no specific retirement date for RR 3 was ever evaluated.
Thus, MEC/NRDC/SC’s recommendation to disallow these costs should be
rejected. However, routine capital costs totaling $1.87 million for 2019 through
the end of the test year are not reasonable and prudent and should be disallowed.
O&M costs for 2019 and the test year should also be disallowed on grounds that
the record in this case demonstrates that RR 3 could have, and should have been
retired at the end of 2018. (PFD, p 46).
DTE Electric believes that the continued operation of RR Unit 3 through May 2020 was,
and remains, justified based on the Company’s obligations to provide sufficient and reliable
generation to its customers, and is further supported by an NPVRR analysis (summarized on
Exhibit A-12, Schedule B6) as well as other factors. DTE Electric agrees with the PFD to the
extent that it rejected MEC/NRDC/SC’s proposed disallowances through the end of 2018, but
takes exception to the PFD’s proposed disallowances of capital and O&M costs for 2019 through
the end of the test year. As indicated in the quote above, the PFD’s proposed disallowances are
based on the premise that “RR3 could have, and should have, been retired at the end of 2018”
(PFD, p 46). That premise is flawed and cannot support the proposed disallowances because,
among other things, DTE Electric has been assigned March 29, 2019 to file an IRP pursuant to
5

 MCL 460.6t, and as the Commission has stated, that IRP proceeding is the proper forum to evaluate
plant retirement dates (4T 605-606):
The Commission agrees with DTE Electric that, although there is a possibility that
one or more of the Tier 2 units might retire early, any plans to do so should await
the outcome of the Company’s 2019 IRP analysis and the results of MISO’s
Attachment Y reliability study. Other matters such as workforce and local
government tax impacts may also be considered in a decision of this magnitude.
[April 27, 2018 Opinion and Order in Case No. U-18419, pp 48-49.]
Regardless, the PFD proceeded to address the question of when RR 3 should be retired in
this case, and to answer that question based on the ALJ’s opinion on the likelihood of
MEC/NRDC/SC’s economic analysis turning out to be correct (See, for example, PFD, p 47:
“Through the testimony of Mr. Allison and Mr. Fagan, MEC/NRDC/SC convincingly showed that
the economics of operating RR3 until the end of the test year is more likely than not to be
detrimental to ratepayers and that there is a significantly greater benefit to retiring the unit in
December 2018”). 5
Instead, the question in this case is whether the projected costs associated with the
operation of RR Unit 3 are reasonable and prudent, and the answer to that question involves more
than just an economic analysis. The Company also evaluates factors including the age and
condition of the generating unit, resource adequacy, grid reliability, local community impacts, and
workforce planning when determining whether a generating unit should be retired and the timing
of that retirement (4T 525-31, 576-77). MISO’s permission is also needed to retire units pursuant
to the Attachment Y process (4T 526-27). Since the Tier 2 units comprise nearly 2,000 MW of net

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, 68586; 658 NW2d 849 (2003).
5

6

 summer capability, it is reasonable and prudent to facilitate a phased transition between now and
2023 (as indicated above) to maintain a safe and reliable supply of energy for customers (4T 524).
MEC/NRDC/SC’s economic criticisms were also overstated. The Company’s NPVRR
analysis for RR Unit 3 consisted of two options (1) operate RR Unit 3 until the planned retirement
date in May 2020, or (2) retire RR Unit 3 as soon as practical, which – at the time the NPVRR
analysis was conducted – was December 31, 2018, after the Company complies with MISO’s
required retirement request filing process (3T 367).
Three sensitivities for capacity price were examined to capture the range of uncertainty
with capacity prices. The NPVRR results ranged from $15 million more costly to $10 million less
costly to maintain the planned 2020 retirement date. This range of sensitivity outcomes supports
continued operation of RR Unit 3 as the most reasonable and prudent option, as further discussed
below, and considering the non-economic factors outlined above and recognized by the
Commission in Case No. U-18419 (3T 369, 373-77; Exhibit A-12, Schedule B6, p. 2, column (c)).
The PFD also appears to have been persuaded by MEC/NRDC/SC witness Mr. Allison’s
identification of an adjustment in the NPVRR analysis (PFD, pp 41-42); however, as Ms. Dimitry
pointed out in her rebuttal testimony, his adjustments still yielded a mixed range of outcomes.
Given the mixed range of financial outcomes (even after Witness Allison’s adjustments), the other
non-economic considerations discussed by Witness Paul support continued operation of RR3 at
this time, along with the requested nominal capital investments and O&M to ensure that such
operations are maintained safely (3T 377-378).
As discussed above, there are additional factors to consider when determining whether to
retire a generating unit, and the Company decided that the best option for its customers is to
continue operating RR Unit 3 until its planned retirement date in 2020 (3T 369, 379-80; 4T 524-

7

 31, 575-76). Further justification for continued operations of RR Unit 3 until May 2020 is provided
by the MISO Attachment Y reliability study report for RR Unit 3, which indicates that retirement
or suspension of RR Unit 3 may create thermal or voltage issues that could require the Company
to shed firm load to ensure grid reliability (Exhibit MEC-43). Firm load shedding is essentially a
technique of last resort to avoid overloading a system, where power would be cut off for some
customers, above and beyond those customers that chose to be on an interruptible tariff, to maintain
system availability for other customers. The Company has significant concerns about relying on
this type of electrical service interruption to customers as means to ensure electric system
reliability. Maintaining and operating RR Unit 3 until its planned retirement date will provide time
to identify and implement alternative solutions that can ensure continued reliable service to
customers (4T 528, 577, 660).
The PFD states: “This PFD agrees with DTE Electric that shedding firm load is not a
reasonable option for dealing with grid stability, but the company has had years to devise a solution
for this potential problem, and it has failed to do so” (PFD, pp 47-48. Emphasis in original). The
PFD’s criticism is unfounded. The ultimate solution to the planned loss of Tier 2 capacity is to
replace it, which DTE Electric is doing in part with the new CCGT plant, and through its otherwise
systematic and well-planned Tier 2 retirement schedule and other activities. The Commission
previously agreed with DTE Electric that “the most reasonable and prudent course of action is to
retire the Tier 2 units by 2023 as DTE Electric proposes” and that “although there is a possibility
that one or more of the Tier 2 units might retire early, any plans to do so should await the outcome
of the company’s 2019 IRP analysis and the results of MISO’s Attachment Y reliability study”
(April 18, 2018 Order in Case No. U-18419, pp 47-49). The Company proactively submitted an
Attachment-Y Suspension request to MISO on January 18 st, 2018 to study the effects of retiring

8

 RR Unit 3 in 2020 and did not receive the final results from this study until March 20 th, 2018. As
such, the Company has not had years to devise a solution as the PFD suggests and near term
electrical system planning and operation is dynamic (4 T 526-528).
MEC/NRDC/SC also relied on their witness Mr. Fagan who suggested the disallowance of
projected capital expenditures for the River Rouge and St. Clair power plants because MISO
Attachment Y studies indicate that they are not needed as System Support resources (6T 2535-36).
Mr. Paul explained that this suggestion should be rejected because the MISO Attachment Y
analysis for RR Unit 3 assumed a 2020 retirement, and the St. Clair analysis assumed a 2022
retirement. No analysis has been completed based on any other retirement date, and MISO would
need six months to perform additional Attachment Y studies (4T 603-604). Mr. Fagan also ignored
other factors that determine the reasonableness and prudence of continued operations of a
generating unit, as indicated above (4T 525, 604) and recognized by the Commission. April 27,
2018 Opinion and Order in Case No. U-18419, pp 48-49 (quoted above).
The PFD correctly rejected MEC/NRDC/SC’s proposed disallowance of capital
expenditures for the St. Clair units, explaining in part: “Because DTE Electric is expected to file
an IRP within a month, the issues raised by MEC/NRDC/SC concerning the economics of retiring
St. Clair units and Trenton Channel earlier than planned should be addressed as part of that
proceeding, as the Commission has directed” (PFD, p 49). The PFD is correct, and should have
applied this same correct reasoning to RR 3. The PFD’s only explanation for not doing so is:
“These units are not currently expected to retire for three years or more, thus they are not similarly
situated to RR 3” (PFD, p 49).
The Commission was well aware that DTE Electric’s Tier 2 units were scheduled for
retirement between 2020 and 2023 (see, for example, April 18, 2018 Order in Case No. U-18417,

9

 p 30), but the Commission treated all of the Tier 2 units collectively, as indicated above. There is
no sound basis to deviate from the Commission’s recent Order and instead now carve out RR 3 for
special treatment as the PFD suggests.
With respect to DTE Electric’s Trenton Channel and St. Clair plants, the PFD states:
Although this ALJ does not recommend deferral or disallowance of capital costs at this
time, given that all aspects of the retirement of these units will be addressed in the IRP, the
issue of cost recovery for these units should nevertheless be included in the company’s
next rate case, and the company should be directed to submit an up-to-date NPVRR for the
St. Clair and Trenton Channel units” (PFD, p 49).
DTE Electric disagrees that the Company should be required to essentially litigate the same issues
in multiple cases, with potentially different outcomes. As the PFD initially observed, “all aspects
of the retirement of these units will be addressed in the IRP.” The PFD’s suggestion that the
Commission should instead act inconsistently threatens an illegal result. Application of Michigan
Consolidated Gas Co, 304 Mich App 155, 173; 850 NW2d (2014) (vacating reconciliation orders
because MPSC “acted unreasonably, or capriciously” in setting a prospective pricing change, then
applying that change retroactively); Michigan Gas Utilities v Public Service Comm, 200 Mich App
576, 584-85; 505 NW2d 27 (1993) (rejecting MPSC attempt to disavow its prior decision,
explaining that if an estoppel existed, it was against the MPSC).6
Mr. Paul explained that Mr. Allison’s proposal to disallow recovery of future capital costs
related to RR Unit 3 lacked merit for the reasons indicated above regarding Mr. Fagan’s flawed
proposal (4T 605-606). Ms. Dimity agreed (3T 379-80), and further explained that Mr. Allison

6

See also, St. Cloud Public Service Co v St. Cloud, 265 US 352, 363 (1924) (gas company and rate setting entity
entered into a contract fixing rates); Wiersma v Michigan Bell Telephone Co, 156 Mich App 176, 185; 401 NW2d 265
(1987) (“The state, as well as an individual, may be estopped by its acts, conduct, silence and acquiescence”); Entergy
Gulf States, Inc v Louisiana Public Service Comm, 730 So2d 890, 901 (1999), reversing Public Utility Commission’s
attempt to preclude a utility from recovering certain expenses as “untenable” and finding all its reasons to be “arbitrary
or capricious or unsupported by the record.” 730 So2d at 901.

10

 improperly focused on what he considered to be the most likely scenario, while dismissing other
sensitivities, which is not a reasonable and prudent basis for making power plant retirement
decisions. In contrast, the Company considered an appropriate range of capacity price sensitivities
in its RR Unit 3 economic analysis to capture the range of uncertainty in capacity prices, as
indicated above. Moreover, the June 2018 PACE capacity price forecast was the most recent
available and appropriate for a low forecast of capacity prices. The Cost of New Entry (“CONE”)
represented an appropriate upper boundary for capacity prices in MISO. The 50% of CONE
sensitivity represented a very reasonable middle range sensitivity, which closely compares to
capacity prices paid by the Company in 2017 and the recent November 2018 PACE capacity price
forecast (3T 374-75). The change in PACE capacity forecasts from June 2018 to November 2018
further supports the Company’s consideration of a full range of sensitivities, and demonstrates the
unreasonableness of Mr. Allison’s focus on what may appear to be most likely at one point in time
(3T 376).
Even if one were to give some credence to Mr. Allison’s views (which would be
inappropriate), there are still non-economic considerations – including concerns about reliability
– that support continuing operation of RR Unit 3 at this time, along with the requested nominal
capital and O&M to ensure that those operations are maintained safely. These non-economic
factors become even more important in cases like this where economic analyses yield mixed or
marginal outcomes. It simply would not be reasonable or prudent to make long-term decisions
regarding capital intensive assets every time an economic analysis suggests a shift in value (3T
377-78). Proposed cost disallowance (to effectively force immediate retirement) is also contrary
to the Commission’s recent conclusion that any early retirements should await the outcome of the

11

 Company’s IRP, and that non-economic factors may be considered when contemplating an early
retirement of Tier 2 units such as RR Unit 3 (3T 379-80).
Ms. Dimitry explained that the decision to retire a generating unit earlier than planned
requires diligent analysis using comprehensive and internally-consistent data, and must be
supported with specific reliability studies under MISO’s Attachment Y process, as outlined above
and recognized by the Commission in its April 27, 2018 Order in Case No. U-18419. Unless and
until such a comprehensive analysis is completed (as is planned for the Company’s IRP to be filed
March 29, 2019) it is reasonable and prudent for the Commission to approve the recovery of capital
and O&M investments to ensure the continuing safe operations of Tier 2 plants through their
current retirement dates (3T 380-81).
The PFD also appears to have been persuaded by MEC/NRDC/SC’s suggestion that the
capacity-related reliability need, and the capacity value of Tier 2 units, are unclear (PFD, p 47).
To the contrary, the record includes an extensive discussion by Mr. Arnold regarding capacity
market fundamentals and how local resources like the Company’s Tier 2 plants support MISO
Zone 7 (where DTE Electric’s service territory is located) meeting the MISO Zone 7 Local
Clearing Requirement (“LCR”), which has both economic and reliability benefits (3T 296-302).
The future is, of course, inherently unclear (as demonstrated by changing capacity predictions over
time), but this favors a conservative approach to plant retirements, contrary to the PFD’s
recommendation.
More specifically, the Local Reliability Requirement (“LRR”) and Capacity Import Limit
(“CIL”) are directly used to calculate the LCR (the amount of capacity needed in a MISO zone to
meet the NERC reliability standard of a one-day loss of load event every 10 years). From Planning
Year (“PY”) 2018/2019 to 2019/2020, the MISO Zone 7 per-unit LRR increased from 115.3% to

12

 117.2% of zonal coincident peak demand, and the MISO Zone 7 CIL dropped from 3,785 MW to
3,211 MW. This situation results in a need for more local resources to meet the NERC reliability
standard, holding all else constant (3T 296-97). Applying the PY 2019/2020 MISO Zone 7 perunit LRR and CIL values to the 2017 Capacity Demonstration indicates that MISO is 1% away
from not meeting the LCR in 2021/2022 (3T 298). MISO Zone 7 not meeting the LCR would
result in the MISO Zone 7 Planning Reserve Auction (“PRA”) clearing price for capacity being
set to the Cost of New Entry (“CONE,” which will be $88,830 / Zone 7 Zonal Resource Credit in
the 2019-2020 PRA). For approximately 670 MWs of unforced capacity (the size of St. Clair Units
1, 2, 3 and 6) that the Company is short to its planning requirement, the Company’s customers
would pay approximately $60 million in any Planning Year that MISO Zone 7 is short to the LCR
(3T 299).
Mr. Allison argued that excess capacity can be expected based on June and September
2018 PACE forecasts (6T 2621-23). This suggestion is based on outdated information. MISO
posted the 2019/2020 LOLE Study Report in October 2018, after the June and September 2018
PACE forecasts were developed, and Mr. Allison’s discussion does not include the recent increase
in MISO Zone 7 LRR and decrease in MISO Zone 7 CIL (3T 301). Mr. Allison’s heavy reliance
on out-year forecasts is also inappropriate because the future is uncertain. For example, MISO’s
2017 LOLE Study Report forecasted the Zone 7 PY 2019/2020 per-unit LLR would be 113.2%,
but the actual Zone 7 PY 2019/2020 per unit LRR is 117.2% - a 4% increase in 2 years (3T 300).7

7

MEC/NRDC/SC witness Mr. Fagan similarly relied on out-year forecasts. He used the 2019/2020 and 2024/2025
MISO Zone 7 LRR values from the 2019/2020 LOLE forecast to indicate MISO Zone 7 will have increased headroom
and the transmission system will be relatively unconstrained for exchanging capacity (6T 2535, 2537, 2539). These
claims are founded on the assumption that MISO’s out-year forecast will turn out to be accurate, which is speculative
as indicated above regarding the recent 4% (from projected to actual) increase in per-unit LRR. MISO has also
recommended discontinuing out-year forecasts due to volatility and changing variables. Mr. Fagan’s further discussion
of potential developments (including transmission projects) beyond the planned retirement dates lacks relevance (3T
301-302).

13

 Resource adequacy concerns are a significant consideration in the retirement of RR 3. The
numbers are a moving (and therefore uncertain) target, and the Company’s decision-making cannot
be judged based on speculation

8

or hindsight. As the Court explained in Detroit Edison Co v

Public Service Comm, 261 Mich App 448, 452; 683 NW2d 679 (2004) (reversing the MPSC’s
attempt to use hindsight to determine whether DTE Electric could recover its costs), the utility
“does not have the benefit of hindsight in accruing costs, and the PSC must review the utility’s
expenditures in light of the knowledge that was available at the time the expenditures were made.” 9
The Commission should recognize the capacity-related reliability need and capacity value of Tier
2 plants, and continue to approve rate recovery of future capital costs to support local capacity
needs in Michigan’s lower peninsula (3T 302).
Therefore, the PFD’s proposed disallowance of $1.87 million of RR 3 routine capital costs
for 2019 through the end of the test year should be rejected.
In addition to capital, the PFD also recommends that “O&M costs for 2019 and the test
year should also be disallowed on grounds that the record in this case demonstrates that RR3 could
have, and should have, been retired at the end of 2018” (PFD, p 46. See also, p 138, which identifies

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).
8

9

See also, ABATE v Public Service Comm, 208 Mich App 248, 260; 527 NW2d 533 (1995) (rejecting challenge to
utility’s cost recovery as “inconsistent with the prudent investment test under which the end result of a utility’s efforts
do not determine how much is recoverable. Rather, utilities are compensated for prudent investments at their actual
costs when made regardless of whether the investments are deemed necessary or beneficial in hindsight.”); RRC v
Public Service Comm, 198 Mich App 144, 151; 497 NW2d 558 (1993) (“The reasonable utility management test for
prudence is whether the costs in question are those a reasonable utility manager would have incurred, in good faith,
under the same circumstances and at the relevant point in time. Under this test, the fact that a management decision
turns out to have been wrong in hindsight is not relevant.”); Consumers Energy Co v Public Service Comm, 261 Mich
App 455, 460; 683 NW2d 188 (2004) (“An approval made contingent on future unknown facts that may indeed
eradicate the initial approval is not a provision for full recovery.”).

14

 the proposed O&M disallowance as $17.7 million). The PFD offers no further explanation, but
notes that the Commission “approved full recovery of O&M costs” in Case No. U-18255 (PFD, p
46, n 61).
The PFD’s proposed O&M disallowance should be rejected. In addition to the discussion
above, the PFD’s proposal is contrary to the Commission’s decisions in Case No. U-18255, where
the Commission approved operational expenses. On rehearing, the Commission further approved
maintenance expenses, explaining in part:
The Commission approved approximately $6.1 million in operational expenses (out
of a total O&M request of $15.536 million), but disallowed all maintenance
expenses, amounting to $9.173 million . . .The Commission agrees with the utility
that, while the unit is in use, reasonable and prudent maintenance costs should be
approved to ensure safe operation and a smooth transition to retirement. (June 28,
2018 Order on Rehearing in Case No. U-18255, p 6).
Additionally, as noted above, the Commission agreed that any plans to retire the Tier 2
units early “should await the outcome of the company’s 2019 IRP analysis and the results of
MISO’s Attachment Y reliability study” (April 18, 2018 Order in Case No. U-18419, pp 47-49).
The same reasoning applies here, and so the PFD’s contrary recommendation should be rejected.
4. The Commission should approve the Ford combined heat and power
(“CHP”) plant.
The PFD recommended that capital costs associated with the Ford CHP plant should be
disallowed because DTE Electric did not demonstrate compliance with the Code of Conduct (PFD
pp. 58-59). The Company takes exception to this recommendation because the record demonstrates
that the price to be paid by DTE Electric for the CHP plant is at or below market price as required
by the applicable code of conduction provisions. The Code of Conduct provides:
If an affiliate or other entity within the corporate structure provides services or
products to a utility, and the cost of the service or product is not governed by
section 10ee(8) of 2016 PA 341, MCL 460.10ee(8), compensation is at the lower

15

 of market price or 10% over fully allocated embedded cost. [Mich. Admin Code
R 460.10108(4)]
In order to determine a market price for the CHP plant, DTE Electric retained HDR to
develop an independent cost estimate. This estimate was obtained before the Company received DTE
Power and Industrial’s (“P&I”) cost estimate and it was used to inform negotiations with P&I. HDR
calculated the cost at $84.6 million, hence, the $62.3 million purchase price was determined to be
a reasonable and prudent price that is significantly below the estimated market price (5T 1130,
Exhibit A-28, Schedule R2)). Additionally, the levelized cost of energy (“LCOE”) analysis for
the CHP plant demonstrates that it is in a competitive range with alternative generation
technologies such as solar, wind and combined cycle natural gas (5T 1131). As such the HDR
study was a valid indicator of market price.
Nevertheless, to further address concerns regarding transparency, the contracts related to
the transaction with P&I were also provided to the parties. (Confidential Exhibit A-40, Schedules
DD-1 through DD-8) Those contracts set forth the numerous details regarding the CHP plant itself
(schematics, diagrams, spreadsheets, etc.) and the deal structure between DTE Electric and its
affiliate. While MEC/SC/NRDC witness Mr. Sansoucy raised concerns that the HDR estimate
was not an “apples-to-apples” comparison because DTE Electric did not provide a cost
breakdown from DTE P&I for the project, a review of the contract materials provides detailed
information regarding the plant construction. (See Confidential Exhibit A-40 Schedule DD-4)
In addition to the above, the Company obtained and disclosed the supporting documents
that HDR utilized to prepare its cost estimate, which included estimates from multiple equipment
vendors. (Confidential Exhibit A-40, Schedule DD-8) No party pointed to any specific concerns
regarding these documents. In fact, the parties appear to disregard the contracts and the supporting
documents in their recommendations. Mr. Coppola’s transparency argument cited in the PFD
16

 rests solely on the premise that the Company should have acquired competitive bids and ignores
the remainder of the evidence provided by the Company.
MEC/SC/NRDC also argue that the Company did not provide sufficient evidence that the
cost of the CHP plant was at or below market price. However, neither MEC/SC/NRDC nor the
AG provided any substantive criticisms of the HDR cost estimate aside from the fact that it seems
too high. They suggest that the only satisfactory evidence of market price is alternative bids. The
PFD agrees that the HDR cost study was not sufficient to demonstrate compliance with the Code
of Conduct, although notes that the Company could find alternative means aside from alternative
bids to show that the cost is market based. (PFD p. 59, fn 54) The Code of Conduct does not
specify a particular method to determine market price, and Staff and the PFD inherently recognize
this by suggesting that alternative means could be utilized to demonstrate compliance. Based on
the extensive documentation provided by the Company to support the CHP plant’s cost and the
transaction with DTE P&I, the recommendation to disallow capital costs associated with the CHP
plant should be rejected.
The PFD also cites MEC/SC/NRDC’s argument that HDR’s indirect costs (vs direct costs)
appear to be excessive (PFD p. 55) However, even when the $14 million contingency highlighted
by Mr. Sansoucy is removed, HDR’s estimated project cost is still 70.6 million. In Mr. Sansoucy’s
testimony cited in the PFD he also suggests that valid site construction cost estimates of
approximately $12.5 million and engineering and insurance costs of $4.6 million and $2.7 million
should be disregarded, without any justification (PFD p. 55). But even going one step further for
argument’s sake and discounting these costs generously by one-third, the total estimated cost for
the plant is $63.8 million. Additionally, Mr. Sansoucy’s argument that the Commission should

17

 consider costs associated with the gas pipeline is not applicable here as it will not be an expense
of DTE Electric and subject to review in future DTE Gas rate cases (5 T 1142).
Finally, Mr. Coppola’s characterization of the Ford requests for proposals, as cited in the
PFD (p. 57), is incorrect. Ford did not seek to own their own CHP plant, but instead requested
that DTE Electric provide an integrated solution for the central energy plant as part of the RFP
process (5T 1129).
It also bears consideration that there does not appear to be any significant dispute among
the parties regarding the benefits retained by DTE Electric as a result of this project. Nevertheless,
the PFD’s recommendation disregards the substantial benefits that the Company and its customers
receive by retaining DTE Electric’s largest bundled customer. The Company estimates that it will
retain over $7M in annual revenue by completing the project, or $102.1 million on a net present
value basis over the 30-year life of the facility. This positively impacts affordability for all of the
Company’s customers. (Exhibit A-28, Schedule R1) Thus, taken as a whole, the evidence provided
by DTE Electric in this case shows that the CHP plant is a reasonable and prudent cost that should
be approved.
B.

The Commission should approve DTE Electric’s Distribution
Operations capital expenditures.

DTE Electric supported Distribution Operations (“DO”) capital expenditures of $651.4
million in 2017, which are projected to be $810.2 million for 2018, $285.6 million for the four
months ending April 30, 2019, and $830.6 million for the projected test year 12 months ending
April 30, 2020. Staff proposed disallowances for 2018, the four months ending April 30, 2019,
and the test year. The PFD agreed with Staff’s proposed disallowances corrected for an inflation

18

 adjustment (PFD, pp 71, 76). The Commission should instead reject the proposed disallowances
as discussed below.
1. The PFD’s proposed 2018 disallowance should be rejected.
Staff initially proposed a $64,455,000 disallowance for 2018, based primarily on Staff
applying its forecasting methodology to actual spending from January to August 2018 (8T 4117).
The Company responded by explaining that Staff’s proposal should be rejected for three primary
reasons, including that Staff applied its forecasting methodology inconsistently, and arbitrarily
assumed that no additional capital replacements would be required for Storm from September
through December 2018,10 despite the Company experiencing an average of seven storms between
September and December in recent years (Exhibit A-23). In September and October 2018 alone
there were four storms and the monthly Emergent Replacement spending has exceeded $32 million
per month, which is well above the five-year average of $16.8 million per month (4T 838-845).
Staff then modified its position to a recommended $19,223,000 disallowance, stating that “Staff
agrees with all of the forecasts [shown by Exhibit A-31, Schedule U-7, reflecting actual spending
as of October 31, 2018] except for the projection for Emergent Replacements” (Staff Initial Brief,
p 39). The PFD agreed (PFD, p 71).
The Company disagrees with the proposed disallowance because the problem indicated
above persists when arbitrarily proposing special treatment for Emergent Replacements. Staff
offered the following reasoning for its proposed disallowance:
The Company spent $297,370,000 on emergent replacements from January
through October 2018. Using the straight-line extrapolation methodology
(multiplying by 12/10 or 1.2), the total spending in this category would be
$356,844,000. (Exhibit A-31, Schedule U-7). This amount is simply too high and

For example, Staff stated that: “Storm, the sub-category with the highest YTD actual spending, was determined to
be the sub-category where spending stops” (8T 4115).
10

19

 assumes that the higher-than-forecasted spending in Emergent Replacements will
continue in November and December. [Staff Initial Brief, p 40.]
The Company disagrees and maintains that the forecasts (which Staff acknowledged are
appropriate for all other categories) should be applied consistently. Moreover, there is no
evidentiary support for Staff’s assumption that storm-related costs would suddenly drop off in
November and December of 2018. The record indicates that 2018 was a particularly stormy year,
and that historically, November and December storms are commonplace (Exhibit A-23; 4T 838845). The Commission should not disregard appropriate forecasting and record evidence based on
Staff’s belief (apparently shared by the PFD at p 71) that the result is “simply too high.” Therefore,
the PFD’s recommended disallowance should be rejected.
2. The PFD’s proposed disallowances for the four months ending April 30,
2019, and the Test Year should be rejected.
Staff initially proposed a $31,447,000 disallowance for the first four months of 2019 (8T
4119), and a $61,894,000 disallowance for the projected test year (8T 4121). Staff revised its
recommended disallowance to $21,912,000 for the first four months of 2019, and $33,053,000 for
the test year (Staff Initial Brief, p 42). The PFD agreed with Staff’s proposed disallowances, but
did recognize the Company’s adjustment to include 2019 inflation as calculated in DTE Electric’s
reply brief (PFD, p 76, referencing the calculations set forth above). However, the Company
maintains that no disallowance is warranted.
First, Staff used its 2018 forecast to develop its 2019 and 2020 forecasts (Staff Initial Brief,
p 42). However, as explained above, Staff’s 2018 forecast is improper because it arbitrarily underforecasted emergent replacements. Since Staff used a flawed starting point for its analysis, the
result is similarly neither reasonable nor prudent (4T 850-51).

20

 Second, Staff did not consider the merits of the Five-Year Plan, and instead simply used
historical costs (plus inflation11) to forecast future capital expenditures (Staff Initial Brief, p 43).
There are some cost categories where it is appropriate to use historical costs plus inflation to
estimate future expenditure, but not all categories are a good fit for this forecasting methodology.
For example, when there are planned spending increases beyond inflation, using this methodology
will cause under-forecasting. This methodology is particularly inapt when applied to a category
where the Commission has ordered the Company to reexamine its spending and focus on a fiveyear plan to address reliability issues (MPSC Case No. U-18014, 10/11/17 Order). Staff’s
methodology ignores the fact that the Commission has asked DTE Electric to do things differently
– and the Company has developed a plan to do just that. Staff’s plan would return the Company to
the status quo, which does not address the Commission’s concerns, nor does it produce satisfactory
safety and reliability improvements. DTE Electric’s DO investments are guided by the Five-Year
Investment and Maintenance Plan (“Five-Year Plan,” Exhibit A-23, Schedule M5) that the
Company developed based on a careful evaluation of asset conditions and customer needs. With
the goal of reducing risk, improving reliability and managing costs, the Company evaluated a
broad portfolio of investments and prioritized them based on their ability to meet goals that are in
the best interest of customers (4T 704, 812). Staff’s overly simplistic methodology also stands in
sharp contrast to the significant concerns and substantial effort reflected in the Five-Year Plan (4T
850-52). Mr. Bruzzano explained that using a historical “costs plus inflation” methodology
essentially sets aside the Five-Year Plan:
The Company spent a great deal of effort to develop the Five-Year Plan and
determine what is needed to improve reliability, reduce risk and manage costs as
directed by the Commission in Case No. U-18014 (which was later moved to Case
No. U-20147). The Company collaborated with the Staff in this effort. Solely
11

Staff did not apply inflation consistently; this concern is addressed separately below.
21

 using inflation rates effectively sets aside all the effort that was used to develop a
robustly supported Five-Year Distribution Plan. When the Commission ordered
the Company to create a Five-Year Plan, it did so because it understood that a
thoughtful effort that considered multiple factors was needed. Using inflation rates
does not consider the investments that are needed to address aging infrastructure,
system risks and the need to bring new technology to support improved grid
operations. [4T 851]
The Commission required DTE Electric to create a Five-Year Plan to address aging
infrastructure, system risks and the need to implement new technology. Staff instead asks DTE
Electric to ignore that Five-Year Plan, without identifying any disagreements with the elements of
the plan itself, and merely maintain the status quo. The Commission should not adopt the
PFD/Staff’s proposed disallowance, as it arbitrarily reduces the funding needed to execute the
Five-Year Plan without rejecting or otherwise disagreeing with any part of the Five-Year Plan.
Finally, Staff initially used, and continued to use, an arbitrary and unreasonable approach
to test whether its projection of Strategic Capital is reasonable and prudent (4T 850, 852-53). Staff
reasoned that the Company was “on track” for 63.7% spending in 2018, and that a reasonable
“middle ground” (between 63.7% and 100%) would be 81.9%, so Staff’s projections are
reasonable because they are greater than 63.7% (Staff Initial Brief, p 44-45). Again, this type of
reasoning is not based not upon facts and system needs. Mr. Bruzzano explained that Staff’s
starting point (then 61.3% based on spending as of August 2018) was not appropriate. Strategic
Capital spending was impacted by several adverse weather effects in 2018 and is not indicative of
the pace at which the Company will spend Strategic Capital going forward in 2019 and 2020 (4T
38). Staff’s approach of taking the “middle ground” (between partial-year 2018 spending and
100% of 2019 projected spending) is also unsupported and arbitrary. The Company is ramping up
resources to expend 100% of its planned capital. While there are risks to the ability to always
achieve this, the Company has been pursuing several initiatives to ensure that sufficient resources

22

 are in place to execute all planned investments (4T 796-800). Therefore, there is no sound basis
for the Commission to set the Company’s capital expenditures based on Staff’s “middle ground”
calculation (4T 852-53).
DTE Electric maintains that the proposed disallowances should be rejected completely, for
the reasons discussed above. 12
3. DTE Electric appropriately based its projected DO Capital Expenditures
upon its Five-Year Plan.
The PFD recognizes that the Five-Year Plan has value, but suggests that the value relates
only to providing visibility into system needs, and not necessarily to justify spending (PFD, pp 6566). But that visibility into system needs provides a snapshot of the condition of the Company’s
electric system, including a high number of assets reaching or exceeding expected useful life, and
clearly shows that maintaining the status quo will not meet either the Company’s or the
Commission’s reliability goals. The Company maintains that if its system needs repair, or
improvement, then spending is justified to satisfy that need.
The Company further disagrees with the PFD’s distinction between system needs and
spending because the Five-Year Plan was prepared as directed by the Commission to address the
highest-priority risk and reliability issues faced by the Company’s customers. The next version of
the Five-Year Plan will similarly prioritize highest-priority risk, and the categories where spend is
required are not likely to be significantly different from the current Five-Year Plan. Delaying the
implementation of the investments described in the Five-Year Plan would jeopardize DTE
Electric’s and the Commission’s goal of achieving better safety, reliability and resiliency for the

For completeness, DTE Electric notes that the PFD rejected the AG’s proposed disallowance for Infrastructure
Resilience and Hardening/Redesign and the Staff’s proposed disallowance for the Company’s 3G to 4G upgrade as
duplicative of the Staff’s proposed disallowances (PFD, pp 79, 85). The Company agrees that these proposed
disallowances should be rejected, adding that to the extent that the Commission reaches the merits of these proposed
disallowances, they should be rejected as discussed in DTE Electric’s Reply Brief, pp 37-39, 46-47).
12

23

 Company’s customers. It would not be in the best interest of the Company’s customers to delay
the implementation of the Five-Year Distribution Plan for hypothetical outcomes from other cases
or regulatory proceedings. Moreover, the November 21, 2018 Order in Case No. U-20147 recently
clarified, at page 36, that the purpose of the next round of distribution plans will not be appreciably
different than current, or carry significant new requirements on utilities:
[T]he purpose of the framework for the next round of distribution plans is to
provide focused discussion, longer-term visibility than what is available in a rate
case, and better understanding, not to set prescriptive mandates on utilities . . . The
Commission cannot usurp utility management prerogatives. See, Union Carbide
Corp v Pub Serv Comm, 431 Mich 135, 148; 428 NW2d 322 (1988). Thus, any
framework at this time is not to be treated as a one-size-fits-all approach but is to
be used as a guide for the next iterations of distribution plans to be filed by those
directed to do so. [Nov. 21, 2018 U-20147 Order at p.36]
DTE Electric’s next Five-Year Plan is due by June 30, 2020 (Id). Thus, the present FiveYear Plan and the Company’s testimony and supporting exhibits fully and appropriately support
all planned distribution investments in this case. Changes in the format of future Five-Year Plans
will not reduce the age or improve the condition of the Company’s distribution assets rendering
planned investments unnecessary, as intervenors have suggested (4T 874-76, 883-86).
4. There is no need to revise rate case filing requirements.
In the context of approving historical expenditures, the PFD raised a concern about the
Staff and intervenors having to create a “crosswalk” between spending categories from the
Company’s previous rate case, and suggested that the Commission should consider revising rate
case filing requirements for utilities to explain how spending classifications in a previous case
translate into the current case (PFD, p 67, 93-94). The Company appreciates the PFD’s concern,

24

 and will endeavor to address these issues on a going-forward basis. Since the Company will do
this voluntarily, the PFD’s suggestion to revise rate case filing requirements appears to be moot.13
C.

The Company’s Demand Side Management (“DSM”) programs are
reasonable and prudent and should be approved.

DTE Electric supported capital expenditures for Demand Side Management (“DSM”)
programs consisting of Interruptible Air Conditioning (“IAC”), DTE Energy Insight,
Programmable Communicating Thermostats (“PCT”), and Other DSM Programs (3T 354; Exhibit
A-12, Schedule B-5.6). The Company proposes investment of $6.2 million (for January 2018
through April 2019) to complete the enrollment of the initial 10,000 customer level approved in
Case No. U-18014, and an additional $3.4 million for the projected test year for the enrollment of
an additional 7,000 customers by summer of 2020.
The Commission previously agreed with Staff’s proposal to limit DTE Electric to 10,000
PCTs in Case U-18014, noting that “[i]f DTE Electric demonstrates that its DR programs are
successful in the initial phases, additional DR expenditures will be recoverable in a subsequent
rate case” (January 31, 2017 Order in Case No. U-18014, p 25). In the Company’s last general rate
case, the Commission agreed with the PFD’s recommendation to disallow the Company’s request
for $6,133,000 to purchase 25,000 PCTs, stating that the “Commission agrees with the utility that
complete installation was not necessary to support increased funding, but a showing of initial
success was” (April 18, 2018 Order in Case No. U-18255, p 22).

13

An issue is moot when an event occurs that renders it impossible for the decision maker, if it should decide in favor
of the complainant, to grant any relief. Swinehart v Secretary of State, 27 Mich App 318, 320; 183 NW23d 397 (1970).
Courts generally dismiss cases presenting only abstract questions that do not rest on existing facts or rights. B P 7 v
Bureau of State Lottery, 231 Mich App 356, 359; 586 NW2d 117 (1998) (dismissing appeals because issue presented
became moot). See also, International Union v Michigan, 211 Mich App 20, 29; 535 NW2d 210 (1995) (dismissing
claims that had been rendered moot by subsequent developments); Plumbers and Pipefitters Local Union No 190 v
Wolff, 141 Mich App 815, 818; 369 NW2d 239 (1985) (declining to address moot issues).

25

 The Company proposes investment of $6.2 million (for January 2018 through April 2019)
to complete the enrollment of the initial 10,000 customer level approved in Case No. U-18014.
The Company further proposes an additional $3.4 million for the projected test year for the
enrollment of an additional 7,000 customers by summer of 2020. (Exhibit S-21).
Staff indicated general support for the Company’s DR efforts, but recommended a $9.6
million disallowance for the proposed PCT program ($6.2 million for the 16-month bridge period;
$3.4 million for the projected test year) based on the contention that the Company has not
demonstrated that the program has been successful enough in the early stages to merit the funding
of additional PCT units beyond the 10,000 units that the Commission approved in Case No.
U-18014 (Staff Initial Brief, pp 17-12). The PFD agreed (PFD, p 92).
DTE Electric believes there is confusion with respect to the funding level included in this
case associated with the already approved 10,000 PCT program, and funding levels associated
with incremental new investment in PCT’s. The $6.2 million request in this case is intended to
complete the enrollment of the initial 10,000 customer level already approved in Case U-18014
(Exhibit S-21). Additionally, as shown on Exhibit S-21, the $6.1 million in capital is associated in
large part with an investment in the Company’s Distributed Energy Resource Management
System, which is necessary to run the PCT program whether there are 10,000 or 100,000 customers
enrolled. To deny these costs would essentially deny the Company the ability to run the PCT
program. DTE Electric maintains that its requested funding is justified by the progress and success
in implementing the initial phases of the PCT program. The Company has purchased equipment
and engaged in marketing and outreach efforts to enroll customers. The PCT program successful
in the four events that the Company called during the summer of 2018, with a meaningful decline

26

 in electricity usage in the critical hours of the events (an average of 1.05 kW per participating
customer). (3T 385)
The Company had enrolled approximately 3,900 customers as of November 12, 2018,
which is in line with the revised forecast to enroll 4,500 customers by December 31, 2018 and the
Company’s continuing commitment to achieving 17,000 by the summer of 2020 (3T 386-87).
Enrollment is forecasted to be complete for the initial 10,000 customers by the summer of 2019.
The associated projected investment to fulfill the initial 10,000-customer enrollment goal includes
the historical expenditures as of December 31, 2017 ($2.1 million) plus the projected expenditures
during the bridge period ending April 30, 2019 of $6.2 million (See Exhibit S-21). Thus, current
enrollments support a finding of success in the program’s initial stages.
It is also important to keep in mind that the Company’s efforts to date have been
significantly focused on launching and developing the program. Lessons learned from initial
marketing efforts are being incorporated in new campaigns to increase enrollment and event
participation. Therefore, the PFD/Staff’s proposed $9.6 million disallowance should be rejected
and the PCT program should be fully funded as the Company requests (3T 386-87) to build on the
initial success of the program. In the alternative, the Commission should at least approve $6.2
million to complete the initial 10,000 customer enrollment which was approved in U-18014 as
discussed above.
The PFD also discusses performance goals, but DTE Electric is unclear in the intent of the
discussion. The PFD states:
With respect to the Staff’s recommended performance goals for DSM, this PFD
agrees that such goals should be established as part of DTE Electric’s overall
demand response plan, subject to refinement over time through the IRP process.
For the purposes of this case, the Staff’s recommended performance goals
(expected spending, MW reduction) should be adopted. [PFD, p 92.]

27

 DTE Electric maintains that any performance goals for DR programs should be established
and implemented as discussed by Ms. Dimity (3T 388-89) and disagrees to the extent that the PFD
suggests otherwise.
D.

The Company’s information technology capital expenditures are
necessary to support utility operations and customer service and should
be approved.

DTE Electric supported capital expenditures for the Information Technology (“IT”)
Organization (5T 1350; Exhibit A-12, Schedule B5.7). Staff proposed a $13,619,000 disallowance
($3.889 million in the bridge period and $9.730 million in the test year) for several IT programs
(Staff Initial Brief, pp 20-25). The PFD rejected the Staff’s proposed disallowance for the
ConnectUs Phase 4 project (PFD, p 93), but recommended adopting Staff’s additional proposals
(Id, pp 95, 97-98). DTE Electric maintains that its requested recovery should be fully approved
because it is required for prudent and necessary projects to support utility operations and customer
service (5T 1398).
Staff recommended that the Customer Digital Channels (MSA) Sustainment project be
completely disallowed because it is based on historical needs (Staff Initial Brief, p 22). Mr. Griffin
explained that this project is based on an existing backlog of kiosk, web, mobile, and IVR
enhancements that are prioritized on an ongoing basis throughout the bridge and test periods. This
list is constantly updated based upon the customer team’s analysis of items on the list and anything
that emerges either from customers or from interaction with Staff. This allows the Company to
react to changes in either the consumer experience or to the requests developed by the Commission
or other customer advocates (5T 1408-1409).14 Despite this record evidence, the PFD states:

14

Mr. Griffin further stated in Staff Exhibit S-12.2, page 9 in response to CSM 5.10a, that the scope includes the
following over the next 12-18 months, including a priority focus on improvements, examples of which include:
- Response time enhancements
- Kiosk payment improvements
28

 This PFD agrees with the Staff that its proposed disallowance, totaling $3,195,000
is reasonable. As the Staff contends, given the rapid advances in technology,
historical spending is not necessarily a true indicator of projected spending. In
addition, if the spending in this category represents a backlog, the company should
be able to provide more detail on what it expects to accomplish in the bridge and
test years. [PFD, p 95.]
Historical spending reflects the amount of money that will be spent, but it will not
necessarily be spent on the historical backlog “given the rapid advances in technology” that the
PFD/Staff acknowledge. Actual spending is prioritized and constantly updated, as discussed above
and further explained below.
Staff also proposed a full disallowance for the IT Business Planning and Development
project and partial disallowances for the 2018 Emergent and coDE Sustainment projects, reasoning
that the projects are uncertain (Staff Initial Brief, pp 24-25). The PFD stated that it “agrees with
the Staff that, in light of the uncertainty about the need for the projects, coupled with the unknown
cost of emergent items, the Staff’s recommended disallowances are reasonable and should be
adopted” (PFD, p 98). The Company disagrees. Mr. Griffin explained in part that the projects are
known, it is merely the final scope of the projects that are not yet finalized:
In Exhibit A-38, Schedule BB-1, pages 1 and 2, the Company indicated that the
ITS Annual Planning Cycle (APC) is the process by which the Company prioritizes,
approves and undertakes IT related Projects . . . [detailed discussion of process
omitted]. Each portfolio finalizes its investment list for the next year during the last
quarter of the current year and updates its roadmaps based on those committed
projects and enhancements. Because of this, it is inaccurate to assert that the
Company does not have known and planned work for this recovery. A better
representation would be that the investments that will be included are known and

- Outage trouble reporting
- Improve Move in Move out process on web
- IVR outage reporting enhancements
- Enhancements to Agency website for supporting low income customers
- Managing Customer Profile Information/Functionality (4T 1409).

29

 that it is only the actual final scope that is not solidified earlier in the planning
process. [5T 1402.]
Mr. Griffin explained that the IT Business Planning and Development Sustainment project,
like other customer portfolio projects of this type, has a backlog of requested upgrades and feature
enhancements that the Company prioritizes on an ongoing basis throughout both the bridge and
test periods. This list is constantly updated – sometimes due to interactions with Staff. It is
inaccurate to characterize this flexibility as uncertainty when updated prioritization instead
allocates resources to help ensure that customers’ needs are met in a timely manner (5T 1403).
History has also shown that certain types of investments arise every year and are necessary to keep
the Company running efficiently, so the amount of spend on these items can be forecast in the
aggregate (5T 1403-1404).15
In response to Staff’s apparent misunderstanding, Mr. Griffin explained the 2018 Emergent
project, which allows the Company to take advantage of technology advancements and trends
during the bridge and test periods. The Innovations Project Management Office (“iPMO”) has
been formed to govern the emergent initiatives, experiments and projects represented within this
project. The investments resulting from this project constitute prioritized work on a variety of
programs that are known, sequenced and approved for investment (5T 1404-1405). Mr. Griffin
also explained the following technology trends that are in the pipeline and included in 2018
Emergent: Robotic Process Automation; Drones; Industrial Internet of Things; Augmented
Reality; and Artificial Intelligence and Machine Learning. (5T 1405-1407; Exhibit A-38, Schedule
BB-2).

15

Typical Sustainment work regularly includes the addition of disk storage to account for growth, additional hardware
for memory and performance enhancement, and end-of-life replacements (5T 1404).
30

 The coDE Sustainment project presents another unique scenario, this time involving DTE’s
only in-house custom IT development staff, which operates from a prioritized backlog of requested
upgrades and feature enhancements reviewed on an ongoing basis (again, sometimes due to
interaction with Staff) throughout both the bridge and test periods. Like the previous categories,
these investments are not uncertain. Instead, the Company is working from a known backlog where
the only unknown is exactly which of the programs will be prioritized the highest based on ongoing
input from customers and the Commission or its Staff (5T 1407-1408).
Staff also grouped the Work Management Sustainment (Maximo/ESri/Service Suite), Fuel
Supply Sustainment, GenOps Business Sustain, IT FosGen Business Sustain, and Fermi – Nuclear
Gen Sustain projects together, and generically proposed a partial disallowance based on the
assertion that the Company-provided audit responses include a total expected cost that falls below
the amount originally indicated, so a disallowance should be made for the suggested surplus in
each project (Staff Initial Brief, pp 23-24). The PFD agreed stating:
This PFD finds, that as has occurred in past DTE Electric rate cases, the company
has included “placeholder” amounts for these items identified by Staff, with the
intention of finalizing its spending plan at some point in the future. If the only
information DTE Electric has available at the time it files its case is a draft plan,
to which it apparently adds a financial “cushion,” then it is reasonable for the Staff
or other parties to the proceeding to base their respective projections on the
company’s draft and responses to discovery. [PFD, p 97].
Mr Griffin’s testimony discusses a representative set of investments rather than detailed
breakdown for each project. For example, regarding the specific topic of Sustainment efforts in
Plant & Field, Mr Griffin discussed the “most significant” investments being made in the space
(5T 1370). Mr. Griffin also spoke to these same investment samples, explaining their significance
as “targeted at prudent system investments designed to ensure that our existing systems are
upgraded to comprehend both increased load and to handle expanded demand.” (5T 1373, 1374)

31

 However, these were not presented as the only investments included in the requested allowances
for the Plant and Field space.
Similarly during the audit and discovery phase, the Company provided Staff with year-todate spend in these investments, and answered discovery from the AG. Again, at no point in this
case did the Company suggest that these were the only investments in the Plant & Field space, nor
was any discovery received requesting an exhaustive list of all investments. Moreover, the
extensive long term planning included in the DTE Electric process was explained as an “in-depth
and ongoing analysis of continually evolving backlogs of work driven by customer experience,
enhancement requests, and maturing business needs,” producing backlogs which are, “substantial
and align to many years’ worth of investment,” and which, “results in a body of work that routinely
exceeds a single calendar year of effort, which is used as input into the APC cycle” (5T 1410).
The investments offered as examples and characterized as significant were the investments that
were queued at the top of the backlog list.
The PFD’s recommended disallowance appears to be predicated on the assertion that the
initial work discussed presented by the Company represents the totality of the activity in the
particular business cases. However, Mr. Griffin explained that “[i]t would not be practical for the
Company to produce, or the Staff to have to review, thousands of pages of documentation
regarding each enhancement that makes up the backlog especially since none of the portfolio’s
backlogs will be completely exhausted in a single rate case period.” (5T 1410-1411).
Mr. Griffin also explained Annual Planning Cycle process to prioritize known work into
achievable years as well as the rigor in adopting and establishing this methodology. Specifically,
Mr. Griffin testified that “the investments that will be included are known and that it is only the
actual final scope that is not solidified earlier in the planning process. Because of this early

32

 submission of the portfolio’s business cases can leave one with the impression that this is simply
contingency when in fact it is not.” (5T 1402). The Company received no further indication from
the parties that this explanation was insufficient.
The costs identified by Mr. Griffin are known, and as stated above and in Mr. Griffin’s
testimony, the only unknown is how the projects will be prioritized. It bears emphasis that as
indicated above, DTE Electric’s process for any Sustainment case is an in-depth and ongoing
analysis of continually-evolving backlogs of work driven by customer experience, enhancement
requests, and maturing business needs. 16 These backlogs are substantial and align to many years’
worth of investment. The Company applies the methodology of the APC cycle specifically to
prioritize and form an annual scope of work corresponding to the technology investment plans and
roadmaps maintained for a multi-year period. This results in a body of work that routinely exceeds
a single calendar year of effort, which is used as input into the APC cycle. It would also not be
practical for the Company to produce, and for Staff to review, thousands of pages of documentation
regarding each enhancement that makes up the Sustainment backlog, especially since none of the

16

Mr. Griffin explained that Staff did not consider the information provided by the Company in Exhibit A-38,
Schedule BB-1 pages 1 and 2, which are responses to audit requests CSM-1.2 and CSM-5.1 (5T 1410-11).
In CSM-1.2, Mr. Griffin explained the ongoing annual planning cycle with the following statements: In
general, business cases for 2019 and 2020 are in progress in accordance with the Company’s Annual Planning Cycle
(APC). Based on where in that process the Company is, most 2019 and 2020 business cases have not been finalized
and will continue to be worked through the scheduled completion of the APC. The APC is undertaken each year to
align the capital projects with the planning roadmaps and to ensure that projects are prioritized and sequenced
correctly. As part of the Part III Filing Requirement, the Company did provide draft business cases for anything that
was in the top 25 project list as requested.
CSM 5.1 later raised the question: “When will the 2019 and 2020 business cases be finalized? When is the
scheduled completion of the APC?” Mr. Griffin responded explaining that 2019 Business Cases will be finalized midfourth quarter. Initial planning for 2020 Business Cases has begun and the cycle for 2020 will finalize in the fourth
quarter of 2019. (5T 1410).

33

 portfolio’s backlogs will be completely exhausted in a single rate case period. Therefore, the
PFD/Staff’s proposed disallowance should be rejected (5T 1411-12).
E.

The PFD’s proposed IT reporting requirements should be refined.

Staff also made recommendations regarding documentation that should be provided in
future rate cases (8T 4151-53). Mr. Griffin agreed in part, noting that Staff recommended several
viable points that, in the interest of clarity, the Company would be willing to consider with some
modifications regarding timing, volume, complexity/effort to comply, and spend thresholds (5T
1412). Mr. Griffin discussed each of Staff’s suggestions in detail, along with counter-suggestion
to address the Company’s concerns (5T 1413-17). Staff largely agreed with the Company, stating
that “the ALJ and Commission should adopt Staffs [sic] recommended filing suggestions with
DTE’s modification for all but Staff’s final recommendation,” which is “that the Company
breakdown any IT programs that were approved in its previous rate case that were not completed
or were 20% above or below the approved project amount and include an explanation of why the
project was not completed or why it was off budget” (Staff Initial Brief, p 26). The PFD agreed
(PFD, p 101).
The Company disagrees on the significantly-narrowed, but important issue that remains.
Mr. Griffin explained that unless the Staff’s final recommendation is tempered by a threshold of
projects above $500,000 and limited to those projects for which the Company is seeking additional
funding, the administrative burden of the request would be excessive and unworkable (5T 1417.)
The Company is also concerned that the PFD/Staff’s suggestion to adopt a filing
requirement for past expenditures in a case not seeking additional recovery would invite an
improper exercise in hindsight (5T 1417). As Mr. Stanczak testified, the projected test year is a
projection of the expenditures that are likely to be made given the information known at the time of

34

 the rate case filing. There is no legal basis to use hindsight to reconcile the difference between
projected expenditures from a prior rate case against actual expenditures incurred in a historical
period.17 In a rate case proceeding, the Commission authorizes the Company’s rates based on a
revenue requirement including a reasonable rate of return, but it does not set fixed spending levels
(3T 97; 4T 825). There is no provision in any applicable statute that calls for a reconciliation of
established rates and the Commission lacks authority to order such a procedure. Consumers Power
Co v Public Service Comm, 460 Mich 148; 596 NW2d 126 (1999); Union Carbide v Public Service
Comm, 431 Mich 135, 148-49; 428 NW2d 322 (1988), see generally MCL 460.6a. This is why the
Company proposes to limit the requirement to those projects for which the Company is seeking
additional funding. Only in such a case is the progress and costs on a project relevant to
determining the revenue requirement.
F.

The PFD’s proposed disallowance for Corporate Staff Group capital
expenditures should be rejected.

The PFD recommends that the Attorney General’s proposed reduction of $17,052,000 to
capital expense for the corporate staff group (“CSG”) should be adopted on the basis that the
Company did not provide rebuttal testimony to Witness Coppola’s recommendation. As cited in
the PFD, Mr. Coppola testified:
The $17.1 million is a significant variance from the forecasted level and this underspending trend is likely to continue into the remaining months of 2018. However,
giving the Company the benefit of the doubt that capital expenditures in the
remaining four months will meet the forecasted level, it is reasonable to conclude
that the cumulative under-spent amount of for the 8 months ended August 2018 is
17

The Commission has no common law powers, but only possesses the limited authority that the Legislature conferred
upon it. Consumers Power Co v Public Service Comm, 460 Mich 148, 155; 596 NW2d 126 (1999). The Commission
is an “administrative body created by statute and the warrant for the exercise of all its power and authority must be
found in statutory enactments.” Union Carbide v Public Service Comm, 431 Mich 135, 146; 428 NW2d 322 (1988);
Sparta Foundry Co v Public Utilities Comm, 275 Mich 562, 564; 267 NW 736 (1936). The Commission’s authority
must be conferred by clear and unmistakable statutory language, and a doubtful power does not exist. Mason Co Civil
Research Council v Mason Co, 343 Mich 313, 326-27; 72 NW2d 292 (1955).

35

 likely to remain. Therefore, I recommend that this amount be removed from the
projected capital expenditures and from rate base.
The PFD agreed on the sole basis that the Company did not appear to rebut Mr. Coppola’s
recommendation. The Company disagrees that this is a valid basis for accepting Mr. Coppola’s
recommendation. Mr. Coppola’s testimony is simply an unsupported opinion. Ms. Uzenski, on
the other hand, provided pages of testimony and exhibits to support the capital spending for the
CSG group, identifying particular projects and the cost of those projects (7T 3314 – 3321, Exhibit
A-12, Schedule B5.8). The weight of the evidence supports a finding that DTE Electric’s spending
in this area is reasonable and prudent. Mr. Coppola’s speculation that the Company will not likely
spend what it forecasts, does not outweigh, nor is it more persuasive than, the substantial evidence
provided by the Company. As such, the PFD’s recommended disallowance should be rejected.
IV.

RATE OF RETURN
A.

DTE Electric should have a weighted after-tax rate of return of 5.72%.

The PFD recommends a weighted, after-tax overall rate of return of 5.48% (PFD, p 130,
301). DTE Electric supports the PFD’s cost factors of 4.36% for long-term and 3.56% for shortterm debt (PFD, p 123 and Appendix D), 18 but takes exception regarding the PFD’s recommended
capital structure (PFD, pp 114-16), and return on equity (“ROE”) (PFD, pp 128, 301).

18

PFD, p 123 indicates an uncontested short-term debt rate of 2.77%, which apparently is just a typo, since Appendix
D reflects 3.56%. DTE Electric’s Initial Brief, p 50, summarized the Company’s recommendation for a 3.56% cost of
short-term debt, which includes the interest rate on short-term borrowings and facility fees associated with the credit
arrangements necessary for the issuance of short-term debt. Staff (Initial Brief, p 50) and the AG (Initial Brief, p 92)
agreed. Therefore, the ALJ apparently meant to recommend, and the Commission should adopt, a short-term debt rate
of 3.56%.
36

 1. The Company’s proposed capital structure would allow it to maintain
adequate access to capital at the lowest reasonable cost and should be
approved.
DTE Electric needs to increase its permanent capital structure to approximately 49% debt
and 51% equity, which is stronger than the 50/50 capital structure that the Commission approved
in the Company’s last general rate case (April 18, 2018 Order in Case No. U-18255, p 25) (5T
1037-38, 1057; Exhibit A-14, Schedule D1). Staff agreed (Staff Initial Brief, p 49). The PFD
disagreed, stating: “The PFD agrees with the Attorney General and ABATE that DTE Electric
failed to provide sufficient evidence that its capital structure should be adjusted at this time to
compensate for the purported impacts of the TCJA and the company’s capital spending program”
(PFD, p 114).
The record demonstrates that it is important to strengthen the Company’s capital structure
to 51% equity to enhance the Company’s credit quality and financial soundness. 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). If DTE Electric 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 electric service for its customers (5T 103847, 1057).
The Commission previously maintained DTE Electric’s 50/50 structure, reasoning that
“conditions have not changed to such a degree as to warrant a departure from a balanced equity
ratio at this time” (April 18, 2018 Order in Case No. U-18255, p 25). Mr. Solomon testified that it
is now reasonable and prudent to increase the equity ratio to 51%, explaining in part:
The capital structure recommendation increases the financial soundness and
creditworthiness of the Company at a time when it is facing the material, negative
impacts of the Tax Cuts and Jobs Act of 2017 (“TCJA” or “tax reform”). The
requested equity ratio of 51% is below the peer average, and even lower than peers
when considering the significant adjustments the ratings agencies make to the
37

 Company’s debt calculations. The increased equity level is especially important
given the significant capital investments the Company is making over the next 5
years to maintain and improve the electric infrastructure to benefit our customers.
[5T 1041. See also 5T 1042-47.]
More specifically, the TCJA has significant negative impacts on a utility’s cash flow and,
in turn, its credit metrics. Essentially, the lower tax rate and the loss of bonus depreciation causes
utilities to lose some of their cash flow contribution from deferred taxes. This decreases the Funds
From Operations (“FFO”) to debt ratio, which is a key metric that credit rating agencies use to
measure credit quality. Regulators in other states have acknowledged the negative impacts of tax
reform on utilities and are allowing relief including increased equity ratios (5T 1041-45, 1063).
The TCJA also results in a re-measurement of deferred taxes due to the reduction in the tax rate,
so the Company proposes to credit these excess accumulated deferred income tax (“ADIT”)
balances back to customers beginning with this case (see generally, section VII. F of DTE
Electric’s Initial Brief regarding Income Tax Expense).
DTE Electric will be financing and funding $4.0 billion of electric capital expenditures for
the period of January 2018 through April 2020 (Exhibit A-12, Schedule B5). 19 A capital structure
with 51% equity will enhance DTE Electric’s credit quality and financial soundness, which will in
turn ensure the reasonableness and competitiveness of the Company’s capital costs during this
period of significant system investment (5T 1047).
AG witness Mr. Coppola suggested that Mr. Solomon was misleading in attributing
Moody’s placement of DTE Gas on negative outlook primarily due to tax reform because Moody’s
actions were also due to DTE Gas’s near-record-high level of capital expenditures (5T 1659). Mr.

19

Moreover, as discussed in part above, DTE Electric has capital needs to address its aging infrastructure to ensure
reliability and safety (See also DTE Electric Reply Brief, sections V. A. and C).

38

 Solomon disagreed and noted that DTE Electric and DTE Gas both have near-record-high levels
of capital expenditures:
Moody’s would not have placed DTE Gas on negative outlook if tax reform had
not occurred. The tax reform change prompted Moody’s to downgrade its outlook
on the entire utility industry and in May 2018, downgrade the outlook on DTE Gas.
Moody’s did reference that DTE Gas’s capital expenditures are near record highs.
Similarly, DTE Electric’s capital expenditures are near record highs. The Company
is making significant capital investments over the next five years to maintain and
improve our infrastructure that directly benefit our customers. These capital
expenditures are necessary to provide service to our customers. A common equity
ratio of 51% is reasonable given the negative impact of tax reform on credit metrics
especially during a time of increased capital expenditures. [5T 1063.]
DTE Electric’s proposed 51% equity ratio is lower than the 52.8% average for the
Company’s peer group (Exhibit A-14, Schedule D1.1). After rating agency adjustments to debt,
the average equity ratio for the peer group is 47.8%, compared to 44.6% for DTE Electric (Exhibit
A-14, Schedule D1.2). Thus, on an adjusted basis, the Company’s equity ratio is 3.2% lower than
its peers (5T 1046-47). In other recent peer utility rate cases, the MPSC has authorized a 52% or
higher equity ratio for all utilities except DTE Electric. DTE Electric’s proposed 51% is the lowest
requested ratio among those cases (5T 1045-46).
The AG opposed DTE Electric’s proposed capital structure for three reasons (AG Initial
Brief, p 85-86). The first is Mr. Coppola’s assertion that “the common equity ratio of the peer
group used to assess the cost of common equity in this case, averages 47.6%” (AG Initial Brief, p
85). Mr. Solomon explained that Mr. Coppola’s referenced peer group was not a valid comparison
as it used holding company data. DTE Electric is not a holding company and should be compared
to other electric utilities, not holding companies. The average common equity as of June 30, 2018,
for the electric company subsidiaries of the holding companies that Mr. Coppola selected as his

39

 peer group was 51.6%, which is comparable to DTE Electric’s 51% request in this case (5T 1061;
Exhibit A-35, Schedule Y-1).20
The AG’s second reason for opposing DTE Electric’s capital structure is Mr. Coppola’s
suggestion that it that it would be reasonable for DTE Electric to have the same capital structure
as Consumers Energy (“Consumers”) and that the Commission directed Consumers to move
toward a 50/50 capital structure in Case No. U-17990 (AG Initial Brief, p 86). Mr. Solomon agreed
that DTE Electric and Consumers are similar, and it is reasonable for them to have similar capital
structures; however, Mr. Coppola neglected that the Commission authorized a capital structure
with 52.87% equity in Case No. U-17990, and recently authorized a capital structure with 52.64%
equity in Consumers’ subsequent rate case (March 29, 2018 Order in Case No. U-18322, p 35). In
then-pending Case No. U-20134, Consumers requested a capital structure with 52.5% common
equity, and also noted that the path to 50% equity is no longer reasonable due to the TCJA. Thus,
DTE Electric’s request for a 51% equity ratio is reasonable and comparable to its peers (5T
1062).21
The AG’s third reason is the unsupported assertion that “DTE Energy can make the
Company’s common equity ratio of its subsidiaries whatever it wants” (AG Initial Brief, p 86).
The AG neglected that the Commission must base its decision on the record, which reflects that
DTE Electric also had a 51% equity ratio on December 31, 2017 and is committed to maintaining

Mr. Coppola also took DTE Energy’s common equity percentage strictly from 10Q data, which is inaccurate because
it fails to consider that DTE Energy’s junior subordinated debt and mandatory convertible debt effectively increase
the equity in its capital structure (5T 1061-62).
20

21

The AG then suggested that the Commission should not consider Case No. U-20134 (AG Initial Brief, pp 89-90).
To the contrary, the Commission is certainly entitled to take notice of its own January 9, 2019 Order Approving
Settlement Agreement in Case No. U-20134, and that the AG did not object to that settlement agreement, which
apparently did not alter Consumers’ capital structure.

40

 a 51% equity ratio. DTE Energy has made substantial equity infusions in the past, and plans equity
infusions of $372.2 million in 2018, $200 million in 2019, and $200 million in early 2020, which
will result in a 51% equity ratio for the projected test period (5T 1047-48).
The PFD was unpersuaded by DTE Electric’s evidence regarding impacts on its credit
ratings, but instead opined: “While DTE Electric cites a number of factors that might have some
effect on the company’s credit ratings, the ALJ notes that as of the close of the record in this case,
the TCJA has been in effect for almost a year, with no discernable impact on the Company or its
strong credit ratings’ (PFD, p 115. Emphasis in original). The record plainly demonstrates that
there is recent, negative pressure on DTE Electric’s financial metrics, and therefore its credit
rating, at the same time that DTE Electric is financing and funding substantial capital expenditures.
DTE Electric does not agree that the ALJ should see a discernable negative impact on the Company
or its credit ratings before supporting a stronger balance sheet. DTE Electric has maintained its
capital structure at 51% equity during the time the negative impacts of the TCJA have occurred
and this increased equity level helps protect against negative credit impacts. The proper time to
take corrective action is before a predictable problem occurs, not after it is too late.
The PFD also cited ABATE’s argument that the Company’s plans to increase its dividend
by 2020 is not meant to financial stabilize the Company, but to provide a payout ratio of 136.4%.22
However, the 136.4% payout ratio calculated by ABATE only occurs in the event there is no rate
relief. In ABATE Witness Walters’ Table 5 (7 T 2971), the 136.4% he presents is calculated using
a net income of $401 million, a decrease from 2018 of $241 million. The $401 million net income
is also based on a calendar year rather than the projected test year and assumes no rate relief. These

22

The dividend payment amount reflected on page 114 of the PFD is $886.7 million; however, the correct amount is
$86.7 million.
41

 assumptions, severely impact the resulting dividend payout ratio. The 75% payout ratio with rate
relief shown on Mr. Solomon’s Exhibit A-11 Schedule A2, line 50 is accurate, reasonable and
consistent with historic payouts as Mr. Gorman recognizes in his Table 5 (73% for 2018).
In support of its recommendation, the PFD also cites Mr. Coppola’s testimony that a
possible 24 basis point increase in interest rates would be insignificant compared to the increase
in equity ratio requested. The Company typically issues debt with a 30-year term, therefore, the
24-basis point increase would impact customers over 30 years. It would also impact all subsequent
debt issuances of the Company and in a period of significant capital expenditures the need for
long-term financing will also be significant.
Also of note, while the PFD rejected ABATE’s proposed “regulatory plan” involving the
faster amortization of unprotected excess ADIT balances, the ALJ also recommended that this
option be studied further in the Company’s next rate case. DTE Electric disagrees that there is any
need to study this proposal further given the negative impact to Company’s cash flows as explained
by Mr. Solomon (See 6 T 1064-1065). Furthermore, ABATE’s regulatory plan proposal was based
on an assumption that the Company’s new depreciation rates would be higher due to the retirement
of its Tier 2 plants. In the approved settlement agreement in Case No. U-18150, the Company was
directed to maintain the existing depreciation rates from the U-16117 Order for its Tier 2 plants.
As a result there is no increased depreciation expense, thus making the proposed analysis
unnecessary.
In summary, DTE Electric needs a strong equity component of its capital structure to
maintain adequate access to capital at the lowest reasonable cost during a period of significant
capital investment. DTE Electric is also facing the material, negative impacts of the TCJA, which
could lead to a credit rating downgrade that would reduce access to capital and could negatively

42

 impact credit spreads, increasing the cost of debt and adding to customer costs (5T 1048). DTE
Electric also continues to balance capital investment plans, credit metrics and customer rate
impacts, while it continues to face significant ongoing and emerging business challenges, as further
discussed below (see also section VI. C. 3 of DTE Electric’s Initial Brief). Accordingly, the
Commission should strengthen DTE Electric’s equity ratio from 50% to 51%.
2. The Company’s proposed return on common equity is reasonable and
necessary given the economic and financial environments.
The PFD recommended maintaining the 10.0% return on equity (“ROE”) for DTE
Electric’s common equity capital (PFD, pp 128, 301). The Commission should instead adopt Dr.
Vilbert’s recommendation that a just and reasonable ROE for DTE Electric’s common equity
capital is 10.5%. This is at the upper end of Dr. Vilbert’s range of 9.75% to 10.75% because DTE
Electric has greater-than-average risk (6T 1919, 1975-76, 2016). The uncertainty in the capital
markets, the more challenging Michigan economic environment, the differences in financial risk
for DTE Electric as compared to sample companies,23 and the large-scale disruptive changes in the
utility industry justifies an increase in the recommended ROE for DTE Electric relative to the
sample companies (6T 1918-20, 1923-37, 1975-77, 2069-70).
Staff recommended 9.80% (Staff Initial Brief, p 51). The AG recommended 9.5% (AG
Initial Brief, p 92). ABATE recommended 9.3% (ABATE Initial Brief, p 26). 24 The PFD rejected

23

Dr. Vilbert selected a sample of 25 regulated electric utility companies in the same line of business as DTE Electric
(6T 1916, 1937). Also, based on Case No. U-18014, Dr. Vilbert presented a subsample of 6 electric utilities that
excluded DTE Energy, and had net plant greater than $6 billion but less than $20 billion (6T 1938-40).

Wal-Mart and RCG disagreed with DTE Electric’s proposal, but did not offer any alternative (Wal-Mart Initial
Brief, p 3; RCG Initial Brief, pp 8-10). MEC/NRDC/SC (Initial Brief, pp 97-104) suggested that the Commission
should depart from well-established ROE requirements, which invited an unlawful result for purposes of this case.
See, for example, the April 18, 2018 Order in Case No. U-18255, p 26, noting the “landmark United States Supreme
Court cases” concerning the “criteria for establishing a fair return for public utilities.”
24

43

 these proposals to reduce DTE Electric’s ROE; however, the PFD found that the usual discussion
of the parties’ underlying analyses was unwarranted (PFD, p 125), and further stated:
Instead, as the Commission has noted, “it is not realistic to make a significant
change in ROE absent a radical change in underlying economic conditions”
[quoting March 29, 2018 Order in Case No. U-18322, p 44]. Thus, this PFD finds
the determination to be made is whether “underlying economic conditions” have
changed significantly since April 18, 2018, to justify DTE Electric’s
recommended 10.5% ROE or, conversely, to justify the 20, 25 or 65 basis point
reduction in ROE recommended by Staff, the Attorney General, and ABATE,
respectively.
* * *
Absent sufficient evidence to demonstrate that underlying economic conditions
have changed significantly in the past year, this PFD finds that DTE Electric’s
ROE should remain at 10.0% as was set in the Company’s last rate case. [PFD, pp
125-26, 128.]
DTE Electric notes generally that the Staff, AG, and ABATE’s recommendations
underestimate the effect that interest rates have had, and will continue to have, on the cost of capital
for the Company. They also failed to adequately capture the risk in the electric utility industry (6T
2012-13, 2017-21, 2024-26). The recommendations are also understated due to analytical errors
and the misperception that DTE Electric has average risk relative to sample companies. To the
contrary, the uncertainty in the capital markets, the more challenging Michigan economic
environment, and the differences in financial risk for DTE Electric as compared to sample
companies justifies an increase in the recommended ROE for DTE Electric relative to the sample
companies (6T 2013-16).
The PFD similarly did not appreciate the effects of changing economic conditions and
increasing risk. Dr. Vilbert explained that economic conditions have improved since the financial
crisis, but investor risk aversion remains elevated relative to pre-crisis periods. There is, therefore,

44

 an increased cost of capital for all risky investments, including regulated utilities (6T 1918-20,
1923-37).
In DTE Electric’s last general rate case, the Commission set DTE Electric’s ROE at 10.0%,
quoting Dr. Vilbert and stating that it “agrees with DTE Electric that factors such as volatility and
uncertainty are currently particularly significant, and movements are more extreme in comparison
to more stable historical periods” (April 18, 2018 Order in Case No. U-18255, p 32). The
Commission recognized similar factors in recently setting a 10.0% ROE for Consumers Energy
(March 29, 2018 Order in Case No. U-18322, p 43). In September of 2018, the Commission set
DTE Gas’s ROE at 10.0%, despite the ALJ/Staff’s recommended lowering DTE Gas’s ROE from
10.1% to 9.6%. The Commission noted some improved conditions in the approximate two years
since DTE Gas’s prior rate case, but stated that it “agree[d] with DTE Gas that there [was]
increased volatility in the capital markets that may affect the cost of capital” (September 13, 2018
Order in Case No. U-18999, p 54).
i.

Recent and continuing changes in economic conditions,
increasing business risk, and the TCJA’s negative effects on
credit metrics justify increasing DTE Electric’s ROE.

The PFD opined that except for the possible effects of the Tax Cuts and Jobs Act of 2017
(“TCJA”), all of the factors that DTE Electric highlighted in this case were present 11 months ago
and recognized by the Commission in Case No. U-18255 (PFD, p 126). Dr. Vilbert testified to the
contrary --volatility and uncertainty have increased since the Company’s last rate case (6T 1918,
1925, 1930, 1933). Dr. Vilbert explained in part:
There remain serious concerns of a very slow growth recovery and many factors
indicate that these concerns have increased since the U-18255 proceeding. The
Commission should consider the rapidly increasing U.S. Treasury bond yields and
the ongoing volatility and uncertainty, as it did in the U-18255 order. All of these
factors support an increase to the ROE for the Company relative to its previously
allowed ROE in U-18255 (6T 1933).
45

 In his rebuttal testimony filed on November 28, 2018, Dr. Vilbert further testified that
significant uncertainty in the global markets remains, and in some ways has increased, with
continuing effects on U.S. capital markets (6T 2017). He noted that his direct testimony was based
on market data as of the first quarter 2018. The Fed had increased the federal funds target interest
rate twice since then, which increased yields on long-term government securities. This indicates
an increase in the cost of capital since the Commission issued its April 18, 2018 Order in Case No.
U-18255. This trend is expected to continue. 25 Long-term utility bond yields have also significantly
increased since early 2018, further indicating that the cost of capital for the utility industry is
increasing (6T 2017-19).
The PFD does not appear to have considered the effects of rising interest rates, but it is
undisputed that recently-set long-term and short-term interest rates of 4.42% and 1.85% (April 18,
2018 Order in Case No. U-18255, p 26) should be changed to 4.36% and 3.56% (PFD, p 123 and
Appendix D). Although utility ROEs have decreased in recent years during a period of declining
and low interest rates (and factoring in the unique risk and other circumstances of other utilities in
other states), interest rates are rising and are expected to keep rising, and DTE Electric’s ROE is
being set on a forward-looking basis (6T 1924, 1977, 2018).26

25

On December 19, 2018, the Fed increased the federal funds target interest rate again, and made further suggestions
about the outlook for 2019, triggering a steep sell-off in stocks.

26

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. ABATE v Public Service Comm, 208 Mich App 248, 257-258; 527 NW2d 533 (1994). This is
part of the “regulatory compact” under which the utility dedicates its private property to serve the public and
correspondingly receives a reasonable return on the value of its private property. In Board of Public Utility Comm’rs
v New York Telephone Co, 271 US 23; 46 S Ct 363; 70 L Ed 808 (1926), the United States Supreme Court explained
that the just compensation safeguarded to the utility by the Fourteenth Amendment is a reasonable return on the value
of the property used at the time that the property is being used for the public service. Rates that are not sufficient to
yield that present return are confiscatory. 271 US at 31.
46

 Significant business risks facing electric utilities have also increased, due for example to
the transition away from coal-fired generation (6T 2020-21). ABATE witness Mr. Walters
similarly acknowledged: “Transformational risks abound in the Canadian and U.S. utility sector,
especially in electric utilities” (7T 2962, quoting Standard & Poors Global Ratings: “Industry Top
Trends 2018: North America Regulated Utilities,” January 25, 2018, p 1).
Moreover, the TCJA contains provisions reducing the corporate tax rate and revising the
federal tax structure. Credit rating agencies have expressed concern about the financial health of
regulated utilities due to the negative impact of tax reform on the companies’ cash flow and credit
metrics (6T 1934-37, 2021-23). 27 Dr. Vilbert explained in part:
These effects suggest that the allowed ROE and/or the amount of equity in the
capital structure should be increased to offset the negative effects of the income tax
law. It is vital to maintain the financial health of the utility and the ability of that
utility to raise capital on favorable terms, especially during periods of significant
capital expenditures. Declining credit metrics and ratings indicate increased risk for
the company, suggesting that a higher ROE would be appropriate to compensate
for this risk to equity holders and/or a higher equity share in the capital structure
should be allowed in order to improve the financial profile of the company [6T
1937.]
Although, as Staff pointed out, Moody’s revised the outlook of 24 regulated utility
companies to negative and did not include DTE Electric, credit rating agencies have all expressed
concern about the TCJA’s negative impact on the cash flow and credit metrics of regulated utilities,
as indicated above. Dr. Vilbert explained in his rebuttal that since his direct testimony, credit rating
agencies have reaffirmed their negative outlook on regulated utilities as “the negative cash flow

As discussed in section VI. A of DTE Electric’s Initial Brief and above, the lower tax rate and the loss of bonus
depreciation causes utilities to lose some of their cash flow contribution from deferred taxes. This decreases the Funds
From Operations (“FFO”) to debt ratio, which is a key metric that credit rating agencies use to measure credit quality
(5T 1041-43).
27

47

 ramifications of the 2017 Tax Cuts & Jobs Act (TCJA) are beginning to surface in financial
statements and will become more evident in the results of the second half of 2018” (6T 2024-25,
quoting Moody’s Investors Service, “2019 outlook negative amid growing debt and stagnant cash
flows,” November 8, 2018).
The TCJA has negatively affected the Company’s credit metrics (including the FFO/Debt
and Debt/EBITDA ratios), which were already pressured by the large capital spending plan (6T
2025). Moody’s has further noted that the Company’s credit metrics “will weaken going forward
on account of tax reform and higher capex” and that these capital expenditures carry some lag in
operating cash flow and consequently further depress an already weakened CFO profile” (Moody’s
Investors Service, “DTE Electric Company: Update to credit analysis,” May 9, 2018). Due to these
concerns, Moody’s has given the Company a stable credit rating outlook “assuming supportive
regulatory treatment” (Id, quoted at 6T 2025-26. See also 6T 2014).
Since the stable rating depends on supportive regulatory treatment, arguments inviting the
Commission to rely on DTE Electric’s tenuously stable credit rating (which assumes a continuing
“supportive regulatory treatment”) as a basis to withhold the necessary regulatory support are
circuitous and would undermine the Company’s credit rating. This is also a particularly
inopportune time to weaken or neglect the Company’s credit metrics due to the TCJA and the
Company’s need for capital spending, as discussed above.
Past concerns also continue to exist, as the PFD appears to have recognized. For example,
in the current environment of low electric demand growth, DTE Electric’s lack of a revenue
decoupling mechanism or a fixed variable pricing policy places it at increased risk of underrecovering its cost of service relative to some companies in Dr. Vilbert’s sample that benefit from
such mechanisms (6T 1942-43). Moreover, in addition to ongoing uncertainty in the capital

48

 markets discussed above, DTE Electric faces increased risk of under-recovery due to Michigan’s
economy, which is heavily dependent on the auto industry. DTE Electric’s service territory is
primarily in Southeastern Michigan including Detroit, which has a weak economy and declining
and shifting population. DTE Electric also requires significant capital expenditures to comply with
environmental requirements and has an asymmetrical risk (downside risk with no corresponding
upside) due to the responsibilities of owning and safely operating a nuclear power plant.
Therefore, DTE Electric has a higher-than-average business risk relative to companies in Dr.
Vilbert’s sample (6T 1945-48).
ii.

Any reduction of equity in DTE Electric’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, and therefore increases the Company’s cost of
equity. A lower equity ratio component (and a correspondingly higher debt component) in the
capital structure creates a higher level of risk for shareholders and a corresponding need for a
higher rate of return on equity. Dr. Vilbert’s recommended ROE corresponds to a 51% equity
ratio. Staff agreed, and the PFD’s 50% recommendation should be rejected as discussed above. If
DTE Electric has less equity as the PFD recommends, however (and a corresponding increase in
both debt leverage as well as financial risk), then DTE Electric’s ROE must increase to compensate
for the increased risk (6T 1948, 1997-2008).
iii.

Summary and Recommendations Regarding DTE Electric’s
Cost of Equity.

As discussed above (and further explained with detailed ROE analyses in DTE Electric’s
Initial Brief and Reply Brief, which the PFD did not address) a company of average business risk
having a capital structure with 51% equity should have an ROE in the range of 9.75% to 10.75%.

49

 DTE Electric has higher risk than the average sample company, so the corresponding ROE
estimate for DTE Electric is 10.5% (6T 1975-76, 2016).
This is also important to maintain DTE Electric’s access to capital. Maintaining a solid
credit rating and outlook is one important aspect to maintaining access to capital. A supportive
allowed return on equity is important to ensure the utility’s favorable access to credit markets.
Maintaining a strong credit rating is particularly critical during a period forecast to have substantial
capital investment for infrastructure. In addition, it is expected that the cost of capital will increase
as the Federal Reserve continues to adjust its monetary policy, so estimates at the upper end of the
ROE range are more representative of the cost of capital expected going forward (6T 1976-77).
The PFD rejected the understated recommendations by Staff, the AG, and ABATE;
however, the PFD neglected to fully appreciate the effects of recent and continuing changes in
economic conditions and other factors that justify increasing DTE Electric’s ROE to 10.5%.
V.

DTE ELECTRIC’S ADJUSTED NET OPERATING INCOME AND
REVENUE DEFICIENCY SHOULD BE ADOPTED.
DTE Electric projected its Total Electric adjusted Net Operating Income (“NOI”)

to be $801.7 million. The PFD recommends $847.4 million (PFD, Appendix C). DTE Electric
takes exception to this and other matters as discussed below.
A.

The Company’s operating and maintenance (“O&M”) expenses are
reasonable and prudent and should be approved.

DTE Electric supports total O&M of $1,309.8 million (See Attachment A).
1. DTE Electric’s Inflation on O&M Expense is reasonable and prudent
and fully supported.
DTE Electric supports inflation rates of 3.0% for 2018, 2.9% for 2019, and 1.0% for
January 1, 2018 through April 30, 2020 (Exhibit A-13, Schedule C5.15, line 15). These are
composite rates using a 3.0% inflation rate for labor, and the consumer price index (“CPI”)-Urban
50

 for non-labor costs (7T 3302-3303). Staff “used inflation factors of 2.52%, 2.23% and 2.50% for
2018, 2019, and 2020, respectively,” resulting in a $12,338,000 downward adjustment to O&M (Staff
Initial Brief, p 65). The PFD adopted the Staff’s proposed inflation rates by reasoning that the
Commission previously rejected the use of a composite inflation rate (PFD, p 135). It is true that
the Commission previously declined to adopt the Company’s proposed composite inflation rate;
however, the record in this case now compels adoption of DTE Electric’s proposed composite
labor/non-labor inflation rate by reflecting that the Company’s labor costs are driven by collective
bargaining agreements with unionized employees, as Mr. Cooper testified:
Based on existing Collective Bargaining Agreements, the Company is obligated to
increase base pay rates by approximately 3.0% annually through the term of the
contracts. In addition to scheduled pay rate increases, the agreements also provide
for progression increases for those employees that have not yet achieved the
maximum pay rate for their positions [6T 1832.]
The 3.0% annual labor cost escalator reflects that existing collective bargaining agreements
provide for annual increases of about 3.0% through the terms of the contracts and, also provide for
progression increases for employees that have not yet achieved the maximum pay rate for their
position. For employees not covered by collective bargaining agreements, it is expected that the
annual overall pay increase program will be 3.0% for 2019 and 2020, just as it was in 2018 and
every year since 2010. The specific increases are reflected on Exhibit A-32, Schedule V3, which
reflects a summary of increases that was included in Part III, Part 5c, Attachment 6, Item 3 of the
Company’s initial submission (6T 1885-86).
There is no evidence that DTE Electric can avoid paying wage increases as set forth above,
and any proposal that DTE Electric should do so anyway is not possible. DTE Electric cannot

51

 violate its Collective Bargaining Agreements, and the Commission has no authority to become
involved in or dictate results of collective bargaining. 28
The PFD further suggested that “the company did not rebut that Staff’s position, which
recognizes that some inflation is likely to occur, but that productivity increases will offset higher
labor inflation rates” (PFD, p 135). To the contrary, Mr. Stanczak explained that although the
Company’s ability to manage O&M in the past has been exceptional, the Company cannot
continually reduce non-labor O&M to offset wage growth (3T 104). Therefore, the Commission
should reject the PFD/Staff’s proposed inflation adjustments and approve DTE Electric’s proposed
composite inflation rates.29
2. Distribution Operations O&M expenses.
DTE Electric supported $330.5 million of Distribution Operations’ O&M expenses
for the projected test period. This amount includes funding for DTE Electric’s Enhanced Tree
Trimming Program (“ETTP”).
i.

The Company’s Enhanced Tree Trimming Program (“ETTP”) and
surge funding are reasonable and prudent and will provide
significant benefits to customers.

DTE Electric intends to continue utilizing its ETTP, which removes significantly more
vegetation in a clearance corridor rather than the historic clearance circle around DTE Electric’s
lines and equipment. The Commission approved the ETTP in Case No. U-17767, and increased
funding to clear more miles of lines in Case Nos. U-18014 and U-18255. The ETTP needs to
expand further to achieve a five-year trimming cycle because, as discussed in the Company’s Five-

28

The Commission has no common law powers, but instead possesses only the limited authority that the Legislature
conferred upon it. Consumers Power Co v Public Service Comm, 460 Mich 148, 155; 596 NW2d 126 (1999), Mason
Co Civil Research Council v Mason Co, 343 Mich 313, 326-27; 72 NW2d 292 (1955).
The PFD’s adoption of Staff’s inflation rates affects other issues and calculations. As indicated in the Introduction,
DTE Electric takes exception to all of the results, but will not separately address each calculation or other consequence.
29

52

 year Plan, tree interference is the leading driver of customer outages. Tree-caused outages account
for two-thirds of the time that customers spend without power. No other program in the Company’s
portfolio of distribution projects will have a greater impact on mitigating risks, improving system
and customer reliability, and managing the costs of operating the Company’s distribution system.
The Company’s targeted five-year cycle is also comparable to the industry average of 4.9 years
(3T 207-10, 221-22).
The Company requests $95.1 million of O&M for tree trimming in the projected test period
(3T 223; Exhibit A-13, Schedule C5.6, line 18, column (l)). 30 This is not the total amount of
funding needed to achieve a five-year tree-trimming cycle. DTE Electric also proposes a sevenyear surge in tree trimming, but does not seek to recover surge expenses in its O&M levels in this
case’s revenue requirement. Instead, DTE Electric seeks approval to defer surge-related expenses
as a regulatory asset and amortize it over 14 years.
Total forecasted tree-trimming costs are expected to be $1.3 billion from 2019 through
2025. Of this amount, $722 million is proposed to be recovered through base rates (the $95.3
million for the projected test year inflated at 3% per year), and $410 million is proposed to be
deferred as a regulatory asset, and amortized over 14 years (3T 234-36; 7T 3336-37; Exhibit A22, Schedule L3). The Company’s proposal is appropriate because surge-related tree-trimming
expenses will vary, so allowing the deferral of the expenditures above the level that is included in
the rates approved in this case will ensure that customers only pay for work that is accomplished.
The benefits provided by the surge will also continue for years after the work is completed.
Allowing these costs to be deferred and then securitized with a 14-year amortization period will
The Company’s $95.1 million request consists of (1) $80.9 million for maintenance and staff (which is inflationadjusted spending on the $77.5 million approved for this category in Case No. U-18255); (2) $12.2 million for reactive
maintenance (which is inflation-adjusted funding based on 2017 historical spending of $11.2 million); and (3) $2
million for a herbicide program (3T 225-27).
30

53

 better match those benefits to the recovery of the cost. Finally, DTE Electric intends to file a
securitization application for the unamortized balance of the surge costs, which will lower costs to
customers due to the lower cost of debt-only financing (3T 82, 235-36; 5T 1053-57).
ii.

The PFD adopted Staff’s modification, which is generally
aligned with the Company’s goals, but will increase the
surge duration and prolong the recognition of long-term
benefits.

Staff supported the Company’s tree trimming goals – both the five-year trimming cycle
for distribution circuits and the three-year cycle for sub-transmission circuits – and recognized
the need for additional funding. However, Staff suggested cost recovery by increasing current
funding through O&M expense, which means disallowing the $7,053,000 revenue requirement
associated with the Surge and increasing Tree Trim Expense during the test year by $13,007,000,
from $95,092,000 to $108,099,000. In the years following the test year, Staff suggested that the
Company could request increases in spending on tree trimming until the backlog is eliminated
and the five-year cycle is achieved, then drop the O&M amount to its forecasted amount in Exhibit
A-22, Schedule L1 (Staff Initial Brief, pp 71-76, and 119). The PFD “recommends that the Staff’s
proposal, to remove the amortization cost from the company’s rate request and increase tree
trimming O&M expense from $95.1 million to $108.1 million is most reasonable and should be
adopted” (PFD, p 147).
DTE Electric maintains that its surge program should be approved, since it provides
additional customer benefits: (1) faster reduction of tree trim miles (seven years, rather than 8
years 4 months under the PFD/Staff’s proposal), resulting in increased reliability and cost savings
from reduced trouble and storm events; (2) smaller near-term rate increases and the alignment of
rate increases with long-term future customer benefits; and (3) funding certainty will allow the

54

 Company to enter into long-term contracts with tree trimming vendors, which are expected to
provide more competitive pricing and greater labor availability and stability (3T 247-49).
If the Commission does not approve the Company’s filed position, DTE Electric requests
approval of one of the following alternatives:
(1) Approve regulatory asset treatment for the surge costs in the instant case and clarify
that the Commission will address the appropriate amortization period in a future rate case.
(2) Provide additional O&M funding beyond that suggested by Staff. The Company
requests $137.5 million of funding for the Tree Trim Program in the projected test year which
would allow the Company to recover $119.6 million of tree trim expenses in the 2019 calendar
year ($17.9 million less than the Company’s requested surge funding for 2019). This amount
would also help DTE Electric accelerate the needed tree trimming work by providing short-term
funding certainty that is needed to secure additional tree trim labor (3T 249). Either of these
alternatives would be a reasonable compromise between the Company’s surge proposal and Staff’s
alternative funding proposal.
The PFD did not address the first alternative directly, but suggested that DTE Electric’s
financing proposals are too extensive (PFD, p 147). The Company maintains that the surge is the
best way to address tree trimming, and that it is appropriate to address the best way to finance that
program as a whole, rather than continue to revisit tree-trimming on a case-by-case basis. In
addition to the discussion above, future ratepayers will also benefit from the improved reliability
and decreased outages associated with the surge and a regular five-year tree trimming cycle (3T,
248). Therefore, amortization makes sense not only in the context of affordability for current
ratepayers, but also to align payment of the costs with the receipt of the surge benefits.

55

 The PFD rejected the second (O&M increase) alternative, reasoning “that $137 million
would be a 64% increase in the tree-trimming budget at a time when there is significant uncertainty
about the availability of tree-trimming labor in light of recent disasters” (PFD, p 147). While labor
uncertainty does exist in the market, DTE Electric is confident that it will be able to spend, at a
minimum, the $137,500,000 requested and has retained additional tree trimmers. 31 If the Company
is unable to secure the funding requested to support its current spend trajectory then it will be
forced to reduce the existing tree trim work force, delaying both the progress on the ETTP program
and the associated reliability benefits that customers would experience. The PFD’s suggestion that
the Company’s proposed funding increase is too large neglects that the current recovery reflects
tree trimming “as usual.” DTE Electric has proposed a new program – the surge – that requires
additional funding to accomplish its objectives. If the Commission recognizes and agrees with the
objectives of the surge, then the program should be funded adequately through O&M (if not
through the Company’s original proposal) so that the Company can achieve those objectives.
The future is always somewhat uncertain, but this should not stand in the way of attempting
to implement the surge as the PFD suggests. Even though it cannot predict the future, the Company
has appropriately planned for the future. DTE Electric will be transparent with surge program
results and will make regular reports to the Commission that include surge tracking metrics and
progress. The Company intends to work with the Commission and Staff to make appropriate
modifications to the Surge program as actual results dictate (3T 250-51). The Company maintains
that it has designed an appropriate tree trim program that is already providing significant customer
benefits and will continue to provide increased benefits into the future.

31

The Company has been able to secure over 1,150 tree trim contract employees who are actively working on the
DTE Electric system as of March 19, 2019, up from 818 trimmers in June 2018.
56

 History also reflects the Company’s commitment to tree trimming and provides assurance
for the future. Since 2009, the Company has spent $19 million more than approved amounts in rate
cases, reflecting the Company’s continuing focus on trimming trees maximize customer reliability
(3T 252-53). The Company maintained a five-year trimming cycle through the end of 2013 while
maintaining industry standard specifications. In 2014, the Company developed the ETTP, which
essentially removes vegetation in a clearance corridor rather than the historic clearance circle
around DTE Electric’s lines and equipment. The Commission approved and increased ETTP
funding in Case Nos. U-17767, U-18014, and U-18255. The Commission has also been fully
informed in prior rate cases as indicated above, and recognized DTE Electric’s spending and
commitment in other proceedings. 32
Finally, the PFD suggested that the Commission should consider (but made no
recommendation on) a two-way tracker (PFD, pp 147-48). The Company prefers the Surge
methodology to a two-way tracker because, as discussed above, it will allow for smaller near-term
rate increases and will align these rate increases with long-term future customer benefits. If the
Commission were to reject the Company’s deferral and securitization proposal, DTE Electric is
receptive to a two-way tracker as it would protect rate payers in the event of labor shortages and

For example, the Commission opened an investigation regarding utilities’ responses to the 2013 ice storm, which
led to the May 2, 2014 and December 4, 2014 Orders in Case No. U-17542. The Commission recognized that trees
are the primary cause of power outages, and that DTE Electric was spending all of its allocated funding for vegetation
management to prevent such outages. The Commission stated in those prior orders, for example:
32

The Staff recognizes vegetation management to be the most effective tool in outage avoidance and
in limiting the duration of outages . . . With regard to DTE Electric, the Staff finds that its vegetation
management program showed a strong commitment to staying ‘on-cycle’ and spending allocated
funding on vegetation management. [May 2, 2014 Order in Case No. U-17542, pp 16].
Both DTE Electric and Consumers state that the primary cause of damage and outages on their
systems is contact from trees and other vegetation with utility infrastructure . . . DTE Electric reports
that approximately 75% of the damage to its distribution system was caused by trees. DTE Electric
is currently spending all of its allocated funding on vegetation management. [December 4, 2014
Order in Case No. U-17542, pp 4-5].

57

 allow the Company an opportunity to accelerate the tree trimming plan if additional tree trim
resources become available.
Therefore, the PFD’s recommendation should be rejected, and the Company’s treetrimming requests should be adopted by the Commission. In the alternative, if the Commission
agrees with the PFD recommendation, DTE Electric believes that a two-way tracker would benefit
ratepayers and allow the Company to achieve its tree-trimming goals.
3. Customer Service O&M Expenses – meter reading expenses.
DTE Electric O&M expenses for the Customer Service organizations33 include meter
reading expenses. Staff proposed $1.483 million in O&M, which is $2.147 million less than the
Company’s $3.630 million proposal (Staff Initial Brief, pp 70-71). Staff explained that they
“developed a meter-reading cost by applying the cost per meter reader in the historical period to
the number of meter readers in the test year” to arrive at this level of funding (Id, p 71). The PFD
agreed with Staff’s methodology (PFD, p150).
The Company disagrees. Ms. Johnson explained that Staff’s calculation is incorrect
because Staff simply divided the 2017 Meter Reading O&M expense by 58 (the number of external
vendors to read meters in 2017), and then multiplied that result by the number of external vendors
to manually read meters in the projected test period and added inflation. Staff neglected that the
O&M costs cover additional activities including billing operations pertaining to major accounts,
metering operations, consecutive estimate team and special reading expenses. The PFD/Staff’s

33

The Customer Service organizations are Customer Contact Center, Customer Billing, Revenue Management and
Protection (“RM&P”) and Customer Experience. These organizations are responsible for billing, customer contact,
and payment acceptance (7T 3110-12).

58

 proposal should be rejected because it excludes these additional costs that the Company will incur
(7T 3113, 3139-40).
4. The Company’s projected uncollectible expense is accurate, reasonable,
and should be approved.
i.

The Company’s calculation methodology should continue to
be used.

DTE Electric supports $51.6 million of uncollectible expense based on a 2015-17 threeyear average of actual uncollectible expense. Staff proposed to project uncollectible expense with
a cash basis method using a three-year (2015-17) average of the ratio of net charges offs to revenue.
Staff reasoned that the Company’s “assumptions could result in significant forecasting error,” yet
proposed only a $234,000 reduction (Staff Initial Brief, pp 68-69). The PFD agreed with Staff,
reasoning that Staff’s method was used with other utilities and “appears more accurate and less
prone to significant forecasting error” despite the $234,000 at issue (PFD, pp 154-55).
The Company disagrees with the PFD’s recommendation. The most accurate method for
forecasting uncollectable expense is using a three-year historical average of 2015-17 uncollectible
expense as recorded in account 904, resulting in $51.6 million as indicated above. Ms. Uzenski
explained that Staff’s proposed cash-based methodology is flawed because there is not a direct
correlation of the net charge offs and revenues used to calculate the ratio in any given year. There
is a significant timing lag between revenue recognition and when the net charge offs occur. The
Company uses a balance sheet method to accrue a reserve for the estimated portion of customer
accounts receivable that will ultimately be written off (generally 150 days past final bill due date,
which is issued after service is disconnected). The uncollectible expense recorded in the income
statement reflects the change in the balance sheet reserve needed to reflect accounts receivable at
a net realizable amount. In contrast, net charge offs relate to revenues earned in prior periods

59

 without consideration of the age of the outstanding accounts receivable. Therefore, they are not
representative of expense in the current period (7T 3346).
Staff’s methodology is also inaccurate because the ratio of net charges offs to revenue was
applied to the Company’s present revenues to calculate Staff’s projected uncollectible expense.
Final revenues in the projected period will not be known until the conclusion of this case. Rates
are set to cover the Company’s estimated expenses to be recorded in the income statement. The
estimation of future expenses should be consistent with the practice used to record the actual
expenses. An average of the amounts charged to account 904 provides such consistency. The
Commission has also consistently accepted the use of historical period uncollectible expense, as
recorded in account 904, in past rate cases for both DTE Electric and DTE Gas (DTE Electric rate
cases U-18255 and U-18014, and DTE Gas rate cases U-18999 and U-17999). (7T 3346-47).
Therefore, the Commission should reject the PFD/Staff’s proposed alternative
methodology, and maintain its appropriate methodology, resulting a projected uncollectible
expense of $51.6 million as calculated by the Company (7T 3347).
ii.

DTE Electric’s proposed returned check charge should be
approved.

DTE Electric has worked proactively to reduce uncollectible expense (7T 3124-26), and
now proposes to use a third-party vendor to recover insufficient fund checks and increase the
returned check charge from $15.00 to $28.66 (7T 3126-29). Staff did not oppose the Company’s
proposal to hire a third-party vendor, but recommended that the current $15.00 charge should be
retained due to a concern about the impact such an increase would have on customers (Staff Initial
Brief, p 146. See also Soulardarity Initial Brief, p 40). The PFD agreed, asserting that “DTE
Electric’s proposal simply increases the financial burden for those who can least afford to pay”
(PFD, p 156).
60

 The Company disagrees because it anticipates that the increased charge would deter
customers from repeatedly writing checks that are returned for insufficient funds (7T 3129). Thus,
by deterring repeated charges, the Company’s proposal would result in the most-affected
customers paying less in total.
5. Employee pension and benefits expense.
DTE Electric projects $161.9 million of employee pension and benefits O&M
expense, which after adjustments results in a net employee pension and benefits expense of $146.9
million (6T 1831; Exhibit A-13, Schedule C5.10, line 32). In its Initial Brief, the Company also
accepted an adjustment proposed by Staff Witness Welke to reduce active healthcare expense for
the amortization of a one-time credit of $1.7 million (Initial Brief, p.83). While the PFD correctly
states that no party objected to the Company’s projected pension and Other Post-Employment
Benefit (OPEB) expenses (PFD p.158), the PFD is silent on the other components of employee
benefits expenses.
6. Employee compensation.
DTE takes issue with the PFD’s proposed exclusion of the projected $27.1 million
of cost related to the financial measures associated with the incentive compensation programs.
The record supports the Company’s position. In summary, the Company’s overall compensation
policy is to provide a competitive level of total compensation consisting of base pay plus incentive
compensation. DTE Electric’s incentive compensation programs for both its executive and nonexecutive employees consist of short-term incentive plans provided through the Annual Incentive
Plan (“AIP”), applicable to executive level employees, and Rewarding Employees Plan (“REP”),
available to all other non-represented employees. In addition, the Company provides a multiple
year incentive plan delivered through the Long-Term Incentive Plan (“LTIP”), which is generally

61

 available to managers and above, and up to 10% of other non-represented employees. Mr. Cooper
provided a detailed description of the design and mechanics of these plans, including the metrics
used to track Company performance, the method for setting Company performance level targets,
and the conditions for payment of incentive compensation (6T 1842-51, 1865-77; Exhibit A-21,
Schedules K1, K2, K3, and K4).34
DTE Electric seeks to recover the $46.4 million net projected test period expense
of these plans, which excludes the incentive compensation expense allocated to the Company for
DTE Energy's top five executives (Exhibit A-21, Schedule K5, line 63, column (k)). The
components of these expenses are reflected in the table below, as differentiated for the portion of
such expenses based on operating versus financial performance measures (6T 1852).
LTIP

AIP

REP

Total

Financial

$15.4

$2.6

$9.1

$27.1

Operating

$0.0

$4.0

$15.3

$19.3

Total

$15.4

$6.6

$24.4

$46.4

Staff proposed to exclude $27,083,000, representing incentive compensation expense
related to financial measures (Staff Initial Brief, pp 66-68). Staff acknowledged that it “did not
introduce evidence that the Company’s overall compensation was unreasonable. Rather, Staff’s
recommendation is based on the Commission’s Order in Case No. U-14347, which found that

34

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 the J. D. Power National Peer Set. 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 measures related to reducing the length of service interruptions, fossil and nuclear
power plant reliability as well as additional specific measures related to the nuclear generation business unit. The
Operating Excellence measures used at DTE Energy Corporate Services LLC were adjusted to exclude measures to
DTE Gas (6T 1842-53).
62

 when incentive compensation programs are tied to Company earnings and cash flow the plans
largely benefit shareholders” (Id, p 68). Staff similarly suggested that it understood recent
decisions by the Commission to have established a “policy” of excluding financial performance
measures from the revenue requirement (8T 4049).
The AG proposed the complete elimination of incentive compensation expense related to
financial measures ($27.083 million), plus 50% of incentive compensation expense related to
operating measures ($9.649 million) for a total disallowance of $36.732 million (AG Initial Brief,
pp 36-43). Like Staff, the AG’s proposed exclusion of financial measures is based on a broad
policy viewpoint that these measures benefit only shareholders and not customers (5T 1614-15).
The PFD found “that the Staff’s recommendation to exclude the projected $21.7 [sic, $27.1]
million cost of the financial measures associated with the incentive compensation programs should
be adopted” (PFD, p 169), essentially reasoning that little has changed since the Commission
excluded the cost of financial measures in Case No. U-18255 and suggesting that the quantified
customer benefits of the financial related measures are “attenuated at best, and in some cases,
specious” (PFD, pp 169-72).
The Company disagrees with the PFD’s assertion that little has changed since the
Commission excluded the cost of financial measures and that the quantification of the customer
benefits are flawed. The Company maintains that the Commission must base its decision on the
record, and the record in this case fully supports the Company’s proposed recovery. 35 The

35

The Commission has based its decisions on the evidence (e.g., April 17, 2018 Order in Case No. U-18255, p 49)
and has expressly recognized that “each case must be evaluated on the record in that case” (January 31, 2017 Order
in Case No. U-18014, p 85). Michigan’s Constitution requires the Commission’s findings to “be supported by
competent, material and substantial evidence on the whole record.” Const 1963, art 6, § 28. The APA similarly
precludes the Commission from making decisions based on non-record materials. MCL 24.276.

63

 Commission’s older orders also recognize that incentive compensation is recoverable based on the
type of programs that DTE Electric has developed and the type of evidentiary record that DTE
Electric has presented in this case. 36 The PFD’s proposed exclusion of the incentive compensation
expense related to financial measures dismisses the substantial quantified customer benefits related
to financial measures reflected within the cost/benefit analysis on Exhibit A-21, Schedule K5, and
further explained by Mr. Cooper. Financial metrics do not simply benefit shareholders. Instead,
customers benefit from incentive compensation measures that motivate employees to focus on
earnings and cash flow measures because the ability to exceed the annual goals is dependent on
the Company realizing productivity enhancements and cost savings, allowing the Company to
postpone rate increases and producing lower revenue requirements when rate increases become
unavoidable. Ultimately, this also provides higher quality customer service. It is logical that if a
company wishes to create a performance-based culture through the use of variable pay programs
designed to motivate the organization’s overall effectiveness, financial metrics are often used to
provide a common driver and have the advantage of being measured on a comprehensive, timely
and comparable basis.

The Commission long ago recognized that: “Executive bonuses have often been viewed as an appropriate cost of
operating a utility” (October 28, 1993 Opinion and Order in Case Nos. U-10149 and U-10150, p 57 (rejecting the
ALJ’s total exclusion recommendation; adopting Staff’s 50/50 sharing proposal; and advising DTE Gas that “future
approval of an incentive bonus plan like this requires a showing that it will not result in excessive costs and that the
benefits to the utility’s ratepayers will be commensurate with those costs”). See also, for further example, Case No.
U-17767, where the Commission approved DTE Electric’s recovery of costs attributable to operating measures, stating
that:
36

[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) . . . .
[December 11, 2015 Order in Case No. U-17767, p 76.]

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 Financial based measures motivate employees to improve their work processes to use fewer
resources while producing improved performance.

The beneficial impact of the cost and

productivity focuses of the earnings related measures is illustrated by the fact that the Company’s
O&M expenses have increased by dramatically less than inflation from 2009 through the end of
the projected test year. Indeed, the Company’s projected O&M expense as filed for the projected
test year is $226.2 million less than it would have been if the Company’s 2009 O&M expense
increased by the Consumer Price Index, translating to a $21.9 million annual benefit, as reflected
on Exhibit A-21, Schedule K-5. The PFD concludes that this benefit is merely an incentive for
the Company to spend $21.9 million annually less than the level of O&M included in the revenue
requirement (PFD p. 172). This conclusion misses the point of the analysis. As an electric utility,
DTE Electric has little direct control over its revenue; the Commission sets its rates and the
Company’s sales levels are largely dependent on regional economic activity and the weather.
Because the Company does not control either of these factors, its primary ability to improve its
financial performance is through effective cost control. Mr. Cooper’s demonstration that the
Company’s actual and projected O&M from 2009 through the end of the projected test year will
increase less than inflation illustrates how customers have and will continue to receive the benefit
of the Company’s reduced revenue requirement made possible through the effective management
of costs. While Mr. Cooper concedes that salutary effects of the Company’s superior financial
performance made possible through improved cost efficiencies may result in temporary benefits
to shareholders, the benefits to customers of these improved efficiencies are permanent as revenue
requirements reflecting these lower cost levels are adopted by the Commission.

Since the

establishment of the revenue requirements in this and subsequent cases is based, in part, on
historical costs, the long-term benefits to customers will exceed the short-term benefits to

65

 shareholders. This customer benefit is unrelated to the Company’s actual cost levels in the future,
as incorrectly presumed in the PFD.
DTE Electric’s cash flow related measures directly affect its ability to raise capital, and the
cost of capital, that it needs to fund its operations. Mr. Cooper testified that the benefits of the
Company maintaining its existing credit ratings avoids a $15.6 million increase in its annual
interest costs. The PFD concludes that it is inappropriate to attribute the benefits of the Company’s
credit ratings to the incentive compensation programs because it ignores the costs charged to
ratepayers and cites the income requirement adopted by the Commission in its Order in Case No.
U-18255 (PFD p.172).

While the Company’s revenue requirements are borne by its customers,

there is no evidence that the Company’s customers are required to bear any excess costs arising
from the its capital structure. Indeed, as explained by Dr. Vilbert, any increase in leverage would
increase the Company’s cost of equity (6T 1948). Moreover, the benefits of an employee emphasis
on cash flow are similar to the earnings measures. On a day-to-day basis, the Company has little
control over revenues, as described above, but it can control how it uses its resources. While the
earnings benefit quantification was based on the ability to limit the growth in O&M expenses, the
cash flow measures are designed to provide a focus on effective management of the Company’s
capital spending program, as cash flow reflects, among other things, capital expenditures.
Furthermore, DTE Electric’s shareholders are also sharing in the incentive compensation expense,
since the Company’s proposed recovery does not include $10.0 million of incentive compensation
expense for the top 5 executives (6T 1838-41, 1853-56, 1866-67; Exhibit A-13, Schedule C-17).
Beyond the mechanics of the demonstration of the net customer benefits, the propriety of
the Company recovering all if its incentive compensation expenses, inclusive of both operating
and financial measures, is the overall reasonableness of the resulting total compensation. DTE

66

 Electric must also offer incentive compensation opportunities to be competitive with other
employers in attracting and retaining talented and qualified employees (6T 1833, 1841). The PFD’s
focus on the variable portion of total compensation is also inappropriate because DTE Electric’s
incentive programs are not additional compensation over and above what other companies pay for
similar jobs. Instead, DTE Electric’s incentive compensation programs are one of two components
that comprise DTE Electric’s total annual compensation package, which is comparable to other
companies competing for the same employees (6T 1832-34). The most recent study (as of
December 31, 2017) determined that total compensation for non-represented employees exclusive
of executives was less than the market median for all matched positions (6T 1868; Exhibit A-32,
Schedule V1). Similarly, based on a recent Aon Hewitt survey of DTE executive compensation
compared to its peer companies, the total compensation, including incentive compensation, for
DTE is about 4% less than the peer group based on target performance levels (6T 1841-42, 1868).
Without the prospect of total annual compensation equal to the fixed plus the variable
compensation components, DTE Electric 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. Incentive
compensation is just part of total compensation.
In summary, DTE Electric’s proposal to include incentive compensation expense related
to both the operating and financial measures is fully supported by the record in this case as DTE
Electric provided an in-depth cost/benefit analysis demonstrating a $77.3 million net customer
benefit ($123.7 million total customer benefits minus $46.4 million total incentive plan costs). (6T
1854-61; Exhibit A-21, Schedule K5, line 63). DTE Electric has demonstrated in detail that the
customer benefits of its incentive compensation plans significantly outweigh their costs, that the

67

 total compensation is reasonable based on comparison to the Company’s peers, and that there is
no valid reason to disallow the portion of incentive compensation related to the financial measures.
Therefore, based on the evidence in this record, the Commission should reject the PFD’s exclusion
of $27.1 million of incentive compensation expense and approve DTE Electric’s request to include
all of the Company’s incentive compensation expense (except for the top five DTE Energy
executives) in the revenue requirement adopted in this case.
7. Edison Electric Institute Dues
DTE Electric included in its projected O&M expense $1.3 million related to dues paid to
Edison Electric Institute (EEI). MEC/NRDC/SC recommended that $1,269,000 in dues that DTE
Electric pays to EEI, and charges to ratepayers, be disallowed. According to Mr. Rábago, DTE
Electric belongs to many trade associations, including EEI, however, “[u]nbeknownst to most
customers, these payments may be used to fund advocacy with which customers may disagree and
that is contrary to their interests.” Mr. Rábago explained that some portion of EEI dues, the part
associated with the organization’s lobbying efforts, is excluded from O&M expense, but that
amount is determined by EEI and reported to DTE Electric on EEI’s invoice. Mr. Rábago
concluded that, “[t]he Company has failed to demonstrate that the costs associated with EEI
membership dues are limited to activities that benefit ratepayers and therefore are just and
reasonable. The PFD recommends adopting MEC/NRDC/SC’s proposed disallowance of EEI dues
in the amount of $1,269,000 absent any evidence from DTE Electric rebutting Mr. Rábago’s
testimony.
Mr. Rabago did not provide any specific evidence that the EEI dues included in the
Company’s projected O&M related to lobbying activities other than stating the amount is
determined by EEI. As stated in Mr. Rabago’s testimony, the Company does exclude a portion of

68

 the EEI dues from O&M expense. DTE Electric has consistently relied on invoices from EEI for
properly recording recoverable and nonrecoverable dues on its books and has no reason to believe
the amounts provided to us by EEI are inaccurate. Even though Mr. Rábago discussed several
efforts that EEI undertakes that clearly provide ratepayer benefits, including workforce education
and training, public safety campaigns, and EEI’s mutual assistance program, he proposed
disallowing 100% of EEI dues. MEC/NRDC/SC’s recommendation is not justified and the PFD’s
recommendation to disallow $1.3 million of EEI dues should be rejected.
8. Weekend Flex and Fixed Bill O&M expense
DTE Electric is proposing to include $0.4 million and $1.0 million in O&M expense for
the Weekend Flex and Fixed Bill pilot programs respectively. The ALJ’s recommendation to
disallow these amounts are discussed in detail in Section VI.E.
B.

Depreciation and Amortization.

DTE Electric’s projected depreciation and amortization (“D&A”) expense is $883.5
million. 37 The PFD recommends $875,900,000 based on the PFD’s proposed disallowances (PFD,
p 174, citing Appendix A, p 3, (but note that this cite does not exist). DTE Electric takes exception
and maintains that the Commission should approve the Company’s projected D&A expense of
$883.5 million, incorporating the discussions in these Exceptions regarding the PFD’s proposed
disallowances.

DTE Electric’s Initial Brief, pp 91-92, explained and supported the Company’s projected depreciation and
amortization (“D&A”) expense of $883.6 million, which is based on the $948.986 million filed amount minus $65.2
million (due to new depreciation rates from the December 6, 2018 Order Approving Settlement Agreement in Case
No. U-18150, p 3), and $151,000 (due to a $4.5 million reduction to the Company’s capital projections), as discussed
in Section I of DTE Electric’s Initial Brief. DTE Electric’s Reply Brief made an additional $89,000 reduction to
depreciation to properly remove depreciation related to HQ Energy Center contingency at the approved U-18150
depreciation rate. ($240,000 less $151,000).
37

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 C.

Federal Income Tax Expenses.

The PFD does not make an explicit recommendation regarding federal income tax (“FIT”)
expense, but implicitly suggests adopting the level resulting from Staff’s adjustments to the
Company’s projected revenues and expenses (PFD, p 175). DTE Electric maintains that the
PFD/Staff’s proposed adjustments should be rejected as discussed in these Exceptions, with
corresponding tax effects.
D.

Allowance for funds used during construction (AFUDC) and Other
Operating Income Adjustments.

DTE Electric included $32.973 million in total as an AFUDC operating income adjustment.
Staff recommended increasing AFUDC by $1.923 million to $34.896 million (Staff Initial Brief,
p 79). The PFD did not address this matter, but implicitly made Staff’s proposed adjustment,
which is reflected at PFD Appendix C, line 22. DTE Electric maintains its position. Staff did not
disagree with the Company’s inclusion of CWIP for ratemaking purposes and would note that by
AFUDC being in CWIP, it too, is part of CWIP allowed for ratemaking purposes. However, Staff
did disagree with the inclusion of AFUDC in CWIP without an offsetting adjustment to operating
income. Without an offsetting adjustment to operating income the Company would be earning a
return of $2,594,975 on its financing costs (AFUDC) (Exhibit S-9.0) and thus, Staff argued, would
burden the ratepayer with providing the Company recovery of its financing costs prior to those
costs being closed to plant in service (Staff Initial Brief p 80).
Ms. Uzenski testified that this argument confuses two different concepts – AFUDC and
return on rate base (7T 3351). The Company’s accounting practice complies with the Commission’s
Order in Case No. U-5281 because it does not record additional AFUDC on the AFUDC included in
CWIP – i.e., no compounding. The Order in Case No. U-5281 does not state that a return on CWIP,
inclusive of AFUDC, is excluded from rate base. In fact, one of the objectives of the Order in Case

70

 No. U-5281 was to clarify that CWIP is to be included in rate base. In addition, once CWIP is
transferred to plant in service, a return is earned on the entire plant balance, including capitalized
AFUDC. It would be inconsistent to allow a return on capitalized AFUDC in plant, but not on
AFUDC in CWIP. The Company’s method for determining the AFUDC credit for rate-making
purposes is consistent with the order and the practice used in prior rate cases (7T 3351). The
Commission should reject the PFD/Staff’s adjustment and approve the Company’s AFUDC
amount of $32.973 million.
E.

Charging Forward

The Company proposes the Charging Forward program to advance on-road transportation
electrification (see generally, DTE Electric’s Initial Brief, pp 95-102). The PFD reflects that the
other parties generally agreed that the Company’s proposal is beneficial and appropriate, and that
the Company agreed to several specific program changes suggested by other parties (see generally,
PFD, pp 175-81; the agreed-upon changes are also listed at DTE Electric Reply Brief, pp 131-33).
The Company, however, disagreed with several of the modifications proposed by different parties,
and maintains its disagreement to the PFD’s recommendation of those changes. Therefore, the
Company’s Charging Forward proposal, with only the modifications agreed upon by the Company,
should be approved.
1. The PFD’s recommendation to allow site hosts to charge by the
kilowatt-hour should be rejected.
Staff, ChargePoint, ELPC, MEC/NRDC/SC, and EIBC/IEI requested that the Company
modify its current tariff rules to allow site hosts to charge by the kilowatt-hour (i.e., remove the “salefor-resale” prohibition). The PFD agreed, and after quoting MEC/NRDC/SC at length, stated:
The Staff’s and Intervenor’s evidentiary presentations and arguments on this issue
are convincing. A properly structured EV program must free site hosts from the
confines of DTE Electric’s sale-for-resale prohibition. In short, DTE Electric’s
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 proposal to retain its sale-for-resale prohibition would remove a valuable tool from
Charging Forward’s toolbox of pilot program options that should be available to site
hosts and DTE Electric. The reasons for this conclusion are numerous and nicely
summarized by MEC/NRDC/SC, quoted above, and will not be repeated. Lifting
DTE Electric’s sale-for-resale prohibition is necessary if DTE Electric wishes to
properly explore and learn how to best manage the demands of the electrification of
the automotive sector. [PFD, pp 193-94. Footnote omitted.]
The Company strongly disagrees for multiple reasons. Volumetric pricing is an imprecise
signal to the customer and is not necessarily correlated with the Company’s fixed and demand-based
investments. In addition, allowing site hosts to charge services by the kilowatt-hour could create
confusion for customers (i.e., EV drivers) as the rates to be offered by the site hosts would not be
regulated by the Commission and could be quite different than those offered by the utility (i.e., a
customer could call DTE Electric and ask why he/she is being charged 30 cents per kilowatt-hour
when the price they pay for electricity at home is much lower).
Furthermore, the Company believes that there are multiple options for DTE Electric to
collaborate with site hosts to ensure that the pricing for the charging services reflect the conditions in
the electricity system. Limiting a site host to charge on a per kilowatt-hour basis, will mask the pricing
approach that a site host could pursue as it tries to price the interrelated services it provides and the
investments that it is trying to recover through its pricing strategy as, of course, the site host would
also be providing the parking space, billing interface, and potentially other parking-related services
along with the charging functionality.
DTE Electric has proposed the EV program its management believes is appropriate. In
Union Carbide v Public Service Comm, 431 Mich 135; 428 NW2d 322 (1988) our Supreme Court
explained:
The power to fix and regulate rates, however, does not carry with it, either explicitly
or by necessary implication, the power to make management decisions.
‘It must never be forgotten that while the State may regulate with a view to
enforcing reasonable rates and rates, it is not the owner of the property of public
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 utility companies and is not clothed with the general power of management incident
to ownership.’ Missouri ex rel Southwestern Bell Telephone Co v Public Service
Comm, 262 US 276, 289; 43 S Ct 544, 547; 67 L Ed 981 (1923).” 431 Mich at 14849. See also Consumers Power Co v Public Service Comm, 460 Mich 148, 157; 596
NW2d 126 (1999).
DTE Electric appreciates the input and collaboration regarding EV service but does not
wish to implement proposals involving per kWh pricing for EV charging. It bears emphasis that
the proposals (and now the PFD’s recommendation) to remove the “sale-for-resale” provision are
contrary to the fundamental business structure that the Company envisioned for the Charging
Forward program. The Company does not agree to such proposals, and the Commission should
not order the changes set forth in these proposals. The PFD disagreed stating:
DTE Electric’s argument and reliance on Union Carbide is not convincing. In
Union Carbide, the Commission was found to have exceeded its authority when it
ordered Consumers energy to cease operation of its Karn units No. 3 and No. 4 out
of economic order. However, the same court also found that the Commission was
within its authority to regulate to enforce reasonable rates and charges and that it
may prevent the passing through to customers of any unreasonably incurred
expense. In this case, the Commission is called upon to amend a DTE Electric tariff
provision that Staff and Intervenors find unreasonable. Pursuant to Union Carbide,
the Commission has full authority to grant that request. [PFD, pp 194-95. Footnotes
omitted.]
This interpretation misreads Union Carbine to suggest that anything involving “rates and
charges” is within the Commission’s authority. But the Commission’s authority is limited. 38 The
Commission has “ratemaking” authority, but almost any aspect of DTE Electric’s business the

38

The MPSC has no common law powers, but only possesses the limited authority that the Legislature conferred upon
it. Consumers Power Co v Public Service Comm, 460 Mich 148, 155; 596 NW2d 126 (1999). The MPSC is an
“administrative body created by statute and the warrant for the exercise of all its power and authority must be found
in statutory enactments.” Union Carbide v Public Service Comm, 431 Mich 135, 146; 428 NW2d 322 (1988); Sparta
Foundry Co v Public Utilities Comm, 275 Mich 562, 564; 267 NW 736 (1936). The MPSC’s authority must be
conferred by clear and unmistakable statutory language, and a doubtful power does not exist. Mason Co Civil Research
Council v Mason Co, 343 Mich 313, 326-27; 72 NW2d 292 (1955). The MPSC cannot expand its jurisdiction through
its own acts or assumption of authority. Ram Broadcasting v Public Service Comm, 113 Mich App 79, 92; 317 NW2d
295 (1982). The MPSC cannot re-write the Legislature’s language to include new or different provisions. Hanson v
Mecosta Co Rd Comm, 465 Mich 492, 501-503; 638 NW2d 396 (2002). If an MPSC order conflicts with a statute, the
order is void. Manufacturers Nat’l Bank v DNR, 420 Mich 128, 146; 362 NW2d 572 (1984).
73

 Commission regulates may affect rates to some degree, and the Commission cannot expand its
authority by mischaracterizing its decision as “ratemaking.” See Consumers Power Co v Public
Service Co, 460 Mich 148, 157-58; 596 NW2d 126 (2004) (rejecting MPSC’s “ratemaking”
defense and vacating the MPSC’s order as unlawful).
In this case, the PFD recommends changing DTE Electric’s proposed Program. This
unlawfully encroaches on utility management, as illustrated by Ford Motor Co v Public Service
Comm, 221 Mich App 370, 385, 387-88; 562 NW2d 224 (1997), where DTE Electric proposed a
demand side management (“DSM”) program. The Commission modified that proposed program
(much like the PFD recommends here). The Court of Appeals held that the Commission’s
modification of DTE Electric’s DSM program was unlawful, explaining in part: “The PSC here
exceeded its ratemaking authority by, in effect, requiring Detroit Edison’s management to adopt
the DSM program the PSC thought best. The PSC did significantly more than ‘approve’ the DSM
program proposed by Detroit Edison.” 562 NW2d at 234-234. See also Attorney General v Public
Service Comm, 269 Mich App 473; 713 NW2d 290 (2005) (MPSC exceeded its authority when it
ordered the utility to expand its “green power” program and required customers who did not
participate in the program to subsidize its costs).
There is also a well-understood electric regulatory paradigm that must not be upended by
engaging multiple independent agents in activities that might be confused with the provision of
regulated electric service. Only customers qualifying for DTE Electric’s Rider No. 4 (“Resale of
Service”) may engage in the resale of service under limited circumstances, and those customers
who qualify for Resale of Service are obligated to charge the current rates of the utility and
otherwise conform to various service requirements (8T 3617).

74

 Therefore, and in addition to the other reasons discussed above, the well-understood and
non-problematic sale-for-resale probation should remain in place.
2. The PFD’s proposed regulatory asset treatment and amortization would
cause the Company to lose recovery of deferred costs that are amortized
without the expense being included in the revenue requirement
Staff recommended reducing incremental Charging Forward O&M expense by $1,168,000
(Staff Initial Brief, p 70), and that the Commission adopt Staff’s proposal for regulatory asset
treatment and amortization rather than the Company’s proposal (Staff Initial Brief, pp 117-19).39
The Company agreed with the use of account 182.3 for the rebates, and amortization over five
years, which are consistent with the Company’s requests to use account 182.3 and to recover the
deferred costs over five years by including the amortization expense in O&M, as shown on Exhibit
A-13, Schedule C5.8, column (i), line 12. The Company disagreed with Staff’s proposals to (1)
begin amortization the year after the costs are incurred, and (2) delay recovery of the unamortized
balance until after Staff’s review (7T 3330, 3348).40 The PFD agreed with Staff, stating:
In the case at bar, considered as a whole, and recognizing the uncertainty of
Charging Forward’s actual costs, the Commission finds Staff’s proposal most
reasonable. A Staff argues, it protects customers from paying for costs that might
not be incurred and provides DTE Electric to fairly recover its costs actually
incurred. This is particularly important considering DTE Electric’s track record of
slow EV pilot program implementation. Additionally, it has the added benefit of
being consistence [sic] with the EV provisions of the Commission’s January 9 th
orders in Case No. U-20134. Therefore, it is recommended that the Commission
approve the regulatory asset treatment of Charging Forward deferred costs, with a
five-year amortization beginning the year following cost deferral, and allowance
in rate base and expense after a prudency review in future DTE Electric rate cases.
And, as it did in the Consumers Energy case, it is recommended that the
39

More specifically, Staff proposed the use of account 182.3, Other Regulatory Assets, for the rebates and certain capital
and O&M costs; amortization of the regulatory asset over five years beginning the year after the costs are incurred;
inclusion of prudent costs in base rates after a review by Staff; and inclusion of the net unamortized balance of the reviewed
costs in rate base (8T 4056).
The Company also disagreed with Staff’s proposal to include capital expenditures in the regulatory asset because
they are more appropriately classified within Property, Plant and Equipment, as outlined in the Commission’s Uniform
System of Accounts. However, to minimize the number of arguments related to the Charging Forward project, the
Company will accept the classification specified in the final order in this case.
40

75

 Commission direct DTE Electric to examine whether there would be cost savings
realized by use of a tracker for future rebate programs. [PFD, pp 213-14.]
Regarding the PFD/Staff’s first proposal (concerning when amortization begins), Ms.
Uzenski explained that the Company would lose recovery of deferred costs that are amortized without
the expense being included in the revenue requirement. If the Commission approves the proposed
IRM, then DTE Electric might not file another rate case for a few years. Therefore, a portion of the
deferred costs will be amortized but never recovered. The unrecovered amount would be even larger
if the Commission accepts Staff’s adjustment to remove the Company’s forecasted amortization
expense from the projected period in this case. The Company’s support of the EV market will benefit
all customers, not just those owning EVs (see generally, DTE Electric’s Initial Brief, p 100, and PFD,
p 176, n 400: “[I[t is agreed by all that the near-term electrification of the auto sector is a near certainty
with enormous benefits.”). Therefore, the Company should not have to absorb the expenses for the
Charging Forward program. Thus, the costs deferred to the regulatory asset should remain in that
account until the amortization expense is reflected in base rates (7T 3348-49).
In its initial brief, Staff agreed that some costs might not be recovered due to regulatory
lag. Staff also correctly noted that depending on the timing of DTE Electric’s future rate cases,
the Company could over-recover some of the costs. The Company stated in testimony a willingness
to provide Staff with a reconciliation of the actual costs incurred to the amounts included in the
revenue requirement as part of Staff’s audit in the next rate case. This could address the Staff’s
concern regarding over-recovery.
Regarding the PFD/Staff’s second proposal (to delay recovery pending Staff’s review), the
Company agrees that a prudency review by Staff is appropriate, but depending on the timing of future
rate cases and Staff’s reviews, recovery of the deferred costs could be significantly delayed. This
would be even more troublesome if amortization expense starts the year after the costs are incurred
76

 (as discussed above) because some costs would not be recovered at all. For example, as shown on
DTE Electric’s Exhibit A-12, Schedule B5.9, the Company forecasted 2019 costs of $2.8 million,
2020 costs of $5.1 million, and $5.2 million in 2021, totaling $13.1 million. Staff’s proposed treatment
would have the Company expense $0.5 million starting in 2020, increasing to $2.6 million annually
in 2022 without any recovery ($13.1 million / 5 years). Even if the Company filed its next rate case
in 2019 or 2020, the Company would continue to lose a portion of the annual amortization because
the Staff would not be able to audit all 2019 or 2020 costs before they completed their testimony.
Overall, the PFD/Staff’s proposed accounting is a disincentive for the Company to aggressively
implement the Charging Forward program.
The Company wants to proceed with Charging Forward - which received support by all parties
- and the Company believes having the Commission approve the costs now is the most prudent way
forward. Charging Forward represents a program that is proactive and innovative and that seeks to
provide benefits to all utility customers by ensuring the additional load of the system does not trigger
additional investments. The Company believes that it should have an incentive to help drive increased
adoption thorough the deployment of an appropriately sized program. The Company does not believe
that it should bear a higher risk of cost recovery for a new program like Charging Forward.
Furthermore, the costs for Charging Forward are relatively straightforward (primarily rebates where
the amounts per rebate have already being provided by the Company), thereby minimizing the risk of
Staff identifying material amounts of imprudent expenditures. Therefore, the Company proposes that
the net regulatory asset and the related amortization expense be reflected in the projected test period,
as proposed by the Company. The Company can provide Staff with a reconciliation of the actual
costs incurred to the amounts included in the revenue requirement as part of Staff’s audit in the next
rate case. Any additional costs incurred after the projected period should remain on DTE Electric’s

77

 balance sheet for recovery in the next rate case (7T 3349-50). The Company believes this is a
reasonable and fair proposal that should be adopted by the Commission.
3. Staff’s proposed regulatory asset treatment for O&M costs should be
rejected and O&M should be recovered as base O&M.
The PFD states: “DTE Electric agrees with Staff’s position to give Charging Forward O&M
expense regulatory asset treatment with amortization over five years” (PFD, p 211). To the contrary,
the Company proposed that O&M expenses (primarily customer outreach and program management
within marketing) should not be deferred, but instead be recovered as base O&M (See PFD, p211).
DTE Electric maintains its position, which the PFD apparently just misunderstood. The use of a
projected test period also plainly allows the recovery of costs to be incurred in the future. The
Company is expecting to begin the process of hiring new employees to help support the deployment
of the Program, and the lack of certainty on cost recovery could delay the implementation of this
aspect of the program. The Company has already provided, as part of the record on this case, the
specific O&M costs and the purpose for those costs. No party has disputed the need for the activities
associated with the O&M recovery. The Company can (as with the regulatory asset costs) provide
Staff with a reconciliation of the actual costs incurred to the amounts included in the revenue
requirement as part of Staff’s audit in the next rate case. Any additional costs incurred after the
projected test period should remain on DTE Electric’s balance sheet for recovery in the Company’s
next rate case. (7T 3349-50).
4. Additional pilot elements should be rejected, so there is no need to
increase the Charging Forward budget; however, any increase in
program cost must have a corresponding cost recovery.
The complete implementation of Charging Forward as proposed by the Company is
expected to cost approximately $13 million, including O&M, through the end of 2021 (8T 3579;
Exhibit A-12, Schedule B5.9). Staff proposed a $6 million increase in the Company’s requested
78

 funding, for a total of $19 million to cover expanded piloting (Staff Initial Brief, p 103)41. The PFD
agreed, stating:
As discussed above, this PFD recommends that the Charging Forward program be
expanded in scope in several significant ways. For example, it is anticipated that an
expanded school bus pilot will add cost, the amount yet to be determined. It is
possible that removal of rebate caps could also add costs. Additionally, to establish a
minimum network of corridor chargers, DTE Electric may need more than the 32
DCFC that it proposes. Also, DTE Electric indicates that it will be rolling in the costs
of its delayed 2018 EV pilots. And, finally, DTE Electric may find that it has
underestimated the human resources it will need committed to the program and the
large undertaking it represents. In sum, there is sufficient evidentiary support to
conclude additional funding will likely be needed to make Charging Forward the
success all parties to this case hope for and the Michigan citizenry needs.. [PFD, pp
209-210.]
The Company believes it is premature to increase funding and prefers to ensure it is on target
to implement a successful program before it proposes increases in scope and budget to Charging
Forward. The structure and budget for the Charging Forward program were carefully planned and
the Company has not assessed the requirements related to the PFD’s additional recommendations
(plus other pilots and suggestions by Staff and other parties).42 As such, the Company does not have
any basis to determine whether the incremental $6 million in budget is adequate or not. The
Company does not understand what specific objectives are going to be answered by the other
proposed pilots that cannot be answered by its own Charging Forward program (or learnings to be
gleaned from programs across the country).
With respect to the school bus pilot, the PFD stated:
The Staff’s recommendation is well taken. Charging Forward is, in large part, a
collection of pilot programs designed to inform DTE Electric and the Commission
about, among other things, EV consumer behavior, EV technical issues, and the
costs and benefits related to the electrification of Michigan’s transportation sector.
School buses are certainly an important part of that sector and potentially represent
a storage resource to be integrated into the grid. Recognizing that significant
41

However, $13 million plus $6 million totals $19 million rather than $18 million.

42

The Company assumes that other parties will file Exceptions advocating additional program changes.
79

 additional costs are likely associated with Staff’s expanded School Bus Pilot
program, it is, none-the-less very important that this option be explored. In
addition, it is equally important that the financial risks associated with piloting the
new technologies involved not fall on our schools. Therefore, it is recommended
that the commission adopt Staff’s proposal for an expanded Scholl Bus Pilot
program. [PFD, pp 183-84.]
In a footnote, the PFD added:
While DTE Electric has great leeway in formulating a School Bus Pilot Program,
the Commission envisions DTE Electric providing significant financial and
technical support to the participating schools to ensure that schools, who are
essentially serving as guinea pigs in a larger EV experiment, are held financially
harmless. [PFD, p 184, n 444.]
DTE Electric agrees that a school bus pilot is important – that is why the Company
proposed one. The Company also appreciates the intent behind the PFD’s recommendation;
however, the PFD’s recommendation is premature. Overall the Company supports the proposal to
incorporate additional pilot elements into the school bus category, but the Company’s initial objective
will be to find school districts that are willing to add electric buses to their fleets. Once the school
district(s) are identified, the Company will work collaboratively to determine potential pilot scope
additions and evaluate the related costs and benefits within the available program funding. In
addition, the Company will work with the school district to identify sources of funding other than
DTE Electric. Therefore, the Company believes it is premature to request additional expenditures and
Charging Forward activity related to school bus electrification (8T 3615).
In a broader sense, for the different pilot proposals that Staff and other parties have
suggested, the Company has already provided insights into how those elements can be included in
the Program as currently designed and proposed. 43 The Company is concerned that by adding a

The PFD recommended that the Commission take no action on Staff’s recommendation that the
Commission approve an 80 Amp charging pilot (PFD, pp 185-86). The Company supports 80 Amp charging, but does
not believe that an additional piloting element is necessary to properly promote the concept. The Company will educate
customers on this available technology as part of its site host acquisition strategy. Any site host that requests this new
43

80

 significant focus on pilots, the benefits to all of DTE Electric’s customers will be reduced. The
Commission’s recent EV decision in Consumers Energy’s rate case further indicated that “EV
adoption is in its infancy in Michigan, but all indicators point to continued expansion. This expansion
may result in increased load, but it may also result in more efficient use of excess generation and
distribution capacity during off-peak hours to the benefit of all customers, as well as provide new
modes of storage. None of this will materialize until EV chargers become more prevalent and
accessible” (January 9, 2019 Order in Case No. U-20134, p 8). DTE Electric agrees that the key
element at this stage of development is to increase the prevalence and accessibility of chargers which
is the focus of Charging Forward, and not on a broad and all-encompassing view on all the potential
pilots that could be pursued. Finally, and based on its analysis of lessons learned from the initial
stages of Charging Forward, market developments and learnings from research efforts such as DOE’s
US Drive – of which DTE is a member-, the Company might propose changes in scope and funding
in future rate cases that might include new and additional piloting elements (8T 3613).
That said, if the Commission does expand the scope of the Charging Forward program as the
PFD recommends (or otherwise), then the Company is entitled to cost recovery. Rates for utility
service are based on the estimated costs of providing that service, plus a reasonable return on the
utility’s investment. 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

technology will be able to receive it when it meets the connectivity and data sharing requirements of Charging Forward
(8T 3615).
The PFD also declined to recommend Staff’s “future-proofing” proposal, noting that “in light of rapidly evolving EV
technologies, it is difficult to determine what future proofing would entail” (PFD, p 188). To the extent “future-proofing”
as defined by Staff is possible and reasonable, then the Company will do so. When the site host expresses interest in
upgrading the equipment to higher-powered charging in the future (e.g., with Electrify America and Tesla), the Company
will factor this into the make-ready infrastructure requirements. However, the Company does not agree that it is universally
reasonable nor even possible to “future proof” every aspect of an emerging technology 8T 3615-16. See also DTE Electric
Reply Brief, pp 142-43).

81

 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. If the
Commission were to order additional funding for Charging Forward expansion (or anything else),
then that funding must be recovered though a corresponding rate increase. 44 45
5. The Company has already addressed the request to “file a rate that
addresses the issue of demand charges” by offering its D3 General
Services rate.
The PFD recommended a demand charge holiday, stating:
DTE Electric’s position on this issue is unpersuasive. As established by the record,
during the initial stages of EV infrastructure development, demand charges pose a
significant and unnecessary economic impediment to the successful deployment
of publicly available DCDF charging stations. Further, the incongruity of DTE
Electric’s proposed D1.9 Experimental Electric Vehicle Rate, which has a demand
charge, and DTE Electric’s D3 General Service Rate, which does not have demand
charge, is hard to reconcile. Therefore, based on the record presented, it is
DTE Electric has constitutional protections against “takings” and confiscatory rates under the Fifth Amendment to
the US Constitution, which is applicable to the states through the Fourteenth Amendment. Similarly, 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. 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).
44

45

As a matter of fundamental ratemaking law, DTE Electric is entitled to a commensurate return of and on its
investment in providing utility service. 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, 76970; 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).

82

 recommended that the Commission adopt Staff’s proposal for a demand charge
holiday, for EV site hosts, to be offered by DTE Electric for up to five years. [PFD,
p 198.]
The ALJ misunderstands DTE Electric’s rate offerings. First, Rate Schedule D1.9 (available
to both residential and commercial customers) does not have an associated demand as part of its rate
structure (See Exhibit A-16, Schedule F10). Second, the Company’s commercial customers can also
choose additional rate products without demand rates: the D3 General Service Rate, and D3.3
Interruptible General Service Rate. The D3 General Service Rate is a commercial rate without
demand charges (as Staff similarly noted at Initial Brief, p 130). However, it is up to the customer to
decide what is the best rate structure option (8T 3624). Thus, the Company believes that the issue of
a demand charge for site hosts in DTE Electric’s service territory is moot and does not need to be
addressed with any additional requirement. Finally, even if it were true that the Company‘s
commercial rates only had options with demand rates (which it does not), adopting a “demand rate
holiday” disregards the requirement for cost based ratemaking set forth in MCL 460.11 which
provides, “[e]xcept as otherwise provided in this subsection, the commission shall ensure the
establishment of electric rates equal to the cost of providing service to each customer class”.
6. The PFD’s DCFC charging recommendation should be clarified.
The PFD “recommends that the Commission direct DTE Electric to engage in the same
consumer protection measures as were approved in the Consumer’s settlement” in Case No. U-20134
(PFD, p 201). The Company agrees with the concept of reasonableness for DCFC charging and that
it should work to ensure that the cost per charge is within market rates. The Company’s reading of
the Consumers’ settlement is consistent with this viewpoint (See, for example, January 9, 2019 Order
Approving Settlement Agreement in Case No. U-20134, Attachment A: “Educate site hosts about
applicable electricity rates and EV benefits, while site hosts retain ability to set pricing that reflects
on-site needs”).
83

 The Company takes exception seeking clarity because the PFD further stated that
“MEC/NRDC/SC provides the most reasonable solution” (PFD, p 201), and the Company disagrees
with MEC/NRDC/SC’s suggestion that the Commission should establish a specific standard.46 The
Company has indicated that through a collaborative approach with site hosts it will be able to
positively influence the reasonable delivery of EV charging services. The Company will educate site
hosts on acceptable pricing structures and track the price site hosts “charge for charging” and will aim
to identify any outliers and find ways to collaborate to address the situation (8T 3624). At this early
stage in market development, the Company does not see the need to begin to impose specific
standards, especially as there is no evidence that supports their imposition. Through its annual reports,
the Company will provide updates to the Commission and to the extent it feels there is a need to
impose a standard, it will propose one at that time.
F.

Infrastructure Recovery Mechanism (“IRM”).

DTE Electric proposes an Infrastructure Recovery Mechanism (“IRM”) to recover the
incremental revenue requirement associated with certain distribution, fossil generation and nuclear
generation capital expenditures through 2022. The PFD instead agreed with the parties opposing
the IRM, stating that “the IRM, as proposed by the company, is too expensive, too expansive, and
allows the company too much discretion in spending before any review of reasonableness and
prudence occurs . . . [and] the IRM could be rejected on policy grounds alone” (PFD, pp 217-18).
The Intervenor positions do not acknowledge the extensive prior proceedings establishing
and expanding DTE Gas’s very similar IRM, which began when the Commission approved DTE

MEC/NRDC/SC suggested that “a reasonable standard for this purpose would be to limit the total cost per charging
session at a rebated DCFC to roughly the cost of gasoline providing equivalent mileage” (Initial Brief, p 87, quoting Mr.
Jester at 6T 2217-18).
46

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 Gas’s recovery of 2013-17 IRM capital investments for its the Meter Move Out Program
(“MMO”),47 the Main Renewal Program (“MRP”), 48 incremental MRP, and Pipeline Integrity
(“PI”) investments. (April 16, 2016 Order in Case No. U-16999). The Court of Appeals affirmed
each of these investment mechanisms. 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) (2014 WL 7003882). The Commission 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 Commission authorized spending of
$102.1 million in 2016, and $127.6 million in 2017 through 2021 on IRM programs, as well as
flexibility in spending among the programs (December 9, 2016 Order in Case No. U-17999, pp
52, 67). Most recently, the Commission approved additional capital expenditures, including
funding to expand and accelerate infrastructure replacement (September 13, 2018 Order in Case
No. U-18999, pp 21, 26, 32-33).
The Commission has also approved various cost recovery trackers, and the Court of
Appeals has consistently affirmed them. In addition to DTE Gas’s IRM, see, for example, In re
Application of Detroit Edison Company, 296 Mich App 101, 114; 817 NW2d 630 (2012), where
the Court of Appeals affirmed four cost trackers for DTE Electric in Case No. U-15768 (an
Uncollectible Expense Tracking Mechanism (“UETM”), a storm and non-storm restoration
normalization tracker, line clearance expenses tracker, and Choice Incentive Mechanism
(“CIM”)). The Court explained in part that “our case law confirms that the PSC correctly approved

47

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.
48

The Commission approved the MRP in its September 13, 2011 Order in Case No. U-16407.

85

 Detroit Edison’s use of cost tracking mechanisms through which future rates are adjusted to take
account of actual past expenses.”
DTE Electric’s proposed IRM is also appropriate because the Company’s need for rate
increases has been, and is expected to continue to be, largely driven by its need to replace critical
infrastructure that is required to safely and reliably serve its customers. The Company believes
that the proposed IRM may enable it to defer filing for a rate increase until sometime in 2022 for
new base rates in 2023 (3T 75).49 The proposed IRM should therefore reduce resources and costs
for all parties that typically participate in Company rate cases. The systematic implementation of
IRM surcharges should also benefit customers by allowing for more orderly and potentially smaller
rate cases than what would occur if the Company continued to file annual rate cases. The IRM
would support critical infrastructure improvements that will benefit customers for years to come
and should also facilitate the more efficient deployment of capital by providing a level of certainty
for cost recovery (3T 74-75).
The PFD’s criticisms of the IRM are also unsupported by the record, which reflects that
the Company seeks IRM treatment for capital expenditures that are above and beyond replacement
capital (normal capital expenditures that are effectively replacing capital that is being depreciated).
The proposed IRM would cover these capital expenditures beginning May 1, 2020 (the first day

49

DTE Electric cannot guarantee that it will be able to defer filing a rate case until 2022 since the Company faces
many cost pressures and uncertainties beyond the capital expenditures that would be covered by the IRM. These
include incremental capital expenditures that are not included in the IRM, O&M general inflation or other O&M cost
increases, reductions in sales, and any other unforeseen external events, such as new energy legislation. Using a
relatively predictable cost increase of inflation for example, the Company’s proposed O&M for the projected test year
is $1.3 billion. Since O&M is not included in the IRM, even if the Company experiences general inflation of just 2%
per year, it will have to absorb about $26 million of increased costs annually (3T 75-77).
Although there are several cost and revenue areas, beyond the capital expenditures covered by the proposed IRM, that
could make it difficult for the Company to defer filing a rate case until 2022, the Company believes that with the proper
IRM in place, it may be able to defer filing for a rate increase until sometime in 2022 for new base rates in 2023 (3T
105).

86

 after the projected test year) through December 31, 2022. Like DTE Gas’s IRM (see, for example,
December 9, 2016 Order in Case No. U-17999, pp 47-48), capital expenditures used to calculate
the IRM surcharge are made on a calendar year basis. The initial IRM surcharge would be
implemented January 1, 2020, and cover capital expenditures from May 1, 2020 through December
31, 2020. Similarly, incremental IRM surcharges would be implemented January 1, 2021 and 2022
for the IRM capital expenditures for the 2021 and 2022 calendar years (3T 77-78; 5T 1515).
Exhibit A-30, Schedule T1 summarizes the capital expenditures included in the IRM (7T 3337).
Mr. Bruzzano supported Distribution Operations (“DO”) capital expenditures that the
Company proposes to include in the IRM (4T 809; Exhibit A-30, Schedule T2). He explained that
he selected DO programs and projects to include in the IRM because they are either required 50 or
have a high degree of certainty in being executed due to their priority in terms of their ability to
reduce risk, improve reliability, and manage costs (4T 801-803). The Company proposes to include
Strategic Capital projects from the Five-Year Plan as shown on Table 22 at 4T 804 and further
described in Exhibit A-30, Schedule T2.1, which contains a description of the drivers, scope, and
customer benefits for the projects and programs. Table 23 on 4T 806 provides some additional,
directional information on the scope of some of the programs. The Company will also provide
additional information (in the fall annual plan review with Staff, further discussed below) as
detailed engineering, design and procurement activities are completed (4T 803-806, 811).

50

IRM Base capital expenditures include emergent replacements that are necessary to restore service to customers
and return equipment to proper working condition, as well as certain types of new business connections, relocations,
and equipment purchases that directly benefit customers and for which there is a high degree of confidence in the
conservatively-set spending level. Exhibit A-30, Schedule T2, page 1, lines 2-4 shows capital expenditures for
emergent replacements, with the details on page 2. Exhibit A-30, Schedule T2, page 1, line 5 shows capital
expenditures for Small Growth Load Projects, Customer Connections, Small Relocations, and Electric System
Equipment purchases, with the details on page 3 (4T 801-03, 809-10). The same format continues through the exhibit
(4T 810-11).
87

 Mr. Paul supported Fossil Generation capital expenditures that the Company proposes to
include in the IRM for planned and scheduled work needed to ensure continued safe and reliable
operations at the Company’s Tier 1 generating units (Monroe, Belle River, and Greenwood) and
peaker units, along with capital expenditures related to the construction of the 1,100 combined
cycle gas turbine (“CCGT”) plant that was approved in Case No. U-18419 (4T 587; Exhibit A-30,
Schedule T3). Fossil generation proposes that a portion of expenditures relating to the following
four categories be recovered through the IRM: (1) planned outage work on Tier 1 steam generating
units (explained and supported at 4T 588 and shown on line 1 of Exhibit A-30, Schedule T3); (2)
scheduled capital equipment replacements on Tier 1 steam generating units (explained and
supported at 4T 589 and shown on line 2 of Exhibit A-30, Schedule T3); (3) planned outage work
on large gas-fired peakers (explained and supported at 4T 589-90 and shown on line 3 of Exhibit
A-30, Schedule T3); and (4) costs to build the new CCGT plant (explained and supported at 4T
590 and shown on line 4 of Exhibit A-30, Schedule T30).
Mr. Davis supported Nuclear Generation capital expenditures that the Company proposes
to include in the IRM (5T 1296; Exhibit A-30, Schedule T4). Including Nuclear Generation in the
IRM will allow recovery of capital expenditures required to maintain Fermi 2’s current level of
safe and reliable operations beyond the projected test year. Nuclear generation proposes to include
two programs in the IRM: (1) Routine and Small Projects, and (2) Non-Routine and Large Projects.
These two consistently-used programs best align how Nuclear Generation approaches its work,
especially in the context of a refueling outage (5T 1297-98). Non-Routine and Large Projects are
associated with large capital projects that Nuclear Generation expects to implement only once
through Fermi 2’s current operating license expiration in 2045 (5T 1298). Mr. Davis further
discussed the (1) fire header restoration and (2) Emergency Diesel Generator (“EDG”) control

88

 relay projects as examples (5T 1298-1300). Routine and Small Projects are projects that Nuclear
Generation expects to implement two or more times throughout Fermi 2’s remaining life. Many of
these projects are implemented every operating cycle. Mr. Davis further discussed the (1) control
rod blades and (2) snubbers projects as examples (5T 1301-1302).
Exhibit A-30, Schedule T5, page 1 identifies the annual incremental revenue requirements
for 2020 through 2022 relating to DO capital costs (5T 1514-15). Similarly, Exhibit A-30,
Schedule T6, page 1 identifies the annual incremental revenue requirements relating to Generation
capital costs discussed by Mr. Paul and Mr. Davis (5T 1516), and Exhibit A-30, Schedule T7, page
1 identifies the annual revenue requirements relating to the new CCGT plant (5T 1517-18). Mr.
Slater also explained how he calculated amounts for the six months ending April 20, 2020 in these
categories for inclusion in the IRM (5T 1515, 1517-18).
DTE Electric proposes some flexibility in spending, but does not seek to move any capital
between the three broad business units of distribution, generation, and CCGT plant. Within those
business units, however, the Company proposes to be able to move up to 20% of the capital dollars
to or from any discrete category of work as defined on Exhibit A-30, Schedules T2, T3, and T4
(3T 81; 4T 806-807).51
The cost of service methodology relative to IRM rate base will follow the same cost of
service methodology as other similar capital that is reflected in base rates (3T 79-80). Exhibit A-

51

For example, flexibility is needed regarding DO spending because even though the Company has a clear
prioritization of projects and programs that it intends to execute, there is inherent complexity and uncertainty that can
affect actual timing and spending due to delays in obtaining easements and permits, unplanned equipment failures or
adverse weather. The Company similarly needs the ability to switch the order of projects within each category if
required by operational or other circumstances (4T 806-807).
Nuclear Generation similarly needs flexibility because nuclear safety is the overriding priority and changes in plant
conditions and regulatory requirements necessitate some funding reallocation. For example, Fermi 2 must remain in
compliance with all NRC regulations. Following the 2011 events at the Fukushima Dai-ichi nuclear plant, the NRC
issued new regulations necessitating billions in industry capital expenditures and U.S. nuclear plants had only four
years to comply (5T 1303).
89

 30, Schedule T8 reflects the allocation of the production-related IRM revenue requirement to the
various rate classes. Exhibit A-30, Schedule T9 reflects the allocation of the distribution-related
revenue requirement to the various voltages (7T 3225-26). Any revised IRM revenue requirements
resulting from an IRM reconciliation (discussed further below) would be allocated to the various
rate and voltage classes in the same way (7T 3226-27).
The Company’s proposed IRM power supply and delivery surcharges are designed to
collect the above-described revenue requirements by class (5T 1221, 1240-41; Exhibit A-30,
Schedule T10). The Company proposes a per kWh charge for residential and small commercial
customers, and an IRM demand charge for large commercial and industrial customers on rate
schedules with a demand component (3T 80; 5T 1241). The Company proposes to record revenue
on an accrual basis consistent with its accounting for other customer revenues. The capital
expenditures will be recorded to unique accounting codes to isolate the costs (7T 3338).
The Company proposes to reconcile the IRM surcharge such that if the Company under
spends the capital reflected in the IRM surcharge, it will refund the IRM revenue associated with
that under spending. However, there would not be any additional surcharge if the Company over
spends beyond the level approved in the IRM. The Company also proposes to reconcile the revenue
collected through the IRM so that if the Company over or under recovers what it should recover
under the IRM, then the Company will refund or surcharge that difference at the conclusion of the
IRM. In no event, however, would the Company be allowed to recover more than the maximum
amount of revenue defined by the IRM. Thus, if the Company under spends capital, then the total
amount of revenue that the Company can recover will be reduced based on that under spend. In
summary, there would be an asymmetrical reconciliation for capital spending (refund
underspending; no recovery for overspending), and a symmetrical reconciliation for revenue

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 recovery up to the maximum allowed revenue based on the operation of the IRM (3T 78; 5T 1242,
1520). Mr. Slater also prepared an illustrative example (5T 1520-21; Exhibit A-30, Schedule
T13).52
The Company further proposes that any over or under recovery be deferred as a regulatory
liability or regulatory asset until the next IRM reconciliation. Once the IRM is terminated, there
would be one final reconciliation that would include all net amounts over the period (plus any
applicable interest) and result in a refund or surcharge. This is essentially the same over or under
recovery reconciliation methodology that is already in use for the Company’s Transition
Reconciliation Mechanism (“TRM”) for the transition of Detroit Public Lighting Department
(“PLD”) customers to DTE Electric service. Short-term interest should be accrued on any over or
under recovery. The Company proposes to file the initial reconciliation by April 30, 2021 for
capital expenditures from May 1, 2020 through December 31, 2020. Similar reconciliations would
be filed by April 30 of the subsequent years for 2021 and 2022. The IRM surcharge would expire
when new base rates are set by Commission order in the Company’s next general rate case (3T 79;
5T 1242; 7T 3338).
Finally, DTE Electric proposes to report on IRM work to ensure that that capital approved
in the IRM is not only spent, but also spent efficiently and effectively. The Company specifically
proposes to (1) meet with the Staff each fall to review expected IRM expenditures and the scope
of IRM work to be accomplished for the upcoming IRM year, (2) provide Staff with a summary

ABATE suggested that the proposed IRM is an unlawful “automatic adjustment clause” under MCL 460.6a(4).
(ABATE Initial Brief, pp 43-44, quoting the statute in relevant part: “The commission shall not authorize or approve
adjustment clauses that operate without notice and an opportunity for a full and complete hearing, and all such clauses
are abolished”). The Commission and Court of Appeals rejected this same argument (the statutory language was then
in MCL 460.6a(2)) in establishing and affirming DTE Gas’s IRM. In re Application of Michigan Consolidated Gas
Company to increase rates, supra, 2014 WL 7003882 at *2 and *4-5 (explaining that the “full and complete hearing”
requirement is satisfied by limited annual reconciliation proceedings).
52

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 of actual work completed (Program Metrics) 53 in each reconciliation, (3) report performance
indicators to the Staff annually, 54 and (4) meet with the Staff throughout the year to review progress
relative to the plan (3T 80-81; 4T 590-91, 807-808; 5T 1300, 1302, 1304-05). The Company also
proposes to file a report with the Commission regarding the expenditures and metrics for the period
May to December 2020 by April 30, 2021. Annual reports for 2021 and 2022 would similarly be
filed by April 30 of the following year (7T 3337-38).
In summary, IRMs are well established in law and regulatory practice, and the Company’s
proposed IRM is well designed and fully supported. Therefore, it should be approved along with
the Company’s proposed IRM power supply and delivery surcharges included in Exhibit A-30,
Schedule T10.
G.

The nuclear surcharge should be increased, but the PDF’s
recommendation for an updated decommissioning cost study should be
rejected.

DTE Electric proposed to increase the nuclear surcharge due to increased Site Security and
Radiation Protection (“SSRP”) costs and low level radioactive waste (“LLRW”) disposal funding,

53

DO Program Metrics are shown on Table 24 at 4T 808.

For Fossil Generation, Mr. Paul suggested specific program metrics relating to each of the four categories of capital
spending discussed above and shown on Exhibit A-30, Schedule T3, lines 1-4 (4T 591-92). For Nuclear Generation,
Mr. Davis proposed the “number of projects complete” as the metric for Non-Routine and Large Projects (5T 1300),
and “number of units complete” as the metric for Routine and Small Projects (5T 1302).
54

Regarding DO, the Company will provide the Staff with a yearly report on the average age and age risk for key
asset classes (breakers, switchgear, etc.) along with the risk assessments for priority asset classes, so the extent to
which aging and at-risk equipment is being replaced can be evaluated. The Company will also report the operational
performance indicators listed in Table 25 at 4T 809 (4T 808-809). Fossil Generation will provide a report to the staff
on unplanned unit outages that have occurred due to failures on components replaced within IRM projects completed
in the preceding year (4T 592). For Nuclear Generation, Mr. Davis proposed a performance indicator called “Total
Number of Unplanned Power Losses per 7,000 Critical Hours” (for brevity, “Unplanned Power Change Events”). This
is an industry metric that measures organizational effectiveness by counting the number of unplanned automatic and
manual scrams (reactor shutdowns) and the number of unplanned power changes in reactor power greater than 20%
of full power per 7,000 hours of operation (5T 1304-1305).

92

 and lower forecasted jurisdictional sales (5T 1227).55 Staff calculated the proposed nuclear
surcharge in the same manner as the Company did, and agreed with the Company’s proposed
nuclear surcharge increase (8T 4286). ABATE proposed that the Commission should instead set
the nuclear surcharge revenue requirement at $27.482 million (a $10.8 million reduction from DTE
Electric’s proposal) by eliminating LLRW funding ($6 million) and the Nuclear Decommissioning
funding ($2.9 million) and reducing SSRP funding ($1.9 million). The PFD stated:
This PFD finds that DTE Electric’s nuclear surcharge should be approved as
proposed, subject to a requirement that the company provide an updated
decommissioning study in its next rate case, or in a stand-alone proceeding as has
been done in the past. DTE Electric correctly pointed out that the amounts in the
nuclear trust fund cannot be reallocated without NRC approval. However, ABATE
presented compelling evidence that the assumptions underlying the calculation of
the amount needed to decommission Fermi 2 may no longer be valid and should
be revisited. DTE Electric did not dispute that the last decommissioning study was
performed years ago, nor did it rebut Mr. Andrew’s evidence about
decommissioning amounts in trust funds for other nuclear plants that are roughly
50% of the amount DTE Electric has in its trust fund on a cost per kW basis. [PFD,
p 221. Footnote omitted.]
The PFD approved DTE Electric’s nuclear surcharge proposal; however, it was improper
to recommend that the approval be “subject to a requirement” for the future. Detroit Edison Co v
Public Service Comm, 264 Mich App 462, 467; 691 NW2d 61 (2005) (MPSC could not “approve”
a utility’s recovery of costs and later attempt to eradicate that approval based on subsequent
events).
DTE Electric also disagrees that an updated decommissioning study is either necessary or
appropriate. Company witness Mr. Davis explained that Fermi 2 is licensed to operate through

55

The nuclear surcharge recovers costs associated with nuclear site security and radiation protection, the funding for
nuclear decommissioning, and LLRW disposal. These activities are required for Fermi 2’s safe and secure operation.
The Company requests a nuclear surcharge increase primarily for increased LLRW disposal funding (a $2 million
increase from $4 million to $6 million), which is reasonable and prudent to minimize the accumulation of LLRW at
Fermi 2, and dispose of LLRW in a timely and proper manner. There are also inflationary increases to site security
and radiation protection costs. The resulting nuclear surcharge is $38.3 million for the projected test period (5T 129396, 1309; Exhibit A-20, Schedule J1, page 1, line 6, column (b); Exhibit A-16, Schedule F6).
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 2045 (5T 1270). The Fermi 2 decommissioning cost estimate complies with NRC regulations, and
satisfies its intended purpose to provide reasonable assurance knowing that more exact estimates
are timed closer to actual decommissioning. It is also reasonable and complete considering what
is presently known. The cost estimate is consistent with the regulatory guidance, and the
assumptions underlying that cost estimate are well documented and sound. The assumptions
encompass radiological decommissioning of the plant, as well as post-shutdown fuel stewardship
and greenfielding costs. The cost estimate also accounts for taxes, insurance, NRC fees and
hazardous waste fees (5T 1320-21).
The Fermi 2 decommissioning cost estimate remains reasonable and prudent, and has more
than a decade of Commission oversight supporting its central assumptions. The PFD’s proposal
would require DTE Electric to divert time and resources and unnecessarily incur costs to produce
a Fermi 2 decommissioning cost estimate that will still be many years in advance of the projected
cessation of Fermi 2’s operations (5T 1326-27).
The PFD’s suggestion that DTE Electric may be over-recovering decommissioning funds
also disregards DTE Electric’s prior requests to lower the Nuclear Decommissioning funding when
reasonable analysis concluded that it was prudent to do so, with resulting decreases of
approximately $30 million in annual requirements since 2011 (5T 1319-22).56 Moreover, the
nuclear utility industry is one of the most highly monitored and regulated industries in the country.
All aspects of site security and radiation protection are scrutinized on a regular basis. DTE Electric
also provides cost and other regulatory information to the Commission, including the 2018

56

As requested by the Company, the Commission lowered the Nuclear Decommissioning funding from approximately
$33 million to approximately $13 million in Case No. U-16472, and from there to the current $2.9 million in Case No.
U-17767. The Commission re-authorized the $2.9 million in Case Nos. U-18014 and U-18255 (5T 1322).
94

 triennial report (Exhibit AB-7).57 DTE Electric should not be burdened with yet another
requirement that would provide no benefit (5T 1327-28).
Therefore, DTE Electric’s proposed nuclear surcharge should be approved, but the PFD’s
further recommendation to require the Company to provide an updated decommissioning study
should be rejected.
VI.

THE COMMISSION SHOULD ADOPT DTE ELECTRIC’S COST
ALLOCATION AND RATE DESIGN PROPOSALS.
A.

There is no valid basis to revisit production cost allocation.

MEC/NRDC/SC witness Mr. Jester asserted that the Company allocates too much of its
production costs on contribution to peak (4CP) and too little on energy, and proposed that the
Commission should require that costs allocated to capacity (production) be limited to the Cost of
New Entry (“CONE”) adjusted for planning reserve margin with the remainder allocated to energy
(6T 2187-92). Mr. Lacey responded that Mr. Jester’s proposal boils down to a disagreement with
the 4CP 75-0-25 method for production allocation that the Commission adopted in Case No. U17689 (in accordance with 2014 PA 169) and has continuously applied in subsequent DTE Electric
rate cases, Case Nos. U-17767, U-18014, and U-18255. There is no basis to now reconsider or
deviate from that methodology (7T 3234).
MEC/NRDC/SC acknowledged: “Certainly no one could fault Mr. Lacey for allocating
production costs in his COSS consistent with recent precedent” (MEC/NRDC/SC Initial Brief, p
142). Regardless, they asserted that the Commission should modify production cost allocation or
revisit the issue in the next rate case (Id, pp 138-44). The PFD agreed, recommending “that

57

DTE Electric submits a report to the Commission every three years, the latest of which was January 31, 2018 (5T
1323).
95

 production cost allocation should be revisited in either the company’s next rate case, or in a special
purpose proceeding as was done in Case No. U-17689” (PFD, p 228).
DTE Electric disagrees. In addition to Mr. Lacey’s testimony, noted above, there is no valid
reason for the Commission to contemplate revisiting the issue. Although res judicata and collateral
estoppel do not apply “in a strict sense” to the Commission’s ratemaking decisions, “issues fully
decided in earlier PSC proceedings need not be ‘completely relitigated’ in later proceedings unless
the party wishing to do so establishes by new evidence or a showing of changed circumstances
that the earlier result is unreasonable.” Application of Detroit Edison to Implement Opt-Out
Program, unpublished opinion per curiam of the Court of Appeals, issued February 19, 2015
(Docket Nos. 316728 and 316781), lv den 499 Mich 868 (2016), reh den 499 Mich 972 (2016).
(Opinion affirming AMI opt-out charges, p 8, citing Application of Consumers Energy Co, 291
Mich App 106, 122; 804 NW2d 574 (2010), which quoted Pennwalt Corp v Public Service Comm,
166 Mich App 1; 420 NW2d 156 (1988)).
More recently, in response to RCG argument that the opt-out charges should be reduced to
zero, the Court of Appeals explained:
In this appeal, [RCG] again argues that the opt-out charges should be eliminated.
[RCG] first contends that there was no evidence presented in the current proceeding
supporting the amount of the fees. The reason for this was simple: DTE was not
seeking to alter the opt-out fees, which had been set in Case No. U-17053. As the
MPSC has explained previously, there is no need for the MPSC to take new
evidence on an issue that has been decided previously, absent a showing that
circumstances have somehow changed. [Application of DTE Electric Company to
Increase Rates, unpublished opinion per curiam of the Court of Appeals, issued
October 25, 2018 (Docket No. 338378), reh den December 27, 2018, following In
re Consumers Energy Co App, 322 Mich App 480, 493-94; 913 NW2d 406 (2017)
and Pennwalt Corp, supra, 166 Mich App at 9.]
DTE Electric further objects to the extent that the PFD suggests that the Company has some
burden to present an initial case, or otherwise re-prove the status quo. In addition to the discussion

96

 above, see Kar v Hogan, 399 Mich 529, 539; 251 NW2d 77 (1976), where our Supreme Court
explained that “[t]he party alleging a fact to be true should suffer the consequences of a failure to
prove the truth of that allegation.” Moreover, there is a heightened evidentiary presentation
required for “any party proposing to revise the production cost allocation method in a future case”
(January 31, 2017 Order in Case No. U-18014, pp 100-101).
B.

DTE Electric’s proposed capacity charge revenue requirement should
be approved.

The November 21, 2017 Order in Case No. U-18248 (the Company’s capacity charge case)
approved the Company’s method,58 but adjusted for Gross Energy Sales net of fuel, and not the
Company’s recommended Net Energy Sales net of fuel costs. In Case No. U-18255, DTE Electric
maintained its position from Case No. U-18248, but did not oppose Staff’s suggestion to maintain
the status quo in that case only. The Commission agreed with DTE Electric and Staff that the
capacity charge had to be updated, and approved Staff’s proposal regarding gross energy sales net
of fuel costs (April 18, 2018 Order in Case No. U-18255, pp 62-63).
Here, Mr. Lacey calculated and explained the Company’s capacity revenue requirement,
which is reflected on Exhibit A-16, Schedule F1.5. The capacity revenue requirement includes all
production-related costs per Exhibit A-16, Schedule F1.1, except fuel, variable O&M and certain
purchase power costs. This is the same methodology that the Company supported in Case No.
U-18255. As indicated above, the Commission’s April 18, 2018 Order generally adopted this

“The Commission finds DTE Electric’s proposed method, which begins with total embedded production related
costs and subtracts the non-capacity related costs of fuel expense, variable O&M expense, and non-capacity related
purchased power expense to be a reasonable method under Section 6w(3)(a).” (November 21, 2017 Order in Case
No. U-18248, p 65).
58

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 approach, with the only differences being the amounts to be subtracted and the calculation of 2018
energy sales net of fuel on line 2 of Exhibit A-16, Schedule F1.5 (3T 71-72; 7T 3221-22).
As indicated above, the Commission’s April 18, 2018 Order in Case No. U-18255 reflected
a $584 million reduction for energy sales net of fuel, based on a calculation originally adopted in
Case No. U-18248. Here, Mr. Lacey used the $40.3 million calculation of energy sales net of fuel
supported by Mr. Arnold on Exhibit A-29, Schedule S3 (7T 3222).

59

Mr. Lacey also explained

line items in Exhibit A-16, Schedule F1.5, and supported the resulting $1,947 million total capacity
charge revenue requirement (7T 3222-25).
The PFD instead agreed with Staff, ABATE, Energy Michigan, and Kroger that the
Commission should maintain the capacity cost allocation method from Case Nos. U-18248 and
U-18255 (PFD, p 232). DTE Electric disagrees. As explained by Company Witnesses Arnold (3T
288-293) and Stanczak, (3T 70-73), the Company’s calculation of $40.3 million of energy sales
net of fuel is consistent with PA 341 Section 6w (3)(B) and results in Electric Choice customers
paying the same full embedded cost of DTE Electric’s electric generation fleet as bundled
customers. Thus, the Company’s position should be adopted.
The PFD further recommended adopting the Staff’s approach to recalculating and updating
the capacity charge, which appears to contemplate that the final order in this case would produce
a capacity charge incorporating updated costs from this case (PFD, p 233). The Company notes
that generally, any base rate or PSCR factor change will change the capacity charge rates. The

59

Mr. Arnold explained the capacity-related generation costs (PURPA power purchase agreements, PA 295
Company-owned renewable energy systems, PA 295 renewable energy contracts, and capacity purchases) included in
the Company’s PSCR factor as required by MCL 460.6w(3)(A) (3T 288-90; Exhibit A-29, Schedules S1 and S2). He
also explained the projected 2018 energy sales revenue net of projected fuel costs per MCL 460.6w(3)(B) (3T 29093; Exhibit A-29, Schedule S3). He concluded: “The total projected 2018 energy sales revenue of $89.7 million, net
of 449.2 million in fuel related costs and $0.2 million in Schedule 17 admin fees equates to $40.3 million energy sales
revenue net of fuel related costs as shown on Exhibit A-29, Schedule S3, line 32” (3T 293).

98

 Commission must also conduct a capacity charge review by December 1 of each year. MCL
460.6w(3). The Company proposes that the capacity charge rates established by the Commission
pursuant to the December 1 review become effective on January 1 of the following year. There are
costs and revenues in the capacity charge and the PSCR that are directly related. The PSCR
operates on a calendar year basis, so administrative efficiency would be achieved by reflecting
PSCR changes in the capacity charge on a calendar year basis and then reconciling them
contemporaneously for that same calendar year (3T 72-73).
In light of the above, DTE Electric requests that the Commission adopt the methodology
proposed by the Company for calculating and applying the Capacity Charge Revenue
Requirement.
C.

DTE Electric’s residential and commercial secondary monthly service
charges should be adopted.

The Company’s cost allocation resulted in customer-related costs by rate class of $45.53
for residential, and $178.88 for commercial secondary (7T 3221; Exhibit A-16, Schedule F1.4).60
Based on Mr. Lacey’s analysis of customer related costs, the Company could have proposed
moving to higher monthly service charges for both residential and commercial secondary
customers, but in the interest of gradualism, DTE Electric proposes to change the monthly service
charge to $9.00 per customer for residential rate schedules that are not for supplemental electric
service (D1, D1.2, D1.6, D1.8, and D2, but not D1.1, D1.7, D1.9 and D5), and to increase the

60

These customer-related costs were determined using all fixed distribution costs (demand plus customer), in
accordance with the National Association of Regulatory Utility Commissioners (“NARUC”) Electric Utility Cost
Allocation Manual (Exhibit A-39, Schedule CC-1), which classifies both distribution plant and equipment as demandrelated, customer-related, or a combination of those two (and not energy related). Demand-related costs are fixed
costs. Cost causation should match cost recovery as much as possible. Residential and small commercial rates do not
include a demand charge, so the customer charge must be used to collect the demand-related fixed costs. Therefore,
all fixed costs, demand and customer related, should be recovered through the fixed customer charge (7T 3219-21).
99

 monthly service charge to $15 per customer for commercial secondary rate schedules that are not
for supplemental electric service (D1.8, D3, D3.2, D3.3, D4, and R8 separately metered).
The PFD instead found that Staff’s recommendation to maintain the current charges should
be adopted and criticized DTE Electric for again presenting a cost-allocation methodology that the
Commission has not accepted (PFD, p 235). The Company maintains that its methodology is
appropriate and notes that much of the opposition was based on the faulty premise that there would
be a residential rate increase. However, if the service charge does not increase, then the variable
distribution rate must be higher than what is proposed so that the Company’s distribution rates will
recover the same amount of revenue. The Commission has previously recognized that such a fixedcharge increase “does not increase the residential class’ cost of service. Rather, it merely reflects
the fact that a flat customer charge, rather than an energy related charge, is a more appropriate way
of collecting the fixed costs associated with serving each residential customer at any usage level”
(8T 3869; June 10, 2008 Order in Case No. U-15245, p 74).
Most of the revenue collected from residential customers would continue to come from
rates dependent on usage. For a 600 kWh per month D1 customer, the Company’s proposal to
increase the service charge to $9.00 would increase the proportion of the bill due to fixed charges
from 8% to 9%, so 91% of the bill would still be due to variable charges. For a 300 kWh per
month D1 customer, the Company’s proposal to increase the service charge to $9.00 would
increase the proportion of the bill due to fixed charges from 15% to 17%, so 83% of the bill would
still be due to variable charges. Thus, for the examples provided, Exhibit A-16, Schedule F7 shows
that a D1 customer’s bill is still significantly driven by variable versus fixed charges (8T 387071). Exhibit A-16, Schedule F7 also shows that the proportion of customers’ bills due to fixed
costs with the proposed $9.00 charge are very close to the proportions that existed when the service

100

 charge was initially established at $6.00 in Case No. U-15244 (8T 3870-71). In addition, Exhibit
A-16, Schedule F3, page 2 shows revenue from kWh-based charges account for over 90% of the
total D1 revenue, under both present and proposed rates (8T 3871).
Similarly, most of the revenue collected from commercial secondary customers would
continue to come from rates dependent on usage. For a 1,600 kWh per month customer, the
Company’s proposal to increase the service charge from $11.25 to $15.00 would increase the
proportion of the bill due to fixed charges from 5.6% to 7.2%, so over 90% of the bill would still
be due to variable charges. For a 3,200 kWh per month customer, the Company’s proposal to
increase the service charge from $11.25 to $15.00 would increase the proportion of the bill due to
fixed charges from 2.9% to 3.7%, so over 95% of the bill would still be due to variable charges.
The effect on larger customers would be even smaller. The proposed $15.00 service charge would
not significantly affect energy efficiency decisions because customer bills would remain driven by
variable charges (5T 1430-32).
To address concerns with low-income customers, the Company has also proposed to
increase the Residential Income Assistance (“RIA”) Service Provision of the D1 tariff. The RIA
provision currently provides a $7.50 per month credit for qualifying customers, which offsets the
current $7.50 monthly service charge. DTE Electric proposes to increase the credit to $9.00 per
customer per month, so that the credit would continue to fully offset the monthly service charge
(8T 3868-69). The Company also proposes to increase the Residential Senior Service Provision of
the D1 tariff. This provision currently provides a $3.75 per month credit for qualifying customers,
which offsets half of the current $7.50 monthly service charge. DTE Electric proposes to increase
the credit to $4.50 per customer per month, so that it would continue to offset half of the monthly
service charge (8T 3869).

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 D.

DTE Electric’s primary service charge should be maintained.

DTE Electric does not propose to change the $275 monthly service charge for primary
customers. Kroger asserted that this charge is not cost based, and that the Commission should
instead adopt the $53.52 charge that Kroger supported in Case No. U-18255 (Kroger Initial Brief,
pp 1-5). The PFD agreed, stating:
This PFD finds that Kroger’s position has merit, and that the customer charge for
primary customers in this case should be calculated using the same method that
the Commission has consistently approved for residential and commercial
secondary customers. Mr. Bieber’s proposal to use the cost-of-service based
calculation from Case No. U-18255 is also reasonable and should be adopted.
Alternatively, the Commission should direct DTE Electric, in its next rate case, to
calculate the customer charge for primary customers consistent with the method
used for residential and commercial secondary customers discussed above. [PFD,
p 237.]
DTE Electric disagrees because there is no basis for the PFD’s recommendation. Even
Kroger witness Mr. Bieber acknowledged that the Commission rejected using the “Staff method”
to calculate the primary service charge (7T 2713-14). Mr. Lacey testified that there is no merit in
Mr. Bieber’s reasoning that just because the Commission did not expressly say the charge is costbased, that means it must not be. The Commission found the $275 charge to be reasonable in Case
Nos. U-17767, U-18014, and U-18255, and neither the Commission nor the Staff have ever
advocated for using the “Staff method” for anything other than calculating residential and
commercial secondary classes in those cases or this one (7T 3230-31; See also 8T 4268).
Additionally, Kroger’s proposal relies on the record from Case No. U-18255 rather than
the record in this case. 61 Kroger’s proposal that the Commission alter its U-18255 decision based
on the U-18255 record is essentially a request for rehearing of Case No. U-18255, which fails as

61

The Commission’s findings are required to be supported by record evidence. Const 1963, Art 6, § 28; MCL 24.276.

102

 untimely under Rule 437(1) of the Commission’s Rules of Practice and Procedure, R
792.10437(1). The Commission cannot lawfully deviate from its own rules. 62
Kroger also does not offer anything that the Commission has not already considered.
Although res judicata and collateral estoppel do not apply “in a strict sense” to the Commission’s
ratemaking decisions, “issues fully decided in earlier PSC proceedings need not be ‘completely
relitigated’ in later proceedings unless the party wishing to do so establishes by new evidence or a
showing of changed circumstances that the earlier result is unreasonable.” In re Application of
Detroit Edison to implement opt-out program, unpublished opinion of the Court of Appeals, issued
February 19, 2015 (Docket Nos. 316728 and 316781), lv den 499 Mich 868 (2016), reh den 499
Mich 972 (2016) (2015 WL 728383 at * 6), citing In re Application of Consumers Energy Co, 291
Mich App 106, 122; 804 NW2d 574 (2010), and Pennwalt v Public Service Comm, 166 Mich App
1; 420 NW2d 156 (1988). Therefore, the $275 monthly service charge for primary customers from
Case Nos. U-17767, U-18014 and U-18255 should be continued.
E.

DTE Electric’s Weekend Flex and Fixed Bill Pilots should be approved.

DTE Electric proposes to adopt a new Weekend Flex pilot and Fixed Bill pilot to address
customer affordability and satisfaction. The PFD instead recommends that the pilots be rejected,
or that the Commission modify them if they are adopted (PFD, pp 246-48). The Company
disagrees that the pilots should be rejected.

62

Complaint of Consumers Energy Co, 255 Mich App 496, 501; 660 NW2d 785 (2002). See also, DeBeaussaert v
Shelby Twp, 122 Mich App 128, 130; 333 NW2d 22 (1982) (“Once an agency has issued rules and regulations to
govern its activity, it may not violate them”); Bohannen v Sheridan-Cadillac Hotel, Inc, 3 Mich App 81, 82; 141
NW2d 722 (1966) (“When an administrative agency promulgates a rule for the benefit of litigants and then deprives
a litigant of this right, it is a violation of both the 1908 and 1963 Michigan Constitutions”).
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 1. The Fixed Bill pilot should be adopted.
The PFD found “that the proposed Fixed Bill pilot program should be rejected on grounds
that, more likely than not, the effects of the program would be contrary to the energy conservation
goals of the State [of] Michigan and the company’s energy efficiency efforts” (PFD, p 246). The
intent of the Fixed Bill pilot was to design a new customer centric billing option through which
DTE Electric customers can take electric service. As this is a voluntary program, it provides a
compelling response to customer preferences outlined in the supporting consumer research. DTE
Electric is not alone in expanding its tariff options for customers. Other U.S. utilities are currently
offering successful Fixed Bill programs, one of which is Georgia Power with over 236,000
customers enrolled or 11% of its 2.2 million residential customers (6T 2102). While EWR is an
important consideration, it is not the only consideration when designing a product or service that
addresses customer requirements and the Company has carefully designed EWR elements into the
program. Customer preferences in this case should be provided an equal, if not greater
consideration in supporting this pilot. Even so, the PFD’s concerns regarding EWR impacts are
speculative at this point as it is premature to assume any result until the pilots are conducted and
results can be analyzed.
Contrary to Staff and Intervenors’ assertions, Mr. Clinton explained that price signals
would be clear to customers through usage alerts (warning customers of increased consumption
and consequences) 63 and the reasonable usage clause (if the customer increases usage beyond
predefined limits, the customer could be removed from the pilot and charged the difference

63

Customer renewal offers are to be priced predominantly based on customer usage while on the Fixed Bill pilot. If a
customer’s usage increases, then this would result in a higher monthly Fixed Bill for the subsequent year. Program
materials and proactive usage alerts will make the consequences of increased electricity usage abundantly clear for
customers (6T 2121, 2124).
104

 between the pilot rate and the D1 rate).64 Renewal offers for both pilots are to be priced
predominantly based on usage while enrolled in either program. If a customer does increase usage,
it would likely result in a higher monthly energy expenditure; conversely customers who decrease
their usage would likely benefit from lower monthly energy expenditures (6T 2112, 2124). These
key elements of the pilots will ensure that customers are aware of and held accountable for the
consequences associated with the inefficient use of electricity, and also ensure that price signals
are reinforced rather than diluted (6T 2093, 2101-02, 2112-14, 2120-21, 2124).65
The PFD points to a prior Commission Order regarding a 2012 proposal made by the
Company (PFD p. 246 citing December 20, 2012 order in Case No. U-17054). However, reliance
on the previous Commission Order is not relevant here since the program proposed by the
Company in this case is different then what was proposed in 2012. In that case, the Commission’s
primary concern was that the Company requested approval of the program outside of a contested
proceeding. Additionally, specific components of the program that the Commission was concerned
with in the U-17054 order have been addressed in this proceeding. The Fixed Bill program
includes an EWR component with welcome kits that explain energy efficiency programs, provides
usage alerts and reasonable use clause (6T 2101-2102), does not impact customers who are not a
part of the program (6T 2100), and is based on market research (6T 2097, 2116).
It bears emphasis that the Company’s proposed pilots are supported in part by an April
2018 survey of residential customers, which found that 11%, or roughly 218,000 if extrapolated

The Company accepts the PFD’s position regarding the reasonable usage clause. Should the Fixed Bill or
Weekend Flex pilot receive approval in this rate case, customers could be removed for excessive usage, but would
not be required to pay what they would have paid under normal rates.
64

65

DTE Electric seeks to learn as much as possible from pilot participants, so the Company would likely exercise the
reasonable usage clause only if substantially higher customer usage were systemic amongst the enrolled participants
(6T 2115).

105

 across DTE Electric’s residential customer class, would actually enroll in the Fixed Bill pilot. This
is greater than the enrollment of any other existing residential rate or program outside of the
standard D1 residential service rate. Furthermore, 6%, or roughly over 100,000 if extrapolated
across DTE Electric’s residential customer class, would actually enroll in the Weekend Flex
program.

Additionally, 28% to 29% of survey respondents, or roughly over 600,000 if

extrapolated across DTE Electric’s residential customer class, found the Fixed Bill and Weekend
Flex Pilots appealing and would want to investigate further. This is a significant and compelling
portion of DTE Electric’s customer base, and indicates strong customer demand for these offerings
(6T 2089-90, 2097, 2116-17). DTE Electric believes that it is imperative to listen to the expressed
interests of customers and update pricing options with what customers’ desire. That is why the
Company conducted its customer survey and is now proposing to pilot programs that explore the
expressed interests from the survey results (6T 2125).
The PFD further suggested that the Fixed Bill pilot is duplicative and unnecessary since
the Company already offers a BudgetWise Billing program (PFD, p 247). To the contrary, Mr.
Clinton explained that the Fixed Bill pilot would provide absolute bill certainty for each 12-month
term instead of the quarterly adjustments and annual settlement that may be required under the
Company’s existing equal monthly billing (BudgetWise Billing). The April 2018 survey also
indicated that the majority (55%) of the customers interested in the Fixed Bill option would likely
come from current BudgetWise Billing customers. This also shows that there is strong demand for
an offering that provides greater consistency in monthly energy spending beyond what
BudgetWise Billing affords (6T 2116, 2119-20, 2123).

106

 2. The Weekend Flex pilot should be approved.
With respect to the Weekend Flex pilot, the PFD found that it should be rejected as “largely
duplicative of the company’s current TOU rate programs, which, as the Attorney General points
out, could be modified to provide a larger discount for weekend usage. In addition, the design of
the Weekend Flex program is exceptionally complex and could result in significant customer
confusion.” (PFD, p 247)
The Company disagrees with the PFD’s reasoning that the Weekend Flex pilot should be
rejected because time-of-use (“TOU”) rates could instead be modified. Mr. Clinton explained that
the Company’s existing TOU rates already incentivize customers to shift usage to the weekend by
providing a significantly lower rate during the weekends. DTE Electric also already has variable
rate structured time-of-use electric pricing options. These pricing options resonate with certain
customers, but the Weekend Flex pilot is unique because it would offer a time-of-use electric
pricing option with a fixed component for usage. This fixed-component is a key element that may
resonate with certain customers who have otherwise declined DTE Electric’s current options.
Thus, by offering the Weekend Flex provision, there is the potential for greater overall voluntary
enrollment in time-of-use rates (6T 2117-18).
The Company also disagrees with the PFD’s assertion that the Weekend Flex proposal “is
exceptionally complex and could result in significant customer confusion” (PFD, p 247). Mr.
Clinton explained that Weekend Flex would not be much different to explain to customers than
existing time-of-use rates D1.8 or D1.2, since all three share the same foundational element of
multiple price points varying by time of day and/or day of week (6T 2118-19).
In summary, DTE Electric has listened to its customers, studied the desirability of the pilots
and structured them in a manner that the Company believes will increase customer satisfaction,
improve future affordability and shift weekday peak usage to low load periods. As such, the
107

 Company believes these offerings are reasonable and prudent and requests their approval. The
purpose of these pilots (or any pilot for that matter) is to proceed cautiously and gather information
about customer satisfaction, usage behavior, affordability, and Energy Waste Reduction program
participation (6T 2103, 2122-2123, 2125). It is inappropriate to simply speculate about the
outcome of these pilots before conducting them, and in the absence of any data, case studies or
examples to support such speculative conclusions (6T 2112-2113, 2117, 2120-2121). DTE Electric
must instead conduct these pilots to gather necessary data regarding how to proceed (6T 2123,
2125). If the PFD and Staff’s speculation on the outcome of the pilots turns out to be correct (i. e.
increased usage by customers), then the Company would take that into consideration when
determining whether to seek approval of these programs on a permanent basis. However, without
running the pilot there is no data on which to base these conclusions. Therefore, the PFD’s
recommendations to reject the pilots should be rejected and the $1.4 million of related O&M
expense requested by the Company should be approved.
F.

DTE Electric’s Primary Rate Design Proposals.
1. The Company’s proposed voltage level energy discounts and voltage
level demand adjustments reflect the proper allocation of costs of
service.

DTE Electric’s rates are designed to be cost-based in accordance with MCL 460.11 (5T
1222-23), which states in part “[e]xcept as otherwise provided in this subsection, the commission
shall ensure the establishment of electric rates equal to the cost of service to each customer class.”
The statute’s plain language must be applied as written66 and DTE Electric’s voltage level
discounts and voltage level demand adjustments accomplish this requirement. Mr. Bloch explained

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); and Ambs v Kalamazoo County Road Comm,
66

108

 how the Company’s proposed voltage level energy discounts and voltage level demand
adjustments for Rates D6.2, D8 and D11 were determined (5T 1223-24; Exhibit A-16, Schedule
F12 shows the calculations). 67 He also explained how the Company’s transmission-related voltage
level demand adjustments for Rates D11 and D8 were determined (5T 1224-25; Exhibit A-16,
Schedule F12 shows the calculations).
The PFD instead “recommends that the Commission again approve the Staff’s method for
calculating demand and energy level discounts” (PFD, p 252). The Company disagrees.
i.

Energy-based voltage level discounts.

Staff recommended following the method of determining energy voltage level discounts
approved in Case No. U-18255 (Staff Initial Brief, pp 142-64). The PFD agreed, as indicated
above, but the PFD’s reasoning focuses on demand-based voltage level discounts (and is flawed
as discussed below in subsections b and c). Mr. Bloch explained that the Company’s proposed
method of determining energy-based voltage level discounts allocates energy costs to each voltage
level based on loss adjusted sales. Voltage level energy costs are then divided by the corresponding
voltage level billed sales to determine the voltage level energy rate from which voltage level
discounts are determined. Calculating energy voltage level discounts based on loss adjusted sales
at each voltage level better aligns costs with cost causation compared to the method approved in
Case No. U-18255 that calculates these discounts by multiplying voltage level loss factors by the

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”).
Rate Schedule D11 is the Company’s main primary rate schedule and is available to customers served at primary,
sub-transmission, or transmission voltage. Rate Schedule D6.2 is available to educational institution customer
locations (schools, colleges and universities) desiring service at primary, sub-transmission, or transmission voltage.
Rate Schedule D8 is the Company’s primary voltage interruptible rate which is limited to 300 megawatts (5T 1221).
67

109

 class average energy rates.

The Company’s proposed method is also consistent with past

recommendations from ABATE (7T 2848) as the appropriate way to calculate energy voltage level
discounts (5T 1256-57). Witness Andrews also confirmed that ABATE would have no objection
if the Commission approved DTE Electric’s proposed voltage level discounts (5T 2876).
ii.

Demand based voltage level discounts.

The Company’s proposed methodology for determining demand-based voltage level
discounts differs from the method that the Commission approved in Case No. U-18255.68 The
approved method only considers loss differences between voltage levels and does not consider the
voltage level cost responsibility to which the losses are applied. The Commission’s direction to
determine voltage differentiated power supply demand charges should be interpreted to mean
voltage level demand charges that are consistent with cost-based principles (as required by MCL
460.11, quoted above), otherwise rate subsidies occur. The Company’s proposed voltage level
demand rates are cost-based using the same voltage level cost responsibilities that would result by
performing a separate power supply voltage level COSS for each rate (5T 1225).
The PFD asserts that “DTE Electric has not shown that its method is cost-based; in fact
ABATE’s evidence, that under the company’s method the discounts or sub-transmission level are
greater than those for transmission level, appears to demonstrate the opposite” (PFD, p 252). To
the contrary, the Company is the only party in this case (or in Case No. U-18255) that presented a
cost-based proposal for determining demand based voltage level discounts. ABATE supported the
method of determining demand voltage level discounts approved in Case No. U-18255, following

In Case No. U-18014, the Commission directed: “In its next general rate case, DTE Electric shall calculate a
proposed demand voltage level discount for Rates D11 and D8, with the necessary billing determinants, including
demand by voltage level” (January 31, 2017 Order in Case No. U-18014, p 132, ordering paragraph M). The Company
did so, but the ALJ instead recommended the Staff’s method for calculating the discounts, and the Commission
adopted the ALJ’s recommendation (April 18, 2018 Order in Case No. U-18255, pp 67-69).
68

110

 the testimony of its witness Mr. Andrews (ABATE Initial Brief, pp 51-53). Mr. Bloch produced
evidence that the method approved in Case No. U-18255 is not cost based and produces demand
voltage level discounts that increase intra-class subsidies between voltage levels instead of
reducing them. This is because, under the current method, voltage level loss factors are applied to
the average billing demand charge for the class. However, the costs that make up the average
billing demand charge vary by voltage level and Mr. Andrews method does not take this into
consideration. To determine demand voltage level discounts without accounting for voltage level
cost differences, which are known, does not follow cost of service principles. For example, of the
costs allocated to the D11 rate class that are included in the billing demand charge, transmission
voltage level customers have a higher relative cost responsibility than subtransmission and primary
voltage customers due to their higher relative 4CP demand. Voltage level cost differences are
equally relevant to setting voltage level demand discounts as are loss factors and can have a more
significant impact than loss factors on demand voltage level discounts. To not recognize the
voltage level cost differences based on the 4CP demand would be in stark contrast to how the
Company allocates all of its other power supply related capacity costs.
The current method does not account for voltage level cost differences and results in
shifting rates further from cost of service basis and increasing intra-class subsidies which runs
contrary to the principles of setting cost based rates (5T 1257-58). This shifting is most obvious in
Rate D6.2, where the impact of the 4CP cost allocation is much larger than the voltage level loss
adjustment. This results in a sub-transmission voltage level adjustment that is a charge rather than
a discount under the current method. This same issue impacts all voltage level demand charges
that are calculated under the current method (5T 1225-25, 1257-58).

111

 As indicated above, the PFD was persuaded by ABATE’s premise that transmission
customers have lower loss factors and use less infrastructure than subtransmission customers,
which resulted in the proposition that transmission customers have a lower cost to serve. Thus,
DTE Electric’s methodology appears to produce results that seem counter-intuitive (PFD, p 252).
The PFD neglects that during cross examination, ABATE’s witness Andrews identified the
infrastructure cost savings supporting ABATE’s claim that transmission customers have lower
cost to serve are distribution related cost savings which are unrelated to and not included in power
supply capacity or non-capacity (transmission) costs. With respect to capacity related cost
allocation, Mr. Andrews stated “In Michigan, 75 percent of the capacity related costs are allocated
on 4CP…” and also acknowledged that cost allocation based on 4CP is more a function of when
customers use capacity than what voltage customers take service at. (7T 2880, 2879, 2882)
Mr. Andrews’ argument that it is lower cost to serve transmission customers than
subtransmission customers is not accurate with respect to determining power supply capacity and
transmission cost responsibility because these costs are driven by when customers take service and
not voltage level or infrastructure. When given an example comparing a subtransmission customer
to a transmission customer, with all things being equal except the transmission customer had a
4CP that was 20% higher than the subtransmission customer, Mr. Andrews agreed the transmission
customer should pay a higher rate than the subtransmission customer. (7T 2885). When asked to
square this response with his recommendation to only consider voltage level loss factors and not
the underlying capacity cost responsibility at each voltage level and with cost foundation
principles, Mr. Andrews testified on cross-examination that he had never seen a transmission
customer pose more per unit costs than a subtransmission or a lower voltage customer, and that,
while the methodology used by the Company attempts to assign and recover cost consistent with

112

 cost causation principles, he believed the underlying data utilized to do so was inaccurate. When
asked what about the data was inaccurate, Mr. Andrews could not identify any particular flaw
except that it produced results that in his opinion did not “make sense” (7T 2885). Additionally,
while Mr. Andrews testified on cross examination that he had never seen a transmission customer
responsible for more costs than a subtransmission customer, he admits this is because of the
infrastructure costs he identified, as set forth above:
Q
When you say you have never seen a transmission customer responsible for
more costs than a subtransmission customer, is that because of the infrastructure
argument you made?
A

On a per unit basis, yes. [7T 2886]

Considering Mr. Andrews’ prior testimony that infrastructure costs are distribution related costs
and unrelated to setting capacity voltage level discounts, Mr. Andrews’ answer to the above
question during cross examination contradicts his position with respect to determining capacity
voltage level discounts.
iii.

Non-Capacity demand voltage level discounts.

During cross examination, ABATE witness Andrews further agreed that the non-capacity
demand charge collects only transmission expenses and that transmission costs are allocated in
cost of service 100% on 12CP (7T 2889-2890). He also acknowledged that the 12CP by voltage
level can be determined and the methodology of using 12CP by voltage level to determine noncapacity cost responsibility at each voltage level follows cost of service principles (7 T 28902891).
The Company’s proposal is the only proposal that follows cost-of-service principles by
including both loss factors and capacity cost responsibility in determining demand voltage level
discounts. It is also the only proposal that reduces intra-class subsidies.

113

Therefore, the

 Commission should adopt the Company’s proposed changes to the determination of voltage level
energy discounts and voltage level demand adjustments, as well as the Company’s proposal to add
voltage level demand adjustments to the D6.2 Billing Demand charge (5T 1218, 1227).
2. Allocation of Capacity Costs to Rider 3 and Generation Reservation
Fee.
i.

Rider 3 Cost Allocation.

DTE Electric provides bundled retail standby service to customers with on-site generation
under its Standard Contract Rider 3 (“R3”). The Company proposes to change the method of
allocating the power supply capacity costs to R3 to account for R3’s abnormal demand variability
and thereby eliminate the associated subsidy by Rate D11 customers to R3 customers 69. Mr. Bloch
explained that in DTE Electric’s next-to-last general rate case, the Commission directed: “In its
next general rate case, DTE Electric shall treat Rider 3 as a separate rate class for the purposes of
the company’s cost of service study” (January 31, 2017 Order in Case No. U-18014, p 132,
ordering paragraph N). DTE Electric did so, but presented several concerns with respect to treating
R3 as a separate cost of service class, or attempting to allocate power supply costs to R3 on a 4CP
70

basis. 71 The Commission decided against using a separate cost of service class for R3, keeping

R3 in the D11/Other COS class (as recommended by the Company), but approved ABATE’s
recommended allocation of power supply costs for R3, which were based on 4CP data averaged
over 10 years (April 18, 2018 Order in Case No. U-18255, pp 72, 76). The latter decision followed

The Company is not proposing to change how costs are allocated to the “D11 and Other Class”, which R3, along
with D-10 makes up the “other”, but is instead more appropriately has determined a sub-allocation of costs to R3.
69

4CP is the average of the 4 class demands at the time of the Company’s bundled peak hour loads for June, July,
August and September. (5T 1233)
70

“Fundamentally, assigning power supply costs based on 4CP to a standby COS class where loads can be very
irregular and can vary significantly at any point in time compared to normal loads, does not follow proper cost
allocation principles. This is especially true in a small class, where generation size varies greatly, and one customer
can influence the outcome for the entire class.” (5T 1232, quoting U-18255 9T 1974).
71

114

 the PFD’s recommendation, which recognized that the Company had a legitimate concern about
determining R3 costs based on 4CP, but accepted ABATE’s argument that the concern could be
addressed by using an average of 4CPs over a longer term (U-18255 PFD, p 276: “DTE Electric’s
concern that R3 demand variability is not amenable to traditional cost allocation principles is
legitimate. However, as ABATE argues, that variability may be normalized by using an average
over a longer term”) (5T 1232-33. Emphasis added). 72
The Company maintains that 4CP does not provide an appropriate basis to determine suballocating power supply cost to the R3 class, and averaging as ABATE proposed, only masks the
resulting subsidization problem. Mr. Bloch provided three tables demonstrating that due to R3’s
abnormal demand variability, 4CP does not accurately represent the true demands that the R3 class
imposes on the system during peak load periods. Table 1 (5T 1234) compares how often a class is
operating above its 4CP during high demand on-peak hours 15, 16, 17, and 18 from June through
September. These are the summer hours when the Company’s 4CPs normally occur. Table 2 (5T
1234) compares the class 4CP to the average of its 4 monthly class peaks during high demand
hours (4NCP).73 This comparison indicates that normal load classes have variances below 10%
compared to the R3 class which has a variance that is 108% higher than their 4CP. This means
the average of the 4 monthly R3 peak class demands is more than twice their 4CP demand which
is over 1,000% higher than normal load classes. Table 3 (5T 1234) compares the class 4CP to the
class’ highest hourly demand during high demand hours (Class 1NCP during summer hours 15,16,

72

The Company disagrees that averaging 4CPs that do not correlate with R3 customer actual operational
characteristics obtains a “normalized” result. It simply results in a mathematical average that does not represent the
demands R3 customers place on the DTE Electric system during peak hours. (See Table 2 at 5T 1234).
73

4NCP is the average of the 4 class peak hour loads during hours 15, 16, 17 and 18 for June, July, August and
September for each class. (5T 1233-1236).

115

 17 and 18). This comparison also indicates that normal load classes again have variances around
10% compared to the R3 class which has a variance that is 180% higher than their 4CP. These
4CP to 4NCP and 1NCP class load comparisons demonstrate that due to the demand variability of
the R3 class, 4CP is not representative of the actual demands R3 places on DTE Electric generation
capacity during high demand periods and should not be used to allocate costs to R3 rate class. The
currently approved method of averaging 4CPs over several years does not address this variability
(its merely a mathematical average having no meaningful connection to the demands placed upon
DTE Electric generation to serve these few customers) and results in D11 customers subsidizing
R3 customers (5T 1220, 1233-36).
Staff recommended that standby rates should continue to be calculated in the same manner
as ordered in Case No. U-18255, reasoning that there is not sufficient evidence to support a change
(Staff Initial Brief, pp 146-48). ABATE (Initial Brief, pp 45-51) and MEIBC (Initial Brief, pp 114) similarly supported the status quo. The PFD “finds persuasive the recommendation by the
Staff, ABATE, and EIBC/IEI, that the power supply cost allocation method approved in Case No.
U-18255 should be retained” (PFD, p 255).
To the contrary, the Company presented ample and compelling evidence as indicated
above. The PFD was apparently persuaded by Staff’s reasoning that any smaller group of
customers is going to show more variance than the entire class (PFD, p 253). This makes no
relevant point. Mr. Bloch explained that the appropriate question is whether actual 4CP demand is
an appropriate allocator for the R3 rate class. As indicated above, R3 has more variance than
would be expected for a subgroup of D11 customers. This demonstrates that actual 4CP demand
is not an appropriate allocation method for allocating capacity costs to R3 (5T 1251).

116

 The PFD was also persuaded by Staff’s alternative suggestion that it is possible that actual
4CP is a poor allocator for D11, and 4CP could make a reasonable allocator when all rate schedules
are considered in total (PFD, p 253-54). To the contrary, Tables 1, 2 and 3 demonstrate that actual
4CP is an appropriate allocator for D11, in line with all other cost of service classes (5T 1251).
MEIBC/IEI asserted that the Company’s proposal to use an equivalent 4CP moves away
from cost causation principles and arbitrarily allocates power supply costs, and the PFD agreed
(PFD, p 255). However, MEIBC/IEI provided no supporting evidence to support their claim and
their witness confirmed that she has never performed a cost of service study (5T 1251; 8T 34903491). Thus, there is no proper evidentiary basis to rely on EIBC/IEI’s opinion concerning Rider
3 cost allocation.74
The PFD was also apparently persuaded by ABATE witness Mr. Dauphinais, who offered
five bullet points to attempt to support his suggestion that the Company’s arguments are somehow
flawed (PFD, p 254). Mr. Bloch responded by explaining why each point failed to support the
argument. Instead, the Commission can and should approve a power supply cost allocation method
for R3 that best represents the Company’s costs to serve this class and is consistent with power
supply cost allocation to other classes. Only the Company’s proposal accomplishes this outcome
(5T 1248-50).
On cross examination, Mr. Dauphinais agreed that ABATE supports cost of service and
rate design principles that reflect cost causation and does not support rate designs that do not reflect
cost-causation or that shift cost of service away from cost-causation (6T 1787). Mr. Dauphinais
MCL 24.285; 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); In re Complaint of Pelland, 254 Mich App 675, 685-86; 658
NW2d 849 (2003).
74

117

 agreed that ABATE cannot tell exactly when the Company’s peak loads will occur in the future,
but agreed that the peak loads will be during the summer typically June through September and
typically during hours 15, 16, 17 or 18 (6T 1791). Mr. Dauphinais further agreed that the 4CP
column in Table 2 for all classes shown, except R3, is a reasonable way to allocate capacity costs
to those classes (6T 1793), and that applying the R3 108% variance to the D3 &Other class would
result in an extraordinary increase in capacity requirements from 133MW to over 1,500MW (6T
1793, 1795). Notwithstanding these acknowledgements, Mr. Dauphinais did not agree the values
shown in Table 2 under the column labeled “Avg of Monthly Max Hrs” reflects the 4NCP for each
class. Mr. Dauphinais incorrectly asserted “it’s the average of the demands in hours 15, 16, 17
and 18 for all non-holiday weekdays of the summer period of June, July, August, and September,
that’s not a non-coincident peak value” (6T 1792). However, 4NCP is the average of the 4 class
peak hour loads all during hours 15, 16, 17, and 18 for June, July, August and September for each
class (5T 1233-1236), not the “average of the demands in hours 15, 16, 17 and 18 for all nonholiday weekdays of the summer period…” (6T 1792. Emphasis added). The values shown in
Table 2 in Witness Bloch’s testimony under the column labeled “Avg of Monthly Max Hrs” reflect
the 4NCP for each class determined during the hours 15, 16, 17 and 18, non-holiday weekdays,
for months June, July, August and September (5T 1235). Thus, it appears ABATE’s position (and
the resulting PFD recommendation) is based on a misunderstanding of the data shown in that table.
To properly sub-allocate capacity costs to the R3 class, the Company recommends
calculating an equivalent 4CP demand for the R3 class by taking its actual 4NCP demand shown
in Table 2 and reducing it by a variance adjustment in line with normal system load classes, which
all operate with variances below 10%. Using 10% results in an equivalent 4CP demand of

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 approximately 16MW. Allocating capacity costs on this basis results in a capacity revenue
requirement for R3 of $3.895 million (5T 1236).75
The Company’s proposal does not affect how costs are allocated in the COSS since R3 is
included in the D11/Other cost of service class. The proposal only affects the revenue requirements
of R3 and D11. To the extent that the revenue requirement presently assigned to R3 understates
the cost to serve R3, it shifts revenue requirement/cost responsibility to D11, causing D11
customers to subsidize R3 customers. The Company’s proposed capacity revenue requirement
eliminates the current D11 subsidy to R3 that resulted from allocating capacity costs to R3 based
on an arbitrary 10-year average of their 4CP. The Company’s proposed method of allocating
capacity costs to R3 accounts for R3’s abnormal demand variability and results in proper cost
allocation to R3 pursuant to MCL 460.11(1). Therefore, the Company’s proposal should be
adopted (5T 1220-21, 1237).
ii.

Generation Reservation Fee.

DTE Electric also proposes to change the basis for setting the generation reservation fee
approved in Case No. U-18255 due to both cost of service and rate design concerns (5T 1232,
1237). The Commission adopted ABATE’s proposal to set generation reservation based on the
best performing generators of R3 customers (April 18, 2018 Order in Case No. U-18255, p 77:
“The Commission finds that it is reasonable to approve an R3 standby tariff that sets a monthly
power supply reservation charge based on the forced outage rates of the best performing
generators”). The Commission did not specifically address the Company’s concerns that

75

Neither Staff nor any intervenor provided cost analysis or data to support their positions with respect to R3. In
contrast, the Company provided empirical evidence in support of its proposal to allocate capacity to R3 using an
equivalent 4CP demand (5T 1232-39, 1251-52).
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 availability is not an appropriate basis to set the generation reservation fee since availability does
not reflect generator performance and the Company’s need to reserve capacity.
From a cost-of-service perspective, the premise that if a generator has a forced outage rate
of 3.5%, then the generator will fully serve its’ load requirements the remaining 96.5% of the time
is not accurate due to operating costs and other operational considerations. Mr. Bloch compared
three of the Company’s largest R3 standby customers, which all have annual availabilities of 98%
or higher. Their standby service use was not in the 2% range (as the above would suggest); instead
their actual average annual standby requirement was 30%, with a range from over 17% to over
50%. These customers also represent over 75% of the R3 class sales, so the results are
representative of the R3 class. These results demonstrate that availability does not indicate how
well a customer’s generator serves its load and, therefore, does not represent the standby
requirements that the customer places on the system (5T 1238, 1252-53). The PFD disagreed,
stating: “As this PFD found above with respect to the power supply cost allocation, the method for
determining the reservation charge should be retained” (PFD, p 258).
As noted in the PFD, ABATE witness Mr. Dauphinais suggested that setting the R3
monthly generation reservation fee based on the best generator availability is reasonable because
the fee is a minimum required contribution toward fixed power supply costs that must be paid
regardless of how much standby service power is actually taken by the customer (PFD, pp 25657). Mr. Bloch explained that Mr. Dauphinais’ proposal to set a generation reservation fee based
on the forced outage rate of the best performing generators is fundamentally flawed since forced
outage rate is not a measure of, nor indicative of, generator operating performance (5T 1252). In
fact, none of the parties promoting this position provided any supporting evidence demonstrating
a linkage between forced outage rate (generator availability) and generator performance.

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 The PFD also cited MEIBC/IEI’s arguments (PFD, 257), but its witness acknowledged that
the Company is required to stand ready to serve the entire load of the R3 customer irrespective of
the fact they have a generator on site and that a generator with 97% availability might be operating
at 25 percent of its nameplate capacity at any given time (8T 3504, 3506). 76 Additionally, Witness
Dauphinais acknowledged that the Company has no control over customer on-site generation
through R3 and the customer with on-site generation has no obligation or requirement to operate
its generation even to serve its own load (6T 1798).
In contrast, the record evidence outlined above demonstrates that forced outage rate is not
an indicator of generator performance. Even apart from this evidence, the recommendation to set
a generation reservation fee based on the best performing generator is an exception from the
normal rate design practice of setting rates based on average performance. This is like asking a car
insurance company to set collision rates based on their best driver, and if that driver never had an
accident, then the premium for collision insurance should be zero. This methodology should be
rejected as incorrect and contrary to cost causation principles (5T 1253-54, 1256).77
Further, the current R3 rate design has constrained the R3 rate design by having all R3
demand charges based on the D11 billing demand (April 18, 2018 Order in Case No. U-18255, p
77). This limits the ability to design R3 capacity rates equal to R3 costs, which are not determined
based on the D11 billing demand. Therefore, and as discussed above and further explained on the

EIBC/IEI further indicated a concern that “the Company proposes to remove the requirement to take into account a
CHP system’s availability when calculating the generation reservation fee” (8T 3476). The indicated concern does not
accurately reflect the Company’s position. Instead, that position has been, and continues to be, that setting a generation
reservation fee based solely on lowest forced outage rate (highest availability) is flawed, arbitrary, does not follow
cost-causation principles (5T 1255-56).
76

77

This is an apt analogy because the best performing generator in the R3 group has an availability of 100% (5T 1238).
Mr. Dauphinais suggested that this 100% availability (i.e., a 0% forced outage rate) is a “red herring” (6T 1754). To
the contrary, this fact is a reality that exposes the potential consequences (subsidization by other D11 customers
contrary to cost based ratemaking) of following Mr. Dauphinais’s theory (5T 1254-55).
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 record and in DTE Electric’s Initial Brief, the Commission should remove the requirement to set
the generation reservation fee based on generator availability and allow changes in R3 capacity
revenue requirement to be collected through the generation reservation fee (5T 1239).
3. Rate D1 Time of Use rate design (summer on-peak non-capacity
charges).
The Commission previously directed the Company to include a proposal to redesign its
residential rates in its next rate case (this case) (April 18, 2018 Order in Case No. U-18255, pp 8182, and p 86, Ordering paragraph E). DTE Electric moved for rehearing, pointing out that even if
the directive were clarified for accuracy, 78 it still would have unintended consequences by
defaulting approximately 1.9 million customers to time-based rates for non-capacity charges with
significant impacts on the Company’s rate structure and individual customers’ bills. The
Commission granted the request for clarification, re-affirmed the substance of its decision, and left
implementation issues open to further consideration (June 28, 2018 Order on Rehearing, p 7).
i.

The Commission should reverse its prior ruling.

The Company complied with the Commission’s directive (as discussed below), but
maintains its position from Case No. U-18255 and requests that the Commission reverse its prior
ruling. The PFD noted the issue, but proceeded to discuss other matters (PFD, p 258). Thus, the
PFD implicitly recommended denying DTE Electric’s request.
DTE Electric maintains that it should able to retain its existing Rate D1 pricing schedule
because customers should be allowed to choose to opt-in voluntarily to any new and significantlydifferent rate program. The Company also proposes D1 and D1.6 rates using the existing rate
structure in anticipation that the Commission will reverse its prior decision and allow the Company

78

The D1 non-capacity rate is a flat per kWh charge, not an inverted block rate as indicated in the April 18, 2018
Order.
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 to retain its existing Rate D1 pricing structure, and alternatively because there will be a long lead
time to facilitate the change Company-wide. The existing rate structure would need to stay in place
until all customers can be transitioned to the new rate structure (3T 85-86; 8T 3866).
The Company currently offers several different residential rates, so customers have a wide
range of options, including whole home TOU rates, interruptible air conditioning, dynamic peak
pricing, and geothermal rates. If customers believe they can take advantage of savings related to a
TOU rate structure, or any other rate program, then customers will opt-in. Customers should not
be forced onto TOU rates. The Commission’s presently-ordered change in the residential rate
structure will also have significant operational and financial impacts on the Company in several
areas including information technology, customer service, and marketing and communications (3T
84-85). If the Commission does not reverse its prior ruling, however, the PFD recommended that
the Company recover its costs of transitioning to TOU rates (PFD, p 260).
ii.

The PFD/Staff’s recommendation that the Company explore
shadow billing should be rejected.

Staff suggested that the Company explore shadow billing (8T 4146).79 The PFD “agrees
with Staff that, in the company’s next rate case, DTE Electric should be directed to present a plan
for implementing shadow billing for customers wishing to explore different rates” (PFD, p 261).
The Company does not agree that shadow billing would be appropriate in this situation due
to the precise and complex calculations needed to render an alternative bill. The Company is also
not convinced that backwards-looking shadow billing functionality is helpful. Instead, a rate
calculator (of some form that balances complexity, costs, and effectiveness) that helps customers

Shadow billing is a billing practice that calculates a customer’s bill using their actual, historic billing determinants
as if the customer were on a different rate, such as a time-of-use rate. (8T 4146).
79

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 forecast costs would be a more useful tool for educating and informing customers on how the
different rate options will impact their electric bills (6T 2129).
The PFD offered only the following reasoning for its recommendation: “As the Staff points
out, the use of actual data, as opposed to theoretical comparisons is more likely to increase
customer interest in alternative programs” (PFD, p 261). However, there is nothing in the record
to support this position. Reasoning that shadow billing would be “more likely to increase customer
interest in alternative programs”) is also inapplicable to this situation where TOU rates are
mandated, as discussed above.
iii.

The PFD’s recommendations to study alternative rate
structures should be rejected.

DTE Electric complied with the Commission’s directive to develop a time-based noncapacity rate for Rate D1, and (assuming for argument’s sake that the Commission does not reverse
its prior ruling) largely agrees with the PFD regarding rate structure, noting that “[a]s DTE Electric
points out, the Staff’s and MEC/NRDC/MEC’s recommendations do not comport with the
Commission’s order in U-18255.” (PFD, p 264) Nevertheless, the PFD goes on to recommend that
Staff’s proposal be explored further in the Company’s next rate case. The Company disagrees with
this recommendation. The PFD rejected Staff’s proposal recognizing that it does not meet the
requirements in the Commission’s prior order, so it is unclear what benefit would be achieved in
studying it further. This is especially true since the Company will not have studied the impact of
customers’ reactions to the new TOU pricing. If the Staff (or anybody else) wants to make a
proposal in the future, then they are certainly free to do so (subject of course to applicable legal
and regulatory requirements). DTE Electric particularly objects to the extent that the PFD can be
read to suggest that the Company should have some initial burden of either presenting evidence or
proof on another party’s flawed and rejected proposal.
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 Although res judicata and collateral estoppel do not apply “in a strict sense” to the
Commission’s ratemaking decisions, “issues fully decided in earlier PSC proceedings need not be
‘completely relitigated’ in later proceedings unless the party wishing to do so establishes by new
evidence or a showing of changed circumstances that the earlier result is unreasonable.”
Application of Detroit Edison to Implement Opt-Out Program, unpublished opinion per curiam of
the Court of Appeals, issued February 19, 2015 (Docket Nos. 316728 and 316781), lv den 499
Mich 868 (2016), reh den 499 Mich 972 (2016). (Opinion affirming AMI opt-out charges, p 8,
citing Application of Consumers Energy Co, 291 Mich App 106, 122; 804 NW2d 574 (2010),
which quoted Pennwalt Corp v Public Service Comm, 166 Mich App 1; 420 NW2d 156 (1988).
Emphasis added).
More recently, in response to an argument raised by RCG that the opt-out charges should
be reduced to zero, the Court of Appeals explained:
In this appeal, [RCG] again argues that the opt-out charges should be eliminated.
[RCG] first contends that there was no evidence presented in the current proceeding
supporting the amount of the fees. The reason for this was simple: DTE was not
seeking to alter the opt-out fees, which had been set in Case No. U-17053. As the
MPSC has explained previously, there is no need for the MPSC to take new
evidence on an issue that has been decided previously, absent a showing that
circumstances have somehow changed. [Application of DTE Electric Company to
Increase Rates, unpublished opinion per curiam of the Court of Appeals, issued
October 25, 2018 (Docket No. 338378), reh den December 27, 2018, following In
re Consumers Energy Co App, 322 Mich App 480, 493-94; 913 NW2d 406 (2017)
and Pennwalt Corp, supra, 166 Mich App at 9.]
These principles also apply here, since the record demonstrates that Staff’s proposed price
differential should be rejected. The Company’s proposed price differential between on-peak and
off-peak rates is based on the historic summer MISO locational marginal price (“LMP”) in cents
per kWh (5T 1344; 8T 3864, 3883). Staff “recommends that the differential be applied as a
percentage rather than a nominal difference” (Staff Initial Brief, p 153). Mr. Dennis explained that

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 the Company’s proposed methodology provides a more accurate portrayal of the difference in
LMP price (8T 3883-84).
Implementing a larger differential than the Company proposes could have a negative
impact on customer acceptance and satisfaction, and would significantly increase revenue recovery
risk (i.e., the larger the differential, the higher the revenue impact if customers change usage
behavior differently than expected). 80 The Company does not forecast any load shift away from
on-peak hours for the projected test year, due to the time necessary to implement IT changes, as
indicated above, and also in part because of the differential the Company proposed (a 1 cent per
kWh on peak / off peak price differential). If the TOU structure proposed by the Company is
implemented for Rate D1, then the Company will study how customers react to the new rate
structure and analyze whether it should be modified in future cases (8T 3865, 3884-85).
iv.

The Company’s “Recommended Plan” to TOU rate
implementation should be adopted.

If the Commission does not grant the Company’s request as discussed above in subsection
a, then the Company should be allowed to proceed with implementation over a reasonable time
period based on the scope of work involved (3T 85). DTE Electric offered a Recommended Plan
and an Alternative Plan for transitioning residential customers to a summer on-peak rate.
The Recommended Plan allows for piloting multiple rates to allow for a more
comprehensive assessment of potential rate designs. The Alternative Plan allows for the piloting
of only a single rate in phase one, unlike the Recommended Plan which allows for piloting multiple

80

Staff’s alternative proposals (to convert the capacity charge to a TOU rate, and to use the percentage LMP
differentials to determine the on peak / off peak differentials) would result in a price differential that is almost four
times what the Company proposed. This substantial price differential could have a negative impact on customer
acceptance/satisfaction and would increase revenue recovery risk, yet Staff did not address how its proposed price
differential would affect usage (8T 3884-86).

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 rates. Piloting only a single rate results in a projected go-live date of June 2021 compared to May
2022 for the Recommended Plan. The Alternative Plan provides less time to gather information
and study customer behavior due to summer on-peak rate changes, and to develop solutions to
potential issues identified during the pilot phase (3T 101-102).
Staff recommends that the alternative plan be approved (Staff Initial Brief, p 155) and the
PFD agreed, stating:
The ALJ finds the Staff’s position persuasive. There does not appear to be a need
to pilot a number of different rate design alternative[s], especially given the finding
above that the company’s more modest rate design proposal was reasonable and
should be adopted. In addition, the ALJ agrees with the Staff that many of the
company’s proposals are related to other residential programs such as TOU and
critical peak pricing that can be piloted at any time. [PFD, p 266.]
The Company disagrees with the PFD/Staff’s assertion that there is no need for testing.
Mr. Stanczak testified that Staff’s underlying testimony is unsupported and contrary to the research
and best practices provided in Staff’s own Exhibit S-16.1 (3T 103). He further explained that it is
important to get each customer on the right rate and provide for potential opt-in rate alternatives.
The Company must analyze and understand the impacts to customers for whom a summer on-peak
rate is not feasible or appropriate. For example, customers who cannot shift load without
significant adverse impacts, customers who should not shift load due to unique health reasons, and
customers who should be aware of other rate options. Therefore, it is necessary to pilot multiple
rates and evaluate results to determine customer implications from a summer on-peak rate
compared to other opt-in rate alternatives. It would also be missed opportunity for a comprehensive
assessment of rate design that benefits customers in the long term during the rate transition period
(3T 102). The suggestion that proposals can be piloted at any time neglects the fact that timing

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 matters. Study results are moot if action is taken before these results are known so that they can be
used to determine what action is appropriate.
The Recommended Plan also provides additional benefits. Multiple policy goals and
objectives may be achieved through a comprehensive rate design assessment that results in both
new opt-in rate options and default rates. The Recommended Plan includes additional objectives
and benefits, such as: (1) understanding customer behavior and peak load reduction and to assess
feasibility and attractiveness of alternative rate designs; (2) billing analysis to determine
appropriate on-peak/off-peak pricing ratio and impacts to customer affordability; and (3) testing
multiple messages that encourage load shifting among different customer segments (3T 103).
G.

DTE Electric’s Distributed Generation (“DG”) program tariff (Rider
18) is reasonable, equitable and consistent with MCL 460.6a(14) and
should be approved.

DTE Electric proposes a new distributed generation (“DG”) program tariff.

The

Commission’s April 18, 2018 Order in Case No. U-18383 stated that in any rate case filed after
June 1, 2018, utilities must file the DG Inflow/Outflow tariff attached to that Order. Exhibit A-16,
Schedule F10.1 fulfills that obligation, and includes some necessary changes to conform the tariff
for DTE Electric. The Company does not propose approval of that tariff, however, as the
Commission also stated that “the utility may also file its own alternative DG tariff” (April 18, 2018
Order in Case No. U-18383, p 16). The Company has done so, and requests approval of its
proposed DG Program tariff, which is included as part of Exhibit A-16, Schedule F10 Revised (8T
3874-77).
The Company’s proposed Rider 18 utilizes an “inflow/outflow” pricing mechanism, with
a System Access Contribution (“SAC”) charge and is designed to eliminate cost shifting from DG

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 customers to non-DG customers. This is consistent with cost of service principles (8T 3593-95) as
well as Section 6a(14) of Public Act 341, which states:
Within 1 year after the effective date of the amendatory act that added this
subsection, the commission shall conduct a study on an appropriate tariff
reflecting equitable cost of service for utility revenue requirements for customers
who participate in a net metering program or distributed generation program under
the clean and renewable energy and energy waste reduction act, 2008 PA 295,
MCL 460.1001 to 460.1211. (MCL 460.6a(14)) (Emphasis added)
1. The Inflow/Outflow tariff is the appropriate basis for the Company’s
proposed DG tariff (Rider 18).
DTE Electric proposes the following “inflow/outflow” pricing mechanism. For all energy
that a Distributed Generation tariff customer (DG customer) inflows (i.e., receives from the
Company), the customer will be charged the full retail rate of the rate schedule to which the
customer attaches Rider 18. For all energy that a DG customer outflows (i.e., sends to the
Company’s distribution system), the DG customer will receive an outflow credit that is the
monthly average real-time locational marginal price (“LMP”) for energy at the appropriate DTE
Electric load node. The PFD agreed in part, recommending “that the inflow charge be set at the
DG customer’s full service rate” (PFD, p 274), and that only the outflow credit recommendations
proposed by DTE Electric and Staff merit consideration in this case (PFD, pp 274-75; DTE Electric
maintains its position on the outflow credit, as discussed below).
The PFD also made a number of additional “initial findings of fact and conclusions of law”
(PFD, p 272). DTE Electric does not disagree with the PFD’s general statements as the Company
understands them, but reserves the right to present a more nuanced discussion in response to other

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 parties’ exceptions or otherwise as the issues are further discussed. 81 DTE Electric also disagrees
with some of the PFD’s specific recommendations, as discussed below.
2. The System Access Contribution (“SAC”) Charge is cost-based,
equitable, non-discriminatory and should be approved.
DTE Electric’s proposed SAC charge is a proposed monthly charge per kW of installed
nameplate capacity on the customer’s site, as calculated on Exhibit A-16, Schedule F9. The SAC
charge would apply only to DG residential and commercial secondary customers on a rate schedule
that has distribution charges based on kWh consumption. Customers on rate schedules with
demand-based distribution rates would not be subject to the SAC, since demand charges more
appropriately recover distribution costs (8T 3598-3601, 3875-76).
The PFD agreed with the parties opposing the SAC charge, stating:
The PFD agrees with the parties opposing the SAC. The record supports the claims
of the opposing parties that the SAC charge is not COS-based, despite the company’s
protestations to the contrary. Although the SAC charge is ostensibly designed to
recover costs associate[d] with DG customers’ more extensive use of the grid, as
attested to by Mr. Serna and Mr. Mueller, as multiple parties point out, the cost is
actually designed to recover lost revenues resulting from customers’ decisions to
invest in DG. As ELPC argues, “DTE’s methodology explicitly relies on ‘revenue
deficiencies’ and not cost of service[,]” pointing to “Ex. A-16, Schedule F9, Lines 89 (calculating ‘annual distribution revenue deficiency’ and ‘monthly distribution
revenue deficiency’ for purposes of calculating the SAC). Lost revenues are not the
same thing as cost of service.”
Because the DG tariff approved under Section 6a(14), must be COS-based, and a
tariff including a SAC is not, it is not necessary to reach a determination on
whether the SAC charge is “equitable” as the statute also requires. Briefly,
however, and for completeness, the SAC charge is also not equitable. The fact that
the SAC charge is not based on a DG customer’s actual usage of DTE Electric’s
distribution system but rather on the size of the customer’s system. [PFD, pp 28586. Footnotes omitted.]
The Company takes exception as discussed below.

The issues are also discussed in detail in DTE Electric’s Initial and Reply Briefs, which are incorporated by reference
for a fuller discussion of the issues, as well as in response to other parties’ anticipated exceptions.
81

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 i.

Without the SAC, the Company would not recover the full
cost of DG customers’ distribution infrastructure use.

The PFD’s discussion skips over the whole point of the SAC charge, which is that DG
customers should pay for the distribution infrastructure they use. The PFD instead focuses on
criticizing the SAC methodology (which is inaccurate as discussed below), but it is important to
keep in mind throughout this discussion what the PFD is really recommending – that DG customers
pay nothing despite the facts that (1) their inflow (and the resulting Company cost recovery) is
reduced by the intermittent on-site usage of intermittent on-site generation; yet (2) the Company’s
fixed distribution system is and must always be available to serve the DG customer if the
customer’s generation system goes down and to balance, second by second, the changes in the
intermittent generation from the distributed generation system (8T 3897-98).
The PFD does not recognize this suggest that DTE Electric quantified the costs associated
with the SAC, stating:
To provide some scale to the company’s claims, the ALJ notes Mr. Serna’s
testimony: “Across a survey of five states and six utilities, and with cost shift
studies conducted by various parties including utilities, external experts, and state
utility commissions, the estimated range of distributed generation induced annual
cost shift is $444 to more than $1,700 per [non-DG] customer.” 8 Tr 2594.
Although somewhat dubiously sourced, assuming this information were accurate,
the purported subsidy paid by non-DG customers would range from about $0.50
to $1.90 (if Michigan were as sunny as Arizona) per customer per year. [PFD, p
274, n 666.]
The evidence entered in this case shows that there would be cost-shifting (non-DG
customers would subsidize DG customers) without the SAC. Mr. Serna explained that there is a
bidirectional relationship for distributed generation interaction with the grid, which is a physically
different relationship than that of a non-DG customer. This relationship and the services provided
by the grid are discussed in detail in the Electric Power Research Institute (“EPRI”) report titled
“The Integrated Grid” (Exhibit A-34, Schedule X-5). This EPRI report recognized that DG

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 customers receive significant value from grid services (8T 3670), and highlighted five services
that the grid provides to DG customers: 1) reliability (the grid serves as a rebalancing resource to
offset variable and uncertain output from distributed generation resources; 2) startup power, i.e.,
the grid provides instantaneous power for appliance startup that a PV system may not; 3) voltage
quality; 4) efficiency, which allows a DG resource to run at its optimum level without having to
adjust its output based on local load variation; and 5) energy transaction, or the ability to install
any size DER that can be connected to the grid (8T 3671-72). There was no party that disputed
the services provided by the grid or the results from the EPRI report.
Company witness Mueller testified that the average DG customer uses the grid more than
a non-DG customer and may actually add costs to the distribution system (8T 3804 - 3807). This
is in part due to the DG customer’s export of power onto the local grid (8T 3805). Mr. Serna also
testified that the Company has demonstrated that DG customers have a summer net peak demand
half a kW greater than the traditional residential Rate Schedule D-1 customers (See Exhibit A-16,
Schedule F11) (8T 3650).
The SAC accounts for all DG customers having 24/7 optionality to use the full capability
of the electric system (8T 3596). The costs have traditionally been recovered volumetrically, and
a portion of grid costs would still be recovered though the inflow charge. With the lower inflow
of DG customers, however, utility infrastructure costs would remain unrecovered and be shifted
onto the remaining traditional customers without the additional SAC (8T 3599). This concept has
been recognized by experts and many other jurisdictions are considering similar charges (8T 359697). Mr. Serna explained the need for this charge and thatDG customers also have a significantly
different load shape than traditional customers, and their bidirectional relationship with the electric
system is a fundamental distinction from traditional customers (8T 3591-92). Thus, without the

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 SAC, Rider 18 customers would avoid paying distribution costs, which represents a continuation
of the cost shift that the new DG tariff is intended to address (8T 3890, 3894-95).
The PFD did not recognize that the SAC would be recalculated based on updated cost and
usage data with each rate case (8T 3894). The SAC is also appropriately tailored to each customer’s
use of the distribution system because it is dependent on each DG customer’s installed capacity
(8T 3895)82 thus it is an appropriate charge to recover the costs that DTE Electric incurs to serve
DG customers.
Mr. Mueller responded to various assertions by witnesses attempting to justify continuing
DG subsidization (8T 3803-17). He stated that:
(1) An average DG customer uses the grid more than a non-DG customer (8T 3804-3806);
(2) An average DG customer does not use most of its own production on site to serve its
own needs (8T 3805-3806);
(3) DG customer solar operation does not substantially coincide with times of peak load on
the system in the Company’s service territory (8T 3806-3808);
(4) The proposition that there are insignificant system upgrade costs and impacts below
5% DG system penetration lacks any sound foundation (for example due to design flaws in an
underlying cost study) and is inaccurate (for example because DG installations tend to be clustered,
raising the local penetration and potentially overloading the transformer and raising the local
voltage, while the feeder level generation percentage would remain small). (8T 3808-13);

82

The Commission has also approved numerous charges that are fixed in nature (for example, the Service Charge),
and all the Company’s rates are based on averages to some extent. Rates are not designed for each individual customer
separately based on their specific use of the system (8T 3895).

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 (5) The proposition that DG customers off load the grid and can thus be used to satisfy load
growth and reduce grid investment is inaccurate. DG customers may offset some of their own load,
but they do not do so at peak times. Generation must also be schedulable and dispatchable
(available and reliable when needed) to offset grid investment. DG does not meet these criteria.
Instead, it is entirely dependent on the season, time of day and weather and cannot produce power
outside of solar hours. Indeed, these characteristics of intermittent DG generation cause problems
that require additional grid investments to maintain service, as recognized in the same MIT solar
report referenced by Mr. Kenworthy (8T 3813-14).
(6) There are significant grid impacts from the integration of DG into the distribution
system, as reflected by the Company’s discovery responses (relevantly compiled in Exhibit A-43,
Schedule GG-2), which highlight the range of grid impacts that DG imposes on the distribution
system, including: (1) local costs for upgraded services, secondary and transformers; (2)
protection-related costs for changes to fuses, relays and reclosers and their settings; (3) voltage
support related costs from settings changes to regulators or capacitors or potential installation of
new devices; and (4) additional operating costs from switching and safely working around
distributed generation including during restoration. DTE Electric stands by its discovery responses
regarding these DG issues. Moreover, these are not just issues that the Company identified - others
have identified the same issues (8T 3814-17. See also 8T 3650-53, 3664; Exhibit A-16, Schedule
F11, Exhibit A-34, Schedule X-3).
DTE Electric also notes that those parties advocating for continuing cost shifting to other DTE
Electric customers neglect that the Commission lacks authority to authorize cost shifting to subsidize

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 the DG industry83 and the Legislature has mandated the transition away from subsidized net metering
rates (e.g., 8T 3593-96).84
When viewed in light of the controlling law and record evidence, it becomes apparent that
the SAC charge appropriately seeks to make DG customers pay for costs that they cause. The
PFD’s recommendation that DG customers instead pay nothing (which effectively means that nonDG customers would have to pay the DG costs instead) should be rejected.
ii.

The SAC is cost-based.

The PFD opined that DTE Electric’s SAC proposal is not cost-based, but instead seeks to
recover lost revenue from energy that the Company would not supply to a DG customer (PFD, p 285,
quoted above). The PFD was apparently persuaded by ELPC and is accurate to the extent that it
recognizes that volumetric charges to DG customers will be reduced, but ignores that volumetric
inflow rates do not fully account for utility costs incurred on behalf of DG customers). However, this
results in distribution costs not being recovered from these customers absent some other mechanism
like the SAC. Distribution costs not recovered from DG customers represent a cost shift and burden

83

The MPSC has no common law powers, but only possesses the limited authority that the Legislature conferred upon
it. Consumers Power Co v Public Service Comm, 460 Mich 148, 155; 596 NW2d 126 (1999). The MPSC is an
“administrative body created by statute and the warrant for the exercise of all its power and authority must be found
in statutory enactments.” Union Carbide v Public Service Comm, 431 Mich 135, 146; 428 NW2d 322 (1988); Sparta
Foundry Co v Public Utilities Comm, 275 Mich 562, 564; 267 NW 736 (1936). The MPSC’s authority must be
conferred by clear and unmistakable statutory language, and a doubtful power does not exist. Mason Co Civil Research
Council v Mason Co, 343 Mich 313, 326-27; 72 NW2d 292 (1955). The MPSC cannot expand its jurisdiction through
its own acts or assumption of authority. Ram Broadcasting v Public Service Comm, 113 Mich App 79, 92; 317 NW2d
295 (1982).
84

Mr. Jester further suggested that even if all DG customers were net metered and did not pay any portion of the retail
rate, and that the utility is unable to avoid any costs as a result, then the maximum effect would be to shift about 1%
of costs to other customers, (6T 2202-2203). Mr. Dennis disagreed, explaining that the Company is proposing Rider
18 to comply with state law requiring the Company to file a cost-based and equitable distributed generation program
tariff. Regardless of the number of DG customers, if customers are not covering the cost for the services and
infrastructure they are utilizing, then those costs will be shifted to other non-DG customers (8T 3904). Mr. Serna
further discussed DG customers’ usage (“net load”) profiles and net load shape as reasons why the level of distributed
generation penetration should not be a factor in defining a new DG tariff (e.g., 8T 3668-69, 3674-75).

135

 imposed on non-DG customers. The Company’s proposal moves away from the cost shifts associated
with net metering to properly cost-based rates in accordance with well-established ratemaking
principles and as required by 2016 PA 342 (8T 3676-77). The PFD elsewhere recognizes that delaying
the implementation of cost-based DG rates is not a viable option (PFD, p 274).
The SAC is also supported by cost of service evidence on the record. Mr. Dennis explained
that the SAC was designed to recover fixed costs of the distribution system for both residential
and commercial secondary customers. The distribution costs being recovered are developed by
the Company’s cost of service witness Mr. Lacey (Exhibit A-16, Schedule F-1.2). Based on the
revenue requirement for these classes, DTE Electric developed a cost-based distribution charge
(line 5, Exhibit A-16, Schedule F9) which was used in development of the SAC. Thus, the SAC
is cost based (8T 3898; Exhibit A-42, Schedule FF2). The SAC is designed using the Company’s
distribution cost of service study (numerator) and the Company’s forecasted load (denominator)
so that the Company will recover its revenue requirement, nothing more or nothing less (8T 3899).
The PFD’s allegation that, “lost revenues are not the same thing as cost of service” (PFD, p 285)
in this instance is inapplicable. The Company did not argue SAC revenues should be recovered
simply because they are “lost” – the Company has shown, as explained above, the revenue
proposed to be recovered by the SAC is based on the amount the cost of service study shows these
customers should be paying based on the services they receive and the costs the company incurs
to provide those services.
The PFD suggests that the proposed SAC represents a “double-recovery of the utility’s
costs to deliver the DG exports” (PFD, p 284, quoting Mr. Kenworthy at 6T 2336). To the contrary,
Mr. Dennis explained that the SAC would not compensate the Company for a DG customer’s
outflow and would not double charge for distribution services. The Company calculated the SAC

136

 charge by utilizing on-site consumption, which does not include customer outflows (Exhibit A-16,
Schedule F9). Under the Company’s Rider 18 proposal, no charge is designed to apply distribution
charges to DG customers for outflow (8T 3898).
iii.

The SAC is not discriminatory.

The PFD suggests that the SAC is not equitable because it treats DG customers differently
than non-DG customers (PFD, pp 285-86, quoted above). To the contrary, there is nothing
inappropriate about treating different things differently, 85 and DG customers are plainly different
than other customers, as discussed above (for example, DTE Electric Witness Serna explained that
there is a bidirectional relationship for distributed generation interaction with the grid, which is a
physically different relationship than that of a non-DG customer at 8T 3671-72).86
As explained above, the SAC is designed to only recover DG customers’ allocable costs
of the Company’s distribution system (8T 3898-99). The Company’s proposed Rider 18 is also
just one of the various rate offerings that customers can choose if it suits their purposes.87
iv.

DG customers are not comparable to customers who reduce
consumption through energy efficiency or demand response
measures.

The PFD suggested that the proposed SAC would inappropriately treat DG customers
differently than non-DG customers, because both types of customers have variable usage (PFD, p
286, quoted above). Mr. Dennis explained that this is not an accurate comparison because DG
customers use the Company’s electric system to both receive and export energy, while non-DG

85

See generally, Goldstone v Bloomfield Twp Public Library, 479 Mich 554, 568-69; 737 NW2d 476 (2007) and
Crego v Coleman, 463 Mich 248, 258-59; 615 NW2d 218 (2000).
86

See also the EPRI report titled “The Integrated Grid” (Exhibit A-34, Schedule X-5).

87

The PFD did not indicate that it found any merit in suggestions that the SAC charge would somehow be illegal. The
record further reflects that the Company’s proposal complies with Michigan law and does not conflict with any federal
law (8T 3649).
137

 customers just use the system to receive energy. Thus, for example, energy efficiency customers
reduce inflow and truly consume less energy, but a DG customer reduces inflow only when onsite generation is generating. Also, the on-site generation does not reduce the amount consumed
on site (i.e. the amount the Company must be ready to serve at any point in time). (8T 3903-3904).
Staff similarly recognized that “EWR is basically incapable of reducing a customer to no net load
served by the utility” (8T 4233). This is a critical difference that creates a cost responsibility that
cannot be ignored (8T 3668, 3673-74). Mr. Serna further explained that DG customers are
different than voluntary demand response customers:
For demand response, the risk is very low that the assumed capacity reductions
will not occur as expected by DTE Electric. For distributed generation, the lack of
specific performance requirements and lack of control by the Company makes it
much less likely that a capacity contribution will be available at the time the
Company needs it… [D]istributed generation customers under net metering have
little to no incentive to manage their level and timing of power inflows and
outflows, as their customer bills are essentially invariant to their level of onsite
generation. Thus, there is also no incentive for a distributed generation customer
to address equipment problems when there is no contribution to the utility’s
capacity requirements. [8T 3656-59].
In summary, the SAC appropriately seeks to recover costs that DG customers impose, and
that would otherwise be shifted to non-DG customers. The SAC is also appropriately designed and
supported by cost of service evidence. Therefore, it should be approved.
3. Michigan Law sets the requirements for the outflow credit.
DTE Electric proposed an outflow credit that is consistent with the first option provided by
MCL 460.1177(4). Staff suggested a different interpretation of MCL 460.1177(4). The PFD found
that other parties’ proposals need not be discussed (PFD, p 274), and agreed with Staff, stating:
The ALJ agrees with the Staff, that the plain language of MCL 460.1177(4), when
read in its entirety, makes clear that the outflow credit, whatever [sic, whether?]
based on LMP or power supply less transmission, applies only to excess generation
above monthly consumption for the billing month (e.g., “the quantity of electricity
generated and delivered to the utility distribution system by an eligible electric
138

 generator during the billing period [that] exceeds the quantity of electricity
supplied from the electric utility during the billing period shall be credited[.]” The
ALJ also agrees with Staff that subparts (a) and (b) describe alternate pricing
mechanisms and that the language at the beginning of Section 177(4) cannot be
ignored. Again, as DTE Electric asserts, every word and phrase of the statute must
be given effect to avoid rendering any of the statute surplusage. Moreover, the ALJ
finds that this interpretation of the statute does not conflict with Section 177(5),
which only comes into play if “A charge for net metering and distributed
generation customers [is] established pursuant to section 6a of 1939 PA 3, MCL
460.6a[.]” Because the SAC was rejected, Section 177(5) does not apply.
Consistent with the analysis above, the Commission should approve the Staff’s
recommendation with respect to netting inflows and outflows. [PFD, pp 280-81.
Emphasis in original.]
The PFD neglects that MCL 460.1177 generally concerns electric meters and billing, as
stated in the title to that statute. MCL 460.1177(4) is specific with respect to the elements to be
included in the outflow credit as follows:
If the quantity of electricity generated and delivered to the utility distribution
system by an eligible electric generator during a billing period exceeds the quantity
of electricity supplied from the electric utility or alternative electric supplier during
the billing period, the eligible customer shall be credited by their supplier of
electric generation service for the excess kilowatt hours generated during the
billing period. The credit shall appear on the bill for the following billing period
and shall be limited to the total power supply charges on that bill. Any excess
kilowatt hours not used to offset electric generation charges in the next billing
period will be carried forward to subsequent billing periods. Notwithstanding any
law or regulation, distributed generation customers shall not receive credits for
electric transmission or distribution charges. The credit per kilowatt hours
delivered into the utility’s distribution system shall be either of the following:
(a) The monthly average real-time locational marginal price for energy at the
commercial pricing node within the electric utility’s distribution territory, or for
distributed generation customers on a time-based rate schedule, the monthly
average real-time locational marginal price for energy at the commercial pricing
node within the electric utility’s distribution service territory during the time-of-use
pricing period.
(b) The electric utility’s or alternative electric supplier’s power supply component,
excluding transmission charges, of the full retail rate during the billing period or
time-of-use pricing period. (Emphasis added).

139

 MCL 460.1177(5) further provides:
A charge for net metering and distributed generation customers established
pursuant to section 6a of 1939 PA 3, MCL 460.6a, shall not be reduced by any
credit or other ratemaking mechanism for distributed generation under this
section. (Emphasis added).
MCL 460.1177(4) plainly does not say what Staff proposed and the PFD now recommends.
Instead, as set forth in the Company’s briefs (Initial Brief pp. 148-151, Reply Brief pp. 215-219),
the statute simply provides for a billing credit where there are “excess kilowatt hours generated
during the billing period” instead of, for example, measuring on-site generation or providing that
utilities must bill total inflow and send checks to customers for their total outflow. The second
sentence of the statute states how the credit shall appear on bills, and further specifies that that the
credit “shall be limited to the total power supply charges on that bill.” The statute then goes on to
state that DG customers “shall not receive “credits for electric utility transmission or distribution
charges.” 88 There is only one provision in the statute that addresses the outflow credit:
The credit per kilowatt hours delivered into the utility’s distribution system shall
be either of the following:
(a) The monthly average real-time locational marginal price for energy at
the commercial pricing node within the electric utility’s distribution territory, or for
distributed generation customers on a time-based rate schedule, the monthly
average real-time locational marginal price for energy at the commercial pricing
node within the electric utility’s distribution service territory during the time-of-use
pricing period.
(b) The electric utility’s or alternative electric supplier’s power supply
component, excluding transmission charges, of the full retail rate during the billing
period or time-of-use pricing period.

MCL 460.1177(4)’s use of “shall” as well as the further use in MCL 460.1177(5) 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”).
88

140

 There is no mention of “excess kilowatt hours” as the PFD seems to suggest. Instead, the statute
discusses “excess kilowatt hours” in the prior provisions regarding billing, but later, concerning
the outflow credit, uses “kilowatt hours.”
The Legislature plainly was drawing a distinction and intended that the credit is to be
applied to “kilowatt hours delivered into the utility’s distribution system.” The statute’s plain
language must be applied as written.89 The Michigan Supreme Court also recently explained:
Generally, when language is included in one section of a statute but omitted from
another section, it is presumed that the drafters acted intentionally and purposely
in their inclusion or exclusion. Similarly, “[c]ourts cannot assume that the
Legislature inadvertently omitted from one statute the language that it placed in
another statute, and then, on the basis of that assumption, apply what is not there.”
People v Peltona, 489 Mich 174, 186; 803 NW2d 140 (2011), quoting Farrington
v Total Petroleum, Inc, 442 Mich 201, 210; 501 NW2d 76 (1993) (Emphasis
added; footnote omitted).
Mr. Serna also discussed the language changes in Act 342 as they relate to net metering
versus distributed generation (8T 3640-43). The table provided in Mr. Serna’s testimony also
provides a side-by-side comparison of the language in Act 342 and the corresponding sections of
Act 295.
The PFD was also apparently persuaded to simply follow Staff’s recommendation because
the Commission addressed this issue in its April 18, 2018 Order in Case No. U-18383. The issue
merits more consideration than it has received, however, and the current PFD/Staff position is
contrary to statutory requirements, as indicated above. In Case No. U-18383, the Commission

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”).
89

141

 recognized the arguments made by DTE Electric and Consumers Energy that MCL 460.1177(5)
restricts the Commission from approving outflow credits from offsetting any distribution charges
applied to inflow since those charges are intended to recover the COS pursuant to Act 341. The
Commission found that “this prohibition is explicitly directed toward credits for the portion of outflow
that exceeds inflow under the modified net metering billing method” (Case No. U-18383 April 18,
2018 Order, at 14-15) The U-18383 Order also stated that “[s]ection 177 does not apply to any DG
billing method, such as the Inflow/Outflow billing mechanism, that implements a COS based tariff
under Act 341, Section 6a(14).” (Id. at 15) However, if Section 177(5) was directed only at modified
net metering customers, the statute would not have referenced both “net metering and distributed
generation customers.” Reading the term “distributed generation customers” out of Section 177(5)
renders that term surplusage or nugatory in contradiction to defined statutory construction case
law.90 Moreover, the statute broadly refers to “any credit or ratemaking mechanism” and not to a
specific credit granted to modified net metering. In addition, Section 177(5) specifically refers to
charges, “established pursuant to section 6a of 1939 PA 3, MCL 460.6a”, and thus the U-18383 Order
statement that Section 177 does not apply to any tariff under Act 341, Section 6a(14) is contrary to
the language of Section 177.
Section 177(4) plainly says: “Notwithstanding any law or regulation, Distributed Generation
customers shall not receive credits for electric utility transmission or distribution charges.” The
PFD/Staff’s interpretation leaves unexplained how the broad and unlimited directive that
“notwithstanding any law or regulation” distributed generation customers shall not receive credits for

“Effect must be given to every word, phrase, and clause in a statute, and the court must avoid a construction that
would render part of the statute surplusage or nugatory.” Book-Gilbert v Greenleaf, 302 Mich App 538, 541; 840
NW2d 743 (2013); Jenkins v Patel, 471 Mich 158, 167; 684 NW2d 346 (2004) (“Courts must give effect to every
word, phrase, and clause in a statute and avoid an interpretation that would render any part of the statute surplusage
or nugatory”)
90

142

 electric utility transmission and distribution could somehow reasonably be interpreted as anything
other than a universal restriction on such credits.
Section 177(5) also confirms that “any charge for net metering and distributed generation
customers established under [MCL 460.6a] shall not be reduced by any credit or other ratemaking
mechanism…” The PFD offers no analysis, but instead only states: “Moreover, the ALJ finds that
this interpretation of the statute does not conflict with Section 177(5), which only comes into play
if ‘A charge for net metering and distributed generation customers [is] established pursuant to
section 6a of 1939 PA 3, MCL 460.6a[.]’ Because the SAC charge was rejected, Section 177(5) does
not apply” (PFD, p 281). The PFD’s conclusion does not withstand reasoned scrutiny. Section 177(5)
contains no “if” qualification and does not refer to only certain situations in which it “comes in to
play.” If Section 177(5) was only to come in to play under certain situations, the legislature surely
could have crafted it to say so. The plain reading of Section 177(5) states that a charge for
distributed generation customers established pursuant to section 6a of 1939 PA 3, MCL 460.6a
shall not be reduced by any credit or other ratemaking mechanism for distributed generation. To
ignore this provision of the law by apparently suggesting no charges will be established pursuant
to section 6a of 1939 PA 3, MCL 460.6a is flawed. Again, nowhere in the law does it suggest
177(5) only applies “if” a charge is established, it simply states, “a charge established”. Public Act
342 of 2016 added this section to limit the amount of charges that can be reduced by any credit or
ratemaking provision of the distributed generation program. The statutory language is clear. Indeed,
it is hard to conceive of a clearer Legislative intention. Therefore, the PFD’s recommendation should
be rejected.
Moreover, Act 342 requires programs to be “cost effective” (MCL 460.1001(2)) and Act 341
requires that: “In establishing cost of service rates, the commission shall ensure that each class, or

143

 sub-class, is assessed for its fair and equitable use of the electric grid.” MCL 460.11. As proposed,
DTE Electric’s outflow credit model is consistent with MCL 460.1001(2), MCL 460.11 and MCL
460.1177(4).91 The Legislature has also twice (once in 2008 PA 295 and again in 2016 PA 342) made
clear that there cannot be credits for transmission or distribution associated with net metering and/or
distributed generation.
Further, during examination by MEC/NRDC/SC, Company witness Serna also made it
clear that customer credits apply to all generation delivered into the utility’s distribution system:
Q. O.K. And as I understand your testimony, you interpret credit to mean that any
recognition of exports from a customer generator to the distribution grid falls
within the meaning of credit. Is that fair?
A. I believe that the, for the power that is delivered into the electric distribution
system, I believe that to mean the Outflow rate, and that's why I believe that the
Outflow rate should be set on any of these two options.
Q. So my question is: Any outflow, if we're going to recognize that outflow from
customer generator to distribution grid, we need to call that a credit? That's your
premise; is that fair?
A. I do believe that it is a credit. That the customer is getting a credit for that power
that he is delivering to the distribution system, and as such deserves to receive
some value for that power that he is delivering and a credit for that power that he's
delivering to the system.
Q. Is there any definition of the term credit that you're aware of that provides that
definition that you're applying?
A. When I read the legislation and look at the language on how it is structured and
how I have analyzed, I do think that the word credit in this context -- I'm not being
the legal expert -- indicates that for that power that is delivered, and under the
proposed Inflow/Outflow method you have to apply a particular mechanism that
91

In addition, the Legislature changed statutory language to remove the net metering references from section MCL
460.1177(4) and instead used the words “distributed generation,” so that section does not simply apply to grandfathered
net metering customers as has been suggested. The suggestion that the Company’s interpretation would render the
inflow/outflow model invalid similarly neglects that the applicable statutory language (“The credit per kilowatt hour for
kilowatt hours delivered into the utility’s distribution system shall be either of the following…”) plainly indicates that the
credits do not apply to generation used onsite. This plain language also reflects that the customer credit choices set forth
in MCL 460.1177(4) apply to ALL kilowatt hours “delivered into the utility’s distribution system,” not just the net outflows
(8T 3639-44).
144

 the Company is proposing from the Commission, it then does follow that it applies
to that Outflow rate that we are proposing for that customer to be credited for.
That's how I interpret the legislation, coupled with the proposal that we made in
front of the Commission, and the concept of crediting those powers, that power
delivery to the distribution system, at any of these two mechanisms. I will further
say that that was what the Staff proposed. That was one of the two mechanisms, is
what the Staff itself proposed as part of their rebuttal -- as part of their direct
testimony, Mr. Ozar. (8T 3718-3719)
It also bears emphasis that the Legislature considered how electricity delivered to the utility’s
distribution system should be compensated and provided only two potential approaches: LMP (the
Company’s proposal) or power supply less transmission costs (Staff’s proposal). If the Legislature
believed that compensation for electricity delivered to the utility distribution system could be set
differently or should continue to be debated (as some other parties have suggested), then the
Legislature “surely could have said so.”92 It is also no mere coincidence that the two statutorily
established options to compensate for power delivered to the electric distribution system do not
include either a transmission or a distribution credit, which is consistent with the concept that there
shall be no credit applied to transmission and/or distribution (8T 3647-48).
4. LMP is the appropriate choice for the outflow credit.
DTE Electric maintains that it is appropriate to use the LMP as the outflow credit because
it provides cost-based compensation as it is the actual cost at which energy is traded on wholesale
markets. The LMP is the market construct that most closely aligns with DG behavior, since DG
customers make no commitment to DTE Electric regarding the volume or timing of their output
(8T 3602. See generally, DTE Electric’s Initial Brief, pp 151-54). Staff proposed to instead base

92

Lash v Traverse City, 479 Mich 180, 189; 735 NW2d 628 (2007); see also, People v McIntire, 461 Mich 147, 160;
599 NW2d 102 (1999).

145

 outflow compensation on the Company’s power supply component less transmission costs (Staff
Initial Brief, pp 100-102). The PFD agreed with Staff, stating in part:
This PFD finds that the Staff’s proposal for calculating the outflow credit, based
on power supply less transmission is reasonable and well supported by the record.
As the Staff points out, the company’s outflow compensation based on LMP, as
originally proposed, assumes that DG outflows have zero capacity value. [PFD, p
277.]
The Company is pleased that Staff proposed one of the two alternatives provided by the
Legislature (discussed above), but disagrees with the PFD’s recommendation, which is based on the
proposition that DG customers should be viewed in the aggregate. As further discussed below,
there is no data to support the proposition that distributed generation customers, on an aggregate
basis, provide peak relief to the Company, and pointing to other jurisdictions provides no
meaningful evidence with regard to DTE Electric’s system (8T 3651-52).
Mr. Serna testified why using the LMP is an appropriate and predictable compensation
method because there is only a 1 cent difference between on and off peak rates, and that the
maximum price differential across three years was only $18.15, which when compared to the level
of investment in a DG system seems negligible (8T 3662-3663). Additionally, when the final
outflow is determined, the differentials decrease even further (8T 3663). Moreover, there is no
avoided capacity value.

As Mr. Serna pointed out, under DTE Electric’s proposed tariff,

distributed generation avoids the entire power supply portion of their bill (energy and capacity) for
every kWh generated and used on site (8T 3651).
Mr. Serna’s rebuttal testimony further explained why setting the outflow compensation at the
real-time marginal LMP is the most appropriate methodology (8T 3650-55). For example, under the
Company’s proposal “distributed generation customers receive the capacity benefit for all the
generation that is produced and consumed onsite” (8T 3651). He further observed that despite a

146

 nearly year-long effort, the DG Workgroup led by Staff identified no data proving that DG
customers provide peak relief to DTE Electric (8T 3651). 93 Witness Serna confirmed that behind
the meter DG does not qualify for MISO capacity credits (8T 3653). Finally, Witness Serna
correctly observed that DTE Electric has no temporal production contract with DG customers and
no party has proposed that DG customers be subject to specific generation performance
requirements:
The commercial value of electric generation is, of course, significantly affected by
the purchaser’s ability to predict and rely upon proper and timely delivery of a
specific amount of electric energy – and to be properly compensated when the
seller fails to meet those expectations. DTE Electric is, of course, in the business
of selling electric generation to retail electric consumers. Hence my point that a
renewable-based, intermittently generating distributed generation customer that is
likely not an electric generation expert or principally engaged in the activity of
generating electricity provides relatively little assurance that it will operate its
generation in a manner that furthers the Company’s retail electric business. [8T
3656.]
Any outflow credit based on power supply less transmission could exceed the total power
supply portion of a customer’s bill. Exhibit A-42, Schedule FF1, illustrates how a customer taking
service under the Company’s proposed rates for Residential Time of Day Service Rate Schedule
D1.2 (D1.2) could offset both power supply and distribution costs if the outflow credit was based
on power supply less transmission rates.94 This illustrates an additional reason why the Company’s
proposal to set the outflow credit equal to LMP and limit the application of outflow credit to the

93

Staff acknowledged this fact. (8T 3432)

94

Exhibit A-42, Schedule FF1 shows a simplified bill calculation of a D1.2 customer with Rider 18 using the
Company’s proposed D1.2 rates and Staff’s proposed Rider 18 methodology (bill reflects June-October pricing, and
excludes surcharges). It assumes an on peak inflow of 100 kWh, an on peak outflow of 400 kWh, an off-peak inflow
of 400 kWh, and an off-peak outflow of 100 kWh. Pursuant to Staff’s proposal, the outflow credits are set equal to
the power supply component of the D1.2 rate, less Staff’s proposed D1.2 transmission rate. The Exhibit shows on
line 22 that the total outflow credit is over $73, which offsets the entire power supply component of the bill
(approximately $42 on line 14), and a major portion of the distribution component of the bill (line 18). The total bill
in this example falls to $7.88 (line 23), which is less than even the Company’s proposed service charge of $9.00 (line
16) (8T 3889).
147

 power supply component of a customer’s bill is both reasonable and complies with PA 342.
Otherwise, a DG customer could just select whichever retail rate will maximize the outflow credit
and potentially offset significant amounts of distribution charge (8T 3889-90).
After considering the various comments, the Company proposed an alternative where
distributed generation customers could receive generation capacity credits in the outflow rate, but
only if they sign up for the Company’s Dynamic Peak Pricing (“DPP”) rate, which is further discussed
in DTE Electric’s Initial Brief, pp 152-54. 95 The PFD observed that there appeared to be interest in
the Company’s alternative proposal, and that it should be explored in a future proceeding (PFD,
pp 277-78). DTE Electric agrees if its approach to compensate outflow using LMP is adopted.
The Company’s proposal is a reasonable and prudent approach to provide a capacity credit, where no
data exists to indicate that a capacity credit should be provided for these customers that are not
providing any assurances to the Company that their generation output will be made available at the
time and location needed in the Company’s electric system.
The PFD states, “Staff’s proposal for calculating the outflow credit, based on power supply
less transmission is reasonable and well supported by the record. As the Staff points out, the
company’s outflow compensation based on LMP, as originally proposed, assumes that DG
outflows have zero capacity value.” (PFD, p 277) There is no explanation, however, as toTherthere
how the Company’s position is flawed and the PFD identifies no specific record evidence provided
by Staff to support the notion that distributed generation outflow provides a capacity value equal
Exhibit S-16.3 calculated the transmission unbundled rates for use in Staff’s proposed DG tariff, and Staff indicated
that these rates should either be shown on individual tariffs, or included within the DG tariff, and recalculated each
case to ensure appropriate DG compensation (8T 4301). If the Commission approves Staff’s proposed outflow
compensation method (which would be inappropriate), then (to avoid unjustified burdens and complexity) the
Company would support the alternative whereby the transmission rates would appear only on Rider 18, as opposed to
each individual rate schedule. If Staff’s proposal is accepted, the Company also agrees with Staff that the transmission
rates should be recalculated in each general rate case (8T 3891-92).
95

148

 to the full embedded cost of capacity present in power supply rates less transmission. In fact, Staff
Witness Ozar appears to concede that there is no present evidence of any capacity value for DG.
He testified that:
Given that DTE’s DG program is composed of multiple small end-users, and given
the diversity of DG customers, it is reasonable for DTE to undertake a poweroutflow study subsequent to implementation of the Inflow/Outflow tariff to confirm
that the coincident aggregate program power-outflows are relatively stable, and
predictable, irrespective of any individual DG customer’s power output, and to
quantify the effective DG outflow capacity and associated value. [8T 3431].
Thus, the record reflects that, while acknowledging a present lack of evidence and
quantification of DG outflow capacity and associated value, Staff merely suggests that DTE
Electric, nevertheless, compensate distributed generation customer outflow using the full power
supply rate less transmission which results in a capacity value being paid to DG customers. Thus,
the PFD’s conclusion that Staff’s positions in this regard are “reasonable and well supported by
the record” cannot withstand scrutiny.
The PFD also recommends that, “the Commission should approve the Staff’s
recommendation with respect to netting inflows and outflows.” (PFD p 281) The Company is
somewhat confused with this finding and what it is intended to suggest, as Staff’s proposed
Distributed Generation Program does not propose to net inflow and outflows. Staff’s proposed
tariff (Staff Exhibit S-11.0) proposes that outflow, defined as the metered quantity of the
customer’s generation not used on site and exported to the utility, be credited, and that inflow,
defined as the metered inflow delivered by the Company to the customer, be billed according to
the retail rate schedule.

Thus, the Company clarifies that Staff’s proposed inflow/outflow

methodology does not include netting inflows and outflows (this is further made clear in Staff’s
testimony, 8T 3423, 3436-7, and in Staff’s Initial Brief.)

149

 Finally, in regard to excess outflow credit balances, the PFD states, “The company’s
position now is that customers moving out of their residences should receive a refund of any
unused credit balance. However, customers who end their participation in the program and remain
in the residence, will have any banked credits applied to future bills.” (PFD p. 287). This misstates
the Company’s position on this matter, which was that customers moving out of their residence
should forfeit any unused outflow credit, and that if a customer remained at the same residence
that they should be able to continue to use their credit banks to offset power supply charges for up
to twelve months (8T 3892)
The PFD recommends that the Company and Staff work together informally to find a
mutually agreeable way to both provide information on the interconnection costs charged to DG
customers that Staff requests (in some aggregated form perhaps) and protect customer privacy
(PFD p. 287). While the Company appreciates the ALJ’s suggestion that the Company work
together to achieve this reporting if Staff’s proposal to report on interconnection costs is accepted,
the PFD did not mention several other concerns the Company has with Staff’s proposal. The
proposed reporting will not achieve its intended purpose as a pricing signal to other developers, as
interconnection costs will be highly dependent on the type of generation, size of the generator, the
distance from existing DTE Electric facilities, and the location of the generator and its proximity
to other generators on the system. The pricing signal would give an inaccurate picture of the actual
costs that may be incurred at any given location (8T 3797). Furthermore, it is an unprecedented
request that will raise the general cost to administer the DG program which would have to be
passed along to all DTE Electric customers (8T 3798). Finally, the scope of the proposed reporting
is unclear (8T 3796). Thus, Staff’s proposed reporting on interconnection costs should be rejected.

150

 5. DTE Electric’s proposal to limit the existing Standard Contract Rider
DG to non-renewable generation should be approved.
Staff asserted that the Commission should not approve DTE Electric’s proposal to limit the
existing Standard Contract Rider No. DG to non-renewable types of generation. DTE Electric
disagrees because there is no requirement for the Company to offer additional customer-owned
renewable generation tariffs, such as Rider DG. 2016 Public Acts 341 and 342 contain explicit
direction on creating a distributed generation program and tariff for customer-owned renewable
generation, and the law outlines specific conditions under which customer owned renewable
generation resources qualify for a distributed generation program. The Company is not presently
choosing to provide additional programs at this time. Nevertheless, the PFD agreed with Staff’s
recommendation for a directive, stating:
The PFD agrees with the Staff that Rider 14 (f/k/a Rider DG) should remain open
to customers who do not qualify for Rider 16 or Rider 18. As discussed above,
Union Carbide does not apply in this circumstance, in light of the fact that the
issue concerns an existing tariff (and rate) which should be made available to
customers who do not qualify for Rider 16 or Rider 18. Thus, except for the name
change to Rider 14, the Rider DG tariff should not be revised or closed to
additional renewable generators. [PFD, pp 288-89].
The PFD neglects the guidance of Union Carbide v Public Service Comm, 431 Mich 135;
428 NW2d 322 (1988), where our Supreme Court explained:
The power to fix and regulate rates, however, does not carry with it, either explicitly
or by necessary implication, the power to make management decisions.
‘It must never be forgotten that while the State may regulate with a view to
enforcing reasonable rates and rates, it is not the owner of the property of public
utility companies and is not clothed with the general power of management incident
to ownership.’ Missouri ex rel Southwestern Bell Telephone Co v Public Service
Comm, 262 US 276, 289; 43 S Ct 544, 547; 67 L Ed 981 (1923).” 431 Mich at 14849. See also Consumers Power Co v Public Service Comm, 460 Mich 148, 157; 596
NW2d 126 (1999).

151

 The PFD suggests that anything involving “an existing tariff (and rate)” is within the
Commission’s authority. Instead, the Commission’s authority is limited.

96

The Commission has

“ratemaking” authority; however, almost any aspect of DTE Electric’s business the Commission
regulates may affect rates to some degree, and the Commission cannot expand its authority by
mischaracterizing its decision as “ratemaking.” See Consumers Power Co v Public Service Co,
460 Mich 148, 157-58; 596 NW2d 126 (2004) (rejecting MPSC’s “ratemaking” defense and
vacating MPSC’s order as unlawful).
DTE Electric is not presently choosing to provide additional programs, as indicated above.
The Staff’s contrary proposal (and now the PFD’s recommendation) is inappropriate in the absence
of the Company’s agreement. The PFD recommendation to unilaterally change DTE Electric’s
program unlawfully encroaches on utility management, as illustrated by Ford Motor Co v Public
Service Comm, 221 Mich App 370, 385, 387-88; 562 NW2d 224 (1997), where DTE Electric
proposed a demand side management (“DSM”) program. The Commission modified that proposed
program. The Court of Appeals held that the Commission’s modification of DTE Electric’s DSM
program was unlawful, explaining in part: “The PSC here exceeded its ratemaking authority by,
in effect, requiring Detroit Edison’s management to adopt the DSM program the PSC thought best.
The PSC did significantly more than ‘approve’ the DSM program proposed by Detroit Edison.”
562 NW2d at 234-234. See also Attorney General v Public Service Comm, 269 Mich App 473;

96

The MPSC has no common law powers, but only possesses the limited authority that the Legislature conferred upon
it. Consumers Power Co v Public Service Comm, 460 Mich 148, 155; 596 NW2d 126 (1999). The MPSC is an
“administrative body created by statute and the warrant for the exercise of all its power and authority must be found
in statutory enactments.” Union Carbide v Public Service Comm, 431 Mich 135, 146; 428 NW2d 322 (1988); Sparta
Foundry Co v Public Utilities Comm, 275 Mich 562, 564; 267 NW 736 (1936). The MPSC’s authority must be
conferred by clear and unmistakable statutory language, and a doubtful power does not exist. Mason Co Civil Research
Council v Mason Co, 343 Mich 313, 326-27; 72 NW2d 292 (1955). The MPSC cannot expand its jurisdiction through
its own acts or assumption of authority. Ram Broadcasting v Public Service Comm, 113 Mich App 79, 92; 317 NW2d
295 (1982). The MPSC cannot re-write the Legislature’s language to include new or different provisions. Hanson v
Mecosta Co Rd Comm, 465 Mich 492, 501-503; 638 NW2d 396 (2002). If an MPSC order conflicts with a statute, the
order is void. Manufacturers Nat’l Bank v DNR, 420 Mich 128, 146; 362 NW2d 572 (1984).
152

 713 NW2d 290 (2005) (MPSC exceeded its authority when it ordered the utility to expand its
“green power” program and required customers who did not participate in the program to subsidize
its costs).
6. Transition from Rider 16 to Rider 18.
DTE Electric proposes to add language to its existing net metering tariff, Rider 16, to state
that Rider 16 will be unavailable for new customer on-site generation after the new DG program
(Rider 18) is approved, unless the customer has submitted a completed Rider 16 application to the
Company that is still pending before the Commission issues its order in this case (8T 3607-3608,
3877-78, 3900-01). Staff agreed with the Company’s proposed language (Staff Initial Brief, p 141).
The PFD agreed, but further recommended that “a customer who has an application filed with the
utility before the effective date of the DG tariff may still be allowed to participate in net metering
if the application is found deficient, provided the applicant cures the deficiency within 60 days”
(PFD, p 291).
DTE Electric disagrees with the suggested 60 days to cure a deficiency because it would
essentially invite incomplete applications to be submitted (contrary to the undisputed completion
requirement) by providing another 60 days to cure that deficiency (the incompletion). DTE Electric
maintains that its proposed language is appropriate. Mr. Mueller added that any new requirements
necessary to make an application complete based upon DTE Electric’s own rules would only apply
going forward, and not to applications that had already been deemed complete. DTE Electric would
also incorporate changes to interconnection requirements, the details of which presumably will be
determined during the stakeholder process established in Case No. U-20344 (8T 3799).
For the reasons outlined above and further explained in DTE Electric’s Initial and Reply
Briefs and on the record, DTE Electric’s Rider 18 and related DG proposals should be approved.

153

 H.

Retail Access Service Rider (RASR) changes.

DTE Electric proposes to change the Retail Access Service Rider (“RASR”) (EC2)
conditions for Retail Access Service (Electric Choice) customers to return to full service. The
Company proposes that the less-restrictive return-to-service provisions now applicable to
residential customers be implemented for all customers, since the more restrictive provisions now
applicable to non-residential customers are no longer necessary. Mr. Bloch testified that the returnto-service provisions were established in 2004 to provide adequate planning time and ensure that
returning customers did not cause undue power supply costs to be borne by other full-service
customers. Subsequently, 2008 PA 286 established a 10% cap on Retail Access Service, which
created stability in the Company’s ability to plan for its customers’ needs. The 10% cap was
maintained by 2016 PA 341, which also introduced the State Reliability Mechanism (“SRM”) to
ensure reliable electric service and sufficient capacity resources to Michigan customers. A March
14, 2018 report in Case No. U-18441 reflects that all Alternative Electric Suppliers (“AESs”) with
customers participating in the Company’s Retail Access Service program have demonstrated that
they have sufficient capacity to serve all of their customers for the next four resource adequacy
planning years (June 1, 2018 through May 31, 2022), so the Company will not be required to
secure adequate capacity to serve these customers during this period. After May 31, 2022, if AESs
are unable to secure adequate capacity for their customers, the SRM capacity charge is the
appropriate mechanism to ensure that the Company’s full-service customers are not subsidizing
the capacity requirements of Retail Access Service customers (5T 1230-31).
The PFD instead agreed with Energy Michigan’s proposal to retain both return-to-service
option provisions (PFD, p 298). The Company disagrees. The Company’s proposed changes are
intended to simplify return to full service rules and for consistency and fairness have all full-service
customers operate under the same minimum 12-month rate commitment specified in the
154

 Company’s tariff, Section C4.4. As a practical matter, keeping a short-term option provides no
additional customer flexibility and costs the Company to maintain that option. Currently, any
customer returning to full service who would like to take retail access service again must follow
the allotment process as defined in the April 28, 2017 Order in Case No. U-15801 et al. DTE
Electric reached its 10 percent cap on retail access service participation in November 2009 and
few additional customers have been awarded an allotment to participate since then. Therefore,
there is no need for a short-term return to full service provision as it provides no value to a
customer, which is evident from the fact there are currently no customers taking Option 2 – ShortTerm Service. Eliminating the short-term option would also eliminate any gaming concerns
associated with short-term rate switching (5T 1259-60).
VII.

REQUEST FOR RELIEF
DTE Electric respectfully requests that the Commission issue its final order in this case in

accordance with the PFD as modified by the discussion above:
A.

Granting DTE Electric’s request for final rate relief, as further supported and

explained in its Application, testimony, exhibits, Initial Brief (including Attachments A and B),
Reply Brief (including Attachments A and B), and these Exceptions (including Attachments A and
B ) approving rates that will recover the Company’s revenue deficiency of approximately $248.6
million, based on a May 1, 2019 through April 30, 2020 projected test year;
B.

Approving an annual revenue increase effective as soon as possible in the projected

test year;
C.

Approving DTE Electric’s proposed capital structure and return on equity;

D.

Granting DTE Electric’s request to implement an IRM and the associated

reconciliation process proposed by the Company;

155

 E.

Granting DTE Electric’s request for increased tree trimming expenditures, and the

associated request for regulatory asset treatment and securitization;
F.

Granting DTE Electric’s request to reverse the previous ruling in Case No. U-18255

related to time of use rates, or alternatively allow the Company to implement the transition over a
reasonable time period, and authorize deferral treatment and future recovery of the one-time
operating expenses associated with the transition;
G.

Approving the Company’s proposed Weekend Flex and Weekend Bill pilot

programs, and grant a waiver of the Commission’s Residential Billing Rules R 460.125 and
460.121;
H.

Approving the Company’s proposed electric vehicle program;

I.

Approving new rates effective as early as May 6, 2019 in the manner described in

the Company’s Application, testimony, exhibits, Initial Brief (including Attachments A and B),
Reply Brief (including Attachments A and B); and these Exceptions (including Attachments A and
B);
J.

Granting DTE Electric’s request to approve the PSCR base as requested by the

Company;
K.

Approving DTE Electric’s proposals to implement certain customer rate schedules

and tariffs;
L.

Approving recovery of DTE Electric’s generation investments;

M.

Approving recovery of DTE Electric’s investments related to the strengthening of

the Company’s distribution system and reliability improvements;
N.

Approving recovery of DTE Electric’s investments related to DSM, IT and

Corporate Staff;

156

 O.

Approving a capacity charge based on the methodology proposed by the Company

in this proceeding for calculating and applying the Capacity Charge Revenue Requirement;
P

Granting any accounting authority associated with this case not already the subject

of another application filed by the Company;
Q.

Approving the remainder of DTE Electric’s proposals and requested relief as set

forth in the Company’s Application, testimony, exhibits, Initial Brief (including Attachments A
and B), Reply Brief (including Attachments A and B), and these Exceptions (including
Attachments A and B; and
R.

Granting such other lawful relief that the Commission deems reasonable and

appropriate.
Respectfully submitted,
DTE ELECTRIC COMPANY

Digitally signed by Andrea
Andrea
Hayden
Date: 2019.03.25 16:03:18
Hayden
-04'00'
By:_________________________________

Attorneys for Applicant
Andrea E. Hayden (P71976)
Jon P. Christinidis (P47352)
David S. Maquera (P66228)
Patrick Carey (P41776)
Megan Irving (P75232)
Lauren Donofrio (P66026)
One Energy Plaza, 1635 WCB
Detroit, Michigan 48226
(313) 235-3813

Dated: March 25, 2019

157

 DTE Electric Company
Computation of Revenue Deficiency
for the 12 Month Period Ending April 30, 2020
($000)

Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17

MPSC Case No. U-20162
Exceptions
Attachment A
Page 1 of 4

(a)

(b)

(c)

(d)

Description

ALJ's
Proposal
For Decision

DTE
Exceptions

Company's
Exceptions
Position

Rate Base

$

Adjusted Net Operating Income

16,999,569

$

847,393

Rate of Return

$

(45,656)

5.48%

Income Requirements

152,779

17,152,348
801,737

0.237%

5.72%

931,614

49,106

980,720

Income Deficiency (Sufficiency)

84,221

94,762

178,983

Revenue Conversion Factor

1.3496

Revenue Deficiency (Sufficiency)

$

Tree Trim
Total Revenue Deficiency

113,667

1.3496
$

0
$

113,667

127,894

$

7,053
$

134,948

241,562
7,053

$

248,615

 DTE Electric Company
Rate Base - Average Net Plant
for the 12 Month Period Ending April 30, 2020
($000)

Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22

MPSC Case No. U-20162
Exceptions
Attachment A
Page 2 of 4

(a)

(b)

(c)

(d)

Description

ALJ's
Proposal
For Decision

DTE
Exceptions

Company's
Exceptions
Position

Plant in Service
Plant Held for Future Use
Construction Work in Progress
Acquisition Adjustments
Total Utility Plant

$

$

Less: Depreciation Reserve
Net Utility Plant

$

$

15,409,100

7,359
$

(1) $

$
(2)

151,985

15,527,486

$

15,521,162

$

16,999,569

15,561,085
6,222
112,164

$

151,985

$

15,679,471
0
6,324

$

151,985

$

15,673,147

1,478,407
$

21,314,373
57,923
1,679,418
116,148
23,167,862
7,606,777

6,324

Allowance for Working Capital
Rate Base

$

159,344
159,344

6,222
112,164

Less: Capital Lease Obligations
Net Plant

$

7,599,418

Net Capital Lease Property
Net Nuclear Fuel Property
Total Utility Property and Plant

21,155,029
57,923
1,679,418
116,148
23,008,518

794
$

152,779

(3)

1,479,201
$

17,152,348

Source Detail
(1) Plant in Service
Contingency - Combined Cycle
CHP
Rouge River Unit 3
Monroe Dry Fly Ash Processing
Charging Forward
Demand Side Mgmt (PCT)
IT - Customer Service Projects
IT Plant and Field Projects
IT - Information Technology for IT projects
Distribution Plant - Infrastructure redesign
Corporate Staff - 2018 underspend

Gross Amt
10,533
62,300
1,867
34,100
1,744
9,593
3,674
3,180
6,170
50,524
17,052

Rate Base Impact
8,217
51,059
1,167
21,767
872
7,880
2,144
1,846
4,452
42,890
17,052
$
159,344

(2) Depreciation Reserve
Contingency - Combined Cycle
CHP
Rouge River Unit 3
Monroe Dry Fly Ash Processing
Charging Forward
Demand Side Mgmt (PCT)
IT - Customer Service Projects
IT Plant and Field Projects
IT - Information Technology for IT projects
Distribution Plant - Infrastructure redesign
Corporate Staff - 2018 underspend

PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E

PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E

$

120
1,100
20
396
18
1,607
235
227
290
1,654
1,694
7,359
794
794

PFD Appendix E

$

(3) Working Capital
Charging forward regulatory asset

 DTE Electric Company
Adjusted Net Operating Income
for the 12 Month Period Ending April 30, 2020
($000)

Line
No.

1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25

MPSC Case No. U-20162
Exceptions
Attachment A
Page 3 of 4

(a)

(b)

(c)

(d)

Description

ALJ
Proposal
For Decision

DTE
Exceptions

Company's
Exceptions
Position

Operating Revenues
Sales Revenues
Other Operating Revenue
Fuel and Purchased Power
Net Margin
Operating Expenses
Operations and Maintenance Expenses
Depreciation and Amortization
Property Taxes
Other Taxes
Other Income/Deductions
Total Operating Expenses
Operating Income

$

4,695,905
90,345
1,385,795
3,400,455

$

$

50,289 (1) $
7,609 (2)

$

1,259,482
875,900
275,525
52,234
2,134
2,465,275

$

57,898

$

1,309,771
883,509
275,525
52,234
2,134
2,523,173

$

935,180

$

(57,898)

$

877,282

$

$

Other Operating Income Adjustments
Allow. For Funds Used During Constr
Amortization of Loss on Reacquired Debt
Total Operating Income Adjustments

$

PreTax Net Operating Income

$

966,862

$

69,296
50,173
847,393

Federal Income Taxes
State & Local Income Taxes
Net Operating Income

34,896
(3,214)
31,682

$

-

$

$

(1,923)

4,695,905
90,345
1,385,795
3,400,455

32,973
(3,214)
29,759

$

(1,923)

$

$

(59,821)

$

907,041

$

(10,769)
(3,396)
(45,656)

$

58,527
46,777
801,737

Source Detail
(1) O&M detail
- River Rouge 3
- Inflation
- Incentive Compensation
- Uncollectibles
- Incremental charging forward
- Meter reading

- Weekend Flex / Fixed Bill
- EEI Dues
-Tree trim

PFD page 48
PFD page 135
PFD page 171
PFD page 154
PFD page 213
PFD page 150
PFD page 173

17,650
12,338
27,083
234
1,168
2,147
1,408

PFD page 174
PFD page 147

1,269
(13,007)
50,289

O&M Adj
(2) Depreciation
Contingency - Combined Cycle
Monroe Dry Fly Ash
CHP
Rouge River Unit 3
Charging Forward
Demand Side Mgmt (PCT)
IT - Customer Service Projects
IT Plant and Field Projects
IT - Informaiton Technology for IT projects
Distribution Plant - Infrastructure redesign
Corporate Staff - 2018 Underspend

PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
PFD Appendix E
Depreciation Adj

$

158
653
35
980
36
1,576
429
369
334
1,767
1,270

7,609

7,609

 DTE Electric Company
Computation of Revenue Deficiency
Rate of Return Summary for April 30, 2020
Based on Average Rate Base

Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15

Description
ALJ's Proposal for Decision
Long-Term Debt
Preferred Stock
Common Shareholders' Equity
Total

MPSC Case No. U-20162
Exceptions
Attachment A
Page 4 of 4

Amount
($000)
$

Short-Term Debt
Job Development - ITC - Debt
Job Development - ITC Equity
Total Job Development - ITC
Deferred Income Taxes (Net)
Total

6,515,850
0
6,515,850
13,031,700

Percent
50.00%
0.00%
50.00%
100.00%

Cost %

37.94%
0.00%
37.94%

4.36%
0.00%
10.00%

112,875

0.66%

10,433
10,858
21,291

Weighted
Cost % (1)
2.18%
0.00%
5.00%
7.18%

Weighted
Cost %
1.65%
0.00%
3.79%

1.0000
1.3496
1.3496

1.65%
0.00%
5.12%

3.56%

0.02%

1.0000

0.02%

0.06%
0.06%

4.36%
10.00%

0.00%
0.01%

1.0000
1.3496

0.00%
0.0085%

4,006,648

23.33%

0.00%

0.00%

0.00%

17,172,514

100.00%

5.48%

6.81%

Company's Exceptions Position
16
17
18
19
20
21
22
23
24
25
26
27
28
29

Long-Term Debt
Preferred Stock
Common Shareholders' Equity
Total
Short-Term Debt
Job Development - ITC - Debt
Job Development - ITC Equity
Total Job Development - ITC
Deferred Income Taxes (Net)
Total

$

6,382,775
0
6,648,924
13,031,699

48.98%
0.00%
51.02%
100.00%

37.17%
0.00%
38.72%

4.36%
0.00%
10.50%

112,875

0.66%

10,433
10,858
21,291

2.13%
0.00%
5.36%
7.49%

1.62%
0.00%
4.07%

1.0000
1.3496
1.3496

1.62%
0.00%
5.49%

3.56%

0.02%

1.0000

0.02%

0.06%
0.06%

4.36%
10.50%

0.00%
0.01%

1.0000
1.3496

0.00%
0.01%

4,006,648

23.33%

0.00%

0.00%

0.00%

17,172,513

100.00%

5.72%

7.14%

 DTE Electric Company
Revenue Requirement Adjustments to PFD
for the 12 Month Period Ending April 30, 2020

MPSC Case No. U-20162
Exceptions
Attachment B
Page 1 of 1

($000)

(a)

Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45

Description

(b)
ALJ
Proposal
For Decision

(c)

(d)
Company's
Exceptions
Position

DTE
Exceptions

ALJ's Proposal for Decision

$

113,667

Adjustments to Revenue Deficiency:
Capital Structure
- ROE - 10% versus 10.5%
- Debt/Equity - 50/50 versus 49/51

(1)

44,889
12,147
Rate Base
Changes (2)
8,097
49,959
1,147
21,371
854
6,274
1,909
1,619
4,162
41,236
15,359
151,985

Rate Base - Net Plant
- Contingency - Combined Cycle
- CHP
- Rouge River Unit 3
- Monroe Dry Fly Ash Processing
- Charging Forward
- Demand Side Mgmt (PCT)
- IT - Customer Service Projects
- IT Plant and Field Projects
- IT - Informaiton Technology for IT projects
- Distribution Plant - Infrastructure redesign
- Corporate Staff - 2018 underspend

Attachment A page 2
Attachment A page 2
Attachment A page 2
Attachment A page 2
Attachment A page 2
Attachment A page 2
Attachment A page 2
Attachment A page 2
Attachment A page 2
Attachment A page 2
Attachment A page 2

Rate Base -Working Capital
- Charging forward regulatory asset

Attachment A page 2

Operations and Maintenance Expenses
- River Rouge 3
- Inflation
- Incentive Compensation
- Uncollectibles
- Incremental charging forward
- Meter reading
- Weekend Flex / Fixed Bill
- EEI Dues
-Tree trim

Attachment A page 3
Attachment A page 3
Attachment A page 3
Attachment A page 3
Attachment A page 3
Attachment A page 3
Attachment A page 3
Attachment A page 3
Attachment A page 3

17,650
12,338
27,083
234
1,168
2,147
1,408
1,269
(13,007)

Depreciation and Amortization

Attachment A page 3

7,609

Attachment A page 3 x 1.3496

2,595

Exhibit A-11, Sch A1

7,053
(37)

AFUDC grossed up
Tree Trim Revenue Requirement
Rounding
Total Adjustments to PFD Revenue Deficiency
Company's Exceptions Position

551
3,402
78
1,455
58
427
130
110
283
2,808
1,046

794

54

Line 6 through Line 41

$

134,948

Line 1 + Line 43

$

248,615

(1) PFD Rate Base $16,999 million x change in rate of return (0.272%) x revenue multiplier of 1.3496
(2) Rate Base Change multiplied by pre-tax return 6.81% (Attachment A p4)

 STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
In the matter of the application of
DTE ELECTRIC COMPANY for
authority to increase its rates, amend its
rate schedules and rules governing the
distribution and supply of electric energy,
and for miscellaneous accounting authority

)
)
)
)
)
)
)

Case No. U-20162

PROOF OF SERVICE
STATE OF MICHIGAN
COUNTY OF WAYNE

)
) ss.
)

ESTELLA BRANSON, being duly sworn, deposes and says that on the 25th day of March,
2019, she served a copy of is DTE Electric Company’s Exceptions to the Proposal for Decision, via
electronic mail upon the persons referred to in the attached service list.

Estella R.
Branson

Digitally signed by Estella R.
Branson
Date: 2019.03.25 16:00:23
-04'00'

ESTELLA BRANSON
Subscribed and sworn to before
me this 25th day of March, 2019.

Digitally signed by Lorri
Lorri A.
A. Hanner
Date: 2019.03.25
Hanner
___________________________
16:03:56 -04'00'

Lorri A. Hanner, Notary Public
Wayne County, MI (Acting in Wayne County)
My Commission Expires: April 20, 2020

 MPSC Case No. U-20162
Page 1
ADMINIATRATIVE LAW JUDGE
ALJ Sally L. Wallace
7109 West Saginaw Hwy.
Lansing, MI 48917
wallaces2@michigan.gov
ABATE
Robert A.W. Strong
Clark Hill PLC
151 S. Old Woodward Avenue, Suite 200
Birmingham, MI 48009
rstrong@clarkhill.com
Bryan A. Brandenburg
Clark Hill PLC
212 E. Cesar E. Chavez Avenue
Lansing, MI 48906
bbrandenburg@clarkhill.com
CHARGEPOINT, INC.
Timothy J. Lundgren
Varnum LLP
201 N. Washington Square, Suite 910
Lansing, MI 48933-1323
tjlundgren@varnumlaw.com
Justin K. Ooms
Varnum LLP
333 Bridge St. NW
Grand Rapids, MI 49504
jkooms@varnumlaw.com
ENVIRONMENTAL LAW AND POLICY
CENTER/ECOLOGY CENTER/SOLAR
ENERGY INDUSTRIES
ASSOCIATION/VOTE SOLAR (ELPC et al)
Margrethe Kearney
1514 Wealthy Street SE, Suite 256
Grand Rapids, MI 49506
mkearney@elpc.org
jagada@elpc.org
Bradley Klein
Environmental Law & Policy Center
35 E. Wacker Drive, suite 1600
Chicago, IL 60601
bklein@elpc.org

ENERGY MICHIGAN
Timothy J. Lundgren
Laura Chappelle
Varnum LLP
201 N. Washington Square, Suite 910
Lansing, MI 48933
tjlundgren@varnumlaw.com
lachappelle@varnumlaw.com
Toni L. Newell
Varnum LLP
333 Bridge Street NW
Grand Rapids, MI 49504
tlnewell@varnumlaw.com
GREAT LAKES RENEWABLE
ENERGY ASSOCIATION;
RESIDENTIAL CUSTOMER GROUP
Don L. Keskey
Brian W. Coyer
University Office Place
333 Albert Avenue, Suite 425
East Lansing, MI 48823
donkeskey@publiclawresourcecenter.com
bwcoyer@publiclawresourcecenter.com
THE KROGER CO.
Kurt J. Boehm, Esq
Jody Kyler Cohn, Esq
Boehm, Kurtz & Lowry
36 East Seventh Street, Suite 1510
Cincinnati, OH 45202
kboehm@BKLlawfirm.com
jkylercohn@BKLlawfirm.com
MICHIGAN ATTORNEY GENERAL
Joel King
Assistant Attorney General
ENRA Division
525 W. Ottawa Street, 6th Floor
P.O. Box 30755
Lansing, Michigan 48909
KingJ38@michigan.gov
ag-enra-spec-lit@michigan.gov

 MPSC Case No. U-20162
Page 2
MICHIGAN CABLE
TELECOMMUNICATIONS ASSOC.
Michael S. Ashton
Anita G. Fox
Fraser Trebilcock Davis & Dunlap
124 West Allegan Street, Suite 1000
Lansing, MI 48933
mashton@fraserlawfirm.com
afox@fraserlawfirm.com
MICHIGAN ENERGY INNOVATION
BUSINESS COUNCIL; INSTITUTE FOR
ENERGY INNOVATION
Laura Chappelle
Varnum LLP
201 N. Washington Square, Suite 910
Lansing, MI 48933
lachappelle@varnumlaw.com
Toni L. Newell
Varnum LLP
333 Bridge Street NW
Grand Rapids, MI 49504
tlnewell@varnumlaw.com
MICHIGAN ENVIRONMENTAL COUNCIL;
NATURAL RESOURCES DEFENSE
COUNCIL; SIERRA CLUB
Christopher M. Bzdok
Olson, Bzdok & Howard, P.C.
420 East Front Street
Traverse City, MI 49686
chris@envlaw.com
kimberly@envlaw.com
karla@envlaw.com
breanna@envlaw.com

MPSC STAFF
Spencer A. Sattler,
Amit T. Singh
Daniel E. Sonneveldt
7109 West Saginaw Hwy, 3rd Floor
Lansing, MI 48917
sattlers@michigan.gov
singha9@michigan.gov
sonneveldtd@michiagn.gov
mayabbl@michigan.gov
NicholsB1@michigan.gov
mpscredratecase@michigan.gov
SIERRA CLUB
Chinyere A. Osuala
cosuala@earthjustice.org
Shannon Fisk
sfisk@earthjustice.org
David Bender
dbender@earthjustice.org
SOULARDARITY
Lydia Barbash-Riley
Mark Templeton
Robert Weinstock
Rebecca Boyd
lydia@envlaw.com
kimberly@envlaw.com
templeton@uchicago.edu
rweinstock@uchicago.edu
rebecca.j.boyd@gmail.com
UTILITY WORKERS LOCAL 223
John A. Canzano
Ben King
423 N. Main Street, Suite 200
Royal Oak, MI 48067
jcanzano@michworkerlaw.com
bking@michworkerlaw.com
WAL-MART
Melissa M. Horne
Higgins, Cavanagh & Cooney, LLP
10 Dorrance Street, Suite 400
Providence, RI 02903
mhorne@hcc-law.com