july 28, 2015 - force.com
TRANSCRIPT
STATE OF MICHIGAN
DEPARTMENT OF ATTORNEY GENERAL
P.O. BOX 30755
LANSING, MICHIGAN 48909
BILL SCHUETTE ATTORNEY GENERAL
July 28, 2015
Ms. Mary Jo Kunkle
Michigan Public Service Commission
7109 West Saginaw Highway
Lansing, MI 48917
Dear Ms. Kunkle:
Re: MPSC Case No. U-17767
Enclosed find the Attorney General's Initial Brief and related Proof of Service.
Sincerely,
Michael E. Moody
Assistant Attorney General
c All Parties
1
U-17767 PROOF OF SERVICE
The undersigned certifies that the Attorney General’s Initial Brief was
served upon the parties listed below, by emailing the same to them at the
email addresses listed below on the 28th day of July 2015.
____________________________________
Michael E. Moody
Name/Party E-mail Address
Administrative Law Judge:
Sharon L. Feldman
DTE Electric Company:
Bruce R. Maters, Jon P.
Christinidis, Richard P.
Middleton, Michael J. Solo,
David S. Maquera, and DTE
Energy Filings
MPSC Staff: Bryan A.
Brandenburg Heather M. S.
Durian, Graham Filler, and
Spencer A. Sattler,
Association of Businesses
Advocating Tariff Equity:
Robert A. W. Strong, Leland R.
Rosier, Sean P. Gallagher, James
T. Selecky
Attorney General Bill
Schuette: Michael M. Moody,
Sebastian Coppola, and Wendy
Cadwell
DTE Residential Customer
Group: Don L. Keskey & Brian
W. Coyer
Detroit Public Schools:
Michael G. Oliva and Leah J.
Brooks
2
Energy Michigan and Michigan
Agri- Business Association: Laura
A. Chappelle, Timothy J. Lundgren,
and Sherry Lin
The Kroger Company: Kurt J.
Boehm, Jody Kyler Cohn, Anthony J.
Szilagyi, and Kevin Higgins
Local 223, Utility Workers Union of
America: John R. Canzano and
Jordan D. Rossen
Dan Mazurek [email protected]
Richard Meltzer [email protected]
Michigan Cable
Telecommunications Association:
David E. S. Marvin
Michigan Environmental Council
Natural Resource Defense Counsel
Sierra Club: Christopher M. Bzdok,
Emerson Hilton, Patrick Kenneally,
Shannon Fisk, Laurie Williams, James
Clift, Ruthann Liebziet, and Kimberly
Flynn
Municipal Street Lighting
Coalition (MSLC): John R. Liskey
and Constance De Young Groh
[email protected] [email protected]
David Sheldon
Paul F. Wilk: [email protected]
Wal-Mart Stores East, LP and
Sam's East, Inc.: Richard J. Aaron
and Derrick Price Williamson
STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
___________________________
In the matter of the application of
DTE ELECTRIC COMPANY MPSC Case No. U-17767
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
Bill Schuette
Attorney General
Michael E. Moody (P51985)
Assistant Attorney General
Environmental, Natural Resources,
and Agriculture Division
PO Box 30755
Lansing, MI 48909
517-373-7540
Dated: July 28, 2015
i
TABLE OF CONTENTS
Page
Index of Authorities .................................................................................................................. iii
INTRODUCTION ....................................................................................................................... 1
STATEMENT OF FACTS ......................................................................................................... 2
Argument ...................................................................................................................................... 6
I. ADJUSTED NET OPERATING INCOME ............................................................... 7
1. Distribution Operations ......................................................................................... 8
2. Fossil Power Generation....................................................................................... 13
3. Nuclear Power Generation ................................................................................... 15
4. Uncollectibles Expense .......................................................................................... 18
5. Corporate Services ................................................................................................. 19
6. Combined Operating License (COLA) ............................................................... 20
7. Employee Incentive ................................................................................................ 21
8. Employee Benefit Costs ......................................................................................... 27
9. Summary of O&M Expense Reductions ............................................................ 34
II. Capital Expenditures and Rate Base ....................................................................... 35
(1) Distribution Operation .........................................................................36
(2) Fossil Generation ...................................................................................39
(3) Nuclear Generation ...............................................................................41
(4) Acquisition of 300 MW Power Plan ...................................................42
(5) Customer 360 Project ............................................................................43
(6) Corporate Staff Group ..........................................................................44
(7) Summary of the AG Disallowed Capital Expenditures ............46
ii
III. AMI .................................................................................................................................. 46
IV. Cost of Capital ............................................................................................................... 49
V. Relief Requested………………………………………………………………………..62
iii
INDEX OF AUTHORITIES
Page
Cases
BCBSM v Governor,
422 Mich 1; 367 NW2d 1 (1985)................................................................................................ 7
Caruso v Weber,
257 Mich 333; 241 NW 198 (1931)............................................................................................ 7
Cuttle v Concordia Mut Fire Ins Co,
295 Mich 514; 295 NW 246 (1940)............................................................................................ 7
Dillon v Lapeer State Home & Training School,
364 Mich 1; 110 NW2d 588 (1961)............................................................................................ 7
In re Detroit Edison Co,
MPSC Case No. U-8030-R ......................................................................................................... 7
In re Michigan Gas Utilities Co,
MPSC Case No. U-7484 ............................................................................................................. 7
S C Gary, Inc v Ford Motor Co,
92 Mich App 789; 286 NW 2d 34 (1979) ................................................................................... 8
White v Campbell,
25 Mich 463 (1872) .............................................................................................................. 7, 13
Woodin v Durfee,
46 Mich 424; 9 NW 457 (1881).................................................................................................. 7
Yonkus v McKay,
186 Mich 203; 152 NW 1031 (1915).......................................................................................... 7
1
INTRODUCTION
On December 19, 2014, DTE Electric Company (DTE) filed an application
requesting authority to increase its rates for the distribution of natural gas in the
annual amount of $370 million and for other relief. A prehearing conference was
held on October 11, 2011 before Administrative Law Judge (ALJ) Sharon Feldman.
At the prehearing conference, the ALJ granted the interventions of the Michigan
Department of the Attorney General (Attorney General), the Association of
Businesses Advocating Tariff Equity (ABATE), Michigan Environmental Council
(MEC), Kroger Company, Detroit Public Schools, National Resources Defense
Council (NRDC), Energy Michigan, Michigan Agri-Business Association, Sierra
Club, Local 223 Utility Workers Union of America (UWUA) AFL-CIO, Municipal
Street Lighting Coalition, Wal-Mart Stores East, LP, Michigan Cable
Telecommunications Association, Residential Customers of DTE Electric Company,
Richard Meltzer, Dan Mazurek, Paul F. Wilk, David Sheldon. The MPSC Staff also
participated. Environmental Law & Policy filed a late intervention and was also
granted intervenor status.
On February 9, 2012, DTE filed the testimony and exhibits of Don Stanczk
Vice-President of Regulatory Affairs, in support of its intention to self-implement a
rate increase as permitted by MCL 460.6a(1). The filing included tariffs reflecting a
self-implemented rate increase of $230 million. DTE self-implemented its $230
million rate increase on July 1, 2015.
.
2
STATEMENT OF FACTS
All the parties, except Environmental Law & Policy Center, Local 223 Utility
Workers Union of America (UWUA) AFL-CIO, Michigan Agri-Business Association,
Detroit Public Schools, Mr. Wilk, Mr. Mazurek, and Mr. Meltzer filed testimony in
this case.
DTE Testimony
DTE filed both direct testimony and rebuttal testimony along with separate
testimony to support the self-implementation of the $370 million. DTE presented
the testimony of 23 witnesses; Don M. Stanczak, Franklin Warren, Barry J.
Marietta, Russel J. Pogats, Ryan R. Schoen, Marklus B. Lueker, Kenneth D.
Johnston, Clifford J. Grimm, Timothy A. Bloch, Irene M. Dimitry, Robert E.
Sitkaukas, Kenneth R. Bridge, Martin Heiser, Kelly A. Holmes, Theresa M.
Uzenski, Michael A. Williams, Wayne A. Colonnello, Jeffrey C. Wuepper, Michael
Vilbert, Margaret Suchta, Renee M. Tomina, Edward J. Solomon, and Mary Lewis .
Some of Consumers witnesses only provided direct testimony.
Attorney General Testimony
The Attorney General sponsored direct testimony and exhibits of Sebastian
Coppola. Mr. Coppola submitted direct testimony and exhibits on May 22, 2015 and
Rebuttal Testimony on June 15, 2015 which was bound into the record without
cross examination by any party. Mr. Coppola’s direct testimony consists of 74 pages
along with an Appendix A which contains his qualifications (Tr 2283-2356) along
with 20 exhibits. Mr. Coppola’s rebuttal testimony consists of 9 pages (Tr 2366-
3
2374.) The 20 Attorney General exhibits in Mr, Coppola’s Direct Testimony are as
follows:
1. Exhibit AG-1 Distribution Operations Expense 2013-2014
2. Exhibit AG-2 Vegetation Management Expense 2008-2014
3. Exhibit AG-3 Power Interruption Causes 2005-2014
4. Exhibit AG-4 Fossil Generation O&M Expense 2013-2014
5. Exhibit AG-5 Nuclear Generation Expense 2013-2014
6. Exhibit AG-6 Uncollectible Accounts Expense 2015-2016
7. Exhibit AG-7 Health Care Actual Cost Trend 2010-2014
8. Exhibit AG-8 OPEB Negative Expense 2013-2016
9. Exhibit AG-9 Fossil Generation Capital Expenditures – Actual 2014
10. Exhibit AG-10 Customer 360 Project Discovery Responses on Alternatives
11. Exhibit AG-11 Corporate Capital Expenditures – Actual 2010-2014
12. Exhibit AG-12 BG&E AMI - Maryland PSC Order Excerpts
13. Exhibit AG-13 Overall Cost of Capital
14. Exhibit AG-14 Cost of Common Equity
15. Exhibit AG-15 Cost of Common Equity-DCF
16. Exhibit AG-16 Cost of Common Equity-CAPM
17. Exhibit AG-17 Cost of Common Equity-Risk Premium
18. Exhibit AG-18 ROE Decisions by Regulatory Commissions
19. Exhibit AG-19 AG Revenue Deficiency Calculation
20. Exhibit AG-20 Incentive Pay for the Projected Test Year
Sebastian Coppola
Mr. Coppola testified on the following issues in this case:
4
1. The level of Operations and Maintenance expenses
2. Uncollectible Expense
3. Incentive Compensation
4. Employee Benefits
5. The level of proposed Rate Base and Capital Expenditures
6. The Company’s Cost of Capital
7. The AMI/Smart Meter Program
8. The Company’s Revenue Deficiency
9. The increase in Residential Monthly Service Charge
He also explained that the absence of a discussion of other matters in his
testimony should not be taken as an indication that he agree 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. (Tr
2287.)
He summarized his recommendations regarding these issues as follows:
The Company filed for a base rate increase of $370.4 million. It
is noteworthy to point out that during the four-year period from 2010
to 2013, the Company earned a return on common equity on a
regulatory basis ranging from 10.6% to 11.4% which is higher than the
allowed ROE of 10.5% and 11.0% during the same period.1
Based on the foregoing analysis, I have calculated that the
Company has a revenue requirement deficiency of $58 million for the
forecasted test year ending June 2016. My conclusions and related
adjustments are summarized below:
1 Exhibit A-17, Schedule I4.
5
1. I am proposing a lower level of Operations and Maintenance
expenses for the test year. This reduces the revenue deficiency
by $203.4 million.
2. I am proposing a reduction in capital expenditures of $273.2
million for the test year and a reduction in rate base of $136.6
million. This reduces the revenue deficiency by $12.4 million.
3. I am recommending an allowed rate of return on equity of 9.75%
and a capital structure with 52% debt and 48% equity capital.
This has the effect of reducing revenue deficiency by $96.6
million.
4. I recommend that the Commission should defer recovery of the
depreciation expense for the AMI/Smart Meter program to
mitigate the risk to customers of insufficient cost savings from
the program. The impact on revenue deficiency will depend on
the Commission’s decision.
5. I recommend that the Residential customer monthly service
charge should be increased to no higher than $7.50, instead of
the Company’s proposed $10.00, from the current $6.00.
[Tr 2289-2290.]
The O&M dollar adjustments broken down by topic are as follows:
Summary of O&M Expense Reductions:Amount ($Million)
Distribution Operations 46.5$
Fossil Power Generation 16.5
Nuclear Power Generation 4.7
Uncollectible Accounts Expense 11.0
Corporate Services 5.0
COLA 5.1
Employee Incentive Compensation Plans 40.7
Employee Benefits 73.9
Total Reduction 203.4$
6
As noted above, these reductions equate to a $203.4 reduction in revenue deficiency.
The Capital Expenditure and Rate Base dollar adjustments broken down by topic
are as follows:
Summary of AG Disallowed Capital Expenditures
Distribution Operations
New Business $8.8
Reliability 26.0Vegetation Management 30.0
Fossil Generation 32.06.4
Acquisition of 300 MW Plant 110.0
Corporate Staff Group 60.0
$273.2
Nuclear Generation
Total
Amount (millions)
As noted above, these reductions equate to a $12.4 million reduction in revenue
deficiency. The above total adjustments for all five areas reduce DTE’s proposed
revenue deficiency by $312.4 million to $58 million. (Tr 2290.) These adjustments
do not take into account adjustments by others parties in the case that the Attorney
General adopts in this Initial or Reply Brief.
ARGUMENT
Before examining the Attorney General’s recommendations and arguments
the Commission should consider that Consumers bears the burden of proof to
demonstrate that its rate increase request is reasonable. The obligation of proving
7
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 Moreover, the MPSC may disbelieve even
uncontradicted evidence.6 When the burden of proving a fact falls on one party,
then the other party does not have the burden of proving the opposite fact.7
I. ADJUSTED NET OPERATING INCOME
As explained in the October 20, 2011 Commission Order in U-16472, adjusted
new operating income is the difference between a company’s operating/projected
revenues and operating/projected expenses. The Attorney General raised a number
of Operations and Maintenance (O&M) Expenses recommendations in the direct
testimony of Sebastian Coppola. DTE Exhibit A-10, Schedule C5 shows that O&M
expenses are expected to increase approximately $35 million from $1250 million
adjusted expense level for the year ended December 31, 2013 to $1,285 million for
the test year ending June 2016. (Tr 2290.) DTE has an internal initiative called
Competitive and Affordable Rate Strategy (CARS) to help lower its cost structure
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).
8
and dampen rate increases to customers. Accordingly, Mr. Coppola recommends
that the Commission set recoverable cost levels that challenge DTE to significantly
modify its existing cost structure and help it achieve its CARS objective. (Tr 2291.)
Mr. Coppola analyzed O&M costs by major department and identified more
reasonable expense levels that the Commission should consider in this case. (Tr
2292.)
1. Distribution Operations
2013 vs 2014 Historical Test Year
Attorney General expert witness Sebastian Coppola explained that although
DTE’s 2016 projected operating expense level for distribution operations is $8.2
million less than the historical 2013 period, this is the result of some unusually high
expenses that were recorded in 2013 and a more accurate and recent comparison is
the 2014 period (Tr 2292-2293.) For example, DTE’s operations supervision and
engineering expenses has been in the $32.5 to $37.1 million range between 2010-
2012, however, in 2013 this expense category jumped to $50.7 million in 2013 and
then returned to a more consistent level of $38.5 million. (Tr 2293.) Even though
DTE explained that the reason for the temporary increase in 2013 was the result of
storm activities, it still used the higher 2013 level to project the O&M expense for
the projected test year. (Tr 2293.) In addition to the unusual jump in certain
expenses for 2013, total O&M expense for the distribution operations department
for 2014 were $16.4 million lower than the expense level in 2013. (Tr 2293.) Given
7 S C Gary, Inc v Ford Motor Co, 92 Mich App 789, 803-804; 286 NW 2d 34 (1979).
9
the unusually high amount of supervision and engineering expense in 2013 and the
fact that actual 2014 expenses reflected a more recent and normal level of expense,
Mr. Coppola recommended that the test year projected expenses in this department
be reduced by $16.4 million along with the $5.9 million of cost inflation from 2013 to
2014 since 2014 numbers are being used. (Tr 2293.) This is total reduction in this
department of $22.3 million.
In rebuttal to Mr. Coppola’s $22.3 million in recommended reductions, DTE
witness Russel Pogats testified that the increase in 2013 operation supervision and
engineering was the result of storms costs that were mistakenly included multiple
occasions in the wrong FERC accounts but that DTE did not determine these
mistakes until 2015 (Tr 416-420.) Mr. Pogats admitted that he didn’t know how the
accounts were improperly recorded and admitted that this mistake was not
identified in his direct testimony but only revealed in his rebuttal testimony. (Tr
418-420.) These newly found mistakes do not seem credible since DTE did not
provide revised testimony demonstrating these changes but only first identified
them in response to reductions recommended by Mr. Coppola’s testimony in this
case.
Mr. Pogats also claims that Mr. Coppola is “incorrectly mixing 2014 as the
historical test year with adjustments for 2013 as the historical test year.” (Tr 408.)
Yet, Mr. Pogats adjustments to the 2014 as a historical test year are nothing more
than stated adjustments with no justification other than a paragraph in rebuttal
making the adjustments. (Tr 408.) Mr. Pogats adjustments for vegetation
10
management in 2014 is based on a new vegetation management program that
wasn’t in existence in 2013, and thus cannot support the adjustments since they
involve different metrics discussed elsewhere in DTE’s testimony.
Even with the newly found mistakes to the FERC accounts and unsupported
adjustments to the 2014 year, Mr. Pogats admits that the 2016 projected year is $3
million higher than its own analysis of a 2014 historical test year. Because portions
of DTE’s rebuttal are not credible as discussed above, the ALJ should adopt the
Attorney General’s $22.3 million reduction to this department. At the very least,
the ALJ should adopt the $3 million reduction that DTE itself supports in Mr.
Pogats rebuttal.
DTE’s Doubling of Tree Clearing and Vegetation Management
In addition to the $22.3 million reduction noted above, Mr. Coppola
recommended a $46.5 million reduction in this department for tree clearing and
vegetation management. (Tr 2293, 2296.) DTE proposed to nearly double
expenditures for tree clearing and vegetation management from the $50.7 million
previously authorized in rates in case No. U-16472 to $94 million per year with no
study or analysis to justify this doubling of expenditures other than advocating for a
more aggressive program to reduce power outages. (Tr 2293-2294.) Mr. Coppola
agreed that it is a worthy goal to reduce power outages but noted that the DTE’s
erratic pattern of expenditures over the past few years belies the commitment to
vigorously address the problem in a consistent manner. (Tr 2294.) Since 2008, DTE
has spent between $42.3 and 56.9 million annually on vegetation management with
11
the lowest amount in 2014. (Tr 2294.) In discovery, DTE explained that it has been
pursuing a tree clearing cycle of 3-5 years under the current program and does not
expect that the Expanded Vegetation Management Program (EVMP) will change
that cycle. (Tr 2295.) Mr. Coppola noted that this explanation did not make sense
since either the current program is not achieving the 3-5 year clearing cycle or the
doubling of the expenditures would have little positive impact. (Tr 2295.) In
addition, the $94 million a year seems completely inconsistent with Consumers
Energy, a similarly situated electric utility, proposal to spend only $57.7 million
annually on its tree trimming/vegetation program targeting a 7-year cycle. (Tr
2295.) In fact, Consumers Energy even supported its proposal with a study
performed by an outside expert. (Tr 2295.)
In order to understand the benefit of doubling the cost of the proposed tree
trimming/vegetation program at DTE, Mr. Coppola asked the company in discovery
to identify improvements in power outage metrics, such as SAIDI, CAIDI and SAIFI
that would result from the increased spending. (Tr 2295.) DTE failed to identify
any potential improvements and simply repeated its general objective to reduce
tree-caused outages. (Tr 2295.)
In rebuttal, DTE witness Russel Pogats provided only two paragraphs in
response stating, without support, that Mr. Coppola hasn’t done any analysis and
that reducing the vegetation management to the level it has been since 2008 would
reduce the number of miles cleared from 6,200 miles per year to 3,200 miles per
year or a five year cycle to a 9.5 year cycle. (Tr 409-410.) To begin with, Mr. Pogats
12
confuses the recommendation that Mr. Coppola presented in his testimony. In
rebuttal, Mr. Pogats claimed that Mr. Coppola was reducing the Company’s O&M
vegetation management program by 49% and thus cutting in half the miles cleared
(Tr 409.) This is just a red herring by Mr. Pogats. From 2008 to 2014 DTE was
spending between $42.3 million to $56.9 million annually and expensing the entire
costs through O&M. (Tr 2294.) In the current rate filing, DTE is proposing to
spend $94 million but expense half of the cost through O&M and capitalize the
other half. (Tr 2293-2294.) Mr. Coppola is proposing to keep the vegetation
management funding at the $50 million (the same amount as ordered by the
Commission in Case No. U-16472) but allow DTE to split it between O&M and
Capitalize as it is proposing or simply through O&M. It is disingenuous for DTE to
claim that spending $50 million on vegetation management will cut in half the
amount of miles cleared when its own exhibit A-34, Schedule X-5 demonstrates that
spending around $50 million on average from 2008-2014 clears 6,200 miles. On
cross examination, Mr. Pogats admitted that 6,200 miles, a five year cycle, is best in
class. (Tr 447.) In this rate case, however, Mr. Pogats is supporting a doubling of
the amount based on a new EVMP program but with no study or cost/benefit
analysis to demonstrate that spending double brings any additional benefit.
DTE has the burden to show that the doubling of the vegetation management
program is reasonable and prudent. 8 DTE has not provided any study
demonstrating the reasonableness of the program other than saying that it is
starting a new program called EVMP. DTE provides some details as to how the
13
program will work and how it is different than the current program, but it failed to
provide any study to show that the new program with double the money will
produce a better SAIDI, CAIDI, or SAIFI than the current program. At the very
least, DTE should have at least explained why it must spend twice as much as
Consumers Energy to achieve its vegetation management goals. Simply requesting
double the amount of money spent for a program and then providing forecasts as to
how it will work is not sufficient evidence to satisfy its burden of proving the
reasonableness of the request.
2. Fossil Power Generation
The Company is proposing O&M expenses of $348.9 million for the forecast
test year in contrast to $322.3 million spent in 2013, an increase of $26.6 million or
8.3%. In reviewing the actual O&M expense for the Steam Power Generation
department for 2013 and 2014, Mr. Coppola found that the Maintenance expenses
declined by $15 million from $165.9 million in 2013 to 150.9 million in 2014. (Tr
2297.) The decline occurred in all the cost centers under Maintenance and the 2014
actual results are a more recent and more appropriate based on which to forecast
the projected test year expense level. (Tr 2297.) Accordingly, Mr. Coppola
recommended a reduction of $15.4 million in O&M expense based on using the more
current 2014 numbers from the Company. (Tr 2297.) This number is calculated by
taking the difference of the total Steam Power Generation O&M expenses between
2013 and 2014 and removing the $5.9 million of cost inflation the Company included
8 White v Campbell, 25 Mich 463, 475 (1872).
14
for 2014 (which no longer is necessary using the 2014 numbers instead of 2013). (Tr
2297.)
Mr. Coppola also recommended that the $1.1 million of expense related to the
acquisition of a new natural gas-fueled 300 MW plant should be removed since the
acquisition of the plant is still pending and has not been fully vetted as discussed in
more detail later in his testimony regarding capital expenditures. (Tr 2298.)
Accordingly, in total, Mr. Coppola recommended that the O$M expense for Fossil
Generation should be reduced by $16.5 million. (Tr 2298.)
In rebuttal, DTE witness Franklin Warren criticized Mr. Coppola’s reliance
on 2014 for maintenance expenditures since they can vary over time. (Tr 262.) This
criticism is unwarranted since Mr. Warren used only one year, 2013, to create the
forecast for the projected year numbers. (Tr 2297.) Mr. Warren did not deny that
the 2014 numbers are more current and there was no claim that the numbers are
inaccurate. Mr. Warren’s second criticism was that Mr. Coppola ignored the fact
that operations actual expenses increased by $5.5 million between 2013 and 2014.
(Tr 263.) Again, this criticism is unwarranted because Mr. Coppola took into
account and discussed these increases in his direct testimony when he stated
“[a]lthough increases in Operation expenses partially offset the decline in
Maintenance expenses, the 2014 actual results are a more recent and a more
appropriate base on which to forecast the projected test year expense level.” (Tr
2297.) Mr. Warren then criticized Mr. Coppola’s data in Exhibit AG-4 stating that
he used a new methodology and that the increased operations expense in 2014
15
compared to 2013 is not based on the alleged impact of inflation but rather actual
changes in expenses. (Tr 263.)
Mr. Warren’s criticism of Exhibit AG-4 makes little sense since the exhibit is
simply DTE’s data response to the Attorney General’s discovery request and the
comparison of 2013 to 2014 expenses are taken from DTE’s own numbers. In fact,
$9 million of the $15.4 million recommended reduction is clearly found on line 21 of
Exhibit AG-5 with a simple subtraction of 2013 and 2014 total maintenance
expenses that DTE provided to the Attorney General. The additional $5.9 million
reduction for the cost of inflation is simply using DTE’s inflationary factor that it
uses when projecting from 2013 historical to the 2016 projected year as shown in
DTE’s Exhibit A-10, Schedule C-5 line 1. Accordingly, Mr. Warren’s criticism of
new methodologies and the failure to take into account increases in expenses for
2014 is completely meritless since Mr. Coppola’s method of calculating the $15.4
reduction is taken from DTE’s own numbers and own inflationary projections.
Accordingly, the Commission should adopt the $15.4 O&M reduction as well as the
additional $1 million O&M reduction discussed in more detail in the section dealing
with the 300 MW power plant in capital expenditures.
3. Nuclear Power Generation
DTE proposes a projected test year forecast of $136.8 million in O&M
expenses for its Nuclear Power Generation operations as shown on Exhibit A-10,
Schedule C-5, line 3. (Tr 2298.) This exhibit shows a requested level of expenses of
$11.3 million, or 9%, above the 2013 adjusted actual expenses of $125.5 million. (Tr
16
2298.) Of this $11.3 million, approximately $5.3 million of the increase relates to
inflation over the time period from 2013 to June 2016 and the remaining $6 million
primarily consists of expense normalization adjustments proposed by DTE. (Tr
2298.) DTE explained that one of the normalization adjustments is intended to
synchronize the expense for the next refueling outage to an 18-month cycle. (Tr
2298.) In regards to refueling outage 16, which was completed between February
and April of 2014, DTE extended the cycle from the typical 18 months to 22 months.
Accordingly, DTE explained that there was insufficient expense in 2013 on which to
base the O&M expense forecast for the projected test year and thus the Company
increased operations expense by $1.2 million and increased maintenance expense by
$3.5 million to account for this insufficient expense. (Tr 2298-2299.)
Mr. Coppola recommended the removal of DTE’s $4.7 million ($1.2 plus $3.5)
adder to the 2013 test year because the adjustments were not warranted. (Tr 2299.)
In examining the actual expense levels for 2013 and 2014 in FERC accounts 520
and 530 that the Company proposes to increase by $4.7 million, Mr. Coppola found
that the combined expense in those accounts in 2014 was $26.8 million versus $35.9
million in 2013. (Tr 2299.) Logically, if the refueling outage was delayed several
months from 2014 into 2014, as stated by the Company, then there should be an
increase in expenses in 2014 over 2013 to justify the $4.7 million addition to 2013.
(Tr 2299.) Instead, the 2013 expenses are higher than 2014 for the two FERC
accounts. Even though an argument could be made that using the lower 2014
numbers makes more sense for the projected test year, Mr. Coppola recommended
17
keeping the Company’s 2013 test year number but not artificially increasing the
numbers by $4.7 million since the basis for the increase is not there. Accordingly,
Mr. Coppola recommended that O&M expenses for Nuclear Power Generation
should be reduced by $4.7 million. (Tr 2299.)
In rebuttal, DTE witness Wayne Colonnello claimed that Mr. Coppola did not
look at all the FERC accounts dealing with refueling when concluding that costs in
2013 were higher than 2014. (Tr 1182.) Adding additional costs that were not
reflected in FERC accounts 520 and 530, Mr. Colonnello explained that the actual
2013 was less than 2014 contrary to Mr. Coppola’s determination and thus the
additional $4.7 million increase was necessary.
Mr. Colonnello’s rebuttal explanation that additional FERC accounts should
have been added when dealing with refueling costs lacks credibility. On cross
examination, Mr. Colonnello admitted that none of this new explanation was
included in his direct testimony, exhibits, or workpapers. (Tr 1193.) By adding
these additional costs that were never explained in Mr. Colonnello’s direct
testimony, exhibits, or workpapers or even provided in revised testimony, the costs
between 2013 and 2014 make more sense and support the additional $4.7 million.
The Commission should reject Mr. Colonnello’s newly added accounting discussion
in his rebuttal because he failed to provide this information to the parties in his
direct testimony, thus preventing the parties from critically examining these new
numbers and wasting the resources of parties who relied upon the information
provided. Accordingly, the Commission should adopt Mr. Coppola’s reduction of
18
$4.7 million to this Nuclear Power Generation account because the use of the
adjusted 2013 numbers minus the $4.7 adder is sufficient for the 2016 projected test
year forecast.
4. Uncollectibles Expense
DTE is proposing to use a forecasted amount of $52.8 million for Uncollectible
Accounts Expense for the projected year which matches the amount recorded by the
Company in the 2013 historical test year. (Tr 2300.) Mr. Coppola examined DTE’s
unpaid accounts net write-offs numbers and found that there has been a decline in
the past three years from $87.7 to $52.6 million in 2014. (Tr 2300.) Natural gas
prices are one of the biggest drivers of uncollectible expense and the trend to
reduced prices appears to be continuing in 2015 and 2016 adding to the decline of
net write-offs. (Tr 2301.) In addition to the projected decline of natural gas prices,
Exhibit AG-6 is a discovery response by DTE showing that it has forecasted
uncollectible expense amounts of $42.7 million for 2015 and $40.9 million for 2016
which is an average of $41.8 million. (Tr 2301.) Based on the projected decline in
natural gas prices and DTE’s own forecast for 2015 and 2016, Mr. Coppola
recommended that the $41.8 million uncollectible expense level “is more
representative of the amount that will likely occur in the projected test year than
the $52.8 million that the Company has projected in this rate filing.” (Tr 2301.) It
does not appear that DTE provided rebuttal to this recommendation. Accordingly,
the Attorney General recommends that the uncollectible expense proposed by the
19
Company be reduced by $11 million to better match its own forecast for 2015 and
2016. (Tr 2301.).
5. Corporate Services
DTE is proposing $165.4 million in Corporate Support O&M expense for the
projected test year. (Tr 2302.) This is a decline from the historical test year based
on accounting changes, but offsetting most of the accounting reductions are $6.4
million of inflation cost adjustments, $2.3 million for expense normalization for
injuries and damages, and a $5 million projected increase in Information
Technology costs reflected in Exhibit A-10, Schedule C5.8 (line 13, footnote 4.)
According to DTE witness Teresa Uzenski, DTE has included this additional $5
million in the test year projection to cover “. . .the structural change in the way
software technology is packages, purchased and deployed.” (Tr 2303.). In response
to discovery asking for more information as to when expenditures would begin and
implementation plan, DTE explained that it did not yet have a defined plan and it
was still evaluating a project to replace the e-mail and calendar system that could
be implemented in the second half of 2015. (Tr 2303.) As explained by Mr. Coppola,
“it is clear that the $5 million of expense is simply a vague idea with no firm plan or
sold basis to justify an expense of this magnitude.” Accordingly, Mr. Coppola
recommended that the $5 million be removed from the Corporate Support O&M
expense for the projected test year. (Tr 2303.) It appears that DTE did not provide
rebuttal to this recommendation, thus the Attorney General recommends that this
$5 million reduction be adopted.
20
6. Combined Operating License (COLA)
From 2008 to June of 2015, DTE has accumulated approximately $101.9
million in deferred costs to obtain a combined license from the Nuclear Regulatory
Commission to continue to operate its existing Fermi 2 nuclear plant and also to
operate Fermi 3 nuclear plant, if built, for 40 years from completion of construction.
(Tr 2304.) DTE has stated, in response to discovery, that all these deferred costs
related to Fermi 3. (Tr 2304-2305.) DTE received the combined license on May 1,
2015. (Tr 2304.) Based on the receipt of the license, DTE has proposed to amortize
the deferred balance to $101.9 million over 20 years with first annual amortization
of $5.1 beginning with the projected test year. (Tr 2304.)
Mr. Coppola testified that it is unclear why DTE projected to spend $15
million in additional costs between the end of 2013 and 2015 on a license that was
issued in the first quarter of 2015, why the company has proposed an amortization
period of only 20 year for a license that has a minimum operating life of 40 years,
and whether Fermi 3 will ever be built or whether the rights to build it will be sold.
(Tr 2304.) Based on these concerns, Mr. Coppola stated that it is premature to
begin to amortize any of the deferred cost over any arbitrary period of time before
Fermi 3 is built and operating. (Tr 2304.) Because all these costs pertain to Fermi
3, Mr. Coppola explained:
those costs should not be amortized until the plant begins operation and generates
revenue. Under the accounting matching principle, such costs should be
amortized over the plant’s useful life which is the 40-year operating period
following completion of construction.
It is not fair or reasonable to have current customers pay for costs that are not
related to productive generating assets or assets that are not creating value
21
currently. In summary, the amortization of COLA deferred costs is premature.
As such, I recommend that the $5.1 million amortized expense in the projected
test year should be removed. [Tr 2305.]
In DTE witness Theresa Uzenski’s one paragraph rebuttal, Ms. Uzenski
agreed that assets should be amortized over the period they provide benefit which is
generally when the related revenue is earned. (Tr 1068.) Even though Ms. Uzenski
agreed that the amortization should be over the period the asset provides benefit
(which would be 40 years and not until the Fermi 3 is built), Ms. Uzenski stated
that the Commission could still grant recovery of 20 years as a regulatory asset. (Tr
1068.) Other than stating that the Commission could give the company a
regulatory asset contrary to the normal amortization of such an asset, DTE
provided no reason for requiring its customers to pay for costs that are not related
to productive generating assets. DTE bears the burden of proving that its requests
are reasonable and prudent and simply making a request and saying that the
Commission can grant the request hardly satisfies the burden that the Company
bears in this case. Accordingly, the Attorney General recommends that the
Commission maintain the normal accounting principles and remove DTE’s $5.1
million expense for the amortization of COLA in the projected test year.
7. Employee Incentive
DTE is proposing to recover $40 million of incentive payments of which, $6.5
million relates to its Annual Incentive Plan (AIP), $22.7 million to the Rewarding
Employees Plan (REP), and $11.5 million to its Long Term Incentive Plan (LTIP).
22
(Tr 2305.) The AIP is an annual bonus program based on the following major
categories and specific measures:
1. 50% on Financial Performance (DTEE Net Income, DTEE Cash Flow and
DTE Energy Earning Per Share).
2. 18% on Customer Satisfaction (Customer Satisfaction, Improvement in
Customer Satisfaction and MPSC Customer Complaints).
3. 16% on Employee Engagement (DTE Energy Employee Engagement, DTE
Energy OSHA Incidents, Employee Satisfaction survey results).
4. 16% on Operating Excellence (Recurring Power Outages, Fossil Power
Reliability and Nuclear Power Reliability). [Tr 2306.]
Of the $6.5 million for this AIP bonus, 80% is for corporate and support employees
outside the electric utility. (Tr 2306.)
The REP is very similar in design and function to the AIP with some
variations in the non-financial measures. (Tr 2306.) The AIP is designed for senior
level managers at DTE and its affiliates and the REP covers all other employees at
these companies. (Tr 2306.) Also, of the $22.7 million for this bonus plan, 36%
pertains to non-DTE employees. (Tr 2306.) The LTIP is an annual stock grant plan
focused on achieving multi-year goals and specifically on the following measures:
1. 60% - 80% on Common Stock Total Shareholder Return vs. a Peer Group.
2. 20% Balance Sheet Ratio of Funds from Operations to Debt.
3. 0 – 20% DTEE Average Return on Equity over a 3-year period. [Tr 2307.]
23
The weight of the measures varies depending on whether the employee works for
the utility or the parent company and corporate service group. (Tr 2307.)
Mr. Coppola testified that his overall assessment was that the three incentive
plans are too heavily skewed toward the measures that directly benefit
shareholders and not customers. He also explained 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. (Tr 2307.)
As evidenced above, half of the incentive payout at target level for both the AIP and
REP relates to the Company and its parent, DTE Energy, achieving net income,
earnings per share and cash flow goals. (Tr 2037.) Although the Company claimed
that these goals somehow benefit the customers, Mr. Coppola explained that there
was no direct relationship to customer benefits. (Tr 2307.) The goals are in place to
maximize profit and increase cash flow to pay dividends to shareholders. It is
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, and thus the Commission should not allow
recovery of incentive payments related to these financial goals. (Tr 2308.
As to the AIP and REP programs, the Customers Satisfaction grouping of
measures has only represented between 18% to 25% of the relative weight of the
total payout during the past five years. (Tr 2308.) Mr. Coppola explained that this
reflected the difficulty that the Company has had in meeting the target measures in
a key area that is directly beneficial to customers. (Tr 2308.) The Employee
24
Engagement category has worthy goals but do not rise to the level of being
measures that are visible to customers or create direct customer benefits since they
are primarily internal goals related to employee satisfactions and safe practices in
the workplace. (Tr 2308.) Similarly, the Operating Excellence category has worthy
internal goals to measure performance of the departments responsible for those
operations but they have no direct visibility to customers. (Tr 2308.) The only
measure that has a direct link to customers is the number of repetitive power
interruptions. (Tr 2308.) This measure was implemented in 2012 and represents 6-
7% of the total measures for the AIP and REP for 2014 and yet the over the past
three years the Company has had difficulty in consistently meeting the target
performance level of 25%. (Tr 2309.)
As to the LTIP program, it is a plan strictly designed to induce management
to create shareholder value. (Tr 2309.) DTE witness Mr. Wuepper explained that
“There measures … [are] … intended to motivate employees…to keep in mind the
role of their own contribution in the overall success of DTE [Energy].” (Tr 2309.) As
stated by Mr. Coppola, DTE Electric customers should not pay for the overall
success of DTE Energy. (Tr 2309.) The LTIP is weighted 60-80% on total
shareholder return, which is stock price appreciation and dividends paid over a
period of time. (Tr 2309.) The Company’s total return in then measured against a
group of peer companies to trigger a payout. The problem, however, is that this has
nothing to do with creating direct benefits for DTE Electric customers and
everything to do with creating value of DTE Energy shareholders. (Tr 2309.)
25
Similarly, 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
somewhat duplicative of the Net Income and Cash Flow measures included in the
AIP and REP plans. (Tr 2309.)
Although DTE witness Mr. Wuepper presented a calculation which purports
to show that operating and financial cost savings have exceed adjusted 2013
incentive plan payments by $104.1, the calculations are faulty. (Tr 2310.) Mr.
Coppola explained that the results of Mr. Wuepper’s calculations are based on the
premise that the target level of performance is achieved. (Tr 2310.) Yet, the largest
contributor to the total net benefit (77% of the total) to customers is from fewer
service interruptions but the Company has failed to achieve this measure, even at
the lowest threshold level, during the past two years. (Tr 2310.) Accordingly, the
Commission should be skeptical that this measure can be achieved with any
consistency in the future and should not base its decision to grant approval for
recovery of more than $40 million of incentive compensation costs on such poor
historical performance. (Tr 2310.) As to the other measures that have more direct
visibility with customers, the calculations for the Customer Satisfaction grouping
show that allocated incentive payments to these measures exceed the calculated
benefits, demonstrating that there is no net benefit to customers. (Tr 2311.)
Thus, the programs are heavily weighted toward measures that directly
benefit shareholder and not customers. Even with the performance measures that
26
do directly affect customers, the Company failed to show that it has achieved
consistent performance at target levels in those programs. (Tr 2311.)
In rebuttal, Mr. Wuepper argued that the financial metrics such as earnings
and cash flow goals do not solely inure to the benefit of the Company’s shareholders.
(Tr 1292.) Mr. Wuepper claimed that if the Company’s achieves its earnings and
cash flow goals, it is likely a consequence of cost savings which may eventually
trickle down to the customers with the possibility of postponing a general rate case.
(Tr 1292.) Even assuming Mr. Wuepper’s criticism is accurate, he does not rebut
the argument that the three incentive plans are heaving skewed toward measures
that directly benefit shareholders and not customers. Mr. Wuepper did not refute
that the majority of the benefit for these financial metrics are the Company’s
shareholders and that the majority of the measures for the incentive plans are these
financial metrics.
Mr. Wuepper challenged Mr. Coppola’s testimony regarding the Company’s
performance in the measure that actually benefits customers, such as Customers
Satisfaction, but the challenge did not refute the actual numbers themselves but
how to interpret them using longer periods and realizing that the Company has
created “stretch” for it to achieve. (Tr 1293-1295.) Mr. Wuepper claimed that the
Employee Engagement measure is not just workplace safety, having little direct
customer benefit, but that it is also “a measure of employee perceptions of their
work environment that that are directly related to organizational performance,
which includes, among other things productivity, safety and absenteeism.” (Tr
27
1293.) Mr. Wuepper stretched to connect these measures as direct benefits to
customers which further demonstrates why the incentive programs should not be
paid by customers. (Tr 1292.)
Not only are the incentive programs heavily weighted to toward measures
that directly benefit shareholders and not customers, but also the measures that do
benefit customers the Company struggles to meet the performance target levels.
Accordingly, the Commission should deny the requested $40.7 million of incentive
payments following the similar logic of its October 20, 2011 decision in U-16472
regarding a DTE electric rate case dealing with a similar request for incentive
programs. (October 20, 2011 Commission Order, U-16472, p 111-112.)
8. Employee Benefit Costs
DTE requested a total O&M Employee Benefit expense of $183.5 million for
the projected test year which is an increase from the 2013 historical test period. (Tr
2311-2312.) Included in DTE’s test year expenses are amounts related to Active
Employee Health Care, Employee Savings Plan, Non-Qualified Benefit Plans, and
Other Post-Employment Employee Benefits (OPEB).
Health, Dental, and Vision costs
To determine the projected test year health care, dental, and vision costs for
active employees, DTE applied an industry-wide rate increase provided by Aon
Hewitt of 6.5% for 2014 and 7.5% for 2015 /2016. Using these rates, DTE has
projected total medical costs for the projected test year to increase by $17 million
over the expenses in 2013. (Tr 2312.) In response to discovery, the actual average
28
rate of increase in medical costs experienced by DTE during the recent five years
has only been 0.6% which considerably less than the Aon Hewitt numbers. (Tr
2312.) In fact, using just 2014 (the most recent experience provided by DTE in a
discovery response) DTE only had a 3% increase in medical costs which is less than
half of the rate of increase projected by the Company. (Tr 2313; Exhibit AG-7.)
Reducing the rate of increase to 3% is a more reasonable projection and yields an
increase of only $7.0 million instead of the $17 million forecasted by the Company.
(Tr 2313.) Accordingly, Mr. Coppola recommended that the O&M expense for the
projected test year by reduced by $10 million. (Tr 2313.)
In rebuttal, DTE witness Mr. Wuepper claimed that Mr. Coppola applied the
3% annual escalation rate to only the cost categories reflected on Exhibit A-10,
Schedule C5.9, but ignored the impact on the lower escalation assumptions on costs
related to Retiree Actual Benefit Payments that are subtracted from such costs. (Tr
1305.) Applying the 3% annual escalation rate to everything, Mr. Wuepper stated
that Mr. Coppola’s proposed $10 million reduction should only be $4.5 million (Tr
1306.) The problem with this argument is that it makes no sense and appears
designed after-the-fact. Mr. Wuepper’s rebuttal exhibit A-33, Schedule W-4 clearly
shows that Mr. Coppola used all of the same numbers that Mr. Wuepper used
except for the Healthcare, Dental, and Vision expenses (using instead DTE’s own
actual experience instead Aon Hewitt’s numbers.) Mr. Wuepper did not adequately
explain why any change in lines 11-15 of Schedule W-4 must be matched with an
opposite change to line 16. Mr. Wuepper then argued against Mr. Coppola’s use of
29
the 3% annual healthcare escalation since it is based on only recent experience but
also argued against using a six year average of 0.6%. (Tr 1305.) According to Mr.
Wuepper, using any of DTE’s actual numbers for the healthcare escalation (recent
or over time) is a bad idea and that the Commission should use Aon Hewitt’s
numbers for the country since they are at least double any of the numbers DTE
could produce regarding its actual health care costs. Accordingly, the Commission
should adopt the Attorney General’s recommendation of a $10 million reduction and
at the very least the $4.5 million reduction that Mr. Wuepper supports in his
rebuttal. (Tr 1306.)
Employee Savings Plan
In regards to the Employee Savings Plan, DTE forecasted a rate of increase
for wages of 4.2% for 2014 and 4.65% for 2015 and 2016 based on wage information
gathered by Aon Hewitt. (Tr 2313.) Mr. Coppola explained that the 4.2% and 4.65%
increases in base pay seem excessive during a period of economic stagnation and
lower household incomes experienced by Michigan residents in the past few years.
(Tr 2313.) At most, Mr. Coppola recommended only a 2% increase which is in line
with the historical wage increase during the past three years as reported in the HIS
Economics report provided by DTE to Mr. Coppola in response to discovery data
requests. (Tr 2314.) This rate of wage increase is based on information provided by
the Company and is less than half the rate of increase forecasted by the Company in
this case. Accordingly, Mr. Coppola recommended that only half of the $4.3 million
30
increase proposed by the Company be allowed, thus removing $2.1 million of
expense from the projected test year. (Tr 2314.)
In rebuttal, Mr. Wuepper testified that Mr. Coppola objected to the
Company’s use of salary increase assumptions of 4.2% in 2014 and 4.65% in 2015
and 2016 and instead advocated for the use of the 3% rate based a IHS Economics
Report for the entire country on wage increases over the past three years provided
by DTE in response to discovery request AG/DE1.19b (Tr 1309; 2314 fn 19.) Mr.
Wuepper argued that Mr. Coppola’s reliance on DTE’s wage increase report is
unsupported and unreasonable because Mr. Coppola was unable to identify which
category of the IHS report he relied upon. (Tr 1309.) Mr. Wuepper’s rebuttal is
completely contrived and unreliable because on cross examination Mr. Wuepper
admitted that he did not review his Company’s’ own discovery response (AG/DE
1.19b) or even the IHS economics report contained in the discovery response. (Tr
1322.) It is incredible that Mr. Wuepper can prepare rebuttal claiming Mr. Coppola
did not identify which category of the IHS report he relied upon when Mr. Wuepper
did not even review the Company’s discovery response that contains the IHS report
that is being questioned. Clearly, Mr. Wuepper’s testimony should be disregarded
by the Commission because is completely unreliable. It is stretches the imagination
to believe that in preparing his rebuttal about the discovery response AG/DE 1.19b,
Mr. Wuepper did not even review the discovery response. Accordingly, the
Commission should adopt Mr. Coppola’s $2.1 million reduction to this expense since
31
the 2% rate is from DTE’s own economics report and Mr. Wuepper provided little if
any credible rebuttal to that rate.
Non-qualified Benefit Plans
In regards to Non-qualified benefit plans, DTE has included $8.2 million of
costs related to the Executive Supplemental Retirement Plan (ESRP),
Supplemental Retirement Plan (SRP), and the Deferred Compensation Plan. (Tr
2314.) Mr. Wuepper testified that these costs are legitimate business costs for
retirement programs typically offered to executive management by many
corporations. (Tr 2314.) He acknowledged that the Commission declined to include
these costs in rates in past rate cases, however, he felt that their continued
exclusion was unreasonable and the link to the limitation imposed by the Internal
Revenue Code (IRC) to be illogical. (Tr 2314.)
Mr. Coppola testified that the Commission has been very consistent in
disallowing recovery of costs for non-qualified benefit plans that benefit executive
level employees. (Tr 2315.) The same practice is frequently followed by other
regulatory commission around the country. (Tr 2315.) In fact, some of the utilities
in Michigan and in other states no longer even attempt to recover such costs in their
rate case filings based on this history. (Tr 2315.) Mr. Coppola explained that the
IRC limitations were enacted because legislators wanted to limit the cost to
taxpayers of benefits which applied to only a limited number of high income
executives. (Tr 2315.) Employers still see value in providing them to their
executive employees but that does not mean that the costs should be borne by
32
customers. (Tr 2315.) These exclusions are similar to lobbying and corporate
advertising expenses, which are beneficial to the Company, but are not expenses
recoverable in rates. (Tr 2315.) Moreover, Mr. Coppola noted that DTE has made
no attempt to show how non-qualified benefit plans directly benefit customers, other
than to say that they are part of a reasonable and competitive set of benefits offered
to attract and retain executive management. (Tr 2315.) Accordingly, Mr. Coppola
recommended that the Commission continue to disallow recovery of these costs and
remove $8.2 million from DTE’s projected O&M expense in this case. (Tr 2316.)
In rebuttal, DTE witness Mr. Wuepper again admitted that the Commission
has consistently disallowed rate recovery of ESRP and SRP but not the Deferred
Compensation Plan – claiming that at pp 66-67 of Commission Order U-16472 the
Commission allowed rate recovery of other non-qualified benefit expenses. (Tr
1301.) This statement is completely untrue. At page 66 of U-16472 in the section
titled “Other Benefit Costs”, the order reads “[t]he ALJ recommended that the
Commission adopt the Staff’s proposal to exclude all non-qualified pension and
deferred compensation costs . . .” and then concludes at page 67 that “the Staff’s
disallowance should be adopted.” Mr. Wuepper then argued that Mr. Coppola
provided no support for his understanding of the IRC limitation and then Mr.
Wuepper proceeded to provide his own unsupported (no study or exhibit) diatribe on
the appropriate meaning of the IRC limitation finishing with an explanation that
legislative intent of the IRC is irrelevant anyway – thus negating his own created
history of the regulation. (Tr 1302-1303.)
33
OPEB Negative Expense
In regards to the OPEB plan, DTE is proposing to defer the negative expense
related to the OPEB plan. (Tr 2316.) According to DTE, in 2012 and 2013 the
Company restricted the OPEB plan to freeze participation by new employees and
changed the benefits paid for retiree drug and dental coverage. (Tr 2316.) These
changes to the plan significantly reduced the accumulated projected obligations and
created negative costs – 2013/2014 the Company recorded $74.9 million of negative
OPEB expense boosting earnings; 2015/2016 the Company projected negative OPEB
expense of $52.5 million and $54.7 million; and for the projected test year ending
June 2016, the amount of negative OPEB expense is $53.6 million. (Tr 2316.)
Instead of reflecting this negative expense in the projected test year requirement,
DTE proposed to defer the $53.6 million and use it to offset any future positive
OPEB expense that could occur in the future. (Tr 2316.)
Mr. Coppola testified that DTE’s proposal “is too late and not in the best
interest of customers in the near term.” (Tr 2317.) He explained that DTE should
have proposed such a deferral in conjunction with the restructuring plan that
occurred in 2013. Instead, DTE chose to flow the benefit of $102.2 million for the
first two-and-a-half years to its bottom line. (Tr 2317.) It is not a convincing
argument by DTE to now change approaches mid-stream especially in light of the
significant rate increase it is seeking in this case. (Tr 2317.) DTE has flowed the
benefit of this negative OPEB expense to the bottom during the lag period between
rate cases but once it filed a new rate increase DTE proposed a new idea to avoid
34
flowing that benefit to customers. Such clear gaming of the treatment of the OPEB
negative expense should not be rewarded by the Commission. Accordingly, the
Attorney General recommends that DTE’s deferral proposal be rejected and the
$53.6 million be applied as a reduction to the Company’s revenue requirement.
In rebuttal, DTE witness Ms. Uzenski claimed that “[i]t would not be prudent
recurring, temporary credit item” and that OPEB costs will probably increase in
2017 as the credit items expire. (Tr 1066.) This argument is completely inconsistent
with how DTE has been treating the OPEB negative expense. As Mr. Coppola
testified, it would have been more convincing if DTE had originally sought a
deferral for the OPEB negative expense, than to use the negative expense for its
benefit while in between rate cases but then change course when there is a
possibility that the benefit could be directly flowed to its customers during a rate
increase request. DTE wants the Commission to believe that it is prudent and
reasonable to attempt to achieve a customer rate reduction based upon a non-
recurring, temporary credit item in between rate cases but during a rate increase
request it is not prudent and reasonable. Such double talk should not be rewarded
and any claim of expenses into 2017 should be appropriately projected in the rate
case or treated when it actually occurs – instead of retaining the money on the
belief that the Company may need to use it sometime in the future.
9. Summary of O&M Expense Reductions
The Attorney General’s recommendations are summarized in Mr. Coppola’s
testimony as follows:
35
Summary of O&M Expense Reductions:Amount ($Million)
Distribution Operations 46.5$
Fossil Power Generation 16.5
Nuclear Power Generation 4.7
Uncollectible Accounts Expense 11.0
Corporate Services 5.0
COLA 5.1
Employee Incentive Compensation Plans 40.7
Employee Benefits 73.9
Total Reduction 203.4$
II. Capital Expenditures and Rate Base
DTE proposed a Rate Base level of $13.6 billion for the projected test year
which is an increase of $2.2 billion or nearly 19.3% over the Rate Base level of $11.4
billion in the historical 2013 test year. (Tr 2319.) This increase is primarily driven
by $43.6 billion of new capital expenditures proposed by the Company during the
two-an-half years ending June 2016. (Tr 2319.) Mr. Coppola explained that such a
level of increase is unusual for a utility with relatively flat sales. (Tr 2319.) Of the
$3.6 billion in forecasted capital expenditures, only a small portion is generating
new revenue and most of the capital expenditures have no new incoming revenue
associated with them thereby requiring higher rates to customers in order for the
Company to recover its investment. (Tr 2319.) Mr. Coppola warned that “the
Commission should carefully review the need for all of the proposed capital
additions” because “[t]o continue to increase the cost structure in a relatively flat
36
sales market and to increase rates in order to make up the revenue shortfall is not a
sustainable business model for the long term.” (Tr 2320.) Accordingly, Mr. Coppola
analyzed DTE’s forecasted capital expenditures by major department or functional
area and identified more reasonable expenditure levels that the Commission should
consider. (Tr 2320.)
(1) Distribution Operation
DTE forecasted nearly $1.2 billion in capital expenditures during the 30
months ending June 2016 for the Distribution Operations Department. (Tr 2320).
New Business
In regards to New Business, DTE included $11.8 million of capital
expenditures in a line item labeled Miscellaneous/Undesignated Business. In
response to discovery, DTE stated that this line item includes unknown potential
new business projects that may occur during the year. (Tr 2320-2321.) As Mr.
Coppola noted “[i]t appears that the amount projected for this line item for the first
six months of 2016 is a catch-all of what may occur and is not specific to any
planned project.” (Tr 2321.) Accordingly, Mr. Coppola explained that the
Commission should not approve unknown and obscure capital expenditures for
inclusion in rate base and rates since such expenditures do not pass the basic test of
being used and useful if it is not known what they are for. (Tr 2321.) Thus, the
Attorney General recommends that the incremental amount over the $2.9 million
2014 level expenditure or $8.8 million should be removed from capital expenditures
forecasted for the first six months of 2016. (Tr 2321.)
37
In rebuttal, DTE witness Mr. Pogats agreed that it did not have specific
projects at the time of filing DTE’s application. Conveniently after intervenors filed
their testimony commenting on this lack of specifics, Mr. Pogats presented a list of
four projects that exceed the $11.8 capital expenditure. In fact, in response to
discovery from the Attorney General on this $11.8 million, DTE continued to state
that this line item includes unknown potential new business projects. (Tr 2320-
2321.) DTE never supplemented its discovery response or filed revised testimony
with these new projects. Unsurprisingly, Mr. Pogats stated in rebuttal that “the
emergence of these projects confirms the Company’s expectations concerning the
amount of new business likely to materialize in the projected test year.” (Tr 44.)
The Commission should reject DTE’s gamesmanship on the “emergence” of these
new projects after the filing of direct testimony by intervenors. Such sandbagging
denies intervenors the opportunity to fully explore the new information, denies
intervenors the ability to discuss this information in direct testimony, and more
importantly, denies the Commission a full record on which to base its decision to
include or exclude these capital expenditures that did not exist until the time of
rebuttal.
Reliability
In this section, DTE forecasted $46.2 million of capital expenditures for 2014,
$54 million in 2015, and $32 million for the first six months of 2016 for the
“Duration-Efficient Frontier.” (Tr 2321.) DTE spent only $28.3 million in 2013 in
this area and stated that the Duration-Efficient Frontier is the same as the
38
Repetitive Outage Pocket Program for which the company forecasted an additional
$43.2 million between 2015 and the end of June 2016. (Tr 2321.) Mr. Coppola
explained that the amount of capital expenditures forecasted for 2014, 2015, and six
months in 2016 for the Duration-Efficient Frontier were not specifically discussed in
Mr. Pogats’ direct testimony and no justification was provided as to why this level of
expenditure is needed. (Tr 2321-2322.) The $46.2 million of expenditures in 2014
are a 63% increase over the expenditures in 2013 and in addition to the 17% and
19% increases for 2014 and 2015 the capital expenditures in this line item will have
more than doubled between 2013 and 2016. (Tr 2322.) Mr. Coppola recommended
that the Commission should only allow $40 million annually for the Duration-
Efficient Frontier capital projects until the Company better defined and justified
the need to exceed this amount. (Tr 2322.) Therefore, the Attorney General
recommends that $26 million in capital expenditures by removed from 2015 and the
six month period ending June 2016.
In confusing rebuttal, Mr. Pogats admitted that in discovery it told the
Attorney General that the Duration-Efficient Frontier and Repetitive Outage
Pocket Program were the same but then clarified this in a later response. Yet, in his
rebuttal, Mr. Pogats quotes from a discovery response that essentially links the two
together as one. (Tr 411-412.) Mr. Pogats then confusingly stated that he did
“specifically” discuss the Duration-Efficient Frontier program at pages 12 to 14 of
his direct testimony, yet nowhere on pages 12 to 14 of his direct testimony are the
words “Duration-Efficient Frontier “ ever mentioned. (Tr 411-412.) Mr. Pogats
39
after-the-fact claim that pages 12 to 14 provide the justification for a program that
is not named in the testimony is incredulous. Even assuming for the sake of
argument that the Duration-Efficient Frontier and Repetitive Outage Pocket
program are different programs, nowhere in Mr. Pogats direct testimony at the
pages he cites, 12-14, are the words Duration-Efficient Frontier. Accordingly, the
Commission should adopt the Attorney General’s recommended $40 million for the
Duration-Efficient Frontier capital projects and remove $26 million in capital
expenditures from 2015 and the six month period ending June 2016.
Vegetation Management
As discussed in more detail in the O&M section of this brief and Mr.
Coppola’s direct testimony, DTE proposed a $45 million annual capital program to
manage vegetation growth under power lines, including $45 million of capital
expenditures for 2015 and $22.8 million for the first six months of 2016. (Tr 2322.)
Based on his earlier analysis that the vegetation program is not adequately
supported and needs to be scaled down to a more reasonable level, Mr. Coppola
recommended that $20 million of the projected capital expenditures for 2015 be
removed and similarly $10 million from the first six months of 2016, for a total of
$30 million. (Tr 2322.).
In summary, the Attorney General recommends that the Commission exclude
$64.8 million from the capital expenditures projected for Distribution Operations.
(2) Fossil Generation
40
DTE proposed $998.3 million in capital expenditures in this department for
the 30 months period ending June 2016. Nearly half relates to improvements to
reduce particulate emissions, mercury emissions and other environmental projects.
(Tr 2323.) The remainder relates to both routines and discrete capital expenditures
to upgrade, replace and renew steam power generation, hydraulic generation and
other generation equipment. (Tr 2323.) Mr. Coppola identified a $32.6 million
reduction in forecasted capital expenditures proposed by the Company. (Tr 2323.)
He explained that the reduction is simply the difference in the capital expenditures
projected by the Company for 2014 versus the capital expenditures actually
incurred for that year. (Tr 2323.)
As explained in his direct testimony, Mr. Coppola noted that the Company
projected capital expenditures for 2014 of $445.5 million but in response to a data
request, included as Exhibit AG-9, the Company reported that actual expenditures
for 2014 were $412.9 million or $32.6 million less than projected. (Tr 2323.)
“Although some of these projects may be just delayed, it is likely that the delays will
cause a cascading effect and projects scheduled for 2015 and 2016 may be pushed
past the end of the projected test year.” (Tr 2323-2324.) Accordingly, Mr. Coppola
testified that it is likely that the level of expenditures projected by the Company
will not occur as forecasted with the future test year since these numbers are so
significant. (Tr 2323-2324.) Thus, the Attorney General recommends that the
Commission remove $32.6 million of capital expenditures from DTE’s forecast in the
Fossil Generation area.
41
In rebuttal, DTE witness Mr. Warren did not directly response to Mr.
Coppola’s testimony but did state that his rebuttal to staff regarding ACI/DSI
applies to Mr. Coppola’s testimony on this topic. (Tr 261-262.) Mr. Warren admitted
that it was reasonable to reduce some of the original project cost recovery requested
as a result of the difference in projected and actual expenditures for 2014 and stated
that the Company has reduced the forecasted cost of ACI/DSI projects and the
Monroe FGD/SCR projects. (Tr 261.) Mr. Warren did not directly refute Mr.
Coppola’s testimony that the level of expenditures projected by the Company will
not occur as forecasted, but did claim that the ACI/DIS projects will be completed by
April of 2016 to be compliant with MATs. The MATs compliance partially unknown
as a result of the U.S. Supreme Court’s ruling on MATs. Accordingly, the
Commission should adopt the Attorney General recommendations to remove the
$32.6 million of capital expenditures from DTE’s forecast in the Fossil Generation
area because DTE has failed to satisfy its burden of proving the reasonableness of
its forecast it light of the difference between forecasted and actual numbers for 2014
and its lack of rebuttal to Mr. Coppola’s argument regarding the cascading effect of
moving back projects that were not done as forecasted.
(3) Nuclear Generation
DTE projected 429.4 million of capital expenditures for the 30 months ending
June 2016 relate to the purchase of nuclear fuel and other capital projects. (Tr
2324.) Included in this amount are expenditures of $4.4 million and $2.1 million in
42
2015 and first half of 2016, respectively for Emergent Projects. (Tr 2324.) In
response to discovery for more information on these projects, DTE stated that no
details could be provided because the dollars represent contingency amounts. (Tr
2324.) Thus, the total amount of $6.4 million does not represent specific
expenditures for equipment or projects that should be included in rate base but
rather are merely contingency amounts which may or may not occur. (Tr 2324.)
Because these Emergent Projects fail the test of used or useful, Mr. Coppola
recommended that these amounts be removed from the projected capital
expenditures for Nuclear Power Generation. (Tr 2324.) DTE does not appear to
have provided rebuttal to Mr. Coppola’s testimony on this reduction.
(4) Acquisition of 300 MW Power Plan
In its capital expenditures, DTE included the acquisition of two power plants:
(1) $240 million for the purchase of the Renaissance Plant which the Company
concluded in early 2015; and (2) $100 million for an expected purchase of a second
peaker plant with 300 MW nameplate capacity. (Tr 2325.) This second plant has
not yet been purchased. (Tr 2325.) On May 18, 2015, in response to Staff data
requests, DTE announced that it had plans to purchase an affiliated merchant plant
owned by DTE Energy Services but that it would not know the exact purchase price
until after the closing of the transaction. (Tr 2325.) Mr. Coppola explained that
because the information regarding the second plant purchase was not received until
four days before direct testimony was due for intervenors that there was no realistic
opportunity for discovery and investigation by intervenors in this case. (Tr 2326.)
43
The fact that the transaction is with an affiliate of the Company raises the level of
scrutiny and yet no time was given to provide even a modest level of scrutiny before
testimony was due. (Tr 2326.) Accordingly, the Mr. Coppola concluded that
including any portion of the acquisition cost of the second power plant in the rate
base in this rate case is premature and that the Commission $110 million be
removed from the Company projected capital expenditures. (Tr 2326.) DTE does not
appear to have provided rebuttal to Mr. Coppola’s testimony on this reduction.
(5) Customer 360 Project
In its application, DTE proposed to replace its customer service and customer
billing computer systems and estimated the total cost of the project at $215 million
with a target implementation date of April 2017. (Tr 2326.) As Mr. Coppola noted,
this is nearly the same amount as the purchase of the $240 million 732 MW
Renaissance Power Plant. (Tr 2327.) With a project of this size, Mr. Coppola
testified that he would expect the Company to evaluate difference alternatives and
vendors before deciding to select SAP as the vendor. In response to discovery for
support for the selection, DTE skirted the main question and never answered what
other alternatives the company evaluated. (Tr 2327.) As Mr. Coppola testified, this
is not a project that is fully justified by cost savings since one must but into the
obsolescence of the existing systems and the need to move to more current
technology in order to justify the need to spend $215 million for a new system. (Tr
2327.) He explained that “[g]iven the large scope of the project, I am concerned
about delays in implementation and cost over-runs.” Accordingly, Mr. Coppola
44
recommended that the Commission warn the Company that recovery of any further
increases in the cost of the project may not be allowed in the future. (Tr 2328.)
(6) Corporate Staff Group
DTE projected capital expenditures totaling $342.5 million for the 30 months
ending June 2016 for this Corporate Staff Group. (Tr 2328.) This represents an
average annual expenditure level of $131.4 million which is less than the $158.5
million spent in 2013 but considerably higher than the $61.9 million spent annually
on average during the prior three-year period from 2010-2012. (Tr 2328.) This
increase in capital spending is reflected across many areas, however, Mr. Coppola
identified two projects that are of questionable value to customers and should be
partially disallowed from recovery in the rate base. (Tr 2328.) The first project is
the Workplace Transformation. Between 2012 and 2014, DTE has spent
approximately 61.7 million to transform its offices into, as DTE explained in
response to discovery, a worker oasis with a centralized café on each floor, central
copy/print rooms, meeting spaces, updated technology, fore suppression, LED
lighting, low flow faucets and water closets, and furniture and carpet made from
recycled components, among other improvements. (Tr 2328.) Accordingly to DTE,
the objective is to increase efficiency, reduce costs and attract a new generation of
younger workers after the older workers retire. (Tr 2329.) For 2015 and the first six
months of 2016, DTE is projecting to spend an additional $33.9 million making the
total for the Workplace Transformation nearly $100 million during a four-and-half
year period. (Tr 2329.) DTE last made significant renovations in 2011 and while
45
renovations are expected from time to time, $100 million in renovations appears
excessive and unfair to make customers completely absorb in the form of higher
rates. (Tr 2329.)
The second project that Mr. Coppola questioned is the $24.6 million already
spent and being spent into the first six months of 2016 (which may easily grow to
nearly $30 million by the end of 2016) for a Neighborhood Revitalization Initiative.
(Tr 2329-2330.) This second project involves urban revitalization, work place
transformation, an office campus extension, neighborhood beautification, creation of
a public space for employees and neighbors and a crime deterrence initiative for
reduce and prevent crime near the Company’s headquarters building. (Tr 2329.) On
cross examination, DTE witness Mr. Stanczak admitted that part of the DTE’s
Neighborhood Revitalization Initiative is the creation of a park on a vacant lot that
will feature food trucks, concerts, and restaurants on the open space. (Tr 174-175.)
Although the Neighborhood Revitalization project may be worthwhile and
beneficial to the neighborhood surrounding the DTE headquarters, this is clearly a
goodwill project by the company that is similar to some the charitable contributions
and corporate advertising made by the Company and thus the costs should not be
completely borne by DTE’s customers but rather shared with shareholders who
equally benefit from such goodwill/charitable spending. Similarly, the massive $100
million renovation to the DTE headquarters is far too excessive to impose solely on
DTE’s customers in order to make the headquarters more inviting to young
workers. Accordingly, Mr. Coppola recommended that DTE segregate half ($60
46
million) of the $120 million of capital expenditures into a non-utility asset account
for which DTE would not receive recovery in rates by excluding those capital costs
from rate base.
(7) Summary of the AG Disallowed Capital
Expenditures
Mr. Coppola summarized his capital expenditure recommendations as
follows:
Summary of AG Disallowed Capital Expenditures
Distribution Operations
New Business $8.8
Reliability 26.0Vegetation Management 30.0
Fossil Generation 32.06.4
Acquisition of 300 MW Plant 110.0
Corporate Staff Group 60.0
$273.2
Nuclear Generation
Total
Amount (millions)
Mr. Coppola concluded by stating that “[b]ased on my analysis and information
presented in my testimony above, the Commission should reduce the Company’s
proposed capital expenditures by $273.2 million and rate base by $136.6, using the
average half-year convention.” (Tr 2331.)
III. AMI
With the installation of AMI proceeding close to schedule, the main question
that remains is whether or not the projected cost savings and other benefits
47
materialize as projected. (Tr 2332.) As Mr. Coppola explained the expected net
present value benefit of the electric meters and the overall net PB benefit for the
entire project has varied significantly from one cost/benefit update to the next due
to changing assumptions and updated information. (Tr 2332.) Such variations do
not inspire confidence that the projected cost savings in particular are sufficiently
firm to be relied on as reasonably achievable. (Tr 2332.) DTE has proposed to stop
providing cost/benefit analyses in its rate case to prevent the public from assessing
whether or not the program was actually successful (Tr 2333.) As Mr. Coppola
explained “[i]t is strange and inopportune time for the Company to propose to stop
updating the cost/benefit analysis now that the installation is reaching completion
and the financial benefits should begin to be realized to a much larger degree.” (Tr
2333.) Accordingly, the Attorney General recommends that the Commission require
DTE’s cost/benefit analysis be updated and presented in future rate cases until such
time that enough financial benefits have been realized for the Commission to
conclude that the program has been deemed successful. On cross examination, DTE
witness Robert Sitkauskas admitted that future AMI cost/benefit analyses could be
included in future rates cases and stated that the Company would do it if the
Commission requested it. (Tr 784-785.)
Mr. Coppola explained that there are still significant risks that the financial
benefits will not materialize to the extent projected in the cost/benefit analysis. (Tr
2333.) He noted that “[w]e are still at the beginning in the long cycle of realization
of financial benefits” and that “[c]ost savings and other financial benefits are now
48
beginning to ramp up and should continue to do so until the 2030 time horizon in
the cost/benefit analysis is reached.” (Tr 2333.) He continued that “[i]t is still likely
that assumptions made by the Company may prove to be optimistic and the cost
savings and other financial benefits may fall far shorter than were forecasted” and
“[t]herefore customers are still at risk of paying for a very costly program with an
investment in excess of $500 million and not realize sufficient financial benefits
that will more than offset that cost.” (Tr 2333.) In order to mitigate the risk of the
AMI program currently placed entirely on customers, Mr. Coppola recommended
that the Commission could limit recovery of the AMI program costs in rates to only
certain costs until actual cost savings and other quantifiable benefits begin to
exceed the overall program costs. (Tr 2334.)
Instead of placing all of the risk of the success or failure of this AMI program
on its customers, Mr. Coppola proposed that the Company could defer recovery of its
investment, i.e. the depreciation expense, until the projected cost savings and other
financial benefits begin to materialize and they exceed the program costs. (Tr 2334.)
Mr. Coppola provided a lengthy quote from the Public Service Commission of
Maryland that ordered the company, Baltimore Gas and Electric, to establish a
regulatory asset to defer recovery of all AMI costs until the utility delivers a cost-
effective program with real quantifiable benefits. (Tr 2335.) Instead of a complete
deferral of all AMI costs, Mr. Coppola noted that his approach of just deferring the
depreciation cost of the investment mitigates the risk and still allows DTE to
recover a portion of its costs. (Tr 2336.) Mr. Coppola concluded that “the
49
Commission should not allow the Company to recovery its capital investment until
sufficient cost savings and financial benefits materialize.” (Tr 2336.)
In rebuttal, DTE witness Mr. Sitkauskas testified that he disagreed with Mr.
Coppola’s deferral of depreciation proposal and argued that it is common for utility
investments to have a profile where capital costs are incurred early in the program
and benefits are realized over the life of the program. (Tr 736.) Mr. Sitkauskas then
differentiated the Maryland Commission decision from DTE’s program by stating
that BGE appeared to rely on supply side savings to offset their costs and enhance
their NPV, whereas DTE relied on operational savings. (Tr 737.) Mr. Sitkaukas’
rebuttal, however, does not refute the idea of deferring depreciation for DTE’s AMI
program. Rather, Mr. Sitkauskas simply stated that it is commonly done
differently for utility investments and that DTE’s AMI program relies on
operational savings versus supply side savings like BGE. Because the AMI is more
than just a common utility investment and because the costs and impact on
customer rates are significant, the Commission should consider deferring the
depreciation in order to protect customers from bearing all the risks of the AMI
program not achieving DTE’s claimed benefits.
IV. Cost of Capital
Mr. Coppola began his testimony with analysis of DTE’s capital structure.
(Tr 2336-2337.) Because DTE chose a 2013 historical test year he explained why
DTE’s proposed capital structure is unreasonable as follows:
The Company has proposed a permanent capital structure with a
common equity component of 50.0% for the projected test year. This is
50
an increase over the historical test year percent of 47.97%.9 For the
projected test period, the Company assumes a mix of equal parts of
common equity and long term debt (i.e. a 50/50 capital structure)
which results in common equity increasing from $4.2 billion in the
historical period to $5.2 billion. It is difficult to imagine how the
Company would achieve a $1 billion increase in its common equity
level without substantial issuance of new common equity at the parent
level of DTE Energy. First of all, DTE Energy issued no new common
equity in 2014 other than to employee benefit plans. In discovery, I
asked the Company whether DTE Energy has “…indicated publicly
that it expects to issue new common equity prior to the end of the
projected test year in this case…” The Company’s response was: “DTE
Energy has indicated publicly that it is targeting $200 million of equity
issuance in 2015 and $800 to $900 million [in] 2015-2017…”10
However, The Capital Resources and Liquidity section of DTE Energy’s
Form 10-K for 2014 recently filed with the Securities and Exchange
Commission indicates that approximately $200 million of new common
equity will be issued through benefit plans in 2015, and makes no
mention of any equity issuances above this $200 million level.
Additionally, Company witness Solomon’s Exhibit A-11,
Schedule D2 shows long term debt outstanding for DTE Electric of $5.7
billion (beginning of test year) to $5.9 billion (end of test year). This
level of long term debt is $500 million greater than the debt level
shown in Company Exhibit A-11, Schedule D1 used to develop the
overall cost of capital.
Given DTE Energy’s limited plans to issue new common equity
for investment into its subsidiaries in 2015 (according to its Form 10-K
filing with the SEC) and the vague nature of any other plans to issue
common equity between 2015 and 2017, I have set the permanent
capital levels equal to the percentages in the historical test year for
purposes of this case. [Tr 2336-2338.]
As to DTE’s return on equity and overall return on capital, Mr. Coppola
recommended 9.75% and 5.53%, respectively. (Tr 2339.) The analysis that supports
this recommendation is lengthy and involves and examination of rates across the
country and the utilization of three approaches (DCF, CAPM, and Risk Premium)
9 Exhibit A-4, Schedule D1.
51
for determining the cost of common equity. Accordingly, Mr. Coppola’s entire
analysis is provided as follows:
Q. PLEASE EXPLAIN THE DEVELOPMENT OF THE
OVERALL COST OF CAPITAL IN EXHIBIT AG-13.
A. To develop the overall cost of capital on line 10, 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 5.53%.
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 and other taxes paid by DTEE for
calculation of the pretax weighted cost of 7.83% in column (h).
Q. WHAT GENERAL PRINCIPALS HAVE YOU
CONSIDERED IN DETERMINING THE COST OF
COMMON EQUITY FOR THE COMPANY?
A. 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 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…” 10
DTEE response to data request AG/DE-1.87.
52
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.
Q. PLEASE EXPLAIN THE DEVELOPMENT OF THE COST
OF COMMON EQUITY IN EXHIBIT AG-14.
A. 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 assessing this cost. These are the
Discounted Cash Flow (DCF) Method, the Capital Asset Pricing Model
(CAPM) and a Risk Premium approach. Also, I have considered the
current circumstances in the Capital Markets and any potential
changes in the risk profile of DTE Energy as a result of changes
occurring in its electric business and the improving Michigan economy.
In addition, I have considered the cost of common equity for a
proxy group of peer companies using the group proposed by Company
witness Vilbert as a starting point. Witness Vilbert proposes using a
group of 28 companies which includes DTE Energy and seven other
companies that are highly inappropriate for inclusion in the peer
group.
First, I have excluded DTE Energy from the proxy group since
we are attempting to determine the cost of common equity by reference
to other companies. The seven other companies I have excluded from
witness Vilbert’s peer group have market capitalization levels far
lower than DTE Energy (they range from $1.0 billion to $3.5 billion of
market capitalization) and are El Paso Electric, Vectren Corp., MGE
Energy, Allete, IDACORP, Portland General Electric and Otter Tail
Corporation—this later company being arguably a “micro-cap” stock
with a market capitalization of just $1.0 billion.
These smaller companies tend to have higher risk levels and in
some cases above average growth prospects. As such, these companies
are not appropriate for inclusion in the peer group of companies to be
considered in this case.
Q. PLEASE DESCRIBE THE DISCOUNTED CASH FLOW
(“DCF”) APPROACH.
53
A. The DCF approach is based on the proposition that the price of
any security reflects the present value of all future cash flows
(dividend flows) from the security discounted at a single discount rate -
which, in the case of common stocks, is the required return of equity.
Expressed mathematically, the resulting equation can be reconfigured
to solve for the required rate of return and this equation is:
R = D/P + g
where “R” = the Required Equity Return
“D/P” = the Dividend Yield on the Security
and “g” = the expected growth rate in dividends
Generally, the “D” or dividend is known and the “P” or stock
price is also known as the stock trades each day. Also, recent growth
in the dividend is known or estimates of growth furnished by stock
analysts can be relied upon with some degree of certainty. With this
information, one can solve for “R” which is the required rate of return.
Q. PLEASE EXPLAIN THE RESULTS OF YOUR DCF
ANALYSIS.
A. The results of my DCF analysis are summarized in Exhibit AG-
15. The stock price information in column (c) on this exhibit reflects
the average of the high and low prices for each of these equity
securities on each of the 30 trading days from March 4, 2015 to April
15, 2015. The annual dividend in column (d) is the projected dividend
level for the period April 2015 to March 2016 as projected by the Value
Line Investment Survey. Column (h) shows the average long-term
earnings growth rate based on Value Line and Yahoo Finance analysts’
projected growth in earnings per share between 2014 and 2019. The
resulting calculation of the DCF Method indicates an average required
return on common equity of 8.44% for the proxy group. This result is
lower than the Company’s “basic” DCF study result of 9.5%. The lower
cost of equity rate in my DCF study reflects a lower dividend yield
from the increase in the price of utility stocks since the time of the
Company’s analysis. The decline in interest rates since the Company
performed its cost of equity analysis has increased utility stock prices
and lowered their dividend yield, as investors adjust down their
expectations of returns from utility stock investments. In addition, the
Company’s result is higher due to the inclusion of the smaller
capitalization stocks mentioned above and to a lesser extent reduced
growth prospects for some of the other stocks in the proxy group.
54
Also, Dr. Vilbert has calculated a 10.8% DCF cost of capital
using his After Tax Weighted Average Cost of Capital approach
(ATWACC approach) which is an uncommon methodology for setting
the cost of common equity for regulated utility companies. I will
address this approach later in my testimony.
Q. PLEASE ASSESS THE RESULTS OF THE DCF ANALYSIS
YOU PERFORMED.
A. The DCF analysis relies upon financial market information for
the Dividend yield portion of the equation. However, it also relies
upon judgments of dividend 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 very high growth rates which in some cases are as high as 9.25%.
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 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.
Q. PLEASE EXPLAIN THE CAPITAL ASSET PRICING
MODEL (CAPM) APPROACH TO DETERMINING THE
COST OF COMMON EQUITY CAPITAL.
A. The Capital Asset Pricing Model (CAPM) is based on the
proposition that the expected return on a common equity security is a
function of risk as measured by the “Beta” of that security. In equation
form, CAPM is as follows:
ke = Rf+ (B x Rp)
where ke = The market cost of common equity for a
specific security
Rf = the “risk free” rate of return
Rp = the overall return of the market less the
risk free rate (over several years)
B = the systematic risk of a particular
common equity security vs. the market
55
Q. PLEASE EXPLAIN THE BETA OR “B” COMPONENT OF
THE EQUATION.
A. This measure of risk reflects the extent to which the price of a
particular security varies in relationship to the movement of the
overall market. Some securities vary less in price over time than the
overall market. In these cases, the Beta will be less than 1.00.
Securities that vary over time more than the overall market will have
a Beta that is greater than 1.00.
Q. PLEASE EXPLAIN EXHIBIT AG-16 SHOWING THE
RESULTS OF THE CAPM APPROACH.
A. Exhibit AG-16 shows the results of the CAPM method based
upon (1) a projected 4.0% risk free rate as explained in the next page
paragraph; (2) Beta information available from Value Line; and (3)
Historical Market Risk Premium (Rp) rate of 7%. This 7% rate is the
average of the 6.5% and 7.5% Market Risk Premium rates utilized by
Company witness Vilbert and is similar to other Market Risk Premium
estimates presented as evidence in at least one other case now pending
before this Commission.
Normally, I would use a historic risk free rate (the current yield
on 30-year treasury bonds) which as of early May 2015 approximates
2.9%. However, sentiment in the market is fairly universal that
interest rates will rise as the Federal Reserve Bank winds down its
“quantitative easing” efforts and the United States economy continues
to improve. Company witness Vilbert utilizes two different risk free
rates (3.78% and 4.03%) in his analysis which are reasonable estimates
of the 30 year U. S. Treasury bond rate. I have developed a 4.0% risk
free rate by considering interest rate projections available from Value
Line as of May 1, 2015.
The result for my CAPM approach is 9.11% for the proxy group
average. The Company’s “basic” approach to CAPM results in rates of
8.87% to 9.36% depending upon the Market Risk Premium employed.
The average of these two rates is equal to my 9.11% result.
Also, Dr. Vilbert has calculated a 9.9% CAPM rate utilizing his
ATWACC approach which I will discuss later in my testimony.
Q. PLEASE ASSESS THE CAPM APPROACH.
56
A. I believe that CAPM has value in assessing the relative risk of
different stocks or portfolios of stocks. As such, it can be useful.
However, 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. In actuality, investors take into consideration company-
specific factors in assessing the risk of each particular security. As
such, I give the CAPM approach less weight than the DCF approach in
determining the cost of common equity.
Q. PLEASE ADDRESS THE 10.8% DCF RATE AND THE 9.9%
CAPM RATE DERIVED BY DR. VILBERT USING HIS
“ATWACC” APPROACH FOR PURPOSES OF
DETERMINING THE COST OF COMMON EQUITY IN
THIS CASE?
A. With respect to the 10.8% DCF rate developed by Dr Vilbert, his
methodology starts with his DCF estimated proxy group common
equity results (which averages 9.5%) and the cost of long term debt
securities for this sample group which he determines to be 4.4%. He
also determines the market value of all common equity and preferred
stock and long term debt for each of the proxy group companies. On
this basis the average market capitalization of the proxy group is 60%
common equity and 40% long term debt and the result is a 6.8%
ATWACC. This result is demonstrated below
Common Long
Equity Term Debt Total Required Return on Securities 9.5% 4.4%
Capital Structure % (market values) 60.0% 40.0%
Sub Total 5.7% 1.7%
Less Income Taxes 0.0% (0.6)%
After Tax Cost of Capital 5.7% + 1.1% = 6.8%
The above summation is presented in greater detail in Company
Exhibit A-11, page 35. Dr. Vilbert then takes the result of 6.8% as a
starting point in Exhibit A-11, page 37 and (1) subtracts the after-tax
cost of debt (based on a 50% debt ratio—not 40%) which results in a
residual common equity component of 5.4%; and (2) then divides this
5.4% component by a 50% common equity ratio to derive the 10.8% cost
of common equity.
57
Dr. Vilbert has adjusted his “basic” CAPM results in a similar
manner to produce a higher CAPM cost of common equity result of
9.9% (average of the methods using a 6.5% and 7.5% Market Risk
Premium rates).
The “driver” in this mechanical exercise is to (1) initially
compute the after tax cost of capital using 60% common equity (DCF)
or 55% common equity (CAPM); and (2) then to recast the results
based on a 50%/50% capital mix with the different capital mix
producing higher returns on equity. Moreover, the higher levels of
returns generated by this exercise are arguably the by-product of the
substantial decline in interest rates in recent years which has
increased equity prices relative to book value in a material way and
decreased the cost of common equity. It is my opinion that this
decline in the cost of common equity has not been fully recognized in
rate case orders yet due to regulatory lag and an attitude of
“gradualism” among regulatory commissions.
In discovery response AB/DE-2.9, Dr. Vilbert acknowledges that
the ATWACC method “…is not in wide-spread use by regulatory
commissions in the states.” Moreover, he was unable to identify any
general rate case proceeding in the United States where the
commission embraced this methodology to set the cost of utility
company common equity.
I believe that the Commission should give no weight to Dr.
Vilbert’s results which involve this ATWACC approach. This
methodology has no place in determining the cost of common equity for
regulated utilities and to my knowledge no other regulatory agencies
give it any merit.
Q. PLEASE EXPLAIN THE RISK PREMIUM ANALYSIS
APPROACH OF ESTIMATING THE COST OF COMMON
EQUITY.
A. In general, one can estimate the cost of common equity by
estimating three components and adding them together. The three
components are (1) the risk free rate of return on 30-year U.S.
Treasury Bonds; (2) the historical differential between yields of the
rated utility bonds of the Company and the 30 year U.S. Treasury
Bonds (risk-free rate); and (3) the average return differential of utility
common stocks over utility bonds.
58
Q. PLEASE EXPLAIN YOUR RISK PREMIUM ANALYSIS
RESULTS.
A. Exhibit AG-17 shows the three components required to estimate
the cost of common equity under this approach. The results for this
approach reflect a return on common equity for the peer group of 9.7%.
I estimate the historical spread between Electric Utility Common
Stocks and bonds to be 4.4%. Also, 30 year bonds issued by electric
utility companies in late 2013 were issued at a spread over comparable
U. S. Treasury securities of 1.02% (A rated securities) and 1.57% (BBB
rated securities). For the risk-free rate, I used the projected 4.00% 30-
year Treasury rate discussed under the CAPM section of my testimony.
Q. PLEASE EXPLAIN WHY THE CAPM AND THE RISK
PREMIUM ARE PRODUCING HIGHER COST OF
EQUITY RATES COMPARED TO THE DCF APPROACH?
A. We should keep in mind that the CAPM and Risk Premium
approaches in my exhibits assume a 4.0% risk free rate of return,
which is 1.1% above the current risk free rate of 2.9%. The DCF
approach does not involve any assumptions of the risk-free rate.
Therefore, it is likely that utility stock investors may not anticipate the
higher interest rates assumed in the CAPM and Risk Premium cost of
equity calculations.
Additionally, the U.S. financial markets are experiencing an
extended period of low interest rates and low inflation. The deep
economic recession that began in 2008 has been prolonged by slow
economic growth and slow growth in employment. Although the
upheaval in the financial markets has significantly subsided and
markets have stabilized, the Federal Reserve continues to inject
liquidity into the economy and keep interest rates low. Their concern
appears to be with price deflation instead of inflation and ensuring
that the economy is solidly on the road to recovery before further
altering their course.
In the face of such a long-term scenario of low interest rates,
investors looking for income and higher yield investment opportunities
are investing more funds into safer investments such as utility stocks
that are paying attractive dividends. Therefore, the return
expectations of investors investing in utility stocks have been lowered
given the lower return from alternative investments in interest
bearing accounts and securities. Accordingly, we should not be
surprised to see high single digit cost of equity returns on utility stocks
59
when long-term U. S. Treasury securities yield less than 3% and
inflation is negligible.
Q. HOW HAS THE ECONOMIC AND INTEREST RATE
ENVIRONMENT CHANGED IN RECENT YEARS FOR
THE COMPANY?
A. The Michigan economy has substantially recovered from the
most recent recession and interest rates are stable at lower levels
thanks in part to the monetary policy of the Federal Reserve Bank.
These factors have placed the Company in a better position with
respect to sales levels, interest rates and uncollectible sales amounts.
The Company’s access to the capital markets is strong as witnessed by
its issuance of $950 million of new long-term debt at rates between
3.375% for ten-year debt and 4.60% for 30 year debt.
Accordingly, the Company’s proposed rate of return on common
equity of 10.75% is unsupportable and is largely based on Dr. Vilbert’s
unorthodox ATWACC analysis. The results of my DCF, CAPM and
Risk Premium analysis, together with lower interest rates, a better
Michigan economy and a very favorable regulatory environment all
point to the authorized return on common equity being closer to 9.5%.
Q. PLEASE DISCUSS WHAT RETURN ON EQUITY RATES
OTHER REGULATORY COMMISSIONS HAVE GRANTED
IN THE MOST RECENT 12 MONTHS.
A. Since 1990, return on equity rates approved by regulatory
commissions have been on a steady decline from over 12.7% in 1990 to
less than 10% during 2014 and in certain quarterly periods since 2011.
Exhibit AG-18 shows this historical trend and the more recent
decisions. Although the true cost of equity capital has declined much
more rapidly, regulatory commissions have been slow to embrace lower
rates during this prolonged period of low interest rates and lower cost
of capital environment. In exhibit AG-14, I have shown the equity
rates of return granted to electric utilities by regulatory commission
during the most recent four quarters. The data shows that the
declining trend continues with allowed ROE of 9.66% during the first
quarter of 2015.11
11
This average rate for the first quarter of 2015 includes five companies and exclude Virginia
Electric Power as an unusual outlier situation.
60
Q. PLEASE EXPLAIN YOUR CONCLUSION CONCERNING
THE APPROPRIATE RETURN ON EQUITY RATE THE
COMMISSION SHOULD USE IN THIS CASE.
A. In Exhibit AG-14, I have summarized the cost of equity rates
from the three methods I used. The ranges of returns for the industry
peer group are from 8.44% at the low end, based on the DCF approach,
to 9.70% using the Risk Premium approach.
As explained earlier in my testimony, I give more weight to the
DCF method as a more reliable approach to estimating the cost of
equity. In this regard, on line 4 of Exhibit AG-14, I have calculated a
weighted return on equity of the three methodologies using a 50%
weight for DCF and 25% for each of the other two methods. The result
is a weighted return on equity of 8.92% for the average of the industry
peer group. However, I have rounded this number up to a 9.5% return
on common equity for DTEE’s business in this case for the reasons
explained below.
First, although the industry peer group return is an appropriate
check on the reasonableness of my conclusion, it may not incorporate
the unique risks and circumstances that exist with DTEE and how
investors perceive those risks—in particular, serving a territory that is
highly dependent upon the automotive industry. Second, as mentioned
above, 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
would produce a 0.40% increase in the cost of capital under the DCF
approach.
I understand that the Commission may be reluctant to set an
ROE for the Company at the true cost of equity of 9.5% and perhaps
even below it. As shown in Exhibit AG-14, regulatory commissions
during the past four quarters have granted an average ROE of 9.79%
and trending down to 9.66% in the first quarter of 2015. Therefore, I
recommend an ROE rate of 9.75% in this case, as a gradual transition
to the true cost of equity. [Tr 2339-2354.]
61
In rebuttal, DTE witness Dr. Vilbert attempted to discredit Mr. Coppola’s
analysis by stating that he confused DTE Electric from DTE Energy. (Tr 1509-
1510.) On cross examination, however, Dr. Vilbert could not identify where in Mr.
Coppola’s direct testimony that confusion could be found. (Tr 1551-1560.) Dr.
Vilbert on a number of occasions admitted that it was his interpretation that there
was confusion but nothing directly in the testimony demonstrated that confusion.
(Tr 1551-1560.) Dr. Vilbert also admitted on cross examination that the trend for
return on equity across the country in the past four years has been downward. (Tr
1561.)
In summary, the Attorney General recommends that the Commission set an
ROE rate of 9.75% and an overall return on capital of 5.53% as demonstrated on
Exhibit AG-13.
62
V. Relief Sought
For the reasons stated above, in Mr. Coppola’s direct and rebuttal testimony
and exhibits, and summarized in Exhibit AG-19, The Attorney General recommends
that the Commission adopt the Attorney General’s adjustments and
recommendations and issue an order granting rate relief to the Company in an
amount not exceeding $58 million.
.
Respectfully submitted,
Bill Schuette
Attorney General
Michael E. Moody (P51985)
Assistant Attorney General
Environmental, Natural Resources,
and Agriculture Division
PO Box 30755
Lansing, MI 48909
517-373-7540
Dated: July 28, 2015