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STATE OF MICHIGAN DEPARTMENT OF ATTORNEY GENERAL
P.O. BOX 30755 LANSING, MICHIGAN 48909
DANA NESSEL ATTORNEY GENERAL
January 11, 2019
Ms. Kavita Kale Michigan Public Service Commission 7109 West Saginaw Highway Lansing, MI 48917 Dear Ms. Kale: Re: MPSC Case No. U-20162
Enclosed find the Attorney General’s Initial Brief, and related Proof of Service.
Sincerely, Joel B. King Assistant Attorney General
cc: All Parties
STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
___________________________
In the matter of the application of DTE ELECTRIC COMPANY MPSC Case No. U-20162 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. /
ATTORNEY GENERAL INITIAL BRIEF
Dana Nessel Attorney General Joel B. King (P81270) Assistant Attorney General Special Litigation Division PO Box 30755 Lansing, MI 48909 517-373-1123
Dated: January 11, 2019
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TABLE OF CONTENTS Page
INTRODUCTION .......................................................................................................... 1
STATEMENT OF FACTS ............................................................................................. 2
ARGUMENT .................................................................................................................. 9
I. OPERATIONS AND MAINTENANCE EXPENSES ....................................... 10
A. Inflation Adjustment ................................................................................... 11
B. Power Generation O&M Expenses ............................................................. 17
C. Distribution O&M Expenses ....................................................................... 21
D. Customer Service and Marketing ............................................................... 27
E. Administrative and General Expenses ....................................................... 35
F. Pension and Benefits ................................................................................... 43
II. CAPITAL EXPENDITURES AND RATE BASE ............................................. 47
A. Contingent Capital Expenditures ............................................................... 48
B. Distribution Operations .............................................................................. 49
C. Power Generation ........................................................................................ 63
D. Corporate Staff Group ................................................................................. 68
E. Charging Forward EV Pilot ........................................................................ 72
IV. INFRASTRUCTURE RECOVERY MECHANISM ........................................... 75
V. DEPRECIATION EXPENSE ............................................................................. 80
VI. WORKING CAPITAL ADJUSTMENTS ........................................................... 81
VII. COST OF CAPITAL ........................................................................................... 84
VIII. RATE DESIGN ................................................................................................. 110
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IX. CONCLUSION AND RELIEF SOUGHT ........................................................ 111
1
INTRODUCTION The Attorney General of Michigan, Dana Nessel, by and through Joel B.
King, Assistant Attorney General, files this Initial Brief before the Michigan Public
Service Commission (“MPSC” or “Commission”) to respond to DTE Electric
Company’s (“DTE,” “DTE Electric,” or the “Company”) application seeking increased
revenue for its electric business.
After reviewing the testimony, exhibits, and discovery conducted in this case
and with the help of her expert witness, Mr. Sebastian Coppola, the Attorney
General concludes that the Company has a revenue deficiency for the projected test
year of approximately $78 million. Additionally, the Attorney General makes other
recommendations with regard to the Company’s filing as laid out in this brief.
On July 7, 2018, DTE Electric Company filed an application requesting
authority to increase its electric rates in the annual amount of $328 million and for
other relief. This $328 million calculation includes a $196 million negative rate-
adjustment for tax reform. This means that the total requested increase, excluding
the benefit to ratepayers of the tax reform, is in the annual amount of $524 million.
A prehearing conference was held on July 25, 2018 before Administrative
Law Judge (ALJ) Sally Wallace. At the prehearing conference, the ALJ granted
intervention to: the Michigan Department of the Attorney General (“Attorney
General” or “AG”), the Association of Businesses Advocating Tariff Equity (ABATE),
Energy Michigan, Residential Customer Group (RCG), Michigan Cable
Telecommunications Association (MCTA), ChargePoint, Inc., Environmental Law
2
and Policy Center/Ecology Center/Solar Energy Industries Association/Vote Solar
(ELPC et al.), Great Lakes Renewable Energy Association (GLREA), The Kroger
Co., Michigan Energy Innovation Business Council/Institute for Energy Innovation
(EIBC), Michigan Environmental Council (MEC), Natural Resources Defense
Council (NRDC), Sierra Club, Utility Workers Local 223 (UW 223), and Walmart
Inc. The MPSC Staff (Staff) also participated. Additionally, on August 14, 2018
Soulardarity filed a petition for leave to intervene out of time, which the ALJ
granted on August 21, 2018.
The case schedule was discussed at the prehearing and was set by the ALJ on
the record, as reflected in the July 25, 2018 Amended Scheduling Memo.
STATEMENT OF FACTS
Pursuant to the schedule set at the prehearing conference, all intervenors
were required to file direct testimony on or before November 7, 2018. Direct
testimony was filed on that date by the Attorney General, as well as MEC, Energy
Michigan Inc., Walmart Inc., ChargePoint Inc., Staff, the EIBC, Kroger, ABATE,
Soulardarity, ELPC, and GLREA.
DTE Testimony
DTE filed both direct testimony and rebuttal testimony to support its
requested revenue increase of $328 million. In its proposal, the Company’s
requested rate relief spans the 12-month period ending April 30, 2020 (“projected
test year” or “test year”).
3
The Company is also seeking incremental rate relief associated with $524
million of capital expenditures, over two years and eight months, included in the
Investment Recovery Mechanism (IRM). As part of its case, DTE is requesting a
return on equity (ROE) of 10.50% and an after-tax, overall rate of return of 5.76%
on its total rate base. The Attorney General would like to note up front that DTE is
making these requests and asserting that more than $500 million of rate relief is
necessary a mere three months after the Company was granted a rate increase of
approximately $65 million in its last gas rate case, U-18255. Additionally, this
request is coming 17 months after the Company was granted a rate increase of
approximately $184.3 million in its second-to-last gas rate case, U-18014. All of
that adds up to significant cost increases for customers in less than two years.
Attorney General Testimony
The Attorney General sponsored direct testimony and exhibits of its expert
Sebastian Coppola, which was filed on November 7, 2018. His direct testimony and
exhibits were bound into the record without cross examination by any party on
December 19, 2018. Mr. Coppola’s direct testimony consists of 103 pages along with
an Appendix A, which contains his qualifications (5 Tr 1586-1704) along with 33
exhibits. In addition, 16 additional exhibits, numbered AG-34 through AG-49, were
admitted during cross examination. The 49 total Attorney General exhibits are as
follows:
1. Exhibit AG-1 Actual O&M Expense Below Inflation Adjusted 2007-2017 2. Exhibit AG-2 O&M With AG Adjustments
4
3. Exhibit AG-3 Rate Case O&M Forecast versus Actual 2017 4. Exhibit AG-4 Power Generation O&M Adjustments 5. Exhibit AG-5 Distribution O&M Expense 6. Exhibit AG-6 Customer Service O&M Adjustments 7. Exhibit AG-7 Corporate Staff O&M Adjustments 8. Exhibit AG-8 Compensation and Employee Benefits Adjustments 9. Exhibit AG-9 Tree Trimming Surge Event Outage Forecast
10. Exhibit AG-10 DTEE Response – 2015 Achieved Measures AIP, REP, etc. 11. Exhibit AG-11 Incentive Plan Operating Measures Achieved 12. Exhibit AG-12 Contingency Capital Expenditures 13. Exhibit AG-13 DTEE Response – Distribution Ops Cap Ex 2018 Variance 14. Exhibit AG-14 DTEE Response – New Business Distribution Cap Ex
Unidentified 15. Exhibit AG-15 DTEE Response – Distribution Ops Resiliency Cap Ex
Variance 16. Exhibit AG-16 DTEE Response – Distribution Ops Redesign Cap Ex
Variance 17. Exhibit AG-17 DTEE Response – Battery Pilot Programs 18. Exhibit AG-18 DTEE Response – Power Gen Monroe Fly Ash Programs 19. Exhibit AG-19 DTEE Response – CHP Plant 20. Exhibit AG-20 DTEE Response – Corporate Staff Cap Ex Variance 2018 21. Exhibit AG-21 DTEE Response – Corporate HQ Energy Center 22. Exhibit AG-22 DTEE Response – EV Make Ready Cap Ex 23. Exhibit AG-23 Capital Expenditures and Rate Base Adjustments 24. Exhibit AG-24 Working Capital Adjustments 25. Exhibit AG-25 Overall Cost of Capital 26. Exhibit AG-26 Cost of Common Equity-Summary 27. Exhibit AG-27 Cost of Common Equity-DCF 28. Exhibit AG-28 Cost of Common Equity-CAPM 29. Exhibit AG-29 Cost of Common Equity-Risk Premium 30. Exhibit AG-30 Electric ROE Decisions by Regulatory Commissions 31. Exhibit AG-31 DTEE Response – Cash Flow and Credit Ratios 2018-2019
5
32. Exhibit AG-32 DTEE Response – No Credit Agencies Actions 33. Exhibit AG-33 Value Line – Volatility versus Risk 34. Exhibit AG-34 Case No. U-18014: Exhibit A-10, Schedule C5 35. Exhibit AG-35 Case No. U-18014: Theresa M. Uzenski Rebuttal Testimony
pp. 4-5 36. Exhibit AG-36 DTEE Response to AGDE-6.327a and b 37. Exhibit AG-37 DTEE Response to AGDE-6.313a and b 38. Exhibit AG-38 DTEE Response to AGDE-6.314 39. Exhibit AG-39 Work Paper AG27-4 40. Exhibit AG-40 DTEE Response to AGDE-6.324a, b, and c 41. Exhibit AG-41 DTEE Response to AGDE-6.316 42. Exhibit AG-42 DTEE Response to AGDE-6.323 43. Exhibit AG-43 DTEE Response to AGDE-2.107 44. Exhibit AG-44 DTEE Response to AGDE-6.317 45. Exhibit AG-45 DTEE Response to AGDE-6.319a, b, and c 46. Exhibit AG-46 DTEE Response to AGDE-6.320 47. Exhibit AG-47 DTEE Response to AGDE-6.321a, b, c, and f 48. Exhibit AG-48 Direct Testimony of Michael J. Vilbert from Case No. U-
18255, page 64. 49. Exhibit AG-49 Direct Testimony of Michael J. Vilbert from Case No. U-
18255, page 56.
Sebastian Coppola
After reviewing the testimony, exhibits, and discovery conducted in this case,
Mr. Coppola concluded that the Company has a revenue deficiency for the projected
test year of approximately $78 million. Mr. Coppola’s conclusions are based on
recommendations and related adjustments for the following major topics:
1. The level of Operations and Maintenance expenses 2. Incentive Compensation 3. Employee Benefits
6
4. The level of proposed Rate Base and Capital Expenditures 5. The Company’s Cost of Capital and Working Capital 6. Electric Vehicle Pilot Program 7. The Company’s Proposed Infrastructure Recovery Mechanism 8. Rate Design Issues and New Fixed Billing Pilots
He also explained that the absence of discussion on other matters in his testimony
should not be taken as an indication that he agrees with those aspects of DTE’s rate
case filing. The narrow focus of his testimony is, instead, a consequence of focusing
on priority issues within the available resources. (5 Tr 1591).
He summarized his conclusions, adjustments, and recommendations
regarding these issues as follows:
The Company filed for a base rate increase of $231 [sic – this number should read $328] million. It is noteworthy to point out that during the five-year period from 2013 to 2017, the Company earned a return on common equity on a regulatory basis generally at or above the authorized ROE rate. The actual earned ROE is also considerably higher than the Company’s true cost of capital of approximately 9%.1 Based on my analysis of the Company’s case, I have reached the following summary conclusions and recommendations:
1. I am proposing a lower level of Operations and Maintenance expenses of $128.9 million for the test year.
2. I am proposing a reduction in capital expenditures of $415.9 million for the test year, and a reduction in rate base of $394.8 million. Including adjustments to working capital.
3. I recommend that the Commission reject the proposed Infrastructure Recovery Mechanism.
4. I recommend an authorized rate of return on equity of 9.5% and a capital structure with 50% debt and 50% equity capital.
1 Ex. AG-26.
7
5. I recommend that the Commission reject the Company’s proposed increases of the monthly customer charge for Residential customers and small commercial customers’ general service rate.
6. I recommend that the Commission reject funding the Company’s proposed fixed-billing pilot programs.
[5 Tr 1593-94.]
The O&M dollar adjustments broken down by topic are as follows (Tr 1623):
AmountSummary of O & M Expense Reductions ($Millions)
Inflation Expense Adjustment 75.4$
Power Generation 6.5
Customer Service and Marketing 4.8
Injuries and Damages 1.9
Employee Incentive Compensation 36.7
Employee Benefits 3.7
Total Redustion 129.0$
8
The Capital Expenditure and Rate Base dollar adjustments broken down by
topic are as follows (Tr 1646):
As noted above, these reductions equate to a reduction of the Company’s proposed
capital expenditures and deferred costs by approximately $250 million. These
adjustments do not take into account adjustments by other parties in the case or
those that the Attorney General adopts in her Initial or Reply Brief.
This Initial Brief has been prepared based on available resources and
therefore it focuses on the significant issues of concern summarized above. The
Attorney General’s silence on other issues should not be construed as approval of
the Company’s position. Additionally, the Attorney General reserves the right to
address, in a Reply Brief, other issues raised by other parties in their Initial Briefs.
Summary of AG Disallowed Capital Expenditures
Contingent Capital Expenditures 15.0$ Distribution Operations
New Business 61.5 Infrastructure Resiliency & Hardening 8.7 Infrastructure Redesign 46.3 ADMS 84.3
Power GenerationMonroe Fly Ash Projects 90.9 CHP Plant 62.3
Electric Vehicle Pilot ProgramCharger Service Connections 1.7
HQ Energy Center 28.1 2018 Underspent 17.1
415.9$
Corporate Staff Group
Total
Amount (millions)
9
ARGUMENT
While examining the Attorney General’s substantive objections and
adjustments, the Commission should consider that DTE Electric bears the burden of
proof to demonstrate that its proposals are just and reasonable. The obligation of
proving any fact lies upon the party who substantially asserts the affirmative of the
issue.2 A plaintiff always has the burden of proving its cause of action.3 In
administrative cases, a party seeking relief must prove his, her, or its claim by a
preponderance of the evidence.4 Likewise, in MPSC Cases, a utility has the burden
of proof by a preponderance of the evidence.5 Given the nature of the burden of
proof, the Commission may reject even uncontradicted evidence.6 When the burden
of proving a fact falls on one party, the other party does not have the burden of
proving the opposite fact.7
In addition, as the Commission has previously explained and as has been
clarified in prior proposals for decisions, the utility has an obligation to support its
rate base projections in a general rate case:
2 White v Campbell, 25 Mich 463, 475 (1872). 3 Caruso v Weber, 257 Mich 333; 241 NW 198 (1931). 4 Dillon v Lapeer State Home & Training School, 364 Mich 1, 8; 110 NW2d 588 (1961), and BCBSM v Governor, 422 Mich 1, 88-89; 367 NW2d 1 (1985). 5 In re Michigan Gas Utilities Co, MPSC Case No. U-7484, Opinion & Order dated 8-30-83, p. 10, and In re Detroit Edison Co, MPSC Case No. U-8030-R, Opinion & Order dated 7-9-87, pp. 16-17. 6 Woodin v Durfee, 46 Mich 424, 427; 9 NW 457 (1881). Accord, Yonkus v McKay, 186 Mich 203, 211; 152 NW 1031 (1915), and Cuttle v Concordia Mut Fire Ins Co, 295 Mich 514,519; 295 NW 246 (1940). 7 S C Gary, Inc v Ford Motor Co, 92 Mich App 789, 803-804; 286 NW 2d 34 (1979).
10
“Section 6a (1) of Act 286, MCL 460.6a(1) provides that a utility “may use projected costs and revenues for a future consecutive 12-month period” to develop its requested rates and charges. As the Commission has discussed previously: In a case where a utility decides to base its filing on a fully projected test year, the utility bears the burden to substantiate its projections. Give the time constraints under Act 286, all evidence (or sources or evidence) in support of the company’s projections should be included in the company’s initial filing. If the Staff or intervenors find insufficient support for some of the utility’s projections, they may endeavor to validate the company’s projection through discovery and audit requests. If the utility cannot or will not provide sufficient support for a particular revenue or expense item (particularly for an item that substantially deviates from the historical data) the Staff, intervenors, or the Commission may choose an alternative method for determining the projection.8
Therefore, before examining the Attorney General’s recommendations and
arguments, the Commission should consider that DTE bears the burden of proof to
demonstrate that its request for a rate increase is just and reasonable. The
following sections lay out the Attorney General’s analysis of DTE’s case and support
for the Attorney General’s recommendations.
I. OPERATIONS AND MAINTENANCE EXPENSES
In his direct testimony, the Attorney General’s expert witness, Mr. Coppola,
addressed a number of Operations and Maintenance (O&M) Expense reduction
recommendations. (5 TR 1594-1623). To begin with, DTE has projected an O&M
expense increase in this case of $78.3 million, or 6.3%, over the historical level. (7
TR 1594). Additionally, as Mr. Coppola discusses, if the Company’s $35.3 million
8 September 8, 2016 Order in Case No. U-17895, p. 4, citing January 11, 2010 order in Case No. U-15768 et al., pp. 9-10.
11
projected decrease in pension expense is factored in, the increase of O&M expenses
is actually $113.6 million, or 9.2%, above the 2017 historical amount. (7 TR 1594).
This increase from the 2017 historical expense level to a projected test year expense
level ending two years later, in April of 2020, is significant.
A. Inflation Adjustment
Approximately $75.4 million of the projected O&M increase represents
inflation increases estimated by DTE based on a blend of (a) the Consumer Price
Index (CPI) and (b) forecasted annual wage rate inflation for employees of the
Company and employees working for contractors. (7 TR 1595). As noted by Mr.
Coppola, the “[u]se of such a ‘blended rate’ has been rejected by the Commission in
prior general rate cases as inappropriate.” (7 TR 1595). In MPSC Case No. U-
18014, the ALJ and the Commission directly rejected DTE Electric’s proposed
blended inflation rate. (In the matter of the Application of DTE Electric Company,
MPSC Case No. U-18014, January 31, 2017 Commission Order, pp 71-72.) In U-
18014, the Commission agreed with the ALJ’s statement that the Commission has
never approved a composite rate derived from internal and public sources and
concluded that “the Commission has never found sufficient justification or support
to approve a composite labor/non-labor inflation rate.” (U-18014, p. 72.) In MPSC
Case No. U-18255, the Commission reinforced its past findings and conclusions,
stating that, “[t]he Commission agrees with the ALJ that DTE Electric has not
presented sufficient evidence in this case to induce the Commission to depart from
its decisions in the 2017 order and previous rate cases rejecting a blended inflation
12
rate.” (In the matter of the Application of DTE Electric Company, MPSC Case No.
U-18255, April 18, 2018 Commission Order, p. 38.)
Not only did the Commission explicitly reject this blended rate of inflation in
DTE’s last two electric rate cases, the evidence in this case demonstrates that DTE
has not experienced across-the-board inflation pressure on its operating costs. (7
TR 1595). Based on DTE’s own numbers in this case, actual O&M costs have been
on a declining trend in the most recent 6 years, including 2017. (7 TR 1595). The
following chart, which comes from page 10 of Mr. Coppola’s direct testimony, is
based on DTE’s own numbers and shows that DTE’s O&M expenses have been on a
declining trend over the last 6 years. (7 TR 1595).
Looking at these numbers and the graphic developed by Mr. Coppola, it is
difficult to understand why the Company would project inflation-related increases
for 2018, 2019, and the first four months in 2020. Further, it is disingenuous for
$1,100,000
$1,150,000
$1,200,000
$1,250,000
$1,300,000
$1,350,000
$1,400,000
2012 2013 2014 2015 2016 2017
DTEE O&M Expenses($000)
O&M Expenses O&M Trend Liine
13
the Company to continue predicting inflation-related increases in each subsequent
rate case, when the trends and numbers clearly do not bear that out.
Mr. Coppola also provided additional analysis on the O&M expense projected
by the Company in U-18014, which had a test period ending July 2017, to get a
better feel for how the Company’s projections have played out historically. (7 TR
1596). By way of analysis, Mr. Coppola extended the O&M expense projection to
the end of 2017 by applying the inflation factor for the months of August to
December to get a comparable inflation adjusted amount for 2017. (7 TR 1596). A
comparison to the actual 2017 O&M expense shows that the Company’s projection
was higher by $112 million.9 So, as in prior years, either the anticipated inflation
did not materialize or the Company was able to more than offset any inflationary
increases with significant cost reductions.
On cross examination, Company witness Mr. Stanczak was asked about the
Company’s projected inflationary cost increases. First, he was asked about several
exhibits in the case, specifically Exhibit A-13, C5 and exhibit AG-1. (3 TR 109-11).
With regard to Exhibit A-13, C5, which was sponsored in this case by Company
witness Theresa Uzenski, Mr. Stanczak agreed that the total forecasted inflation
that the Company is asking for in rates in this case is approximately $70 million. (3
TR 109-10). He then discussed Exhibit AG-1, which was compiled by Mr. Coppola.
While Mr. Stanczak himself did not create this exhibit, he did review it and he
agreed that, to his knowledge, the numbers in the exhibit were accurately sourced
9 Ex. AG-3 shows a more detailed analysis.
14
from Company work papers, exhibits, and responses to discovery requests. (3 TR
110). Exhibit AG-1 shows that while the CPI city average has increased annually
every year, save one, in the past decade, the Company’s O&M expenses have stayed
very static. (Ex. AG-1). In fact, the Company’s actual O&M expenditures in 2017
were significantly less than those in 2007. (Ex. AG-1). Additionally, the Company’s
actual expenditures over the past decade have never reached the 2007 cumulative
inflation adjusted expense (shown in the last column to the right on Ex. AG-1). (Ex.
AG-1). This shows that, despite the Company’s protestations in direct and rebuttal
testimony, the Company has been able to keep O&M expenses well below the
cumulative rate of depreciation during the last decade. The Company has provided
no valid reasons why that might change.
On cross, Mr. Stanczak was also asked about Exhibit AG-3, which was
prepared by Mr. Coppola. (3 TR 112-13). Mr. Stanczak agreed that he reviewed the
exhibit and that the exhibit depicts that, if the O&M expenses presented by the
Company in U-18014 are extended for inflation to the end of 2017, the Company’s
actual O&M expenses were still $112 million below the inflation adjusted level. (3
TR 112-13). Mr. Stanczak did not discuss or dispute this calculation or exhibit in
his rebuttal testimony. (3 TR 113).
Also on cross, Mr. Stanczak was asked about the Company’s ability to
continue to manage O&M expenses as it has in the past. (3 TR 113). He agreed
that in rebuttal testimony, he stated that the Company would not be able to
continue to manage O&M expenses as it had in the past in order to offset wage
15
growth. (3 TR 113). In that context, he was asked about Exhibit AG-34, which is
Exhibit A-10, C5 from Case No. U-18014, sponsored by Ms. Uzenski. (3 TR 113).
That specific exhibit summarized the Company’s projected O&M expenses for U-
18014. (Ex. AG-34). On cross, Mr. Stanczak agreed that in case U-18014, the
Company asked for inflation cost adjustments of around $76-77 million, and
projected total O&M expenses of more than $1.3 billion. (3 TR 113-14). After a
review of Exhibit AG-35, which is comprised of several pages from Ms. Uzenski’s
rebuttal testimony in Case No. U-18014, Mr. Stanczak agreed that in U-18014, Ms.
Uzenski stated generally the same opinion espoused by Mr. Stanczak in this case,
that the Company needs a large inflation-related increase in the test year because it
would have difficulty keeping O&M expenses below inflation. (3 TR 115). However,
as shown in Exhibit AG-3 in this case and as discussed above, the Company’s
projected O&M expenses in Case No. U-18014 overestimated actual 2017 expenses
by approximately $112 million. (Ex. AG-3). Based on that analysis, the Company
was clearly able to achieve actual O&M costs below the inflation adjusted level in
2017, contrary to Ms. Uzenski’s testimony. Mr. Stanczak offered the same
testimony in this case regarding the Company’s need for large inflation increases
and there is no reason presented by the Company to suggest that the outcome in
this case will be any different from the 2017 historical results.
On re-direct by the Company, Mr. Stanczak was asked to refer back to
Exhibit AG-34, specifically columns (g), (h), and (i) where the Company detailed its
request for around $76 million in inflation adjustments. (3 TR 187-88). He stated
16
that the Commission did not grant this request in total in U-18014, and that his
“expectation” is that if the Company would have received such a rate increase, it
probably would have spent closer to what was forecasted. (3 TR 188). First, what
the Company would or would not have done under different historical circumstances
is complete speculation by Mr. Stanczak and is unsupportable. Second, this
statement actually corroborates the AG’s point in this area, in that the Commission
denied the Company’s request for millions of dollars in inflation related costs, and
yet the Company still kept functioning and found different ways to manage its
O&M costs. This shows that if the Commission works to keep increases reasonable
and denies the Company recovery where projections are vague and unsupported,
then the Company will find ways to keep costs in check.
At base, the Company has not provided any evidence that its operations are
facing inflationary cost pressures that it cannot manage in the course of operating
its business. Therefore, the proposed $75.4 million in inflation cost increases is not
likely to occur in the coming months as the Company has predicted. The Company
will continue to manage its operations in a manner that offsets the low level of
forecasted inflation with increased operating efficiencies.
DTE has failed to provide evidence that its operations are facing inflationary
pressures that it cannot manage in the course of operating its business. The
Company is proposing $75.4 million in inflation cost increases in the coming
months, but it has not provided evidence to support these inflationary projections
other than the Commission rejected blended rate increase projection. (7 TR 1596).
17
Mr. Coppola explained that “[a]s a matter of policy, it is not advisable to
allow utilities to escalate costs for forecasted future inflation.” (7 TR 1597). He
explained that increasing future costs with inflation increases becomes a self-
fulfilling prophecy, which then fuels and justifies further inflationary trends. (7 TR
1597). A more reasonable approach for the Commission to take is to only grant
inflation cost increases when such increases are actually experienced and are
therefore more likely to occur in the future. The Commission should refrain from
granting inflation cost increases just because it has been past practice to do so.
In this case, the evidence is clear that inflation cost increases are not
warranted or necessary. In his direct testimony, Mr. Coppola did identify one
exception, which the Attorney General adopts. The Attorney General does support
providing an inflationary increase of $5.9 million for medical cost inflation, based on
the approximately 4% inflation increase identified in Mr. Coppola’s testimony. (7 TR
1598). Accordingly, the Attorney General recommends that the Commission
disallow the remaining $75.4 million of inflationary cost increases projected by the
Company.
B. Power Generation O&M Expense
In his direct testimony, Mr. Coppola provided a summary of the projected
expenses proposed by DTE for power generation:
On page 1 of Exhibit A-13, Schedule C5, the Company has included $266 million of adjusted historical O&M expenses for Steam Power Generation, $8.1 million for Fuel Supply & MERC Handling, $143.5 million for Nuclear Power Generation, $10.3 million for Hydraulic Power Generation, and $14.6 million for Other Power Generation. These adjusted 2017 costs are before inflationary cost increases and other adjustments. Collectively these costs total to $442.4
18
million for the historical test year 2017. Exhibit AG-4 shows these 2017 costs, the Company’s projected inflation and other adjustments, as well as my recommended adjustments. (7 TR 1598-99). [internal citations omitted]
Along with removing all inflation cost adjustments from the Company’s
projections, which the Attorney General previously discussed, the Attorney General
also proposes 1) removal of the Company’s $3.6 million adjustment related to the St.
Clair outage event and 2) a $2.9 million adjustment to the PERC regulatory
amortization amount.
The St. Clair outage event involved a mechanical failure and a fire at the
power station. (7 TR 1599). While Company Exhibit A-13, Schedule C5.1 shows a
normalization adjustment of $1.6 million in column (f) related to the St. Clair
outage event, the Company did not provide an explanation for this adjustment in its
direct testimony. (7 TR 1599). In discovery and rebuttal testimony the Company
did provide further information on the projected O&M expense, but the response
was unclear and failed to adequately support the Company’s proposal. (Ex. A-41).
According to the Company’s response to AGDE-4.256a, which is included as
schedule EE-2 of Exhibit A-41, certain adjustments related to the St. Clair fire
event led to an increase in O&M costs in the projected test period. (Ex. A-41, sched
EE-2, page 1 of 2). The answer states that it will give a “breakdown of the
adjustments related to the” fire that led to this increase in O&M costs in the
projected test period, but then fails to do so. (Ex. A-41, sched EE-2, page 1 of 2).
The rest of that answer from Company witness Paul is a confusing discussion
regarding fire restoration work, insurance proceeds, and a calculation that
19
subtracts net fire restoration expense from the Company’s straight time labor
charged to fire recovery work orders in 2017 as O&M expense. (Ex. A-41, sched EE-
2, page 1 of 2). The response concludes with the statement that O&M costs for the
projected test period are being increased by the $1.6 million figure, but it is unclear
why that is the case. (Ex. A-41, sched EE-2, page 1 of 2).
Mr. Paul’s rebuttal testimony states that Mr. Coppola misunderstood the
relevant discovery responses, but like the direct testimony, fails to provide a clear
rationale for increasing the O&M figure in this case. The Company appears to be
saying that the proposed increase in O&M costs10 stems from the fire event.
However, Mr. Paul’s rebuttal testimony also seems to imply that these costs were
simply costs that were shifted to fire restoration work in the interim, and now need
to be shifted back to normal operations.11 This would seem to indicate that no
increase in O&M is necessary for this St. Clair event.
Mr. Paul was asked about this issue on cross examination, but he was unable
to clear up the discrepancies or adequately support the Company’s request in this
area. One of the issues is that it is impossible to verify that the $3.6 million is an
amount that was actually spent for fire-recovery labor, because those details were
not provided to the Attorney General or any party in this proceeding. (4 TR 613).
10 The AG would also like to point out that it is unclear whether the Company is proposing an increase of $1.6 million or $3.6 million in its projected test year, with regard to the “normalization adjustment” at issue. 11 Paul Rebuttal p. 3, lines 17-19 – “[T]he $3.6 million is the ordinary historical day-to-day expense of these DTE Electric personnel which will continue to be incurred into the future now that ordinary St. Clair power plant operations have resumed.”
20
Additionally, it was unclear from Mr. Paul’s answers how the $3.6 million fits into
the test year. According to his testimony, the $3.6 million for fire recovery work
completed in 2017 was for St. Clair Units 6 and 7. (4 TR 613). However, according
to his testimony and the discovery response included in Exhibit AG-36, the $3.6
million of straight time labor costs will be incurred for St. Clair Units 1, 2, 3, 6, and
7 and common systems. (Ex. AG-36). It is unclear how the Company reconciles
these positions or how it arrived at the conclusion that the fire restoration work
corresponds directly to future labor costs at functioning Units.
At base, the Company has not adequately supported any increase in O&M
expense for power generation stemming from the St. Clair event. While this section
of the Attorney General’s brief appears disjointed, it is because of the difficulty the
Attorney General has had in deciphering the Company’s testimony and discovery
responses on this topic. Accordingly, the Attorney General recommends that the
Commission remove the $3.6 million from the Company’s O&M expense for the
projected test year.
With regard to the PERC expense, Mr. Coppola provided the following
summary:
[O]n page 1 of Exhibit A-13, Schedule C5.3, the Company included $12.7 million of amortization expense for the projected test year. In Case No. U-18255, the Commission approved the deferral of all PERC costs exceeding $4.9 million annually and also approved recovery in rates of the amortization of these costs in future years. Line 22 on page 1 of Exhibit A-13, Schedule C5.3, shows that there is no PERC amortization expense in 2017, but the Company has estimated amortization expense in the projected test period of $12.7 million. Schedule C5.17 of the exhibit shows how the $12.7 million expense amount was determined. This exhibit shows that the amortization amount
21
consists of $4.4 million of costs pertaining to 2017, $5.3 million for costs incurred in 2018, and $2.9 million for costs pertaining to 2019. (7 TR 1600).
The Attorney General argues that the extent to which 2019 costs will exceed
the $4.9 million threshold and when that will happen is speculative at best. There
has not been sufficient evidence presented in this case that such an event will occur,
and it is not appropriate for the Company to begin recovering amortization costs
pertaining to 2019 when it is not yet known with any accuracy what PERC costs
will actually be incurred. If PERC costs are incurred in 2019 above the $4.9 million
threshold, the Company will defer those costs and can recover them in a future rate
case. Therefore, the Attorney General recommends that Commission disallow $2.9
million of amortization of 2019 PERC costs in this proceeding.
C. Distribution O&M Expenses
In his direct testimony, Mr. Coppola provides a summary of the Company’s
projected Distribution O&M expenses in its test year:
On page 1 of Exhibit A-13, Schedule C5.6, the Company shows Distribution O&M expense in 2017 of $303.9 million. To this amount, the Company has added $21.4 million for inflation cost increases, $4.9 million for additional tree trimming expenses, and $0.3 million for miscellaneous maintenance costs to arrive at its test year projection of $330.5 million. These costs are summarized in Exhibit AG-5. Page 3 of Exhibit A-13, Schedule C5.6, shows the Company’s proposed base amount of tree trimming expense for the projected test year at $95.1 million, consisting of $5.9 million of inflation increases and $4.9 million of additional spending above the 2017 actual amount of $84.3 million. In addition, through the direct testimony of Heather Rivard, the Company has proposed a 7-year tree trimming surge program from 2019 to 2025 with increased spending of approximately $410 million over the inflation-escalated base level. Exhibit A-22, Schedule L1, shows the proposed expenditures.
22
According to the Company, the additional investment is necessary to reach a 5-year clearing cycle and reduce the number of power outages caused by falling tree branches on power lines. [5 TR 1601-02].
As summarized in Exhibit AG-5, the Attorney General, as per the prior
discussion, continues to recommend that the Commission disallow all projected
inflation cost increases in this area.
With regard to the Company’s proposed tree-trimming surge, the AG has
some serious reservations, as laid out below, and recommends that if the
Commission does allow recovery of any of the Company’s proposed tree trimming
surge expenses, that specific conditions and parameters be placed on that funding to
ensure that customers actually benefit from the large levels of increased spending.
The Company’s proposed additional amount of $410 million in increased
spending for the surge program, over a 7-year period, is significant and promises to
be costly for customers. Although the Company proposes to defer the incremental
cost into a regulatory asset and amortize it over 14 years, the costs do not go away,
they simply impact future rates. In his direct testimony, Mr. Coppola provides
further analysis on the Company’s proposed program. (7 TR 1602-05).
The goal of the Company with the additional spending is to achieve a 40% reduction in tree-related power outage events by the year 2026. The Company expects to have approximately 58,000 tree-related power outages in 2019, and subsequent to implementing the surge program reduce that number down to approximately 33,000 to 34,000, beginning in 2026. Exhibit AG-9 includes the Company’s workpaper showing these numbers under the Surge Program Events caption. [7 TR 1602].
So, according to the Company’s numbers, at best the program will avoid
approximately 24,000 to 25,000 power outages annually. (Ex. AG-9). The surge
23
program will not do away with all tree-related power outages and it fails to decrease
outages by even 50%. The following table, which was included in Mr. Coppola’s
direct testimony, shows the potential decrease in tree-related outages. (5 TR 1603).
So, the Company’s proposal is to spend $410 million to avoid around 25,000
outages annually. The Attorney General is always supportive of attempts by
utilities to decrease their outages and thus decrease inconvenience and problems for
customers. However, the Attorney General is unconvinced that this level of
spending, to achieve this level of outage reduction, is prudent.
At this time, the Attorney General does not outright oppose the Company’s
proposed surge program and, on balance, supports the program with regard to the
potential benefits for customers. However, the Attorney General recommends that
the Commission approve some or all of the program only if there are specific
guidelines and parameters in place that hold the Company accountable for
Surge CurrentYear Program Program Difference
2019 58,176 58,176 -
2020 56,372 59,320 (2,947)
2021 53,128 61,042 (7,915)
2022 50,384 63,217 (12,833)
2023 45,719 62,773 (17,054)
2024 41,049 62,615 (21,566)
2025 36,831 62,748 (25,917)
2026 33,649 62,140 (28,491)
2027 33,490 60,802 (27,313)
2028 33,601 59,293 (25,692)
2029 33,741 57,335 (23,594)
2030 34,025 55,740 (21,715)
Table 1 - Power Outage Events
24
achieving results that show measurable benefits to customers. With that in mind,
the Attorney General recommends that the Commission approve the program with
the following conditions as laid out in Mr. Coppola’s testimony:
1. The Commission should set the number of forecasted outages as target levels for the Company to achieve for each year 2019 to 2030. The target levels are reflected under the Surge Program in the Company workpaper HDR-1 shown in Exhibit AG-9 and duplicated in Table 1 above.
2. The Company should provide a report to the Commission in early 2022 reviewing the spending, accomplishments and, most importantly, the effectiveness in reducing the number of tree-related outages against the targets during the first three years of the program. The three-year time frame would be sufficiently long to show any improvements. This review and report should reoccur annually thereafter for the entirety of the program.
3. If the Company achieves at least 80% of the target reductions in outages, the Commission should affirm continuation of the program.
4. If the Company fails to achieve at least 80% of the average reductions in the target levels versus the Status Quo levels shown in workpaper HDR-1 for the 2019 to 2021 period, and subsequent cumulative periods, then the Company will forfeit recovery of 1% of the deferred expense for those years for each percent it falls short of the 80% level.
5. If the Company fails to achieve any reduction or the number of outages increases over the Status Quo level during 2019 to 2021, or cumulative subsequent periods, then the Company will forfeit 100% of any remaining balance in the deferred regulatory asset.
6. If the Company fails to achieve at least 50% of the target outage reductions over the review period, the Commission should set a new spending level that the Company can recover in future years and warn the Company that any amounts exceeding the approved level are not likely to be recovered in rates in future years unless the program is able to achieve at least 80% of the target reductions.
For the Commission to simply approve a program of more than $400 million
in additional spending, without tracking and quantifying results, would be
25
imprudent and a poor deal for customers. Achieving specific numeric goals must be
a part of the program. In rebuttal, the Company was unwilling to agree to outage
reduction targets. (3 TR 250). Company witness Ms. Rivard stated that Mr.
Coppola’s suggested conditions were “unwarranted” and that the Company should
not be held to accountability targets or subject to penalties. (3 TR 254-55).
On cross examination, Ms. Rivard was asked about her disagreement with
Mr. Coppola’s suggestions in this area. (3 TR 254-62). Part of her rationale that
the Company should not be held to any kind of accountability requirements is that
the Company plans to securitize at least a portion of these expenditures. (3 TR
255). However, as Ms. Rivard admitted on cross, securitization of these costs is not
assured, and the Company would continue to earn a return on expenditures
included in the deferred regulatory asset until those costs were securitized. (5 TR
255). Ms. Rivard also stated that under her proposal, the Company would obtain
full cost-recovery for this program, regardless of the amount of reductions in tree-
related outages that the Company achieved with the “surge.” (5 TR 255-56).
While Ms. Rivard did discuss status meetings with the Commission Staff
during the program and a possible annual report filing in order to monitor progress,
her testimony is light on details for how such proceedings would work and how
customers would be protected in the event that projected results were not coming to
fruition. (5 TR 256). During one exchange, she was asked whether those meetings
would include other parties, such as the AG. (5 TR 256). She responded, “I am not
sure how those proceedings would work. I think that the Commission could
26
certainly issue orders or processes to allow that to happen.” (3 TR 257). It is
obvious that the follow-up discussions and meetings contemplated by Ms. Rivard
are a preliminary, undeveloped suggestion without framework for how those would
work to protect customers. Ms. Rivard also stated during cross that the Company
does not contemplate any payback to customers if it fails to achieve a reduction in
tree-related outages. (3 TR 258).
Ms. Rivard also argued that Mr. Coppola did not account for weather-based
volatility, as a reason that his suggestions are unwarranted. (3 TR 250). She
stated that major storms could cause large swings in the volume of outage events
from one year to the next, which could result in a significant financial loss to the
Company under Mr. Coppola’s proposal. (3 TR 250). However, as she agreed on
cross, the whole objective of the Enhanced Tree Trimming Program is to widen the
tree free corridor around power lines, which should lessen or prevent power outages
caused by trees during storms. (3 TR 258-59). She even mentioned how significant
the reductions in outages have been thus far. (3 TR 259). According to the
Company’s rationale, these significant reductions in outages should make major
storms much less of a problem if the Commission adopts the Company’s proposal,
meaning that weather-based volatility year to year should not be a concern.
Additionally, Ms. Rivard agreed that the Company has the ability to calculate and
report weather-normalized outage reduction results over different time periods,
lessening concerns of weather-based volatility. (3 TR 258-59).
27
Finally, Ms. Rivard discussed the Company’s inability to predict the tree trim
labor markets or the availability of tree trimmers as a reason that Mr. Coppola’s
suggestions are unwarranted. (3 TR 250-51). When questioned about this on cross,
Ms. Rivard stated that the non-availability of tree trimmers may cause the
Company to miss targets, but then turned around and stated that the Company
believes it is going to be able to secure the necessary resources to complete the tree
surge plan. (3 TR 260). It is difficult to reconcile those statements and difficult to
see why, if the Company truly believes that recruiting adequate tree trimmers may
be a significant problem that causes difficulty achieving the program, the
Commission should approve these cost requests.
Based on the Company’s testimony, rebuttal, and questions asked of Ms.
Rivard on cross-examination, the Company has failed to demonstrate that this
program is reasonable and prudent without specific targets and parameters set that
help protect customers. Accordingly, because the Company is not willing to agree to
a set of appropriate conditions on this expensive tree surge program, the Attorney
General recommends that the Commission approve a funding level for tree-
trimming equal to the amount approved in Case No. U-18255.
D. Customer Service and Marketing In his direct testimony, Mr. Coppola provided a summary of the level of O&M
expenses that the Company is requesting for its customer service and marketing
department:
28
In Exhibit A-13, Schedule C5.7 and Schedule C5.8, the Company has included $139.4 million and $11.0 million of adjusted historical O&M for its Customer Service and Marketing departments, respectively, before inflationary cost increases and other adjustments.12 The cost increases anticipated by the Company other than inflation, are (a) $2.6 million for additional Merchant Fees (credit card costs); (b) $1.4 million for amortization of its Customer 360 regulatory asset; (c) $1.2 million for the Company’s Charging Forward (electric vehicles) program; (d) $1.4 million for cost associated with two pilot billing programs; and (e) $0.3 million for a demand side management program designed to encourage customers to shift electric usage to non-peak periods. Collectively, these items represent $6.9 million of additional costs. Each of these items, except for the Customer 360 amortization and demand side program costs, is discussed in more detail below. Exhibit AG-6 provides a summary of these costs and proposed adjustments. (7 TR 1606).
After review of the Company’s testimony and proposals in this area, the Attorney
General makes several recommendations.
Merchant Fees Costs
With regard to the merchant fees costs for credit card use, the Company has
proposed adding an additional $1.7 million of merchant fees related to its non-
residential credit card payment program and an additional $0.9 million for its
residential program. (7 TR 1606-07). This brings the total projected expense in this
area to $10.8 million in the projected test period. (7 TR 1606-07). Company witness
Tamara Johnson sponsors this cost level on page 15 of her direct testimony and also
in Exhibit A-13, Schedule C5.7, page 1 lines 6 and 7. (7 TR 1607). She points out
that the Company “…has experienced a year-over-year increase of 90% and a five-
year compound annual growth rate of 60% in merchant fees for corporate credit
cards.” (7 TR 3121). She goes on to state that the Company is now seeking
12 Exhibit A-13, Schedule C5.7, page 1, line 23, col. (g) and Schedule C5.8, Line 15, column (e).
29
Commission approval to curtail the non-residential program to small businesses as
a means of controlling its merchant fee costs. (7 TR 3121-22).
Creating a credit card payment program for residential customers in order to
increase customer convenience and reduce the risk of uncollectible costs makes
sense. However, the same reasons do not necessarily apply to non-residential
customers and a related program. The Attorney General agrees with the
Company’s proposal to prohibit large commercial and industrial customers and
secondary choice customers from paying by credit card. The AG also supports the
Company’s requested increase of $0.9 million for additional merchant fees related to
its residential payment program.
However, the Attorney General does not support the Company’s proposed
cost increase of $1.8 million for its non-residential program, because the Company
has failed to provide sufficient support to show that any cost increases are
warranted. Based on Mr. Coppola’s testimony, the Attorney General recommends
that the expense level for the non-residential program be set at half the $3.2 million
historic 2017 level, or $1.6 million. (7 TR 1607-08). The Company currently pays,
on average, 6.7% in fees on electric bills paid by credit cards. (7 TR 1607-08). The
AG recommends that the Commission support a system whereby the Company is
granted permission to charge a 3% fee to businesses paying by credit card. This in
turn will minimize the Company’s costs. The reasoning for this is that non-
residential customers, who are primarily small to medium size commercial
customers, tend to have much larger bills which can add to significant credit card
30
fees for the Company. Splitting the credit card fees between the Company and this
group of customers is a reasonable change to the program and is a way to avoid
ever-increasing card fees for the rest of the customer base to absorb.
Therefore, the AG recommends that the Commission approve only $1.6
million of expense in this area, instead of the Company’s request of $5.0 million,
and thus remove $3.4 million of expense for the projected test year.
Fixed Bill and Weekend Flex Pilot Programs
The Attorney General opposes these two programs for the reasons that follow
and recommends that that Commission deny approval.
Mr. Coppola provided a summary of the Company’s proposed “fixed bill pilot
program,” referring primarily to Company witness Mr. Clinton’s direct testimony,
noting that under this proposal:
Participants would pay a fixed monthly bill irrespective of the amount of gas used, subject to some limitations and adjustments in subsequent periods. The Company plans to solicit 5,000 customers to participate in this program, which would commence in January 2020. Mr. Clinton points out that the Company surveyed 700 residential customers in April 2018 and that 11% indicated that they may be interested in a “Fixed Billing” offering. Mr. Clinton states that “The primary reason…was “Consistent Bill/No surprises”. He does not present any other benefits or reasons for this program. The Company has included $1 million in O&M expense in the projected test year to launch this pilot program. [7 TR 1608-09].
The Attorney General opposes this program for several reasons. First, the
Company already offers a budget bill program with equal payment amounts
throughout the year (6 TR 2138-39), so this new program appears to be duplicative
and unnecessary for those customers interested in a program that offers predictable
bills. On cross examination, Company witness Mr. Clinton agreed that the
31
Company already offers this BudgetWise billing program, which provides for fixed
monthly billing. (6 TR 2138-39). So, for customers interested in the convenience of
a fixed monthly bill, the AG contends that the Company already has a useful budget
billing program which offers that.
Second, and most concerning for the AG, this new program is likely to
discourage energy conservation. Offering customers fixed bills, regardless of the
amount of electricity that they use in a given month, removes the strong monetary
incentive for energy conservation. Similar to an ‘all-you-can-eat buffet,’ offering
customers unlimited energy at a set price discourages them from turning off lights,
using energy efficient settings on appliances, and minimizing the use of electric-
powered heating/cooling devices for the home, such as furnaces and air conditioning
units. While the Company has proposed some mechanisms to adjust the fixed bill
up or down on a year-by-year basis, that is unlikely to deter customers in the day-
to-day from ignoring energy conservation measures in the same way that paying for
actual consumption does.
On cross examination, Company witness Clinton was asked about these
mechanisms and brought up the “reasonable use clause,” which is a mechanism the
Company intends to use to deter abuses of the system. (6 TR 2136). According to
Mr. Clinton, to the extent customers exceed 30 percent of their usage in a single
month as compared to that month during the previous year, there is a “possibility”
they could be removed from the program. (6 TR 2136). First, 30 percent is quite a
large divergence in one month. For example, a customer who uses 29% more in a
32
single month than they used in that month the previous year would not face any
repercussions. Or if a customer used 20-25% more electricity every month of the
year than the year before, that customer would not face any repercussions.
Additionally, as Mr. Clinton points out, removal is at the Company’s discretion. (6
TR 2137). So, according to his testimony on cross-examination, even if customers
exceed electricity usage in a given month by 30% over that same month in the
previous year, they still might not be removed from the program. This program
would be at odds with other programs offered by the Company that promote energy
conservation, especially during peak demand periods. As a final point, Mr. Clinton
confirmed on cross that the programs as designed only have clauses in place to
remove a party that is using 30 percent more than in the previous year and do not
include anything for customers who stay well-below prior year usage.
The Company has not made a compelling case that the underlying reasons for
the pilot program are sound and in the best interest of all customers. It is also not
clear if the $1 million forecasted cost is the only cost or if there will be additional
Information Technology (IT) costs in subsequent years to modify the Company’s
billing system to accommodate this new billing method. Therefore, the AG
recommends that the Commission reject the Company’s request for the $1 million
O&M expense for this “fixed bill” pilot program.
Mr. Coppola also provided a summary of the Company’s proposed “Weekend
Flex” pilot program:
[T]he Company advocates spending $0.4 million during the projected test period to implement and run the program. However, the actual cost is much
33
higher. In his estimate, Mr. Clinton did not include $1.2 million of additional IT capital expenditure which the Company would seek to recover in a future rate case proceeding. Thus, the full cost to implement the pilot program is $1.6 million. This program seeks to reward customers who shift electric usage to the weekend, which is a non-peak period. The Company would charge a fixed amount for weekend consumption. The calculation to determine the weekend fixed amount is rather complex, as is evident from reading Mr. Clinton’s testimony. [7 TR 1610].
As with the fixed bill pilot program, the Attorney General has significant
concerns with this program and recommends that the Commission deny approval.
Although the stated goal of the “Weekend Flex” pilot program, reducing electricity
usage during peak demand periods of the work week, is sound and is one that the
AG fully supports, there are simpler ways to achieve the objective that will be
cheaper for customers than testing and implementing a new pilot billing program.
By way of example, one option would be for the Company to change its time-
of-use rates to provide for a significantly lower rate during weekend days. This
would incentivize customers to shift usage to weekend days because of the lower
rate while still allowing them to pay for actual usage. Providing for a lower rate on
the weekends, as compared to the weekdays, would be easier for customers to
understand than the complex and convoluted calculations contemplated by the
Company’s fixed weekend bills.13 Customer service representatives would be able
to explain to customers that they pay two separate rates, one rate during the week,
13 Also, similar to the fixed bill pilot program, the fixed component of the weekend bill is troubling in that it discourages energy conservation.
34
and a lower rate on the weekend, but that they still simply pay for whatever they
use.
Another issue that will make this more difficult for customers to understand
is that this “Weekend Flex” program proposed by the Company adds a second
“weekend program” that the Company would operate simultaneously with the
Company’s existing ‘time-of-use’ rates that is structured to incentivize customers to
shift usage to the weekend. (6 TR 2131). On cross examination Mr. Clinton
mentioned that this Weekend Flex program also has a “fixed component” to the
price. (6 TR 2131). This raises the same concerns that the AG mentioned above,
that the fixed component of these bills will dissuade energy conservation and
efficiency by customers. As Mr. Clinton said on cross: “[t]he customer would pay a
fixed amount irrespective of their consumption on the weekend.” (6 TR 2132). Also
on cross Mr. Clinton agreed that the Company does engage in different energy
efficiency programs, and these fixed bill programs seem to fly in the face of those
efforts. (6 TR 2133-34).
While the AG applauds DTE’s efforts to reduce electricity usage during peak
times and to smooth out the load curve, the AG believes that there are simpler and
less costly ways to achieve that objective than a pilot program with a complicated
fixed rate calculation. Accordingly, the AG recommends that the Commission reject
recovery of the $400,000 projected by the Company for the Weekend Flex pilot and
any other related expenditures to the pilot in this case and future rate cases.
35
E. Administrative and General Expenses
The Company’s Administrative and General Expenses are shown in Exhibit
A-13, Schedule C5.9. The exhibit shows $175.5 million of expenses for the historical
period and $184.8 million in the projected test period. The AG recommends
numerous changes to the Company’s test-year projections, which are shown in
Exhibit AG-7. First, the AG recommends removal of $12 million in inflationary
expenses, for the reasons discussed earlier. Second, the AG recommends removal of
$1.9 million from the Company’s Injuries and Damages expense. Third, the AG
recommends removal of $36.8 million of incentive compensation expense.
With regard to the Company’s Injuries and Damages expense, Mr. Coppola
used a three-year average to calculate the expense for the projected test year
because the 2013 expense amount included in the Company’s calculation is
significantly higher than the remaining years used in calculating the average
amount. (7 TR 1612). In 2013, the Company incurred $18 million of actual Injuries
and Damages costs, which is more than $5.0 million higher than more recent
expenses. (7 TR 1612). Injuries and Damages costs ranged from $8 million to $13.2
million during the other four years, so the $18 million level in 2013 is a significant
anomaly. (7 TR 1612). Although the Commission has accepted the use of a five-
year average for calculating the expense level for injuries and damages for the
projected test year, that practice should not preclude a change to the methodology
when there are significant events in one year that are not likely to reoccur. The 3-
36
year average that the AG proposes in this case normalizes the cost forecast by
removing the unusual amount from 2013.
Therefore, the AG recommends that the Commission reject the Injuries and
Damages expense proposed by the Company by removing $1.9 million from the
forecasted O&M expense.
With regard to the Company’s incentive compensation expense, the Company
seeks to recover $46.4 million of employee incentive payments in this case. (7 TR
1612). Based upon the information provided on page 45 of the revised direct
testimony of Company witness Michael Cooper, $6.6 million pertains to the Annual
Incentive Plan (AIP), $24.4 million to the Rewarding Employees Plan (REP), and
$15.4 million pertains to the Long Term Incentive Plan (LTIP). (7 TR 1612-13).
Mr. Coppola summarizes the three plans as follows:
Annual Incentive Plan – the AIP is an annual bonus program focused on the following major categories and specific measures: 1. 40% on Financial Performance (DTE Electric Operating
Earnings, DTE Electric Cash Flow, and DTE Energy Earnings per Share).
2. 20% on Customer Satisfaction (Customer Satisfaction Index,
Improvement in Customer Satisfaction, and MPSC Customer Complaints).
3. 20% on Employee Engagement (DTE Electric Employee
Engagement, DTE Electric OSHA Incident Rate, and OSHA Dart Rate).
4. 20% on Operating Excellence (Two measures of Distribution
system reliability, Fossil plant reliability, and four measures of Nuclear Plant performance).
37
These measures are for the year 2018. A review of the measures in place for the prior five years reveals that certain measures and target levels have varied from year to year. These changes make a direct comparison over the years more challenging. Rewarding Employees Plan – The REP is very similar in design and function to the AIP with some variations in the non-financial measures. Where the AIP is designed for senior level managers at DTE Electric and its affiliates, the REP covers all other employees of these companies. Long Term Incentive Plan – The LTIP is an annual stock grant plan focused on achieving multi-year goals and specifically on the following measures: 1. 60% on Common Stock Total Shareholder Return vs. a Peer
Group. 2. 20% Balance Sheet Ratio of Funds from Operations to Debt. 3. 20% DTE Gas Average Return on Equity over a 3-year period. The weight of the measures varies depending on whether the employee works for the utility or the parent company and the corporate service group. The testimony of Company witness Michael Cooper provides more details on the AIP, REP and LTIP. [7 TR 1613-14].
The issue of incentive compensation is one that the AG feels passionately about and
is an area where the AG has a long history of objecting to the levels of recovery
requested by the Company. In his testimony, Mr. Coppola’s assessment was that
the three incentive plans are too heavily skewed toward measures that directly
benefit shareholders and not customers. (7 TR 1614). He also noted that “the
customer benefits presented by the Company are based on a faulty premise of
historical cost savings and an expectation that future targets of performance will be
achieved.” (7 TR 1614).
38
For example, with the AIP and REP, nearly half of the incentive payout
relates to the Company and its parent, DTE Energy, achieving net income, earnings
per share, and cash flow goals. (7 TR 1614). DTE continues to claim that achieving
these goals somehow benefits customers, but there is no direct relationship to
customer benefits. As noted by Mr. Coppola, “[t]hese goals are in place to maximize
profits and increase cash flow to pay dividends to shareholders” and “[i]t is even
more inappropriate to charge customers for incentive pay costs related to achieving
DTE Energy earnings per share since those earnings include earnings from the gas
and non-utility businesses of DTE Energy.” (7 TR 1615). While increasing
shareholder benefits and happiness is a laudable goal and certainly part of the
Company’s mission, using ratepayer money for that goal is not appropriate. Thus,
the Commission should not allow recovery of incentive payments related to these
financial goals.
The Customer Satisfaction grouping of measures in the AIP and REP for
2018 represents only 20% of the total measures and the benefits achieved in these
groupings, as reported by DTE in Exhibit A-21, Schedule K5, are far less than the
costs. (7 TR 1615). The Employee Engagement measure is a worthy goal for the
Company, but it does not rise to level of measures that are visible to customers and
does not create direct customer benefits. (7 TR 1615). Instead, these are primarily
internal goals related to employee satisfaction and deployment of safe practices in
the workplace. (7 TR 1615). Similarly, the Operating Excellence measure is a
worthy internal goal for the Company because it allows the Company to measure
39
the performance of the department responsible for those operation, but it has no
direct visibility to customers. (7 TR 1615). The only measure within this category
that has a direct link to customers is the Electric Distribution Response Time
metric, which represents a small portion of the expected payout. (7 TR 1615). In
rebuttal, Mr. Cooper argued that improved electric distribution reliability, as
measured by All Weather SAIDI, provides quantifiable benefits to customers. (6 TR
1871). However, on cross, Mr. Cooper was asked to look at the All Weather SAIDI
analysis included in Mr. Bruzzano’s testimony. (6 TR 1892). Mr. Cooper agreed
that, according to the figure on page 12 of Mr. Bruzzano’s direct testimony, there
was a major spike in 2017 due to a severe storm, and that the other years in the
figure are up and down. (6 TR 1892). Figure 3 shows the SAIDI index without the
major storm events, but even that presentation shows an uptrend in SAIDI since
2012. Thus, according to the Company’s own testimony, there were no real
quantifiable benefits in 2017 or over the past 6 years from SAIDI.
Although the AIP and REP plans have around 20% of the total measures
related to customer benefits, the LTIP is strictly designed to induce management to
create shareholder value. (7 TR 1616). As stated by DTE witness Cooper, “[t]hese
measures reflect the long-term financial performance of DTE Energy and are
intended to motivate employees of the individual operating companies, such as DTE
Electric, to keep in mind the role of their own contributions to the overall long-term
success of DTE.” (6 TR 1850). As the Attorney General continues to point out, DTE
40
Electric’s customers should not pay for the overall success of DTE Energy. (7 TR
1616).
The LTIP is weighted heavily (60%) on total shareholder return, which is
stock price appreciation and dividends paid over a period of time. (7 TR 1616).
DTE’s total return is then measured against a group of peer companies to trigger a
payout. (7 TR 1616). As explained by Mr. Coppola, “[t]his has nothing to do with
creating direct benefits for DTE customers and everything to do with creating value
for DTE Energy shareholders.” (7 TR 1616). The other two measures, the Debt
coverage ratio and the DTE Electric return on equity, are also very removed from
any quantifiable benefits that directly accrue to customers and, in some degree,
these two measures are simply duplicative of the Net Income and Cash Flow
measures included in the AIP and REP plans. (7 TR 1616).
DTE’s Exhibit A-21, Schedule K5 purports to show that recent operating and
financial costs are exceeding adjusted incentive plan payments by $77 million. (7
TR 1617). The problem with this analysis is that the largest net benefits shown in
this exhibit are in the areas of (1) Operating Excellence ($69 million), and (2)
Financial Measures ($10 million). (7 TR 1617). Again, these metrics relate more to
achieving bottom line operating performance than customer benefits. In fact, in
direct contrast to these two metrics, the benefits versus expenses related to
Customer Satisfaction metrics shows a net loss of $5.1 million. (7 TR 1617).
Not only do the AIP and REP plans have measures that don’t directly benefit
customers, but also the Company is only achieving around 50% of the target
41
performance in most of these measures. (7 TR 1617). DTE assumes, for purposes of
its proposed incentive compensation payouts and related benefits for AIP and REP,
that the Company will achieve 100% target performance in all 15 individual
measures listed in Exhibit A-21, Schedule K1. (7 TR 1617). DTE’s actual numbers
show that in 2016, 7 out of the 14 non-financial performance measures in the AIP
were well below 100% and also below the minimum threshold level. (7 TR 1617). In
fact, the results show that only 50% of the operating measures were achieved at
target level or better. (7 TR 1617). Similarly, for the REP in 2016, six of the 13
non-financial measures were not achieved at 100% target level and the results are
nearly the same of worse for the Corporate Services and Nuclear Operations
employees’ short-term plans. (7 TR 1617-18).
Similar performance results exist in 2015. (7 TR 1618). Less than half of the
operating performance measures were actually achieved. (7 TR 1618). Accordingly,
DTE’s testimony in this case provides little assurance that all operating measures
can be achieved at 100% of target level in the future with any consistency, as is
assumed by DTE in calculating the incentive compensation expense sought to be
recovered in this case. Since the Company did not provide the results of the 2017
incentive performance plans in its rate case filing, no analysis of that year was
possible. In rebuttal, Mr. Cooper said that he did not agree with Mr. Coppola’s
analysis of historical operating performance measures, in part because Mr.
Coppola’s analysis excludes incentive plan performance results for 2017. (6 TR
1872). However, on cross Mr. Cooper admitted that he did not include the 2017
42
performance results with his pre-filed direct testimony. (6 TR 1893). Exhibit AG-
41 includes the 2017 performance results. However, they were only provided to the
AG after filing of rebuttal and in response to a discovery request, which did not give
the Attorney General adequate time to include that analysis in its filing. (6 TR
1893). It is difficult to see how Mr. Coppola could have used 2017 results that he
did not have.
As Mr. Coppola’s testimony demonstrates, only approximately 50% of the
operating performance measures were achieved at 100% or higher in 2016 and 2015
for both the AIP and REP plans for all employee groups. (7 TR 1618). Thus, DTE
has failed to show that it has achieved consistent performance at target level to
justify recovery of 100% of incentive pay expenses relating to operating performance
measures.
The Attorney General’s recommendation is that the Commission remove the
entire $27.1 million related to financial performance measures as it has done in
both of the Company’s last two rate cases, since these do not have any direct benefit
to customers. Cognizant of the fact that the Commission has recently allowed
recovery of a portion of the short-term incentive pay related to operating
performance measures with regard to DTE and Consumers Energy, the AG
recommends that the Commission should only allow recovery of 50% of the $19.3
million, or $9.6 million. This recommendation is based on the grounds that DTE’s
assumption that it will achieve 100% of the operating measures at 100% target level
continually proves to be wrong. As DTE’s own testimony and exhibits demonstrate,
43
DTE typically achieves only around 50% of operating measures at the 100% target
level or above. (7 TR 1619-20; Exhibit AG-11). Accordingly, the Commission should
disallow $36.7 million of the $46.4 million of incentive compensation expense
requested by DTE in this case.
F. Pension and Benefits DTE has included $163.6 million of historical O&M expenses for pension and
other employee benefits before inflation cost increases and other adjustments. (Ex.
A-13, Sched C5.10, p. 1). DTE’s Exhibit A-13, Schedule C5.10, page 2 provides
further details on the inflation adjustments and other adjustments to arrive at the
proposed total expense of $146.9 million for the projected year. (5 TR 1620). The
following is a simple reconciliation of the Company’s expenses in this area between
the historical 2017 test period and the projected test year. (5 TR 1621).
Employee Pensions & Benefits O & M Items 2017 Historical O & M per Company $163.6 Def. Benefit Plan Cost (35.3) Active Health Care Inflation 9.5 Other Inflation Included 1.3 New Hire VEBA & Employee Savings Plan 10.1 Other-Primarily Surcharge Programs (2.3) Projected O & M for Test Year $146.9
Exhibit AG-8 shows the cost levels for 2017, the projected test year, as well as Mr.
Coppola’s proposed adjustments of $8.6 million to arrive at revised projected O&M
expense for Pensions and Benefits of $138.2 million for the test year.
44
In his direst testimony, Mr. Coppola explains the adjustments he proposed in
Exhibit AG-8, which the AG now recommends.
First, I have removed the inflation adjustment of $1.3 million for non-medical expenses be for the reasons previously explained. Second, I propose a lower level of healthcare inflation and an expense reduction of $3.6 million. Third, I propose that $3.7 million of expense be removed for certain benefit plans that pertain to a small group of executives and highly-paid employees. This includes $2.8 million for the Company’s Supplemental Savings Plan and Deferred Compensation Plan. These benefits are for highly-paid employees whose benefits are not payable from the Company’s tax qualified benefit plans. The remaining $0.9 million pertains to the MCN supplemental retirement plan. This plan pays former employees of MCN Energy Group the difference in benefits between DTEE’s benefit plans and the higher benefits that those employees had before joining the Company after DTE Energy’s acquisition of MCN. In response to a discovery question, DTEE justifies the inclusion of this expense in electric rates due to the fact that former employees of MCN now provide services to the Company. Although that may be true, such differences in benefits are usually considered part of the acquisition premium that the Company pays to acquire another company. The Commission has not allowed DTE Electric to recover in rates the acquisition premium that DTE Energy paid for MCN. DTE Electric customers should not be burdened with expenses that resulted from the acquisition of MCN. Therefore, I recommend that the Commission remove the $0.9 million in expense for the projected test year. Regarding health care inflation for the active employees plan, the Company has proposed health care cost escalations of 7% annually based on forecasts from its actuarial consultant and other sources. The Commission in the last two rate cases for DTE Electric has determined that it is more appropriate to look to cost percentage increases over the most recent three-year period for costs actually incurred by the Company. On page 2 of Exhibit AG-8, I have calculated the three-year historical average increase at 4.1%. By applying this percentage annual increase, I have calculated active employee health care cost increases of $5.9 million between 2017 and the projected test year. This amount is $3.6 million less than the Company’s estimate of $9.5 million. Therefore, in addition to removing the non-healthcare inflation of $1.3 million, I recommend that the Commission remove $3.6 million of healthcare plan inflation and $3.7 million for the other benefit plans from the Company’s forecasted O&M expense for the projected test year. This is a total proposed disallowance of $8.6 million. [5 TR 1621-23].
45
In rebuttal, Mr. Cooper disagreed with Mr. Coppola’s proposed increase to
healthcare costs of 4.1%, in comparison to Mr. Cooper’s higher projections. (6 TR
1878-81). One of Mr. Cooper’s primary rationales is the 2017 increase in health
care expenses. (6 TR 1878-79). On cross, Mr. Cooper was asked about Exhibit AG-
43, which stems from discovery request AGDE-2.107. (6 TR 1896). To the discovery
response, the AG added “line 9,” for ease of discussion on cross. The original
discovery response shows actual healthcare expenses for the five years from 2013 to
2017, and line 9 calculates the percent change year-over-year. (6 TR 1896). Mr.
Cooper agreed on cross that, with the exception of 2017, the percent annual increase
in healthcare expenses has ranged from a half percent to 2.7 percent. (6 TR 1897).
Also in rebuttal, Mr. Cooper disagreed with Mr. Coppola’s disallowance of
expenses related to the Deferred Compensation Plan (DCP). (6 TR 1882-83). On
cross, Mr. Cooper was asked about Exhibit AG-46, which includes the Company’s
response to AGDE-6.320. As noted in Ex. AG-46, there are 16 participants
remaining in the DCP, each of whom received average annual compensation of
$368,000 as of the end of 2017. (6 TR 1903). So, by including this specific expense
in rates, customers are paying for the costs of 16 employees choosing to defer taking
their compensation, and defer paying taxes on that compensation, until a later date.
This is the main reason that the AG recommends disallowance of expenses related
to the DCP.
Mr. Cooper also provided rebuttal testimony on Mr. Coppola’s proposed
disallowance of expenses for the Supplemental Severance Plan, or SSP. As
46
discussed on cross, these expenses relate to differences in the plan benefits between
MCN, MichCon, and DTE’s benefit plans, all stemming from the MCN and MichCon
merger. (6 TR 1904-1906). As discussed, DTE established this plan in 2016 after
former MCN and MichCon employees approached the Company and brought up the
benefit differences. (6 TR 1905). Originally there was no plan by DTE to recognize
these differences. (6 TR 1905). Mr. Cooper was then asked why these costs should
are not considered ‘merger-related’ costs, which would not be passed on to
ratepayers. (6 TR 1905). He answered:
A Because at the time of the merger, there was no contemplation of doing anything for these MCN plan participants; instead, it was focusing on creating a new plan, a cash balance plan.
This goes directly to the problem that the AG has with inclusion of these costs in
rates. If these are not considered merger-related costs, then anything that comes
up “after” the merger can be placed into rates. This allows and encourages the
Company to come up with ways to avoid calling specific costs ‘merger-related,’ and
thus inappropriately recover those costs from all ratepayers. The AG contends that
this is an abuse of the system and recommends that the Commission disallow
recovery of these costs.
The AG agrees with Mr. Coppola’s analysis and recommends that in addition
to removing the non-healthcare inflation of $1.3 million, the Commission remove
$3.6 million of healthcare plan inflation and $3.7 million for the other benefit plans
from the Company’s forecasted O&M expense for the projected test year. This is a
total proposed disallowance of $8.6 million.
47
Summary of O&M Expense Reductions The Attorney General’s recommendations are summarized in Mr. Coppola’s
testimony as follows:
Accordingly, the Attorney General recommends total reductions to O&M expenses
of $128.9 million as discussed above and summarized in the above table. (5 TR
1623). Exhibits AG-2 to AG-8 provide additional details of the areas where the
Attorney General has proposed O&M expense adjustments.
II. CAPITAL EXPENDITURES AND RATE BASE
DTE is proposing a Rate Base level of $17.2 billion for the projected test year.
(Exhibit A-9, Schedule B-1). In comparison to the rate base level of $15.2 billion in
the historical test year, the projected rate base is increasing by $2 billion. (5 TR
1624). This increase is primarily driven by $4.3 billion of new capital expenditures
proposed by the Company during the 28 months ending April 2019. (5 TR 1624).
This would be another record increase in both capital expenditures and rate base for
AmountSummary of O & M Expense Reductions ($Millions)
Inflation Expense Adjustment 75.4$
Power Generation 6.5
Customer Service and Marketing 4.8
Injuries and Damages 1.9
Employee Incentive Compensation 36.7
Employee Benefits 3.7
Total Redustion 129.0$
48
DTE Electric, and the AG urges the Commission to consider carefully the impact
that such increases have on ratepayers. Exhibit A-12, Schedule B-5 provides a
summary of the capital expenditures.
With the help of Mr. Coppola, the Attorney General analyzed the Company’s
forecasted capital expenditures by major department or functional area and has
identified more reasonable expenditure levels that the Commission should consider.
A. Contingent Capital Expenditures DTE is including total contingency costs of $4,470,000 in its forecasted
capital expenditures for 2018 and the 16 months ending April 2020. (5 TR 1624).
This contingency amount should be excluded from the calculation of rate base for
the projected test year. The fact that these added costs are contingent means that
they may not be spent in whole or in part, and thus it is not fair or reasonable for
the Company to recover the depreciation expense and the return on the investment
on potential costs that may not be actually incurred but have been added to rate
base. (5 TR 1625).
The $4,470,000 of contingency costs excludes $10.5 million of contingency
costs related to the Combined Cycle Plant being built by the Company. (5 TR 1624-
25). Page 126 of the Commission’s order of April 27, 2018 in the Combined Cycle
Plant case, No. U-18419, states that only actual costs, up to the amount of $951.8
million, shall be recovered through rates. Although the $951.8 million includes
contingency costs of $17.8 million, it is clear from the Commission order that only
actual costs are to be included in rates. In his rebuttal in support of these
49
contingency costs, Company witness Matthew Paul included a quotation from the
Commission Order in U-18419. (4 TR 598). On cross examination, Mr. Paul
confirmed that the last line of the quotation he included from the Commission is,
“[o]nly actual amounts incurred up to $951.8 million shall be recoverable through
rates.” (4 TR 616-17). Therefore, the $10.5 million of contingency costs pertaining
to the Combined Cycle Plant should also be removed from rate base in this general
rate case.
In DTE’s prior electric rate case, U-18255, the Commission addressed the
issue of contingency costs and approved the removal by the parties of $8.4 million in
contingency capital expenditures from capital expenditures and rate base. (In the
matter of the Application of DTE Electric Company, MPSC Case No. U-18255, April
18, 2018 Commission Order, p. 6). The Commission similarly affirmed this
exclusion in its order in Case Nos. U-18124, U-18014, U-17999, U-17990, U-17767
and U-17735. (5 TR 1625). Accordingly, the Attorney General recommends that the
Commission exclude $15,003,000 from the forecasted capital expenditures in this
rate case filing. Exhibit AG-12 includes the Company’s response to a discovery
request detailing the contingency cost amounts.
B. Distribution Operations DTE forecasts $1.9 billion in capital expenditures for the 28 months ending
April 2020 for additions to Distribution Plant. (Ex. A-12, Sched. B5.4). After
reviewing the testimony and exhibits of Company witness Marco Bruzzano and
50
conducting additional discovery, the Attorney General has identified certain capital
expenditure reductions applicable to several areas.
New Business Projects
In his direct testimony, Mr. Coppola provided a summary of the Company’s
forecasted capital expenditures for New Business Projects:
On page 4 of Exhibit A-12, B5.4, the Company shows forecasted capital expenditures of $50,758,000 (line 44) for the year 2018 for New Business Projects. Additionally, the Company has forecasted $52,230,000 for the year 2019, $68,219,000 for the 16 months ending April 30, 2019 and $52,702,000 for the 12 months ending April 2020. From this information we can determine that the amount pertaining to the 4 months ending April 2019 is $17,461,000 (16-month ended April 2019 total of $68,219,000 – 2018 total of $50,758,000). [5 TR 1626]. To assess the reasonableness of the projected expenditures for 2018, the AG
asked the Company to provide the actual expenditures for the first 8 months of
2018. In comparing the actual expenditures from January to August 2018 to the
amount forecasted for the same months, it is evident that the Company has spent
considerably less than it has forecasted. The Company projected that it would
spend $27,272,000 during the 8-month period. (5 TR 1627). In actuality, it spent
$17,480,000, which is $9,792,000, or 36% below forecast. (5 TR 1627). Exhibit AG-
13 includes the information provided by the Company for the eight months actual
and forecast.
The $9.8 million is a significant variance from the forecasted level and this
under-spending trend likely continued in the later months of 2018. However, giving
the Company the benefit of the doubt that capital expenditures in the final four
months met the forecasted level, it is reasonable to conclude that the cumulative
51
under-spent amount of $9,792,000 for the 8 months ended August 2018 is an
accurate under-spend. In rebuttal testimony, Mr. Bruzzano argues that this
underspent amount should not be disallowed, because the Company overspent in
other areas. (4 TR 856-57). However, Mr. Bruzzano did not provide any details or
data with his rebuttal that justifies why there was excess spending in other areas.
(4 TR 903-05). He attempted to equate the small load projects in the “overspend
area” with the New Business projects where the underspend has occurred, but that
was done at a high level without any detail or evidence. (4 TR 903-05). Generally,
New Business projects tend to be more discreet and for higher dollar amounts per
project than small load projects, so there is no appropriate comparison between the
two sets of projects.
This is an inappropriate, after-the-fact attempt by the Company to
retroactively support a large underspend. The Company has not adequately
supported this underspend and simply “spending money in other areas” is not a
valid justification for recovery in rates of a separate pot of money. Therefore, the
AG recommends that this amount be removed from the projected capital
expenditures and from rate base.
The AG also recommends another disallowance from the Company’s projected
capital expenditures for New Business Projects.
On line 43 of page 4 of Exhibit A-12, B5.4, the Company shows forecasted capital expenditures for Expected New Business Projects not yet specifically identified at the time of the rate base filing. Based on the information provided in the exhibit, the amounts pertaining to the four months ended April 2019 is $11,818,000 and $39,902,000 for the 12 months ending April 2020. In discovery, the Company was asked to provide additional information on the
52
number of contracts it had already signed to complete the new business projects in 2019 and 2020. In the response, which is included in Exhibit AG-14, the Company stated that it had perhaps signed six contracts for 2019 and no contracts had been signed for 2020. No specific amounts were provided on the contracts signed. [5 TR 1627-28].
Based on the discovery response included in Ex. AG-14, the AG concludes
that the Company included an estimate of potential future costs to be completed in
2019 and 2020 as placeholders for future expenditures. The Commission has made
clear in prior rate cases that placeholder amounts would not be accepted for
inclusion in rate base.
There is not sufficient support from the Company that these expenditures
will be made. If recovery is granted but projects do not happen, the Company would
recover costs in rates for capital expenditures that were not actually made. If the
Commission disallows these expenditures from rate base in this case, the Company
can still ask for recovery of these costs in a future rate case, if they are actually
spent. (4 TR 906). Therefore, the AG recommends that the $11,288,000 and
$39,902,000 be removed from the Company’s forecasted capital expenditures.
Infrastructure Resilience and Hardening
On page 7 of Exhibit A-12, B5.4, the Company shows forecasted capital
expenditures of $199,054,000 for the year 2018 for Infrastructure Resilience and
Hardening. To assess the reasonableness of the projected expenditures for 2018,
the AG asked the Company to provide the actual expenditures for the first 8 months
of 2018. In comparing the actual expenditures from January to August 2018 to the
amount forecasted for the same months, the Company spent significantly less than
53
it forecasted. The Company projected that it would spend $116,931,000 during the
8-month period. In actuality, it spent $108,217,000, or $8,711,000 less than
projected. Exhibit AG-15 includes the information provided by the Company for the
eight months actual and forecast.
In rebuttal testimony and on cross examination, Mr. Bruzzano attempted to
support this underspend by arguing that spending must be looked at in totality and
that the Company underspent in some of these areas due to choices and tradeoffs
that the Company has to make as far as priorities and spending. (4 TR 862-64; 4
TR 909-13). It is clear that much of this spending that did not occur in the first part
of 2018 is not important enough, relative to other projects that the Company is
engaged in, for the Company to make it a priority and spend large amounts of
capital on the specific projects at this time. Those projects may wind up being more
important in the future and the Company can come back and seek for recovery for
them if that money is actually spent in the future. Because the projected
expenditures in this area are so far below the forecasted rates, it is not fair to
customers, nor is it reasonable and prudent, to include them in this rate case.
Confusingly, in rebuttal testimony and on cross, Mr. Bruzzano states that the
Company does possess sufficient resources to execute the relevant projected level of
capital. (4 TR 865, 913). This contradicts Mr. Bruzzano’s continued testimony
about problems balancing tradeoffs and issues with the availability of resources.
The $8.7 million is a significant variance from the forecasted level and this
under-spending trend likely continued in the remaining months of 2018. However,
54
giving the Company the benefit of the doubt that capital expenditures in the
remaining four months met the forecasted level, it is reasonable to conclude that the
cumulative under-spent amount of $8,711,000 for the 8 months ended August 2018
is an accurate reflection of under-spend by the Company in this area. Therefore,
the AG recommends that this amount be removed from the projected capital
expenditures and from rate base.
Infrastructure Redesign
On page 8 of Exhibit A-12, B5.4, the Company shows forecasted capital
expenditures of $121,905,000 for the year 2018 for Infrastructure Redesign. To
assess the reasonableness of the projected expenditures for 2018, the AG asked the
Company to provide the actual expenditures for the first 8 months of 2018. In
comparing the actual expenditures from January to August 2018 to the amount
forecasted for the same months, the Company spent significantly less than it
forecasted. The Company projected that it would spend $77,533,000 during the 8-
month period, after removing $2,197,000 for costs related to non-wire pilot
programs that are discussed separately. In actuality, it spent $37,248,000, which is
$40,285,000, or 52%, below forecast. Exhibit AG-16 includes the information
provided by the Company for the eight months actual and forecast.
The $40.3 million is a significant variance from the forecasted level and the
under-spending trend likely continued into the remaining months of 2018.
However, giving the Company the benefit of the doubt that capital expenditures in
the remaining four months met the forecasted level, it is reasonable to conclude that
55
the cumulative under-spent amount of $40,285,000 for the 8 months ended August
2018 is an accurate reflection of under-spend by the Company in this area.
Therefore, the AG recommends that this amount be removed from the projected
capital expenditures and from rate base.
Non-Wire Alternatives Pilot Programs
In his direct testimony, Mr. Coppola provided a summary of the Company’s
forecasted capital expenditures for Non-Wires Alternatives Pilot Programs:
On line 40 of page 8 of Exhibit A-12, B5.4, the Company shows forecasted capital expenditures for pilot programs for non-wire alternatives. The total amount for the 28 months ending April 2020 is $6,015,000. For the full three years from 2018 through 2020, the total amount is $7.5 million. Beginning on page 59 of his direct testimony, Mr. Bruzzano describes the non-wire alternatives that the Company’s wants to test over the coming years through pilot programs. These projects basically consist of research and development work on battery technology to pair battery storage with solar generation, and the use of batteries in a moveable trailer to plug into the grid for temporary power supplement from one to four hours.
The Attorney General does not agree with the Company’s characterization of
these programs as “pilot programs” and argues that the Company has not provided
adequate support for these programs to justify the expenditure of ratepayer funds.
Pilot programs utilized by Michigan utilities, such as the one that was used by DTE
to launch its AMI implementation program, are usually used to ensure that proven
technology will work on a small scale and to sort out problems before full
implementation of the program. In this situation with the battery pilot programs,
the Company is involved in early research and development (R&D) work with
technology firms. (5 TR 1631). There is no proven product that can be readily
implemented, after a short pilot, for the benefit of DTE’s customers. In addition,
56
other utilities are involved in this early R&D with battery technology. The AG
argues that it does not make sense to duplicate the same work at the expense of
ratepayers.
Exhibit AG-17 includes responses from discovery requests to the Company on
this subject matter. Based on the Company’s responses to those questions, there
are at least four utilities in the US already engaged in similar programs. (Ex. AG-
17). On cross, Mr. Bruzzano stated that Company employees have been in contact
with those utilities in order to learn more about the other utilities’ experiences. (4
TR 914). This supports the AG’s contention that the Company should be able to
learn from other utilities in this area. Additionally, Mr. Bruzzano noted on cross
that while this technology is commercially available, the Company presented no
cost/benefit analysis in this case. (4 TR 915-16). Also on cross, Mr. Bruzzano stated
that, “these pilots that we are pursuing are directed more at technical and
operational learnings than they are at a sort of purely economically driven
investment.” (4 TR 915-16). It is tough to reconcile that statement with the
statement in his rebuttal that this Pilot program will result in assets that are used
and useful. (4 TR 867). It is unclear how the Company can know that there will be
used and useful assets before the program is completed, especially in light of the
fact that the program is aimed more at “technical and operational learnings.” Mr.
Bruzzano agreed on cross that if the pilot reaches the end and does not show
economical benefits, then a larger program would not proceed. (4 TR 917). In that
very set of circumstances, the program would not result in ‘used and useful’ assets.
57
The Attorney General’s main concern in this area is that the Company has
not presented a preliminary business case for how the battery technology will
reduce costs or provide other financial benefits to the Company and its customers to
justify launching pilot programs. The AG supports the use of solar technology,
specifically when paired with battery storage, in the Company’s service territory, as
a way to decrease reliance on fossil fuels and provide renewable options for
customers. However, the Attorney General is wary of expensive “pilot programs”
that skew more to the R&D side of the technology and are likely to saddle
ratepayers with higher costs for unproven technologies that may never benefit the
customers.
If there is proven technology available in this area, a business case should be
made before a pilot is launched. The pilot would then help to confirm the
preliminary business case, like past practice by Michigan utilities. At this time, the
AG argues that it is prudent to wait until other stakeholders sort through the
technology and its implementation instead of spending $7.5 million of ratepayer
money on research and development work over the next three years. Therefore, the
AG recommends that the Commission reject the Company’s request and remove
$6,015,000 related to the non-wires alternatives pilot programs for the projected
test year from the forecasted capital expenditures under Distribution Infrastructure
Redesign. The Commission should also direct the Company to present a business
case in a future rate case before resubmitting a proposal to launch pilot programs
for non-wire alternative solutions.
58
Advanced Distribution Management System (ADMS)
In his direct testimony, Mr. Coppola provided a summary of the Company’s
forecasted capital expenditures for the Advanced Distribution Management System
(ADMS):
On lines 3, 4 and 5 of page 9 of Exhibit A-12, B5.4, the Company shows forecasted capital expenditures of $86,797,000 from the year 2017 to the end of the projected test year for implementation of the Advanced Distribution Management System (“ADMS”). According to the Company, the total cost to completion of the project is $116.1 million. Beginning on page 63 of his direct testimony, Mr. Bruzzano describes the various subsystems that comprise the ADMS. The Company began some initial work in preparation of implementation of some of the subsystems in 2017 and expects to complete full implementation by March 2021. Based on information provided by the Company in response to discovery, no other utility in the country has yet implemented the full ADMS suite of systems. A handful of utilities have implemented some of the subsystems. [5 TR 1632]. (internal citations omitted) Based on Mr. Bruzzano’s testimony, it is clear that the Company’s proposal
would make it an early adopter of this technology, indeed the first to implement the
entire suite of ADMS systems, and would bring with it all of the problems and
drawbacks that come with being an early adopter. Being an early adopter of new
technology has risks and it is best to learn from the mistakes of others and
implement technology that is proven and has been in use for a number of years.
The Company has not presented sufficient evidence that the technology it wants to
implement has had a consistent and sufficient record of success to support spending
so much ratepayer money on it. The AG contends that the planned implementation
of the ADMS over the next three years is premature.
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The main benefit that the Company has presented to justify undertaking this
project is the potential reduction in SAIDI time. (5 TR 1633). In Table 20 on page
75 of his direct testimony, Mr. Bruzzano presents a list of potential reductions in
SAIDI from specific uses of the ADMS. (5 TR 1633). The total potential reduction
according to his estimates is between 29 and 60 minutes. (5 TR 1633). Mr. Coppola
analyzed this claim and its relevance in his direct testimony.
Based on the actual all-weather SAIDI of 1,063 minutes in 2017, this would be a reduction of 2.7% to 5.6%. If we use the Company’s normalized baseline SAIDI of 473 minutes, the reduction could be a bit higher. However, SAIDI is never normal. It is in those unusual weather-related occasions when a system such the ADMS would be more useful. It is questionable to spend $116 million on a system that would reduce power interruptions by less than 5%. Although, one could argue that some of the reductions shown in Table 20 are perhaps duplicative or not directly related to the restoration time of an outage, the important point is that these are simply estimates developed by the Company without any specific validation from other implemented ADMS. This is because no other utility has yet implemented the full system. In discovery, the Company was also asked to provide the net present value cost/benefit analysis that justified undertaking this project. In response, the Company provided a project ranking list of this project among others and certain potential cost savings from implementation of the system. By a large measure, the largest potential savings was $97 million from CMI Savings, which appear to be customer minutes interruptions multiplied by some cost factor. The Company did not provide any detail calculations to allow validation of the assumptions behind this number. In the past, when providing customer interruption savings in the context of incentive compensation, the Company has used customer costs related to power outages developed by the Berkeley Laboratory that have been highly inflated and not realistic. In any case, the Company did not provide a robust NPV cost/benefit analysis to justify undertaking a project with a total cost exceeding $116 million. [5 TR 1633-34].
As noted by Mr. Bruzzano on cross, the current systems are stable and
working and the vendors have not stopped supporting the systems. (4 TR 918-21;
Ex. AG-37). Also, based on the Company’s discovery responses contained in Ex. AG-
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37, it appears that the ‘end-of-life’ for these systems as contemplated by the
Company means simply that the systems have been installed for 10 years as of
2018, and has less to do with the functionality of these systems.
Mr. Bruzzano’s rebuttal testimony and answers on cross did not adequately
support his position that the Company should be the first utility to implement this
entire suite of ADMS programs. The Company has no ability to learn from the
problems and mistakes of another Company that has implemented the entire suite,
which makes this a risky proposition for customers. Additionally, in rebuttal Mr.
Bruzzano makes some bold, unsupportable claims as to the possible economic
benefits of ADMS. In his rebuttal testimony Mr. Bruzzano testified that the
economic benefits from ADMS would range from $1.2 to $3.6 billion. (4 TR 873).
Aside from the fact that the contemplated benefits span a range of $2.4 billion
dollars, such purported savings would mean that customers would receive benefits
from ADMS that potentially exceed the total amount billed to them14 in the course
of a year. This is a speculative and unsupported statement on customer savings
that vastly inflates what might possibly be expected from the implementation of
such a system. One source that Mr. Bruzzano cited for the purported financial
benefits is the Lawrence Berkley study included in his rebuttal testimony. (Exhibit
A-31, schedule U-10). Mr. Bruzzano was asked about this study on cross.
Q Exhibit A-31 … Schedule U10…
14 As per DTE Electric’s sales revenue of approximately $3.3 billion in 2017. Exhibit A-13, Schedule C3, page 1 line 1.
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Q Was this the source of the financial benefits based on the Lawrence Berkeley reference that you made?
A … Yes, that is correct. Q Can you please turn to page 16 of this same schedule, U10. A Yes. Q And do you agree that this page lists the limitations of the study? A It does. Q Can you please spend a moment just reading the third bulleted item,
the third bullet there.
A The one that starts, "The further limitations of our research..."?
Q Correct.
A Yes, I have read it
Q And that says that only limited data were available for cities in the Great Lakes, correct?
A It does say that.
(4 TR 929-31). The very study used by Mr. Bruzzano to calculate potential savings
indicates that the Great Lakes region is an area where the study has incomplete
data. Thus, any calculations based on this study are unreliable, and Mr. Bruzzano’s
‘potential savings’ should be disregarded as untrustworthy.
Based on Mr. Coppola’s analysis and the Company’s inability to better
support such an expensive undertaking, the AG concludes that the Company’s
initiation of the ADMS is premature and risky and is without sufficient cost/benefit
justification. Therefore, the AG recommends that the Commission disallow
recovery of the projected capital expenditures for this project from 2018 to the end
62
of the projected test year in the amount of $84,328,000. Additionally, the
Commission should deny the Company’s request for deferred accounting of non-
capitalized costs.
Other Large Projects The Attorney General has additional concern with another large project
within the Company’s distribution area. On line 2 of page 9 of Exhibit A-12, B5.4,
the Company shows forecasted capital expenditures of approximately $81 million
from the year 2017 to the end of the projected test year for modernizing the primary
and back-up System Operating Center (SOC). The total cost to completion of the
project in 2021 is $111 million. (Exhibit A-12, B5.4, line 2 of page 9).
Although the AG agrees that it appears updating the two operating centers
may be necessary in the near future, the costs cited by the Company are excessive.
The modernizing of the primary SOC will be done within the same area of the
Company’s central office complex, while the back-up center will be relocated to
another location. (5 TR 1635). It is not clear from the information provided by the
Company why it costs $111 million to accomplish the relocation and modernization
of the two operating centers. The Company has failed to adequately support this
request, either in its direct or rebuttal testimony, or in discovery responses.
The AG recommends that the Commission deny recovery of the $111 in
capital expenditures and direct the Company to present more detailed costs and
explanations of the necessity to incur such a large expenditure along with actions
taken or to be taken to mitigate the total cost, if they request any future recovery.
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C. Power Generation As shown on page 2 of Exhibit A-12, Schedule B5.1, the Company has
forecasted $911 million in capital expenditures for the 28 months ending April 2020
for Power Generation capital projects. Included in this amount are capital
expenditures for ELG Fly Ash Conversion, Processing and Remediation at the
Monroe power plant, and the construction of a Combined Heat and Power Plant at
the Ford Motor Company Research Center. (5 TR 1635). After reviewing the
testimony of Company witnesses Matthew Paul and Robert Feldmann, related
exhibits, and responses to discovery, the AG has identified capital expenditure
reductions applicable to those areas.
Monroe Fly Ash Projects
In his direct testimony, Mr. Coppola provided a summary of the Company’s
forecasted capital expenditures for the Monroe Fly Ash Projects:
On lines 5, 6 and 18 of page 2 of Exhibit A-12, B5.1, the Company shows forecasted capital expenditures of $14,570,000 for the year 2018, $24,857,000 for the 4 months ending April 2019, and $51,509,000 for projects pertaining to the handling of coal fly ash at the Monroe power plant. In 2015, the Environmental Protection Agency (“EPA”) issued final rules related to wastewater discharge, or Effluent Limitation Guidelines (“ELG”), for steam electric power generators using coal. Under the ELG rule, sluicing (channeling) of waste water and fly ash were more strictly limited. The EPA set a final compliance date of December 2023. The Company has been working to make the Monroe plant compliant with the ELG rules by that date. However, with new leadership at the EPA, the ELG rule is currently under reconsideration to potentially revise the standards for two ELG waste streams (bottom ash and FGD) that impact the Company. Exhibit AG-18 includes responses to discovery requests provided by the Company explaining the ELG rule and current status. [5 TR 1636].
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Given the likelihood that the ELG rule will be revised, the AG contends that
it would be prudent to delay all or most of the work that is currently being done to
meet the current rule by the end of 2023. In addition, the Company has not yet
received approval by executive management to proceed with some of the projects. (5
TR 1636-37). The project work plans provided by the Company show no approvals
have been received for projected spending levels. (5 TR 1636-37). Similarly, no
contract has been entered into with the engineering, procurement, and construction
contractor. Exhibit AG-18 also includes this information provided by the Company.
Based on that analysis, the AG recommends that the total expenditures of
$90,936,000 pertaining to the Monroe Fly Ash projects be removed from the
Company’s forecasted capital expenditures.
Ford Combined Heat and Power Plant In his direct testimony, Mr. Coppola provided a summary of the Company’s
forecasted capital expenditures for the Ford Combined Heat and Power Plant
(CHP):
On lines [sic] 32 of page 2 of Exhibit A-12, B5.1, the Company shows forecasted capital expenditures of $37,728,000 for the year 2018, $2,088,000 for the 4 months ending April 2019, and $22,483,000 for construction of a small power and steam plant at the Ford Research Center. The Company has forecasted that it will pay $62.3 million for a 34 MW Combined Heat and Power (“CHP”) plant to be built by its non-utility affiliate DTE Power and Industrial Group (“DTE P&I”). Ford issued requests for proposals to DTE Electric and other potential developers to build an energy center with the CHP plant as its anchor. Apparently, DTE Electric decided not to bid on the project directly but to have its affiliate DTE P&I bid instead. DTE P&I won the bid to build, manage and own certain assets of the entire energy center, including the CHP plant. Subsequent to winning the project, DTE P&I and DTEE decided that DTEE
65
should own the CHP plant and for DTEE to pay DTE P&I $62.3 million for buying the plant. DTE P&I would operate the plant on behalf of DTEE while also managing and operating other energy related assets in the energy center. [5 TR 1637-38].
The process and circumstances by which the Company (DTEE) is planning to
purchase the CHP plant from its affiliate lack transparency, raise numerous red
flags, and are concerning to the Attorney General both for this case and on a
forward-going basis. The AG recommends that the Commission carefully scrutinize
the facts surrounding the CHP purchase and disallow recovery and inclusion in rate
base of the $62.3 million purchase price.
DTEE and DTE P&I negotiated a purchase price of $62.3 million without
DTEE requesting alternative construction bids from other power plant developers
or Engineering, Procurement, and Construction (EPC) contractors. (5 TR 1638).
Exhibit AG-19 includes responses to discovery questions issued to the Company
admitting to the lack of competitive bids. The lack of a competitive bidding process
is the first major red flag on this issue and raises questions about the fairness of the
$62.3 million purchase price, which the Company wants to include in rate base and
recover in rates. The AG is unequivocally uncomfortable with a situation where
ratepayers foot the bill for a project where the Company “negotiated” a price with
its own affiliate. No matter the intentions of any well-meaning individuals or
groups, the risk of abuse in such a situation is far too great to condone such
behavior through acceptance of costs.
The Company claims that it hired a consultant, HDR, to prepare a cost
estimate of what it would cost to build a similar power plant. (5 TR 1638). Such a
66
solicited, desktop analysis and estimate is not the same, and is not a substitute, for
receiving competitive bids from EPC contractors. The variance of $22.3 million
between the $84.6 million cost estimated by HDR and the $62.3 million purchase
price raises questions about the accuracy of the HDR estimate. The $22.3 million,
26% variance indicates that DTE P&I would be building a plant and selling it to
DTEE at a tremendous loss. This is a ludicrous proposition that the Company
attempts to deflect scrutiny from by stating that it is receiving a wonderful deal for
customers. (5 TR 1174). One wonders what kind of deal actually could have been
achieved for customers had the Company followed a more competitive process.
There has been a lack of transparency as to how the purchase price of $62.3
million was determined. On cross, Company witness Mr. Feldmann was asked
about this:
Q Now, did you present any calculations in your direct or your rebuttal testimony explaining or detailing how that $62 1/2 million purchase price was established?
A No. Q Did DTE Electric request the cost details for that purchase price from
DTE P&I?
A No, it did not.
(5 TR 1173). In essence, the Company is asking customers to pay for a project with
an affiliate that it claims it does not know how the price was established and has
not presented any of that information to customers. The Attorney General actually
requested that the Company request this information from DTE P&I so that it could
67
be examined in this case, but the Company was unwilling to make that request. (7
TR 1175; Ex. A-40).
If the Company had obtained alternative bids for the construction of the
CHP plant alongside a construction bid from its affiliate, it would have been easy to
determine whether the DTE P&I plant cost was fair and reasonable. The fact that
the Company did not request such alternative bids raises questions as to why it was
not done and raises serious suspicions that perhaps the affiliate bid would not have
been the winning bid. On cross Mr. Feldmann attempted to further rationalize this
process by arguing that if the Company had not reached an agreement with its
affiliate in this non-competitive setting, Ford Motor Company would likely have
stopped buying power from DTE. “[I]t would have been easier for us to simply walk
away from that transaction, let a third party build a facility, have Ford Motor
Company take energy and steam from a third party, and today I would be here
saying, well, Ford Motor Company is leaving, we're going to have a significant
reduction in the volume of units we're going to sell over the next 30 years, I'm
looking for cost recovery.” (5 TR 1184). This is a speculative, after-the-fact
justification that attempts to hold other customers “hostage” based on DTE’s
asserted understanding of the whims of one of its largest customers. There are
surely much better ways to make sure that large purchasers of power are happy
with the service they receive from the Company, while still conducting transparent
processes so that other ratepayers can determine they are not getting a bad deal.
68
At this point, it may be too late to receive alternative bids, but it would be
helpful if the Company requested that its affiliate DTE P&I share with Staff,
Intervenors, and the Commission in this case the actual construction cost of the
plant by providing information about EPC contract bids it received to build the
plant, along with other costs and management fees added to arrive at the $62.3
million price. During cross examination, the Company’s witnesses were unable to
provide further detail on the transaction between DTEE and DTE P&I, and seemed
to indicate that they were removed from the proceedings with no knowledge of how
the $62.3 million price was arrived at. (5 TR 1146-48).
Without additional information, it is not possible to support this project or
the related capital expenditures proposed by the Company in this rate case. The
potential for cost subsidy between the utility and its non-utility affiliate is too great
to ignore. If the Commission grants approval for this project with no additional
transparency and without requiring alternative competitive bids, it would set a bad
precedent and it is likely that the Company, and perhaps other jurisdictional
electric utilities, may use the same model of joining with non-utility affiliates on
similar projects in the future, with no competitive process to protect customers from
inflated prices. Therefore, the AG recommends that the Commission reject the
$62.3 million of capital expenditures requested.
D. Corporate Staff Group On page 1 of Exhibit A-12, Schedule B5.8, the Company shows forecasted
capital expenditures of $114,395,000 for the year 2018 for various corporate areas.
69
Additionally, the Company has forecasted $27,590,000 for the 4 months ending
April 2019, and $101,893,000 for the 12 months ending April 2020. (5 TR 1640).
Before examining the various projects, Mr. Coppola assessed the
reasonableness and progress during 2018 of DTE’s forecasted expenditures. (5 TR
1640). Mr. Coppola found that DTE has only spent $47,901,000 in the first six
months of 2018 in comparison to DTE’s forecasted amount of $64,953,000 for those
same six months. (5 TR 1640). The Company’s actual spending level in this area is
$17,052,000, or 26%, less than forecasted. Based on these numbers, Mr. Coppola
concluded that it is reasonable to conclude that DTE’s underspending in this area
likely continued in the latter part of 2018. (5 TR 1640). However, giving the
Company the benefit of the doubt that capital expenditures in the remaining four
months were close to the forecasted level, it is reasonable to conclude that the
cumulative under-spent amount of $17,052,000 for the 8 months ended August 2018
is an accurate representation of the total under-spend. Therefore, the AG
recommends that the $17,052,000 be removed from the projected capital
expenditures and from rate base. To do otherwise would be to grant the Company a
terrific and unwarranted boon.
Other Adjustments to Corporate Staff Capital Expenditures
In addition to the above adjustment to Corporate Staff capital expenditures,
Mr. Coppola recommended an adjustment to the Company’s forecasted capital
expenditures for the Headquarter Energy Center. (5 TR 1641).
On line 5 of page 1 of Exhibit A-12, B5.8, the Company shows forecasted capital expenditures for the Headquarter Energy Center of $684,000 for 2017,
70
$5,022,000 for 2018, $4,661,000 for the 4 months ending April 2019, and $22,161,000 for the 12 months ending April 2020. In total, the HQ Energy Center cost is $32.5 million. Beginning on page 45 of her direct testimony, Ms. Theresa Uzenski describes the HQ Energy Center project and why the Company believes it is necessary. The Company currently relies on steam from Detroit Thermal, a business previously owned by DTEE, for heating and cooling its headquarters building. Apparently, the Company has experienced steam purchase costs increasing at 5% annually in recent years and fears that those costs may continue to increase perhaps at even higher rates. Furthermore, the Detroit Thermal pipes delivering steam are leaking damaging electric wires and landscaping, and interrupting service. The Company also states that its chilled water system is reaching its useful life, and wants to build a new energy center to make its own steam to heat and cool its headquarters building. Ms. Uzenski points to the benefits that the new energy center would provide, such as more efficient chillers, easier access to system controls, better control of steam cost, and avoidance of steam leaks. [5 TR 1641-42].
In discovery, the Company was asked if it had attempted to negotiate a lower
service rate with Detroit Thermal to continue to buy steam at a lower price under a
long-term contract. The Company responded that it had not pursued such
negotiations. The Company was also asked to explain why steam leaks continue
and no action has been taken to repair the leaks. The response states that leaks are
the responsibility of Detroit Thermal and that the Company does not know why the
leaks have not been repaired. Exhibit AG-21 includes these discovery responses.
It does not appear that the Company has adequately considered or presented
alternatives to building an entirely new center. From the discovery responses, it is
evident that the Company has not taken a proactive approach to solve the steam
price issues and leak problems with Detroit Thermal. This lack of action
71
undermines the Company’s argument that the best solution is to build its own
energy center, as the Company has failed to consider or investigate cheaper options.
In discovery, the Company was also asked if it had obtained a separate
estimate for only replacing the chilled water system. In response, the Company
stated that it has not estimated a separate cost for a chilled water system and
would rather continue with the current steam service than build only a chilled
water system. (Ex. AG-21). This also undermines the Company’s argument.
Finally, the Company was asked to provide the cost/benefit analysis, on a net
present value basis, justifying the construction of the new energy center. The
cost/benefit analysis provided by the Company shows that continuing with the
current steam service with Detroit Thermal at an annual cost escalation rate of
5.2% is a significantly lower cost, by $17.7 million on a present value basis, than
building the new energy center. A copy of the summary page of the cost/benefit
analysis is included in Exhibit AG-21.
The new HQ Energy Center is not justified on a financial basis and the
Company has not fully explored other options to lower the cost of purchasing steam
and solve leak problems with Detroit Thermal. Therefore, the AG recommends that
the Commission remove the proposed capital expenditures from 2017 to the
projected test year ending April 2020 for a total amount of $28,058,000, excluding
contingency costs previously removed under the Contingency Costs section.
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E. Charging Forward EV Pilot
In his direct testimony, Mr. Coppola provided a summary of the Company’s
forecasted capital expenditures for the “Charging Forward” EV Pilot:
In his direct testimony, Company witness Camilo Serna discusses extensively the proposal to initiate a 3-year pilot program aimed at increasing electric vehicle charging infrastructure, promoting the purchase of electric vehicles (“EVs”), understanding customer behavior about using and charging EVs, and assessing the market for investment in charging infrastructure by host sites, among other objectives. Mr. Serna proposes spending $13 million on the pilot program over a 3-year timeframe, with $5 million to be recovered through capital expenditures included in rate base, $5 million of customer rebate costs for installed chargers to be booked to a regulatory asset and amortized over 5 years, and $3 million in O&M expense for program management and consumer education. Exhibit A-12, Schedule B5.9 provides further details. (5 TR 1643-44).
The AG agrees with much of the intent and the structure of the pilot program
and believes that it is likely to provide valuable information about the potential
utilization of the installed chargers in order to make a more informed analysis
about the usefulness of customer rebates and other cost funding that may be
requested after the end of the pilot.
However, one economic aspect of the pilot which gives the AG pause is the
“Make-Ready” proposal. Under this plan, the Company would make capital
upgrades or additions to transformers, service drops, meters, other hardware, and
materials with the related labor costs in order to facilitate the installation of Level 2
and DC Fast Chargers. The Company proposes that the costs to install the
upgrades be included in rate base and charged to all customers. (8 TR 3681-82).
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Currently, these costs are paid by the customer requesting the upgrade as
contributions in aid of construction after a standard allowance based on a two-year
estimate of revenue at the service location. (6 TR 2270). The Company feels that
the portion of the costs that should be borne by the customer is an impediment to
the installation of EV chargers at host sites. (5 TR 1645). In other words, the
revenue to be generated from the EV charger is insufficient to reduce the
installation costs to a reasonable level and the host site customer does not want to
make the additional investment. Thus, the Company is asking that all other
ratepayers subsidize the cost of those EV connections and installations. Exhibit AG-
22 includes several responses by the Company to discovery questions seeking
additional clarification on this proposed change to the long-standing policy on line
extensions.
There is a fundamental reason why the line connection policy is in place.
Each new connection or upgrade to a connection must generate sufficient revenue to
justify the investment and return on that investment within a reasonable time
period so that other customers are not subsidizing new customers. The same
concept should apply to EV connections. If the EV charger connection does not
make economic sense under the existing policy, it should not be installed. Although,
the Company is seeking $5 million in capital expenditures to cover potentially
uneconomic EV charger connections only during the three-year period of the pilot
program, once offered, it would be difficult to reverse this proposed change in the
line extension/connection policy. If the forecasted growth in EVs included in Mr.
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Serna’s testimony materializes, the costs to ratepayers could be significant over
time, long after the end of the pilot program. The Commission has worked
diligently in recent years to remove rate subsidies. It makes no sense to introduce
new ones. Therefore, the AG recommends that the Commission approve the bulk of
the “Charging Forward” pilot program but reject the Company’s “Make-Ready”
proposal and the related capital expenditures of $1,744,000 in the projected test
year.
Summary of the AG Disallowed Capital Expenditures
The following table is a summary of the Attorney General’s capital
expenditure recommendations, as expressed in Mr. Coppola’s testimony (5 TR
1646):
Accordingly, the Attorney General recommends that the Commission reduce the
Company’s proposed capital expenditures and deferred costs by $415.9 million and
Summary of AG Disallowed Capital Expenditures
Contingent Capital Expenditures 15.0$ Distribution Operations
New Business 61.5 Infrastructure Resiliency & Hardening 8.7 Infrastructure Redesign 46.3 ADMS 84.3
Power GenerationMonroe Fly Ash Projects 90.9 CHP Plant 62.3
Electric Vehicle Pilot ProgramCharger Service Connections 1.7
HQ Energy Center 28.1 2018 Underspent 17.1
415.9$
Corporate Staff Group
Total
Amount (millions)
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average rate base by $394.8 million, including working capital adjustments
discussed below. Exhibit AG-23 provides additional details and calculations of
these amounts.
IV. INFRASTRUCTURE RECOVERY MECHANISM
Through the testimony of Don Stanczak, Kenneth Slater, and other
witnesses, the Company has proposed a mechanism to recover costs for capital
expenditures to be made after the end of the projected test year, which includes the
8 months ending December 2020 and the full years of 2021 and 2022. In the
proposed Infrastructure Recovery Mechanism (IRM), the Company has included
capital expenditures for Distribution Operations, Fossil Generation, Nuclear
Generation and the New 1,100 MW Combined Cycle Power Plant. (5 TR 1647). In
effect, the proposed IRM is comprised of capital expenditures typically included in a
general rate case. (5 TR 1647). The amount of the projected capital expenditures is
$807 million for the 8 months ending December 2020, $1.054 billion for the year
2021, and $958 million for the year 2022. (5 TR 1647). Exhibit A-30, Schedule T1,
provides the major components with further details referenced to other exhibits.
The Company proposes to impose a surcharge on customer bills during the
relevant time period for additional revenue of $80.3 million in 2020, $165.4 million
in 2021, and $277.9 million in 2022, for a total amount of $523.7 million over the
two years and eight months. (5 TR 1648). At the end of each year, the Company
would file a reconciliation of the capital spending and would credit customer bills for
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the revenue requirement applicable to the amount of actual capital spending below
the forecasted capital level. (5 TR 1648). DTEE also proposes to reconcile the IRM
revenue actually billed to customers to the required amount that should have been
billed. (5 TR 1648). These annual refunds or surcharges from the reconciliation
proceedings would be recorded in a regulatory asset or liability account and actually
refunded or surcharged on a net basis once the IRM terminates. (5 TR 1648). The
IRM would terminate once the Company receives a final order in its next rate case.
(5 TR 1648).
The Company has requested the flexibility to move around up to 20% of the
capital expenditures in any discrete category with the major business units shown
in Exhibit A-30, Schedule T1, but not between these business units. (5 TR 1648).
The Company proposes to meet with the Commission Staff each fall to review
expected IRM expenditures and the scope of work to be accomplished for the
upcoming IRM year. Additionally, the Company would meet with Staff during the
year to review progress toward completion of the capital programs.
In conjunction with the IRM proposal, the Company has stated that it may be
able to defer filing for another rate case until sometime in 2022 for new rates to go
into effect in 2023. However, the Company has made clear that it is not providing
any assurances or guarantee that even with the IRM in place it will wait to file
another rate case until 2022.
The Attorney General has a long history of opposing the use of, as well as any
expansion of, IRM mechanisms. This case is no different, and the AG recommends
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that the Commission deny the Company’s request for such a humongous IRM,
which would provide the Company with unquestioned and un-vetted funding to the
detriment of customers.
The IRM proposed in this case raises several concerns and issues, some of
which are similar to and some that are different from other mechanisms that the
Commission has approved in the past. The IRM is, in effect, an extension of the
current rate case with firm rate increases planned over the subsequent 2 years and
eight months, totaling $524 million, without the benefit of the protections and
examination afforded by a general rate case.
The proposed IRM creates another stand-alone cost tracking mechanism.
While specific projects proposed for the projected test year can be evaluated and, if
necessary, challenged within a general rate case before the Company undertakes
those projects, the review and potential disallowance of costs under the IRM occurs
after costs are incurred, which is more problematic. The potential disallowance of
tens of millions of dollars of capital expenditures places the parties in IRM
reconciliation cases in the difficult position of potentially negatively affect the
Company’s earnings. Despite their best intentions, the Commission may also be
more reluctant to approve disallowances after the costs are incurred. The result is
almost certainly higher costs passed on to customers, for projects that should never
have been undertaken. The Company’s proposal to meet with Staff before the start
of each year to review upcoming projects and then report on the progress of those
projects during the year of implementation is not the same as an evaluation under
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the discovery process with a contested case. The Company’s proposal also
conspicuously excludes other parties that intervene in rate cases and that might
have an interest in challenging the Company proposed projects and expenditures.
On page 15 of his direct testimony, Mr. Stanczak states that the capital
expenditures included in the IRM are above and beyond replacement capital. (3 TR
76). This statement does not match with the capital expenditures included in the
supporting exhibits sponsored by witnesses Bruzzano, Paul, and Davis, where
routine and base capital expenditures are included for recovery in the IRM.
Another important point is that the Company will receive revenues from
some of the investments included in the IRM in addition to the IRM surcharge
revenues. (5 TR 1650). The capital expenditures presented by Mr. Bruzzano in
Exhibit A-30, Schedule T2 include customer connections that will generate
incremental revenues as electricity sales are made to new customers. The inclusion
of these capital expenditure categories, and perhaps others with revenue, in the
IRM seems unnecessary and would likely result in duplicate revenues being
collected for the same capital investments.
Regulatory Policy Concerns
Similar to previous cases, the AG has significant regulatory policy concerns if
the Commission were to approve the proposed IRM. Mr. Coppola details those
concerns in his testimony, addressing some of the major reasons against
implementing the IRM.
1. The prudence and reasonableness review of the capital expenditures before they are incurred is avoided as discussed above in my testimony. One of
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the benefits of a general rate case and having a projected test year is the ability to scrutinize and challenge capital projects before those costs are incurred. The IRM skirts that process. The projected expenditures would be incurred up to four years from now. These projections are simply “ballpark” estimates in many cases without any specific plans. Yet, the Company wants an approval now for capital expenditures to be made years down the road. The review process before the start of the year between the Company and Staff excludes other parties, and is unclear if the Company would remove capital expenditures to which Staff or others objected.
2. The incentive to reduce capital expenditures and other costs would be eliminated since recovery is nearly assured. The IRM gives the Company basically a blank check to further accelerate rate base growth and increase rates almost unabated. The Company is already increasing rate base at a double digit rate. The IRM would accelerate further that rate of growth, not abate it. This risk should be very concerning to the Commission.
3. Once started, the IRM will likely be expanded to other capital cost categories. As we have seen with Consumers Energy, in Case No. U-18424 the company proposed an expansion of its IRM to other capital cost categories from the initial program scope approved by the Commission in a previous rate case.
4. The IRM inappropriately shifts the business risk away from the Company and onto the customers.
5. The IRM reduces regulatory lag in the recovery of capital costs, reduces earnings volatility and reduces overall business risk for the Company. The Company has not made any allowance for this reduction in business risk in the calculation of its proposed return on equity rate of 10.50%, despite Company witness Vilbert’s testimony dismissing the need for an ROE risk reduction.
6. The IRM would function in isolation of other changes in costs and revenues that would be occurring within the Company. Therefore, the Company could be over-earning in the rest of the business and still surcharge customers for a cost that should be offset against the rest of the business. This is particularly concerning since the Company has earned a return on equity at or above the authorized level in the past five years. (Exhibit A-1, Schedule A2, page 4). [5 TR 1651-52].
As one final point, the AG wishes to address the Company’s mention in its
testimony about potentially delaying the filing of another rate case, if the IRM is
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approved. Beginning on page 14 of his direct testimony, Mr. Stanczak seems to
offer a proposal that the Company would delay filing another rate case until
sometime in 2022, if the Commission approves the proposed IRM. (3 TR 75).
However, in the subsequent paragraph and pages, he explains why the Company is
not likely to delay such a rate filing because of other cost pressures, and on cross
examination he gave no guarantee that the Company would delay such a filing. (3
TR 76; 5 TR 1652). This mention and brief discussion by the Company is a
misleading attempt to influence the Commission to approve the proposed IRM and
the Commission should not give this discussion any weight in reaching a decision on
the IRM.
In summary, the Attorney General argues that there is nothing positive about
a large IRM for customers and the AG continues to recommend that the
Commission reject the Company’s proposed IRM.
V. DEPRECIATION EXPENSE
The Company included higher depreciation expense in its proposed revenue
requirement to reflect the higher depreciation rates proposed in Case No. U-18150.
In the revenue requirement filed in this rate case, the Company has included
$175,795,000 of higher depreciation expense based on its filing of higher
depreciation rates in Case No. U-18150. Based on the Commission’s Order in Case
No. U-18150 approving the settlement agreement, the agreed upon depreciation
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expense and the related revenue requirement, including any impact on rate base,
should be reflected in this rate case.
VI. WORKING CAPITAL ADJUSTMENTS
The AG does not agree with the Company’s proposed level of working capital of
$1.529 billion. Instead, the AG proposes that the level of working capital in this
case be reduced by $70 million, to $1.459 billion, to reflect (1) the exclusion of $3.5
million of short term investments classified as cash by the Company; (2) a lower
balance of the Company’s Prepaid Pension Asset of $44.6 million; and (3) a
reduction of the Company’s projected Fuels Inventory in the amount of $21.9
million. These adjustments and the revised level of Working Capital are shown in
Exhibit AG-24.
Regarding the Company’s level of cash in the projected test period, the
Company set the level equal to $14.7 million, which is essentially the same level for
the historic 13-month average. However, in discovery, the Company stated that
approximately $3.5 million of the $14.7 million represents short term investments
with affiliates which bear interest. (5 TR 1654). This amount should be excluded
from working capital. The Commission has stated in prior rate cases that cash
investments that earn interest should be excluded from working capital.
The Company set its pension asset level on line 21 of Exhibit A-12, Schedule
B4, at $841.1 million for the projected test period. However, in response to a
discovery question, the Company indicates that this amount was in error and that
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the proper amount should be $796.5 million. (5 TR 1654). The Company’s revised
calculation reduces working capital by $44.6 million.
With regard to Fuel Inventories, the Company has set the project balance for
the test year at $126.1 million. This balance is $21.9 million higher than the
historic balance of $104.2 million. In her testimony starting at page 54, witness
Uzenski attributes the increase to contracts with coal processors which supposedly
conclude in 2019. (7 TR 3327). According to her testimony, under the contracts, the
Company will be required to purchase $69.2 million in coal. (7 TR 3327). Absent
the end of the contracts, the coal inventory would be maintained by the coal
processors and the Company’s working capital would be lower. The end or
continuation of the coal processing contracts depends upon the continuation of
Federal Tax credits available to the coal processor companies. Apparently, the tax
credits are set to expire in December 2019 for two of the processor companies and in
December 2021 for the third processor company.
Company witness David Milo, as a Fuel Resources Specialist within the
Company’s Fuel Supply Department, provided testimony on fuel supply costs. (6
TR 2296-97). He also provided rebuttal testimony objecting to Mr. Coppola’s
proposed removal of coal inventory balances held by fuel companies that process
coal under the Reduced Emissions Fuel, or REF, program, from working capital. (6
TR 2297). On cross, Mr. Milo was asked to discuss further his rebuttal and his
disagreement with Mr. Coppola’s testimony. Despite being the Company witness on
this topic, Mr. Milo was unable to provide answers to questions posed by the AG or
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otherwise adequately support his arguments. One example during an exchange
when the AG was attempting to understand the REF program and the parties and
interactions included in that program:
Q … So after the coal inventories go through that REF process that we referenced, they're returned to DTE Electric and then inventoried for use in the power plants; is that correct?
A I'm not sure exactly of how, the exact timing of when they become DTE
Electric or REF property, so I don't feel like I'm qualified to answer that.
(6 TR 2298-2300). As Mr. Milo is the Company’s witness in this area, this makes it
impossible to support the Company’s requested inclusion of these inventory
balances in working capital.
The issue in this instance, as the AG understands it, is that some of the REF
contracts expire after some of the federal tax credits that the fuel companies receive
are scheduled to expire at the end of 2019. (6 TR 2299-2300). Accordingly, the
Company has forecast that its coal inventories will increase because some of the
affiliated fuel companies that process the coal for the REF program will no longer
hold coal inventories after December of 2019, but will instead return those to the
Company. (6 TR 2300). Mr. Milo indicated on cross that any repurchase of this coal
would need to occur on or before the last day in 2019. (6 TR 2300). On cross, the
AG elicited that the projected value of the coal that will be returned on that last day
in 2019 is $90 million. (6 TR 2301-02). However, immediately after that, Mr. Milo
stated that that $90 million figure was not provided anywhere in this case. (6 TR
2303). Accordingly, the AG argues that the Company’s position on this issue is
unsupported, because the information was not provided to all parties and there was
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no opportunity to examine those numbers. It is also entirely possible that the
quantity of coal inventory at the end of December 2019 could be materially different
than forecasted, which would change this calculus.
The Company is operating on the premise that the tax credits will not be
extended past the current expiration dates. However, Congress often extends the
termination dates on such tax credits near the date when they are set to expire. (5
TR 1655). It is premature to assume that the tax credits will terminate at the
current expiration dates and that the Company’s coal inventories will increase to
the level projected. On cross, Mr. Milo agreed that he doesn’t have any specific
knowledge about what efforts are being made by the Company or others in the
industry to extend these tax credits. (6 TR 2304). Thus, speculation about them not
being extended is merely that, unsupportable speculation. It is not reasonable to
burden customers with the cost of the higher inventories at this time. Therefore,
the AG recommends that the Commission reject the $21.9 million increase in the
coal inventory balance for the projected test year.
VII. COST OF CAPITAL
In its filing, the Company has proposed a permanent capital structure with a
common equity component of 51%. This percentage is slightly higher than the 2017
historical test year percent of 50.6%, and the AG argues that the Company provides
no compelling support for this higher level of common equity. The Attorney General
continues to recommend that a capital structure of 50% equity and 50% debt, as
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shown in Ex. AG-25, be used in this case. Lines 1 and 3 of Ex. AG-25 show the
projected long-term debt and common equity permanent capital of the Company for
the test year ending April 2020. The permanent capital balances in this exhibit
reflect the numbers set forth in Company Exhibit A-14, Schedule D1, with an
adjustment to rebalance the capital structure. The long-term debt component in
Exhibit AG-25 has been increased by $131 million and the common equity
component has been reduced by the same amount from the amounts proposed by
the Company. The result is a capital structure with 50% common equity and 50%
long term debt, which reflects the capital percentages approved by the Commission
in Case U-18255, which is the Company’s prior general rate case.
The AG opposes the Company’s proposed common equity ratio of 51% for a
number of reasons.
First, the common equity ratio of the peer group, used to assess the cost of
common equity in this case, averages 47.6%. (Exhibit AG-27). It is worth pointing
out that this lower average common equity level supports these companies’ utility
operations, as well as non-utility operations, which tend to be riskier. (5 TR 1657).
The riskier non-utility operations require a higher common equity cushion to
maintain similar credit ratings. (5 TR 1657). Therefore, if an adjustment was made
for the higher equity capital required by the non-utility businesses, the equity
capital for the utility portion of the peer group’s capital structure would be even
lower.
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Second, in case U-17990, the Commission directed Consumers Energy
Company (Consumers), DTE’s most comparable in-state peer utility, to move
toward a balanced capital structure of 50% common equity and 50% debt. (In the
matter of the Application of Consumers Energy Company, MPSC Case No. U-17990,
February 28, 2017 Commission Order, pp 63-64.) Given the similarities between
the companies, it is reasonable to expect DTE Electric to have the same capital
structure.
Third, DTE Electric is a captive subsidiary of DTE Energy. DTE Energy can
make the Company’s common equity ratio of its subsidiaries whatever it wants.
The same executive management that runs DTE Energy controls the Company’s
major decisions and at any time management can direct how much in capital it
wants to inject into the Company from the parent company and call it equity
capital. Such freedom to call for equity capital would not exist if DTE Electric itself
was a publicly-traded company.
With regard to the common equity ratio of the peer group, the average
common equity ratio of the peer company group at June 30, 2018 was 47.6%. (Ex.
AG-27). Even if the two outliers, CMS Energy and Portland General Electric, are
removed the average peer group equity ratio is 48%. (5 TR 1658). The cost of
equity for those companies in the peer group is highly dependent on the financial
risk reflected in their capital structure. Thus, it is critical to synchronize the capital
structure of the Company to the peer group average as closely as possible in order to
have consistency with the cost of equity capital derived from those peer group
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companies. The Company’s proposed common equity capital ratio of 51% creates a
disconnect that is not acceptable and is also costlier to customers.
Consistent with this position, if the Commission believes that a 51% common
equity ratio is appropriate, then the return on equity rate based on a peer group
with lower common equity levels should be adjusted downward.
The Company attempts to support a higher common equity level in this case
through the testimony of Mr. Solomon. Mr. Coppola spent time in his direct
testimony analyzing this:
On pages 9 through 13 of his direct testimony, Mr. Solomon attempts to support the need for a higher common equity percentage by pointing to lower deferred taxes and cash flows in the future as a result of tax reform under the 2017 Tax Cut and Jobs Act (“TCJA”). He claims that the purported lower cash flow puts pressure on the credit metrics supporting bond ratings. He points to certain recent ratings actions of Moody’s Investor Service (“Moody’s”) and Standard & Poor’s (“S&P”), as well as a handful of regulatory decisions in other jurisdictions. However, some of the information he provides is incomplete and somewhat misleading. For example, to justify the higher equity ratio on page 11 of his direct testimony, Mr. Solomon notes that Moody’s has put its affiliate, DTE Gas, on negative outlook. He states that “This is a direct result of the weakened credit metrics…due to tax reform.” The Company provided a copy of the Moody’s announcement in response to a discovery request, which states the reason for the negative outlook as follows:
DTE Gas’s negative rating outlook reflects our expectation that the Company’s decision to maintain existing capital expenditure levels near their record highs, at a time when it is grappling with the negative cash flow impacts from federal tax reform, will result in a sustained weakening of its financial metrics, says Lesley Ritter AVP-Analyst.
Clearly, Mr. Solomon’s efforts to attribute the Moody’s action for DTE Gas primarily or entirely to tax reform are misleading. Furthermore, in the same discovery request, the Company was asked to explain what corrective action DTE Gas is taking to reduce capital expenditures or improve profitability to avoid any future credit rating issues. In response, Mr. Solomon stated that
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“DTE Gas Company has not made material changes to its financial policies or capital budget as of a result of the Moody’s negative outlook. The capital expenditures are deemed necessary by management and provide increased pipeline integrity as well as other benefits to our customers.” It is then apparent that Mr. Solomon and other members of management, who make capital structure and financial decisions for both DTE Gas and the Company, are not highly concerned about the Moody’s negative outlook and its ramifications. Additionally, on page 12 of his direct testimony, Mr. Solomon states that the Florida Regulatory Commission allowed three different utilities to use tax savings that would have been otherwise refunded to customers to offset power restoration costs from Hurricane Irma. This is all well and good as a means to avoid higher rates in the future for power restoration and the like. However, this action does little to nothing to support credit metrics longer term, as Mr. Solomon seems to imply. Finally, on page 12 of his direct testimony, Mr. Solomon states that the Georgia Commission allowed Georgia Power to increase its authorized equity ratio from 51% to 55%. This increase is contingent on other events occurring and was part of a comprehensive settlement that covered many issues to bolster Georgia Power’s financial position. What Mr. Solomon didn’t include in his testimony were the background facts regarding Georgia Power. This company is midway through the construction of two nuclear power plants with $3 billion already spent and with its primary contractor Westinghouse having declared bankruptcy. Georgia Power has now taken over the project itself with the assistance of Bechtel. This is an unusual situation where the Georgia Commission is boosting the equity ratio to support the utility during this period of financial hardship. [5 TR 1658-61].
During cross examination Mr. Solomon was asked about many of these
issues. (5 TR 1073-78). He repeatedly agreed that neither the gas nor the electric
side of the Company has seen its credit rating downgraded and that he has no
knowledge of any intention by a credit-rating agency to do so. (5 TR 1073-78). On
cross, Mr. Solomon also admitted that the gas and electric businesses are different
and that differences between the two have been a factor in preventing rating
agencies from putting any kind of negative outlook on the electric business. (5 TR
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1073-74). He danced around many of these issues on cross, agreeing that the
Company’s strong historical cash flow is likely part of the reason that Moody’s has
not placed the Company on a negative outlook, but then qualifying all of his
answers with nebulous statements suggesting that the Company could face
negative outlooks and downgrades in the future. (See 5 TR 1074-75). Exhibit AG-
32 also includes discovery responses from the Company agreeing that no rating
agencies have placed DTEE on credit watch or requested an increase in the equity
ratio.
In rebuttal, Mr. Solomon argued that Mr. Coppola’s analysis of the DTE
Energy’s common equity percentage is incorrect, because he did not consider other
elements of the Company’s business and capital structure, including instruments in
the balance sheet that are debt-like but have some equity characteristics. (5 TR
1061). On cross, Mr. Solomon was asked if he had done a calculation with those
items he cited in rebuttal, to adjust the debt and equity capital for DTE Energy. (5
TR 1072). He agreed that, subject to check, the adjustments mentioned in his
rebuttal equate to an adjusted common equity ratio of 48.2% for DTE Energy. (5 TR
1071-72; Ex. AG-39). It is unclear how DTE Energy can have a lower equity ratio
than its largest subsidiary, DTE Electric.
Also on rebuttal Mr. Solomon mentioned Consumers Energy, and specifically
their rate case U-20134 and their request for a capital structure with 52.5%
common equity. (5 TR 1062). On cross, Mr. Solomon agreed that the Commission
has not yet ruled on the capital structure in that Consumers case or issued an order
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in that case. (5 TR 1073). Therefore, it is inappropriate to consider that request in
this rate case.
With regard to maintaining DTE Electric’s ratings with S&P, Mr. Solomon
stated on page 11 of his direct testimony that the pro-forma effect of tax reform on
the Funds From Operations to Debt (“FFO/Debt”) will reduce this credit metric from
21.2% in 2017 to 17.8%, implying a potential credit downgrade. (5 TR 1661).
However, in response to a discovery request, Mr. Solomon stated that the
Company’s S&P debt ratings could be imperiled if the FFO/Debt ratio were to fall
below 13%. (5 TR 76). This is approximately five percentage points lower than the
pro-forma level computed by the Company on Exhibit A-14, Schedule D1.3, and far
from any apparent concern.
The Company was also asked to provide the forecasted credit ratios for 2018
and 2019 reflecting the impact of the TCJA. (Ex. AG-31). In response the Company
stated that it could not provide this information. (Ex. AG-31). The Company’s
argument that the TCJA will have a negative impact on the Company’s cash flow
and credit ratios is disingenuous if it cannot provide any evidence of this claim
beginning with the year that the TCJA went into effect. Mr. Solomon was asked
about this on cross and agreed that no attempt was made to provide intervenors
with this information for 2018 and 2019. (5 TR 1076-77). His reasoning that this
was not done was because the S&P adjustments for 2018 and 2019 were not
available and the Company did not want to assume that they would be static. (5 TR
1076-77). However, Mr. Solomon was then asked to discuss meetings that the
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Company has had with rating agencies since the enactment of the TCJA. (5 TR
1077). He agreed that such meetings have taken place since enactment of the TCJA
and that the Company presented pertinent financial results, cash flow information,
and projected credit ratios at that meeting. (5 TR 1077). This is the same
information the AG requested in the discovery requests included in Ex. AG-31, in
order to calculate the 2018 and 2019 ratio of FFO to debt. However, this
information, which was apparently available to rating agencies, was not provided to
the AG. (5 TR 1078).
DTE Electric is not simply a bystander in how its credit ratios will sort out
going forward. Management can take steps to improve cash flow, reduce capital
expenditures and reduce debt in order to maintain its credit rating. The Company’s
arguments through this section are nothing more than a distraction. In summary,
Mr. Solomon has not made a convincing case that a higher equity ratio is justified
or needed.
It is also important to highlight the fact that no credit rating agencies have
downgraded DTE Electric’s credit rating or even put the Company on a credit
watch. (Ex. AG-32). The Company often raises the specter of a credit rating
downgrade to try and influence the Commission to increase the equity ratio. As an
example, on page 16 of his direct testimony, Mr. Solomon stated that a downgrade
could increase debt interest rates by 25-50 basis points. (5 TR 1048). Assuming for
the sake of argument that a downgrade would occur, which is a remote possibility,
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the increase in interest expense is insignificant in comparison to the Company
having a higher equity ratio.
If the Commission were to adopt a 51% common equity ratio instead of 50%
in this case, it would unnecessarily increase the revenue requirement by
approximately $11 million. (5 TR 1663). This amount reflects the additional $131
million of equity capital and the difference between the pretax return on common
equity of 12.8% (9.5% after tax) versus the pretax cost of long-term debt of
approximately 4.4%. (5 TR 1663).
Return on Equity and Overall Return on Capital
As shown in Exhibit AG-25 and based on the work of Mr. Coppola, the
Attorney General recommends an overall return on capital of 5.33%, which includes
a return on common equity of 9.50%. For Long Term Debt, Mr. Coppola utilized the
4.36% rate determined by Mr. Solomon. (5 TR 1663). For Short Term Debt and
Deferred Taxes, Mr. Coppola utilized the cost rates recommended by Company
witness Solomon and for JDITC, he utilized the long-term debt and common equity
rates applicable to this case. (5 TR 1664).
In his direct testimony, Mr. Coppola explained the development of the overall
cost of capital that is included in Exhibit AG-25.
To develop the overall cost of capital on line 11, column (f), I have first developed the percentage weighting of each capital component in column (d) by dividing the individual capital balances in column (b) by the total of all capital components in that column. Next, I have multiplied the weightings in column (d) by the cost rates in column (e) to arrive at the values in column (f). The total of the individual values in column (f) is the total cost of capital of 5.33%.
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Regarding the pretax weighted cost of capital on line 11, column (h), I have multiplied each cost component in column (f) by the conversion factors in column (g). These conversion factors are included to reflect the impact of income taxes paid by the Company for calculation of the pretax weighted cost of 6.60% in column (h). [5 TR 1664].
Accordingly, the AG recommends that the Commission set the overall cost of capital
at 5.33%.
Cost of Common Equity
In his direct testimony, Mr. Coppola discusses at length his development and
determination of the cost of common equity for the Company. (5 TR 1664-68). This
area is one that the Commission has addressed extensively in all recent rate cases.
Mr. Coppola first discussed the general principals that he considered in
determining the cost of common equity for the Company:
A utility company is entitled to a fair return that will allow it to attract capital and be sufficient to assure investors of its financial soundness. In its opinion in Bluefield Water Works and Improvement Company v Public Service Commission of West Virginia (the “Bluefield Case”) 262 U.S. 679 (1923), the United States Supreme Court indicated that:
“A public utility is entitled to such rates as will permit it to earn a return on the value of the property which it employs for the convenience of the public equal to that being made at the same time…on investments in other business undertakings which are attended by corresponding risks and uncertainties; but it has no constitutional right to profits such as are realized or anticipated in highly profitable enterprises or speculative ventures. The return should be reasonably sufficient to assure confidence in the financial soundness of the utility and should be adequate, under efficient and economical management, to maintain and support its credit and enable it to raise the money necessary for the proper discharge of its public duties…”
The principals of the Bluefield Case were re-affirmed by the U.S. Supreme Court in 1944 in the case FPC v Hope Natural Gas Company, 320 U.S. 591. [5 TR 1664-65].
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The Commission is very familiar with the principals of Bluefield and Hope and how
they fit into the determination of the cost of common equity.
Mr. Coppola then discussed his development of the cost of equity in Exhibit
AG-26:
Determining the cost of common equity for an enterprise or an industry group is inexact since investors can only estimate what the future cash flows from any enterprise may be over time. Because of this uncertainty, most financial experts will not rely solely on any one particular method. To determine the cost of common equity, I have utilized three approaches to determine this cost. These are the Discounted Cash Flow (DCF) Method, the Capital Asset Pricing Model (CAPM) and a Utility Risk Premium approach. These methodologies have previously been accepted by the Commission and have been generally accepted by regulatory commissions in other jurisdictions in the United States. Also, I have considered the current circumstances in the Capital Markets and any potential changes in the risk profile of DTE Electric and the improving Michigan economy. While Exhibit AG-26 shows a calculated cost of common equity of 9.01%, from the three approaches, I recommend an allowed rate of return on equity of 9.50% for the reasons explained later in this section of my testimony. In connection with these methods for determining the cost of common equity, I have considered the cost of common equity for a proxy group of peer companies. [5 TR 1665-66].
Mr. Coppola then discussed the development of his proxy group of peer companies:
To develop an appropriate peer group, I started with the 40 electric utility companies followed by the Value Line Investment Survey. From this group of companies, I eliminated thirteen companies due to significant differences in size to DTE Electric. I removed Duke, Exelon, Nextera and Southern Company due to their extremely large size. These companies have revenues of between $17.2 billion and $33.5 billion in comparison to DTEE’s revenues of just over $4 billion. I also removed nine companies with annual revenues of $1.7 billion or less, again as not comparable to DTEE. Next, I eliminated five companies whose dividends have been discontinued, are not growing, or are at risk of being cut. Finally, I eliminated (a) six companies recently involved in mergers or acquisitions (M&A); (b) two companies with large foreign investments; (c) two companies whose earnings declined significantly in 2017; and (d) DTE Energy for obvious reasons. [5 TR 1666-67].
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The result of Mr. Coppola’s work is a proxy group of eleven companies, as shown in
Exhibit AG-27, all of which have growing earnings and dividends and are of
comparable size.
Mr. Coppola’s group of 11 peer companies differs from the Company’s peer
group. The Company itself developed two peer groups of companies. (5 TR 1667).
The larger, or broader, peer group has 25 companies. (5 TR 1667). From this larger
sample, the Company selected a smaller peer group of six companies. On page 25 of
his testimony, Company witness Vilbert indicates that the smaller group includes
only companies with net plant in a range from $6 billion to $20 billion as suggested
by the MPSC Staff in case U-18014.
The Company’s broader peer group of 25 companies includes ten of the
companies in Mr. Coppola’s peer group, plus: (a) eight companies Mr. Coppola
eliminated due to size considerations, (b) PPL and Entergy, both of whom
experienced a significant drop in earnings in 2017, (c) Avangrid (with no dividend
growth) and Edison International (which according to Value Line has wildfire risk
and thus dividend risk), (d) DTE Energy, and (e) CenterPoint Energy and
Eversource Energy. (5 TR 1667). With regard to CenterPoint and Eversource,
these companies were excluded from my peer group due to M&A activity which
occurred after witness Vilbert completed his data collection. (5 TR 1667).
The Company’s broader peer group also includes seven companies that are
very small in size compared to DTEE. In fact, 25% of the peer group represents
small local companies not comparable in size with DTE Electric. Also, the smaller
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market capitalization of these companies makes their stock riskier for investors due
to lower trading activity and the size of trading transactions than occur with larger
companies. The higher business risk from being a smaller utility and the stock
investment risk translate into a higher cost of equity, which is not reflective of
companies in a comparable peer group.
While the Company’s broader peer group is too large and includes numerous
utilities that are not comparable to DTE Electric, Dr. Vilbert’s limited peer group of
six companies is very small compared to peer groups normally presented in electric
rate cases. His effort to construct a relevant peer group of companies could have
benefited greatly from including other companies identified by Mr. Coppola, such as
Consolidated Edison, American Electric Power, Ameren, Excel Energy, Public
Service Enterprise Group, and WEC Energy. The inclusion of those companies
would give Dr. Vilbert’s smaller peer group a much more representative sample size
and help to smooth out anomalies that can be caused by a single company when
there are only six total companies. As such, the Company’s small peer group of six
companies is a very limited sample leading to unreliable results.
For the above reasons, the AG does not believe that the Company’s peer
groups are appropriate and recommends that the Commission reject the Company’s
peer groups.
Methodology Used to Develop Cost of Common Equity
As mentioned in the introduction, Mr. Coppola used three approaches, along
with the principals of Hope and Bluefield, to determine an appropriate cost of equity
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in this case. Mr. Coppola use the Discounted Cash Flow (DCF) Approach, the
Capital Asset Pricing Model (CAPM) Approach, and the Utility Risk Premium
Approach. Not only have these methodologies been accepted by the Commission in
prior cases, these methodologies are generally accepted by regulatory commissions
in other jurisdictions around the country. In his testimony Mr. Coppola discussed
each of these approaches and explained how they differentiate from the approaches
used by Dr. Vilbert.
Discounted Cash Flow Approach
Mr. Coppola’s DCF approach is summarized in Exhibit AG-27 and on pages
84 and 85 of his direct testimony and results in an ROE of 9.15% for the proxy
group. DTE presents a “simple” DCF study result of 10.2% and a “multi-stage” DCF
result of 8.9%, both of which are shown in Table 6 on page 61 of witness Vilbert’s
testimony.
DTE’s methodology to arrive at its “Simple” DCF of 10.2% relies upon a novel
approach that is not used by almost any commission in the country. Company
witness Vilbert goes through a convoluted process to calculate the 10.2% “Simple”
DCF result for his larger-sample peer group. The process involves the use of the
after-tax cost of equity and debt weighted based on market capitalization. (5 TR
1670). The results are then mechanically adjusted by other factors to arrive at the
10.2% cost of common equity capital. (5 TR 1670). This is an extremely
unconventional cost of equity calculation not normally used by other cost of capital
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experts or generally accepted by regulatory commissions regulating gas and electric
utilities in the United States. (5 TR 1670).
Regarding witness Vilbert’s subsample group of six peer companies, he
develops an initial cost of common equity of 9.9%, which he then ratchets up under
the After Tax Weighted Average Cost of Capital (ATWACC) process to an ROE rate
of 10.7%. (5 TR 1670-71). Among other problems, the results of this small sample
size are skewed by certain companies, such as CenterPoint Energy with a calculated
ROE of 12.6% due to an estimated 8.8% growth rate, which is a highly unusual
growth rate.
The ATWACC approach produces skewed results due to the high market to
book ratios in the utility industry as a result of low interest rates and other factors
making utility stocks very attractive to investors. (5 TR 1671). The Commission
should recognize the inherent circularity of the ATWACC process. For example, if
the ATWACC approach was to become universally embraced by regulatory
commissions, the ROEs awarded in regulatory proceedings would increase. The
inflated ROEs would result in higher utility earnings, higher stock prices, and
higher market to book ratios for utility common stocks. The subsequent calculated
ROEs in new rate cases under the ATWACC method would then produce even
higher awarded ROEs because the ATWACC would use the higher stock market
equity capitalization.
It is likely because of this cost-inflating circularity and the complexity of the
methodology that the ATWACC approach has not been embraced in the utility
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industry. In fact, witness Vilbert can cite only a hand-full of instances where it has
been used. These instances are covered on pages 7 and 8 of his Appendix B
attached to his testimony and involve (1) property taxation disputes in Colorado; (2)
Florida’s regulation of small water companies; (3) a valuation dispute before the
FERC; and (4) revenue adequacy hearings for railroads, as well as a revenue
adequacy hearing involving Alabama Power related to its special rate RSE.
Nowhere in his testimony does he mention any state regulatory commission in the
United States endorsing ATWACC in a general rate case proceeding. Therefore, the
Commission should disregard the ATWACC approach to calculating the DCF cost of
common equity.
Finally, Mr. Coppola discussed the results of the DCF analysis that he
performed:
The DCF analysis relies upon financial market information for the dividend yield portion of the equation. However, it also relies upon judgments of growth prospects of security analysts which may or may not be consistent with the beliefs of investors. I will point out that the forecasted growth rates for the proxy group include some high growth rates which in some cases are as high as 7.6%. These high growth rates appear to be the result of a temporary rebound in earnings from a low point in recent years. While these earnings may materialize in the short term, such high rates are not sustainable long term growth rates for electric utilities given that customer and revenue growth continues to be barely in low single digits. As such, the results of the DCF analysis in some cases reflect a return on equity rate that is somewhat higher than what investors currently expect in the long term. Nevertheless, I place a fairly high degree of reliability in the DCF results when considered in conjunction with the results of other approaches to determining the cost of common equity. [5 TR 1672].
Capital Asset Pricing Model
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Exhibit AG-28 and Mr. Coppola’s direct testimony at pages 88-89 explain the
results of the CAPM approach. (5 TR 1673-74). Using this CAPM approach, DTE’s
ROE rate is 8.47% for the proxy group average. (5 TR 1674). Mr. Coppola
commented on DTE witness Vilbert’s calculations of CAPM and explained the
problems with Dr. Vilbert’s analysis.
In Table 5 on page 51 of his direct testimony, witness Vilbert presents six different CAPM estimates for his larger sample group and another six CAPM estimates for his small sample group. In addition, he presents 24 estimates under his ECAPM approach. The number of calculations made by witness Vilbert is excessive and unnecessary. They serve more to confuse the Commission than provide any useful information. The Commission should not rely upon any of these CAPM and ECAPM results, because all of the estimates have been determined utilizing the ATWACC process which, as I discussed under the DCF section of my testimony, leads to faulty and inflated results. For the sake of uncovering some of the other more egregious problems with witness Vilbert’s calculations of the two scenarios he present [sic] in Table 5, I will discuss each scenario and the assumptions made in the calculations. Scenario 1 starts with the development of CAPM results for each peer group company on the basis of using a market risk premium, or MRP, of 6.9% and a projected 30-year U. S. Treasury bond rate of 3.7% as the risk-free rate. Up to this point the result is close to a traditional approach. The problem is the ATWACC adjustment that witness Vilbert applies afterwards. Scenario 2 is the same as Scenario 1 except that witness Vilbert uses an 8.1% MRP, which is 1.2 percentage points higher than he used in Scenario 1 with the same 3.7% risk free rate. The use of an MRP rate of 8.1% versus 6.9%, which is the historical average rate from 1926 to 2016, is highly unconventional and solely based upon witness Vilbert’s opinion that MRP rates have escalated since the 2007-2008 financial crisis. To arrive at a cost of equity rate under the ECAPM, witness Vilbert recommends that a further upward adjustment to the CAPM results should be considered by the Commission. He proposes adding an additional 0.1% to 0.6% to the CAPM results under scenario 1 and 2, respectively. This adjustment is subjective, unconventional, and not supported. In his testimony, witness Vilbert did not discuss if and where the ECAPM was utilized to set rates in other regulatory jurisdictions. However, in Case No. U-18999 the Company was asked to provide a list of the cases where the
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regulatory commission expressed its support of ECAPM as a means to establish an ROE outcome. The only specific regulatory commission that witness Vilbert identified was the Alberta Utilities Commission of Canada. In its order of October 7, 2016, the commission noted on page 45, paragraph 199 of the order that the ECAPM “…appears to be a model that could contribute to the Commission’s determination of a fair allowed ROE…” However, later in the same paragraph, that commission noted the high degree of judgment required by the ECAPM methodology and the Alberta Commission added this statement: “Consequently, the Commission will not rely heavily on the ECAPM results in this proceeding…” [Emphasis added]. While witness Vilbert’s various methods used to calculate the cost of equity capital are inventive, they are highly unconventional, not generally accepted, and are based in part upon his opinion that risk levels have permanently risen since the 2007-2008 financial crisis. The Commission should reject these alternative approaches for the reasons previously discussed, which clearly reflect his attempt to inflate the Company’s true cost of common equity. [5 TR 1675-77]. Finally, Mr. Coppola assessed the CAPM approach, finding that it can be
useful in assessing the relative risk of different stocks or portfolios of stocks. (5 TR
1677). However, he concluded that the CAPM approach should be given much less
weight than the DCF approach in determining the cost of common equity, because
the key issue with CAPM is that is assumes that the entire risk of a stock can be
measured by the “Beta” component and as such the only risk an investor faces is
created by fluctuations in the overall market. (5 TR 1677). In actuality, investors
take into consideration company-specific factors in assessing the risk of each
particular security.
Utility Risk Premium Model
Exhibit AG-29 and Mr. Coppola’s direct testimony at pages 92-93 explain the
results of the Utility Risk Premium approach. (5 TR 1677-78). Using this Utility
Risk Premium approach results in an ROE rate of 9.25%. (5 TR 1678). In this
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context, Mr. Coppola analyzed the economic and interest rate environment in recent
years for DTE and explained that the Michigan economy has substantially
recovered from the most recent recession and interest rates are stable at lower
levels. (5 TR 1678). These factors have placed DTE in a better position with
respect to sales levels, interest rates, and uncollectible amounts. (5 TR 1678).
Despite witness Vilbert’s concerns about the City of Detroit and the higher risk of
serving this area, according to Company witness Leuker, sales in the City of Detroit
are now less than 13% of DTEE’s total sales. (5 TR 1678-79). In addition, DTE’s
access to capital is strong as witnessed by its issuance in April 2018 of $525 million
of new 30-year long-term debt at a rate of 4.05%. (5 TR 1679). The Company’s
senior secured debt ratings are A/Aa3 and its commercial paper program is rated P-
1 (highest) by Moody’s. (5 TR 1679). Also, the Company’s parent DTE Energy
accessed the capital markets in late 2017 issuing $400 million of new sixty-year
long-term debt at a 5.25% rate. (5 TR 1679).
In rebuttal, Dr. Vilbert argued that intervenor testimony failed to adequately
account for the risk in the electric industry, and he then gave examples where he
believes that to be true. First, Dr. Vilbert labeled the transition that some utilities
are making from fossil fuel generation to renewable energy as “significant changes”
that increase the going-forward risk for these utilities. (6 TR 2013). On cross, he
indicated that he generally understands that in Michigan, utilities are able to fully
recover the cost of renewable energy and that utilities have been given the
opportunity to build up to 50% of new renewable generating capacity. (6 TR 2058).
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He also indicated that he is not familiar with Act 295 and 341 in Michigan, which
allow the Commission to preapprove utility capacity projects. (6 TR 2058). Finally,
Dr. Vilbert agreed that, in general, rate-based growth increases a utility's earning
power on a going forward basis. (6 TR 2058-59). Based on the above, and based on
the fact that investments in new generation capacity from renewable and non-
renewable resources will increase and potentially accelerate rate base growth, thus
increasing utilities’ earning power on a going-forward basis, the AG contends that
Dr. Vilbert’s concerns about ‘risks’ stemming from a move to renewable energy
sources are not based in reality.
Also in his rebuttal testimony, Dr. Vilbert discussed the impacts of the TCJA
as negatively affecting the industry and thus being cause for increased risk. (6 TR
2014). However, on cross he conceded that to his knowledge, none of the credit
rating agencies have downgraded DTE Electric’s credit rating since enactment of
the TCJA. (6 TR 2059). Accordingly, and as discussed elsewhere in this brief, this
is not a valid reason to inflate the Company’s ROE and capital structure.
Company witness Vilbert introduced a “new risk premium model” in his
testimony, which the AG argues is instead a new, unproven theory and not a new
risk premium model. Dr. Vilbert’s thesis is that the cost of equity capital can be
determined using the historical difference between the average ROE rates granted
to utilities and the risk-free rates effective in the market at the time the ROE rates
were granted. (5 TR 1681). This difference, or what Dr. Vilbert refers to as a risk
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premium, is then added to the forecasted risk-free rate to supposedly arrive at the
current cost of capital. (5 TR 1681).
There are several flaws with this new theory and approach to determine a
risk premium that Mr. Coppola points out in his testimony.
First, the ROE rates granted by regulatory commissions do not always reflect the cost of equity calculated through proven conventional methods. Commissions use very subjective factors to subtract or add to the cost of equity rates proposed by cost of equity experts, usually adding an additional percentage cushion instead of subtracting from the recommended rates. This alone adds an upward bias to the risk premium calculated by witness Vilbert. Second, there is a significant time lag between the decline in the risk-free rate and the downward or upward adjustment to the ROE rate granted by regulatory commissions. This lack of synchronization makes any comparison between the two rates and calculation of a difference or risk premium totally unreliable. Third, no academic studies have been performed to provide any credence to such a method to calculate a risk premium. [5 TR 1681].
In summary, this “new model” is simply a creation of witness Vilbert because
it fits his desired outcome of a higher ROE of 10.8%. The Commission should
dismiss this latest attempt to influence the process of establishing a fair and
industry comparable ROE rate through gimmicky and unproven methods.
Recent ROE Rates from other Commissions
Mr. Coppola also examined ROEs granted by other regulatory commissions
around the country in 2017 and 2018. He explained:
Since 1990, return on equity rates, granted by regulatory commissions in the U.S., have been in a steady decline from over 12.7% in 1990 to approximately 9.5% in 2017 and 2018. Pages 2, 3 and 4 of Exhibit AG-30 shows the more recent ROE rates granted by state regulatory commissions for electric utilities during 2017 and the first six months of 2018 and published by Regulatory Research Associates, a respected and independent regulatory research
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firm. Nearly 80% of the electric decisions rendered (excluding limited issue riders) involved ROE rates averaging approximately 9.6% during the eighteen month time frame. Page 2 of Exhibit AG-30 shows that there were thirteen ROE decisions for electric companies in 2017 and the first six months of 2018 with ROE rates at 10% or higher with four of these decisions being handed down by the Michigan Commission. In contrast, there were 49 other electric ROE decisions with authorized rates below the 10% level. These 49 decisions are summarized on pages 3 and 4 of this exhibit and include information regarding debt financing subsequent to the rate orders. It is clear from this information that the debt capital markets have continued to be receptive to financing from the utilities with authorized ROEs below 10%, and in fact continue to provide debt capital at competitive interest rates to these utilities. Page 5 of Exhibit AG-30 shows the utility companies who issued 30-year debt in February 2018 and the spread over 30 year U. S. Treasuries in each case. It is obvious from this information that ROE rates below 10% have not had a negative impact on the cost of debt raised by those utilities or impeded their ability to raise capital. [5 TR 1679-80].
As this above analysis demonstrates, ROE’s across the nation are on a declining
trend and are predominantly below 10%. Thus, DTE’s request to increase its ROE
is contrary to determinations made by every other regulatory commission.
In rebuttal, Dr. Vilbert discussed these issues to rebut Mr. Coppola’s
argument that many utilities with ROEs below 10% have been able to adequately
raise capital. (6 TR 2019-20). Asked about these issues on cross, Dr. Vilbert
repeated objections that he made in his rebuttal testimony to Mr. Coppola’s use of
this information but did concede and acknowledge that the utilities listed in Exhibit
AG-30 by Mr. Coppola have been able to raise adequate capital and could likely
continue to do so if need be. (6 TR 2064-65). He also acknowledged that DTE
Electric is not a Company that has extraordinarily weak credit metrics and that he
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has no reason to suspect that those utilities included in Exhibit AG-30 do either. (6
TR 2065-66).
Finally, in his rebuttal, Dr. Vilbert stated that the cost of capital is now
higher compared to the economic conditions that existed in Case No. U-18255. (6
TR 2013). In case U-18255, Dr. Vilbert recommended the same ROE rate of 10.5%
that he recommended in this case. (6 TR 2066). On cross, Dr. Vilbert was asked
about Exhibit AG-48, which contains a table that comes from his direct testimony in
that case. (6 TR 2067). In that case, he calculated a simple DCF cost of equity for
the full sample at 10.9%. (6 TR 2067). In Table 6 in this case, Dr. Vilbert
calculated the same DCF cost of capital at 10.2%. (6 TR 2067). This is 70 basis
points lower than what Dr. Vilbert calculated in U-18255, which suggests that,
according to Dr. Vilbert’s own calculations for this method, the cost of equity has
decreased, and not increased, in this current rate case. Additionally, Dr. Vilbert
was shown Exhibit AG-49, which is Table 6 taken from his direct testimony in Case
No. U-18255. (6 TR 2067-68). He confirmed on cross that this table corresponds to
Table 5 in this case, which is included on page 51 of his direct testimony. (6 TR
2068). Comparing the cost of equity rates in Scenario 1 for the CAPM method in
the current rate case to the same information calculated in Case No. U-18255 shows
that generally, the ROE rates calculated under Scenario 1 are lower in the current
case, as compared to those calculated in Case No. U-18255. This further
undermines Dr. Vilbert’s conclusion that the cost of equity has increased since Case
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No. U-18255, and in fact supports that opposite, that the cost of equity has
decreased.
Accordingly, based on all the above, DTE’s recommendation that the ROE
should be increased to 10.5% is unsupportable and largely based on unconventional
methodologies applied to CAPM, DCF, and Utility Risk Premium cost of equity
calculations. As contained in the analysis by Mr. Coppola, the results of the DCF
analysis, CAPM analysis, and Risk Premium Approach, together with lower interest
rates, a better Michigan economy and a very favorable regulatory environment all
point to a calculated cost of equity closer to 9%.
Conclusion
Mr. Coppola summarized his conclusions regarding the appropriate ROE in
this case in Exhibit AG-26. The ranges of returns for the industry peer groups are
from 8.47% at the low end using the CAPM approach and 9.25% at the high end
using the Utility Risk Premium approach. (5 TR 1682). After weighting the various
approaches, Mr. Coppola calculated a weighted return on equity of 9.01% for the
average industry peer group. (5 TR 1682). Mr. Coppola, however, explained that he
is recommending a higher ROE rate of 9.50% based on a DTE Electric specific
analysis:
First, the extent to which investors anticipate higher interest rates is uncertain. As such, while the cost of common equity under the DCF approach is an accurate assessment of expectations for the forecasted test year, the higher interest rates assumed in this case may very well produce a different result should such higher interest rates become a reality. In this regard, a potential 10% correction in utility stock prices due to higher interest rates would produce a 0.40% increase in the cost of capital under the DCF approach.
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Second, I understand that the Commission may be reluctant to set an ROE for the Company at the true cost of equity of 9.01%. As shown in Exhibit AG-30, regulatory commissions around the country have granted an average ROE of 9.50% to electric utilities during 2017 and slightly above this number during the first six months of 2018. In fact, approximately 80% of the reported ROE decisions in electric utility rate cases reported by “Regulatory Focus” during this timeframe are well below 10%. Therefore, my recommended ROE rate of 9.50% in this case is reasonable and fair, if not generous, as a gradual transition to the true cost of equity. [5 TR 1682-83].
As noted above, Mr. Coppola developed, and the Attorney General recommends, an
ROE of 9.5% in this case as a reasonable and fair, if not generous, and gradual
transition to the true cost of equity.
The Commission should not be concerned that establishing an authorized
ROE of 9.50% in this case will lead to the impairment of the Company’s ability to
access capital markets. In his testimony Mr. Coppola explains:
In recent general rate case proceedings, the Commission seems to have been persuaded by the applicants’ arguments that they should receive an ROE of 10% or higher to ensure the financial soundness of the business and to maintain its strong ability to attract capital in addition to being compensated for risk. Exhibit AG-30 shows several utilities that have accessed the capital markets at competitive interest rates since receiving an ROE substantially below 10%. Similarly, there is no evidence equity investors have abandoned utilities that have been granted ROEs below 10%. On the contrary, stock investors continue to migrate to utility stocks recognizing that authorized ROEs are still above the true cost of equity. Exhibit AG-28 shows the market to book ratios for each of the peer group companies, and many of these companies have received rate orders during the past few years reflecting ROEs ranging from 8.4% to 9.9%. Yet this group of companies has an average Market to Book common equity value ratio of nearly 2.0 times.
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This information is provided to dispel the myth that the Company must receive an ROE above 10% or it will face dire consequences in the financial markets. The fact that the Company needs to raise capital because of a large capital investment program to upgrade its infrastructure and for other purposes is not unique to DTE Electric. Other electric and gas utilities face the same issues and are able to raise capital with ROEs in the single digits. [5 TR 1683-84].
The Commission should also not consider stock market volatility or the
VIX when establishing a fair ROE rate for the Company. Even though
witness Vilbert discusses volatility on pages 17 through 19 of his testimony,
he correctly notes the following starting on line 3 of page 19:
However, it is important to remember that the VIX measures expectations for market volatility in the near term—specifically over the coming 30 days. By contrast, the market risk premium that is relevant in this proceeding represents the compensation investors require to take on risk over a long investment horizon… [6 TR 1932].
The stock market has historically been very volatile. In some years
stock prices move up and down more dramatically than in other years.
Exhibit AG-33 is a Value Line Funds article written by Mitchell Appel,
President of Value Line Funds. Mr. Appel states that volatility is not risk.
He also points out that volatility in 2017 was low by historical standards and
it was near normal levels in 2018. Mr. Appel goes on to say later in this
article that “…volatility is only risk if you act during down times, that is, only
if you sell a stock.” (5 TR 1685).
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Those who invest money in equity portfolios over longer periods of time
and particularly in utility stocks have an aversion to market volatility and
the VIX. In fact, utility stocks are a safe haven for investors during times of
uncertainty and volatility because they are not as susceptible to volatility as
the general stock market. This is reflected in their Beta value of .67 on
average for Mr. Coppola’s peer group, which is significantly less than the
general stock market value of 1. Therefore, the Commission should not give
any weight to arguments that the Company’s ROE should reflect investors’
concerns with stock market volatility.
Finally, Mr. Coppola also calculated that if the Commission grants a 10.0%
ROE in this case versus his recommended 9.5% ROE, then the Commission is
adding an additional $45 million in costs to customers annually. (5 TR 1686).
Accordingly, the Attorney General recommends a 9.50% ROE in this case.
VIII. RATE DESIGN
The Attorney General recommends that the Commission reject DTE’s request
to increase the monthly service charge for residential and small commercial
customers. DTE is seeking to increase the monthly service charge for residential
customers from $7.50 to $9.00. (8 TR 3868). Mr. Coppola summarized his
disagreement with this proposal as follows:
The proposed change from $7.50 to $9.00 per month represents an increase of 20%. In Case No. U-18014, which was decided in January of 2017, the Commission approved an increase of 25% from $6.00 to $7.50 per month. To add another 20% increase on top of the last
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customer charge increase would be nearly a 50% increase in a timeframe of about a year. This would be a very large increase for smaller customers to absorb and defeats the objective of rate gradualism. [5 TR 1687].
Based on Mr. Coppola’s discussion above, the Attorney General recommends that
the Commission reject DTE’s request and maintain the current customer monthly
charges for residential customers.
Similarly, the Attorney General recommends that the Commission reject
DTE’s request to increase the customer charge for small commercial customers from
$11.25 to $15, or 33%, for the same reasons. In U-18014, the Commission approved
an increase in the monthly customer from $8.78 to $11.25 per month. (5 TR 1687).
This represents an increase of 28%. To add another 33% increase on top of the last
customer charge increase would bring the total increase to more than 60% in the
timeframe of about a year. This would be a very large increase for smaller
commercial customers and defeats the objective of rate gradualism. Accordingly,
the AG recommends that the Commission reject the proposed increase in the
general service rate D3 customer monthly charge in this case.
IX. CONCLUSION AND RELIEF SOUGHT
For the reasons stated above, in her expert witness’s direct testimony and
exhibits, and summarized in her exhibits, the Attorney General recommends that
the Commission adopt her adjustments and recommendations.
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Respectfully submitted, Dana Nessel Attorney General Joel B. King (P81270) Assistant Attorney General Special Litigation Division PO Box 30755 Lansing, MI 48909 517-373-1123
Dated: January 11, 2019
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PROOF OF SERVICE - U-20162 The undersigned certifies that a copy of the Attorney General’s Initial Brief, was served upon the parties listed below by e-mailing the same to them at their respective email addresses on the 11th of January 2019. Joel B. King MPSC: Amit Singh Daniel Sonneveldt Spencer Sattler Lori Mayabb [email protected] [email protected] [email protected] [email protected] ALJ: Hon. Sally Wallace [email protected] Attorney General Special Litigation Division: Joel B. King [email protected] [email protected] Sebastian Coppola [email protected] DTE Energy Company: Andrea Hayden David Maquera Lauren Donofrio [email protected] [email protected] [email protected] [email protected]
Environmental Law & Policy Center: Margrethe Kearney Jean-Luc Kreitner [email protected] [email protected] [email protected] Energy Michigan, Inc. Timothy Lundgren Laura Chappelle Toni Newell [email protected] [email protected] [email protected] ABATE: Robert Strong Bryan Brandenburg James Dauphinais [email protected] [email protected] [email protected] MCTA: Michael Ashton [email protected] Michigan Environmental Council: Christopher Bzdok Lydia Barbash-Riley [email protected] [email protected]
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David Bender Shannon Fisk Chinyere Osuala [email protected] [email protected] [email protected] The Kroger Company: Kurt Boehm Jody Cohn Kevin Higgins [email protected] [email protected] [email protected] SOULARDARITY: Lydia Barbash-Riley Kimberly Flynn Mark Templeton Robert Weinstock Rebecca Boyd [email protected] [email protected] [email protected] [email protected] [email protected] Utility Workers Union of America Local 223: John Canzano Benjamin King [email protected] [email protected] RCG: Brian Coyer Don Keskey [email protected] [email protected] ChargePoint, Inc.: Justin Ooms [email protected]
