STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
*****
In the matter of the application of
DTE Electric Company for authority
to increase its rates, amend its rate
schedules and rules governing the
distribution and supply of electric
energy, and for miscellaneous
accounting authority .
)
)
)
)
)
)
)
Case No. U-17767
NOTICE OF PROPOSAL FOR DECISION
The attached Proposal for Decision is being issued and served on all parties of
record in the above matter on October 8, 2015.
Exceptions, if any, must be filed with the Michigan Public Service Commission,
7109 West Saginaw, Lansing, Michigan 48917, and served on all other parties of record on
or before October 27, 2015, or within such further period as may be authorized for filing
exceptions. If exceptions are filed, replies thereto may be filed on or before November 9,
2015. The Commission has selected this case for participation in its Paperless
Electronic Filings Program. No paper documents will be required to be filed in this
case.
At the expiration of the period for filing exceptions, an Order of the Commission will
be issued in conformity with the attached Proposal for Decision and will become effective
unless exceptions are filed seasonably or unless the Proposal for Decision is reviewed by
action of the Commission. To be seasonably filed, exceptions must reach the Commission
on or before the date they are due.
MICHIGAN ADMINISTRATIVE HEARING
SYSTEM
For the Michigan Public Service Commission
Sharon L.
Feldman
_____________________________________
Digitally signed by Sharon L. Feldman
DN: cn=Sharon L. Feldman, o, ou,
[email protected], c=US
Date: 2015.10.08 14:13:45 -04'00'
Sharon L. Feldman
Administrative Law Judge
October 8, 2015
Lansing, Michigan
STATE OF MICHIGAN
MICHIGAN ADMINISTRATIVE HEARING SYSTEM
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
*****
In the matter of the application of
DTE Electric Company for authority
to increase its rates, amend its rate
schedules and rules governing the
distribution and supply of electric
energy, and for miscellaneous
accounting authority .
)
)
)
)
)
)
)
PROPOSAL FOR DECISION
Issued and Served: October 8, 2015
Case No. U-17767
TABLE OF CONTENTS
Page
I.
History of Proceedings…………………………………………………...
1
II.
Overview of the Record and Positions of the Parties………………..
A.
DTE Electric………………………………………………………..
B.
Staff…………………………………………………………………
C.
Attorney General…………………………………………………..
D.
MEC, NRDC, SC and ELPC……………………………………..
E.
ABATE………………………………………………………………
F.
Municipal Street Lighting Coalition………………………………
G.
Walmart…………………………………………………………….
H.
Kroger……………………………………………………………….
I.
Energy Michigan…………………………………………………...
J.
Detroit Public Schools…………………………………………….
K.
Michigan Cable Telecommunications Association………….….
L.
Residential Customer Group……………………………………..
M.
Mr. Sheldon…………………………………………………………
N.
Mr. Meltzer………………………………………………………….
O.
Overview……………………………………………………………
4
4
8
10
11
12
13
13
14
15
16
16
16
17
17
18
III.
Official Notice Requests………………………………………………….
18
IV.
Test Year………………………………………………………………..…
24
V.
Rate Base………………………………………………………………….
A.
Net Plant……………………………………………………..…….
1. Non-nuclear generation……………………………………….
a. ACI/DSI…………………………………………………….
i. cost and timing of new gas plants………….……
ii. alternatives to new gas fired plant………………
iii. market energy, capacity and commodity costs...
iv. variable O&M costs of ACI/DSI……………….…
v. capital cost recovery…………………………….…
vi. additional capital costs………………………....…
vii. MISO Zone 7 capacity shortfall………………....
viii.recommendation…………………………….….…
b. Other non-nuclear generation adjustments……….……
2. New generating plants………………………………….…..…
3. Nuclear generation (Fermi 2)…………………………………
4. Electric Distribution System…………………………….….…
a. Vegetation Management…………………….………..…
b. Spending levels……………………………………………
5. Corporate Staff Group………………………………...……...
25
25
26
28
45
48
49
52
57
58
59
60
65
73
79
81
81
87
96
Page
6. Customer 360…………………………………………………
7. AMI………………………………………………………….….
8. IAC……………………………………………………………...
9. CWIP…………………………………………………………...
Working Capital…………………………………………………...
1. COLA…………………………………………………………..
2. Non-qualified benefits………………………………………...
3. OPEB…………………………………………………………..
Rate Base Summary…………………………………………..…
102
104
112
113
114
115
122
128
132
VI.
Rate of Return………………………………………………………….....
A.
Capital Structure……………………………………………….....
B.
Debt Cost……………………………………………………….....
C.
Equity Cost (Return on Equity)…………………………….……
1. DTEE……………………………………………………..…….
2. Staff………………………………………………………….....
3. Attorney General…………………………………………..….
4. ABATE………………………………………………………….
5. Walmart………………………………………………………..
6. Rebuttal……………………………………………………..….
a. DTEE……………………………………………………..…
b. ABATE…………………………………………………..….
7. Briefs………………………………………………………..….
8. Discussion……………………………………………………..
a. Sample selection…………………………………….……
b. DCF model and growth rates…………………………….
c. ECAPM and CAPM……………………………….………
d. Market risk premium………………………………….……
e. ATWACC……………………………………………………
f. Riskiness of DTEE compared to proxy companies…….
g. overall recommendation…………………………………..
D.
Overall Rate of Return (Summary)……………………………..
132
134
138
139
139
147
150
152
155
156
156
162
163
164
164
166
168
171
172
185
190
193
VII.
Adjusted Net Operating Income…………………………………………
A.
Sales Forecast and Revenue Projection……………….………
B.
Fuel, Purchase and Interchange Expense………………….….
C.
Operations and Maintenance Expenses…………………….….
1. Inflation…………………………………………………….…..
2. Steam Power Generation…………………………………….
a. Limestone and trona…………………………………..…..
b. Other generation O&M expenses…………………...……
3. East China Plant………………………………………………
4. Nuclear Power Generation……………………………….….
193
194
194
195
195
199
199
200
201
202
B.
C.
Page
5. Electric Distribution…………………………………………...
a. EVMP……………………………………………………....
b. Traditional vegetation management…………………….
c. Other distributions operations expense………………...
6. Pension and Benefits………………………………………....
a. Other Post-Retirement Employee Benefits (OPEB)…...
b. Active employee health care……………………………..
c. Employee Savings Plan…………………………………...
d. Non-qualified benefit plans……………………………..…
e. Incentive Compensation……………………………….….
7. Corporate Staff Group……………………………….……..…
8. Uncollectibles Expense……………………………………….
9. Injuries and Damages………………………………………..
10. Competitive Affordable Rates Strategy (CARS)…………..
Depreciation and Amortization Expense……………………….
1. COLA…………………………………………………………..
2. AMI……………………………………………………………..
3. Detroit Corporate Tax………………………………………...
4. Plug-in Electric Vehicle……………………………………….
Allowance for Funds Used During Construction……………....
General Taxes…………………………………………………….
Income Taxes……………………………………………………..
Adjusted Net Operating Income Summary…………………….
203
204
209
212
214
214
215
216
217
217
229
230
233
234
238
238
239
239
241
241
241
241
242
Other Revenue Related Issues……………………………………….…
A.
Nuclear Surcharge………………………………………………..
B.
AMI tariff and charges………………………………………….…
1. History………………………………………………………….
2. Opt-out program……………………………………………....
a. Commission authority…………………………………….
b. Notice and due process issues………………………....
c. Privacy Concerns………………………………………...
d. Health………………………………………………………
e. Commercial customers……………………………...……
3. Opt-out fees………………………………………………..….
4. Access tariff………………………………………………..….
Revenue Deficiency Summary……………………………………….....
242
242
244
244
249
259
260
262
265
270
270
275
275
Cost of Service…………………………………………………………....
A.
Production Cost Allocation……………………………………….
B.
Uncollectible Expense Allocation………………………………..
276
276
277
D.
E.
F.
G.
H.
VIII.
IX.
X.
Page
XI.
Rate Design and Tariff Issues…………………….……………………..
A.
General Issues…………………………………………………....
1. Customer charges………………………………………….....
2. Peak pricing and time-of use rates……………………….....
B.
Rate D11 rate design……………………………………………..
C.
Rider 10………………………………………………………...….
D.
Rider 3…………………………………………………………..…
E.
Experimental Load Aggregation Provision (ELAP)…………...
F.
Rate D8…………………………………………………………....
G.
Line Extension Allowances…………………………………..….
H.
Municipal Lighting……………………………………………...…
I.
Residential and Commercial Distribution charges………..…..
J.
Low Income residential tariffs………………………………...…
K.
Senior Citizen provisions…………………………………………
L.
Residential Time of Day……………………………………..…..
M.
Rate D1.8……………………………………………………….....
N
Standard Contract Rider 16 (Net Metering)………………...….
O.
Rates D2, D1, D1.3, D1.4, D1.5…………………………….…..
P.
Undisputed Items…………………………………………………
1. Rate D3.1………………………………………………….…..
2. Rates E15.1, E15.3, E1.5 and E17……………………….…
3. D5 Water Heating Service……………………………………
4. Rate D1.7……………………………………………………...
5. VHWF credit……………………………………………….…..
6. Rates E15.1, E15.3, E1.5, D17………………………….…..
279
280
280
291
293
295
298
300
302
303
304
316
318
320
322
324
324
325
326
326
326
326
327
327
327
XII.
Miscellaneous Issues………………………………………………….…
A.
Accounting Issues……………………………………………...…
B.
Reporting Issues………………………………………………….
C.
Workgroup…………………………………………………………
D.
AMI cost-benefit analysis………………………………………...
327
327
328
329
329
XIII.
Conclusion…………………………………………………………………
330
Attachments ………………………………………………………………….….Appendix
A
Attachments …………………………………………………….……………….Appendix
B
Attachments ……………………………………………………………………..Appendix
C
STATE OF MICHIGAN
MICHIGAN ADMINISTRATIVE HEARING SYSTEM
FOR THE MICHIGAN PUBLIC SERVICE COMMISSION
*****
In the matter of the application of
DTE Electric Company for authority
to increase its rates, amend its rate
schedules and rules governing the
distribution and supply of electric
energy, and for miscellaneous
accounting authority .
)
)
)
)
)
)
)
Case No. U-17767
PROPOSAL FOR DECISION
I.
HISTORY OF PROCEEDINGS
On December 19, 2014, DTE Electric Company (DTEE) filed a rate application
requesting a $370 million revenue increase, and other relief. The rates requested in the
application are based on a July 1, 2015 through June 30, 2016 projected test year. The
most recent rate case orders for DTEE were issued by the Commission on October 20
2011 and December 20, 2011, in Case No. U-16472 (2011 Orders), with cost allocation
and rate design subsequently addressed in the Commission’s June 15, 2015 and June
30, 2015 orders in Case No. U-17689.
Staff, DTEE, and potential intervenors attended the January 29, 2015 prehearing
conference. Intervention was granted to Attorney General Bill Schuette (Attorney
General); the Michigan Cable Telecommunications Association (MCTA); the Association
of Businesses Advocating Tariff Equity (ABATE); the Municipal Coalition (now the
Michigan Street Lighting Coalition or MSLC);1 the Michigan Environmental Council
(MEC); the Natural Resources Defense Council (NRDC); the Sierra Club (SC); Energy
Michigan; the Michigan Agri-Business Association (MABA); Local 223, Utility Workers
Union of America, AFL-CIO (UWUA); the Kroger Company (Kroger); Detroit Public
Schools (DPS); Wal-Mart Stores East, LP and Sam’s East, Inc. (Walmart); a group of
residential customers referred to as the DTE Residential Customer Group (RCG); and
individual residential customers Dan Mazurek, Richard Meltzer, David Sheldon, and
Paul F. Wilk. The parties agreed to a schedule meeting the time limits of MCL 460.6a.
Also at the prehearing conference, as reflected in the transcript, several people made
comments under former Rule 207, now Rule 413, of the Commission’s rules of practice
and procedure, R 792.10413.
Following the prehearing conference, a motion hearing was held on April 10,
2015, to address DTEE’s motion for a protective order. In accordance with the ruling on
the motion, a protective order was issued on April 10, 2015. Rulings were also issued in
numerous uncontested motions without the need for hearing, as reflected in the docket.
In a May 20, 2015 ruling, the Environmental Law & Policy Center (ELPC) was granted
late intervention based on its uncontested April 28, 2015 motion. On May 29, 2015,
DTEE filed the testimony and exhibits of Don M. Stanczak, Vice President, Regulatory
Affairs for DTEE, explaining the company’s plans to self-implement a revenue increase
of $230 million effective July 1, 2015. At the June 2, 2015 hearing on this selfimplementation filing, Mr. Stanczak’s testimony was bound into the record without any
1
As set forth in its March 2, 2015 motion, the Municipal Coalition subsequently changed its name to the
Municipal Street Lighting Coalition.
U-17767
Page 2
cross-examination, and his supporting Exhibits A-22 and A-23 were admitted into
evidence.2 Subsequently, on June 19, 2015, following the Commission’s June 15, 2015
order in Case No. U-17689, DTEE filed revised versions of Exhibits A-22 and A-23.3
In accordance with the schedule established at the January 29, 2015 prehearing
conference, Staff and intervenors filed testimony on May 22, 2015, and DTEE, Staff and
intervenors filed rebuttal testimony on June 15, 2015. At the evidentiary hearings held
on seven days between June 24 and July 6, 2015, 53 witnesses appeared for crossexamination or had their testimony bound into the record by agreement of the parties.
The parties filed briefs and reply briefs on July 28, 2015 and August 12, 2015, in
accordance with the established schedule. The following parties filed briefs: DTEE,
Staff, ABATE, the Attorney General, Energy Michigan, Kroger, Walmart, the Michigan
Cable Telecommunications Association, the Municipal Street Lighting Coalition, M/N/S,
the Environmental Law and Policy Center, the Detroit Public Schools, the Residential
Customer Group, Mr. Sheldon, and Mr. Meltzer. The following parties filed reply briefs:
DTEE, Staff, ABATE, the Attorney General, Kroger, the Municipal Street Lighting
Coalition, M/N/S, the Environmental Law and Policy Center, the Residential Customer
Group, and Mr. Meltzer.
An overview of the record and the positions of the parties is presented below.
2
See 3 Tr 102-118.
These revised exhibits are not part of the evidentiary record in this case, but were filed for the
Commission’s information regarding self-implementation.
3
U-17767
Page 3
II.
OVERVIEW OF THE RECORD AND POSITIONS OF THE PARTIES
The evidentiary record in this proceeding is contained in 2596 pages of transcript
in 10 volumes, and 231 exhibits admitted into evidence. Additionally, official notice was
taken of Staff’s report in Case No. U-17000, and DTEE’s tariffs, which are available
electronically on the Commission’s website. On July 30, 2015, Staff also filed a request
that official notice be taken of two additional documents, which this PFD declines to do
for the reasons discussed in section III below.
A.
DTE Electric
DTEE reduced its requested revenue increase from the $370 million initially filed
to $349 million in its brief. The utility’s rate request is based on a jurisdictional rate base
of approximately $13.5 billion, a return on equity of 10.75% with an overall cost of
capital of 5.87%, and an adjusted net operating income of $582 million. Mr. Stanczak
testified that the key factors contributing to the revenue deficiency include increased
investments in net plant, working capital, and associated depreciation and property tax
increases, plus a minor increase in Operations and Maintenance (O&M) expense. He
testified that routine capital expenditures, electric reliability improvement projects,
environmental compliance and the acquisition of two new power plants are the causes
of the rate base increase. DTEE presented a cost of service study and proposed
numerous rate design and tariff changes. The company is also seeking future
ratemaking treatment for various categories of expenses, other accounting approvals,
and various tariff changes.
U-17767
Page 4
DTEE presented the testimony of 23 witnesses, and 36 exhibits. Mr. Stanczak
presented an overview of the company’s filing, including a summary of the testimony
accompanying the filing. Margaret Suchta, Principal Financial Analyst in the Regulatory
Affairs Organization of DTE Energy Corporate Services, LLC, presented the revenue
requirements calculation supporting DTEE’s filed revenue deficiency, shown in Exhibit
A-8, Schedule A1, with a rate base of $13.6 billion, adjusted net operating income of
$584.1 million, and an overall rate of return of 5.96%. She also presented required
historical schedules, and she identified the major components of DTEE’s rate request
both in comparison to the rates approved in Case No. U-16472, and in comparison to
the historical 2013 test year revenue sufficiency. Her Exhibit A-10. Schedule C2 shows
the calculation of the revenue conversion factor of 1.6393. Russel J. Pogats, Director of
Electrical Engineering in Distribution Operations for DTEE, testified regarding
distribution system capital and operating expense requirements, reviewing reliability
metrics for DTEE, its vegetation management plans, and other changes forecast for the
2015/2016 test year. Franklin D. Warren, Vice President in charge of Fossil Generation
for DTEE and Irene M. Dimitry, Vice President in charge of Business Planning and
Development for DTE Energy Corporate Services, LLC, testified regarding the
company’s fossil generation system capital and operating expense requirements,
including planned generating plant acquisitions and environmental compliance plans, as
well as routine expenditures. Ms. Dimitry also testified regarding DTEE’s request to
recover the licensing costs for a potential Fermi 3 nuclear power plant over a 20-year
period. Wayne A. Colonnello, Director of Nuclear Support for DTEE, presented
testimony addressing the company’s capital and operating expense requirements
U-17767
Page 5
associated with Fermi 2, and proposed changes in the current nuclear surcharge. Ryan
R. Schoen, Fuel Resource Specialist in the Corporate Fuel Supply Department for
DTEE, testified regarding DTEE’s projected fuel supply capital and operating expenses,
including MERC expenses. Theresa Uzenksi, Manager of Regulatory Accounting for
DTE Energy Corporate Services, LLC, testified to present 2013 historical balance sheet
and net operating income statements with normalizing adjustments. She also explained
proposed
accounting
changes,
including
changes
in
capitalization,
proposed
amortizations and deferred accounting. Her Exhibit A-10, Schedule C1, presents
DTEE’s filed forecast adjusted net operating income of $584.1 million, based on the
testimony of several witnesses. Ms. Uzenski also testified specifically regarding capital
and operating expense requirements for the Corporate Services Group programs,
including software expenditures and corporate office expenditures. Jeffrey C. Wuepper,
Director of Compensation and Benefits for DTE Energy Corporate Services, LLC,
testified regarding employee compensation, including health care costs and other
employee benefits, as well as incentive compensation plans and associated costs
DTEE is proposing to include in rates. Mr. Wuepper also testified regarding retiree
benefits, including pension expense and other post-employment benefits. Robert E.
Sitkauskas, General Manager of the Advanced Metering Infrastructure Group in the
Major Enterprise Projects Organization of DTEE, testified to describe DTEE’s Advanced
Metering Infrastructure (AMI) progress and plans, and to support projected capital and
operating expense. Renee M. Tomina, Director of Revenue Management and
Protection for DTEE, testified to support requested capital and operating expenditures
for customer service operations within DTE, including customer service, billing, and
U-17767
Page 6
collection expense, the company’s low income initiatives, and the choice program.
Kenneth R. Bridge, Director of the Program Management Office for DTEE, testified
regarding DTEE’s Customer 360 project, including projected capital and operating
expenses. Mary Lewis, Director of Tax Operations and Assistant Tax Officer for DTE
Energy Corporate Services, LLC testified to present DTEE’s historical and projected
federal, state, and municipal income tax, property tax, and other tax expenditures. She
also explained the calculation for payroll taxes, and presented DTEE’s request for
normalization of the difference in deferred tax balances arising from the change in the
City of Detroit’s corporate tax rate. Edward J. Solomon, Vice President and Treasurer,
testified regarding DTEE’s capital structure and debt costs; Dr. Michael J. Vilbert,
Principal with The Brattle Group, testified to explain and support DTEE’s requested
return on equity of 10.75%. Markus B. Lueker, Manager of Corporate Energy
Forecasting for DTEE, provided historical and forecast sales and system output.
Clifford Grimm, Martin L. Heiser, Michael Williams, Kelly A. Holmes, and Timothy A.
Bloch testified regarding cost of service allocations, rate design, and proposed tariff
changes.
Mr. Stanczak, Mr. Colonnello, Mr. Warren, Mr. Pogats, Mr. Sitkauskas, Ms.
Dimitry, Mr. Wuepper, Dr. Vilbert, Mr. Solomon, Ms. Uzenski, Mr. Heiser, Ms. Holmes,
Mr. Williams, and Mr. Bloch also presented rebuttal testimony, along with Barry J.
Marietta and Kenneth D. Johnston, responding to the recommendations of Staff and
intervenors. Witnesses Stanczak, Warren, Marietta, Pogats, Dimitry, Sitkauskas, Heiser,
Holmes, Uzenski, Williams, Colonnello, Wuepper, Lewis, Vilbert, and Solomon were
U-17767
Page 7
cross-examined on their testimony, while the testimony of the remaining witnesses was
bound into the record without the need for them to appear.
B.
Staff
Staff’s filing recommended a revenue deficiency of $173.9 million, based on a
projected test year rate base of $13.457 billion, a return on equity of 10%, and adjusted
net operating income of $645 million as shown in Exhibit S-1, Schedule A1. Staff also
presented a cost of service study and rate design recommendations. Staff’s briefs
recommend additional adjustments to the revenue deficiency calculation.
Staff
presented the testimony of 16 Staff members, and 28 exhibits.
Brian A. Welke, Auditor with the MPSC Auditor in the Financial Analysis and
Audit Division of the MPSC, was principally responsible for presenting Staff’s revenue
requirement calculations, relying on testimony from several other Staff witnesses for
various components. Mr. Welke testified regarding certain employee compensation
components, projected injuries and damages and uncollectible expense, and DTEE’s
CARS program. Mr. Welke and Kevin S. Krause, Auditor in the Electric Reliability
Division of the MPSC, testified regarding DTEE’s request to recover costs of obtaining a
license for a Fermi 3 nuclear plant. Kavita Bankapur, Auditor in the Financial Analysis
and Audit Division of the MPSC, presented testimony regarding the elements of the rate
base calculation, including utility plant, accumulated provision for depreciation, and
working capital, as well as CWIP and depreciation and amortization expense amounts.
Naomi Simpson, Public Utilities Engineer in the Electric Reliability Division of the MPSC,
testified to present Staff’s recommendations regarding DTEE’s proposed environmental
capital and operating expenditures for its generating plants, presenting Exhibits S-8.1
U-17767
Page 8
through S-8.7. Lisa Kindschy, Public Utility Engineering Specialist in the Regulated
Energy Division of the MPSC, also testified regarding the limestone and trona
component of DTEE’s proposed environmental spending, addressing DTEE’s request to
have those expenses included in PSCR costs. Peter J. Derkos, Public Utility Engineer
Specialist in the Operations and Wholesale Marketing Division of the MPSC, testified to
present
Staff’s
proposed
distribution
system
capital
and
operating
expense
recommendations, including Staff’s recommendation that DTEE not capitalize expenses
associated
with
its
enhanced
vegetation
management
program,
and
Staff’s
recommendation that projected expenditures for this program be reduced. Patrick L.
Hudson, Manager of the Smart Grid Section of the MPSC’s Electric Reliability Division,
and Cody Matthews, Public Utilities Engineer in the same section, testified regarding the
AMI/Smart Grid plans and costs. Yerva C. Talbert, Auditor in the Financial Analysis and
Audit Division of the MPSC, testified regarding Staff’s recommended adjustment to
property tax expense related to DTEE’s acquisition of the Renaissance Plant.
Harshleen Sandhu, Financial Analysis in the Financial Analysis and Audit Division of the
MPSC, testified regarding the appropriate capital structure and cost of capital elements,
including Staff’s recommended return on equity, as well as Staff’s recommended
inflation rates. She also testified that Staff supports DTEE’s proposed revisions to its
nuclear decommissioning surcharge. Julie Baldwin, Manager of the Renewable Energy
Section of the MPSC’s Electric Reliability Division, recommended revisions to DTEE’s
net metering tariff and recommended that the Commission establish a workgroup. Brian
J. Sheldon, Departmental Analyst in the Operations and Wholesale Markets Division of
the MPSC, presented recommendations regarding cyber security, including Staff’s
U-17767
Page 9
request for reporting by DTEE, also presented Exhibit S-11 on this topic. Staff’s cost of
service study, summarized in Schedule F1 of Exhibit S-6, was presented by Charles E.
Putnam, Departmental Analyst in the Regulated Energy Division of the MPSC, while
David W. Isakson, Deanne B. Rivera, Departmental Analysts in the Regulated Energy
Division, and Nicholas M. Revere, Manager of the Rates and Tariffs Section of MPSC’s
Regulated Energy Division, presented testimony on rate design, tariff, and rule changes.
Mr. Isakson, Mr. Revere, Ms. Simpson, and Mr. Hudson also presented rebuttal
testimony. Mr. Matthews and Mr. Hudson were cross examined on their testimony, while
the testimony of the remaining Staff witnesses was bound into the record without the
need for them to appear.
C.
Attorney General
The Attorney General presented the testimony of Sebastian Coppola,
independent consultant and President of Corporate Analytics, Inc., and 20 exhibits.
Based on Mr. Coppola’s analysis, the Attorney General recommends a revenue
deficiency of $58 million, reflecting a recommended reduction of $273.2 million in
DTEE’s capital expense projections in the categories of fossil and nuclear generation,
distribution operations, and corporate services, and reflecting a reduction of $203.4
million in O&M expense projections in the categories of fossil and nuclear generation,
distribution operations, uncollectible expense, corporate services, and employee
compensation and retirement benefits. He further recommends that the rate of return be
based on DTEE’s historical test year (2013) average capital structure of 52% debt and
48% equity, with an authorized return on equity of 9.75%. Mr. Coppola also made
U-17767
Page 10
recommendations regarding the treatment of AMI costs, accounting treatment
requested by DTEE, and the residential monthly customer charge.
In his briefs, the Attorney General also adopts certain recommendations made by
Staff and by the Municipal Street Lighting Coalition, in particular recommended that
expense projections for contingencies be rejected, that the monthly residential customer
charge be limited to its current $6.00 level, and that the Commission initiate a
collaborative to consider rate design for street lighting.
D.
MEC, NRDC, SC and ELPC
MEC, NRDC, and SC (M/N/S) jointly presented the testimony of four witnesses,
all independent consultants. George Evans, President of Evans Power Consulting; Paul
Chernick, President of Resource Insight, Inc., and Dr. Ranajit Sahu each testified
regarding DTEE’s request to recover the capital and O&M costs of retrofitting several of
its plants with DSI and ACI technology to meet environmental requirements, concluding
that DTEE had not supported its request to recover these expenses. M/N/S together
with ELPC presented the testimony of Karl R. Rábago, principal and owner of Rábago
Energy LLC, raising concerns with the use of fixed monthly charges in rate design.
MEC and NRDC jointly presented the testimony of Douglas B. Jester, Principal of 5
Lakes Energy LLC, addressing cost allocation and rate design issues, recommending
expanded use of dynamic pricing incorporating certain economic principles, and
providing an analysis of the use of fixed charges in rate design. M/N/S and ELPC do
not present a revenue requirements calculation, but do make specific recommendations
regarding projected capital and O&M expenditures in the generation and distribution
categories, and regarding rate design.
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E.
ABATE
ABATE presented the testimony of James T. Selecky, Managing Principal of
Brubaker & Associates, Inc., and Christopher C. Walters, a consultant with the same
firm, along with 11 exhibits. Mr. Selecky testified regarding cost of service allocation and
rate design issues, recommending that the Commission adopt a 4-coincident-peak
demand allocator for production costs, with an alternative recommendation if the
Commission incorporates an energy weighting, and a 12-coincident-peak allocator for
transmission costs, with additional recommendations regarding rate design including the
voltage level discounts for Rate D11, the charges for Rider R10 and Rider R3, and the
nuclear decommissioning surcharge. Mr. Walters testified to recommend that the
Commission authorize a rate of return on equity not greater than 9.5%. He reviewed
and critiqued Dr. Vilbert’s analysis for DTEE, including disputing his use of certain
modeling adjustments, and discussed the risks facing DTEE. Both Mr. Selecky and Mr.
Walters presented rebuttal testimony. In addition to subjects addressed in his initial
testimony, Mr. Selecky addressed the interruptible Rate D10, while Mr. Walters
addressed the rate of return on equity. Their testimony was bound into the record
without the need for them to appear.
In its briefs, regarding the revenue requirement, ABATE argues that DTEE’s and
Staff’s recommendations regarding the cost of equity are excessive and should be
rejected. Regarding rate design, ABATE argues that the voltage level discounts in Rate
D11 should be increased, with different demand and energy charges for each voltage
level, and opposes the Rate R10 administrative charge proposed by DTEE, as well as
its proposal to eliminate the market power supply option under Rider R3. ABATE also
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endorses Staff’s proposal to create a work group to review cost of service and rate
design issues.
F.
Municipal Street Lighting Coalition
The MSLC presented the testimony of Douglas B. Jester and Nathan Geisler,
and 27 exhibits. Mr. Jester’s testimony addressed DTEE’s current and proposed rate
design for street lighting, testifying that DTEE’s contribution-in-aid-of-construction
requirements and light replacement policies are not cost based and retard the use of
energy efficient lighting. Mr. Geisler’s testimony addressed Ann Arbor’s experiences
using LED lights, including a discussion of the benefits of the lighting and the costs it
faces as a customer of DTEE. Mr. Jester’s and Mr. Geisler’s testimony was bound into
the record without the need for them to appear.
In its briefs, the MSLC asks the Commission to reject DTEE’s proposed rate
design for the lighting tariffs, recommending that the Commission establish a
collaborative to work out better rate design. In the alternative, MSLC presents specific
modifications to the proposed rate design, including contributions in aid of construction,
with a further proposal to protect customers who have already paid such contributions,
with lamp and energy charges that effectively retain the current lamp charges, and
MSLC calls for a Staff audit of DTEE’s administration of its current tariffs.
G.
Walmart
Walmart presented the testimony of Steve W. Chriss and 4 exhibits. Mr. Chriss
testified to the need for rates to be kept at an affordable level. He identified as areas of
particular concern the rate of return on equity and the eligibility of CWIP expenses for
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rate base treatment, and presented information regarding rates of return authorized by
other commissions. Regarding cost of service allocations and rate design, he testified
that Walmart does not object to DTEE’s proposed cost of service model or the proposed
rate design of Rate D11. Mr. Chriss’s testimony was bound into the record without the
need for him to appear. In its brief, Walmart raises the concerns identified by Mr. Chriss,
and takes issue with Mr. Selecky’s proposal to set separate demand and energy
charges for each voltage level.
H.
Kroger
Kroger presented the testimony of its consultant, Neil Townsend, Principal at
Energy Strategies, LLC, and 4 exhibits. Mr. Townsend testified to address two revenue
requirement issues: the recognition of the impact of bonus tax depreciation on DTEE’s
revenue requirement, and DTEE’s use of an inflation factor in projecting test year nonlabor O&M expenses. Mr. Townsend also testified regarding cost of service and rate
design issues. He testified that he generally supports the utility’s cost of service
allocations, but objected to its classification of customer-related costs for the purpose of
establishing monthly fixed charges, presenting a revised calculation. Mr. Townsend
recommended elimination of the distribution charges for Rate D11, but he testified that
he opposes the elimination of the Experimental Load Aggregation Provision (ELAP). Mr.
Townsend also presented rebuttal testimony objecting to Mr. Jester’s recommendations
on behalf of MEC/NRDC that would explicitly incorporate the cost of new entry in setting
the cost of capacity. His testimony was bound into the record without the need for him
to appear.
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In its briefs, Kroger argues that DTEE’s revenue requirement should reflect the
extension of the bonus tax depreciation, endorses the Commission’s decision in Case
No. U-17689 to resolve cost of service issues, and opposes DTEE’s proposals to
increase the monthly customer charges and to eliminate the ELAP. Kroger also argues
that the Commission should reject Mr. Jester’s recommendations regarding capacity
cost allocation.
I.
Energy Michigan
Energy Michigan presented the testimony of independent consultant Alexander J.
Zakem, whose office is in Plymouth Michigan, and 4 exhibits. Mr. Zakem testified to
identify and explain DTEE proposals affecting choice customers. He testified that DTEE
should not be permitted to recover the costs associated with certain incentive
compensation programs. Responding to DTEE testimony regarding the ability to
procure capacity for customers returning from choice to full service, he took issue with
DTEE’s assertion that there will be a shortfall of capacity in the MISO region, and with
its estimates of capacity prices.
He explained his objection to DTEE’s proposed
allocation of production plant. He also explained his objections to DTEE’s allocation of
uncollectible expenses, proposing an alternative separating uncollectible expenses into
power supply and distribution components. Turning to rate design, he raised concerns
with the rate design for Rate D11, and the interruptible Rate D8. And he objected to
DTEE’s proposed changes to its line extension allowance.
In its brief, Energy Michigan proposes that any incentive compensation program
approved by the Commission be revised to reflect costs and benefits to customers,
proposes the revised allocation of uncollectible expense recommended by Mr. Zakem,
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and also addresses the line extension allowance and Rate D8 interruptible rate in
accordance with Mr. Zakem’s recommendations.
J.
Detroit Public Schools
The Detroit Public Schools argue that they are currently being overcharged for
electric service under DTEE’s Rate D3.2, noting that under both DTEE and Staff
proposals, Rate D3.2 should be reduced. In the event the Commission approves a
revenue deficiency less than DTEE’s self-implemented amount, they also seek a refund
a provided by law.
K.
Michigan Cable Telecommunications Association
The MCTA did not present a witness, but it did present an exhibit. In its brief,
MCTA argues that DTEE’s calculation of the revenue deficiency of its unmetered
service rate, Rate D3.1 should be based on current data rather than data from DTEE’s
previous rate case. MCTA indicates that DTEE has acknowledged this, and also that
Staff relied on more current data in its calculations, but emphasizes its position that the
8.2% rate increase calculated using the stale data should be rejected.
L.
Residential Customer Group
The RCG presented the testimony of Geoffrey C. Crandall and 13 exhibits. Mr.
Crandall testified regarding the rate and tariff provisions applicable to customers
seeking to opt out of the AMI smart meters, recommending an opt-in rather than an optout tariff, with no additional charges, and recommending that the Commission prevent
DTEE from cutting off service to customers without an opportunity for a hearing. In its
briefs, the RCG reviews discovery responses and cross-examination responses to
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support its arguments, asserting that the Commission lacks authority to approve the optout program or set opt-out fees, citing the Fourth and Fourteenth Amendments of the
U.S. Constitution as well as the Michigan Constitution. The RCG also objects to DTEE’s
proposal to amortize deferred taxes of $12.7 million attributable to the City of Detroit’s
increase in the municipal tax rate.
M.
Mr. Sheldon
Mr. Sheldon presented the testimony of Dr. David O. Carpenter, who discussed
the research regarding the health risks of AMI meters and electromagnetic fields
generally. Dr. Carpenter advocated for the use of a precautionary principle in which
technology is not allowed until it has been proven to be safe. He also testified regarding
differences between industry-funded and non-industry-funded research, and he
presented 2 exhibits. Dr. Carpenter was also cross-examined on his testimony.
In his brief, Mr. Sheldon argues that the AMI program costs are not reasonable
and prudent expenses and should be excluded from rate base and from the revenue
requirements calculation. In the alternative, he urges the Commission should condition
its continued approval of AMI costs on the utility’s willingness to develop an opt-out
program that is acceptable to customers who are concerned with health or privacy
issues.
N.
Mr. Meltzer
Mr. Meltzer did not present a witness, although he participated in the hearings.
In his briefs, he asks that customers choosing to opt-out of the AMI program be allowed
to retain their analog meter and that DTEE not be allowed to shut off service to
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customers based on a smart meter dispute. He argues that medical and biological
research and the precautionary principle justify customers’ decisions to reject
installation of the AMI meter, further objecting to the lack of information available. He
also argues that customers should be allowed to self-report their meter readings,
subject to audit, to negate the meter reading expense.
O.
Overview
The positions of the parties are discussed in greater detail below. After Staff’s
Official Notice Requests are discussed in Section III, Section IV addresses the choice of
test year to be used in setting rates. Section V addresses the rate base, including the
appropriate net plant and working capital amounts. Section VI addresses the rate of
return, including the appropriate capital structure to use in setting rates and the
individual cost elements to use in determining the overall cost of capital. Section VII
addresses the test year adjusted net operating income. Section VIII discusses other
revenue requirements-related issues. Section IX summarizes the revenue requirement
analysis. Section X addresses the cost of service studies and cost allocation issues
raised by the parties. Section XI addresses rate design.
The testimony of each of the witnesses is discussed in more detail below, in
conjunction with the positions of the parties.
III.
OFFICIAL NOTICE REQUESTS
Staff’s July 30, 2015 Request to Take Official Notice asked that notice be taken
of two unrelated documents. The first document is a press release by Fitch Ratings
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dated June 9, 2015, generally addressing a recent DTE Energy debt issuance and
containing approximately 5 pages of discussion of the bases for its evaluation. Staff
argues that the press release is relevant because it demonstrates that Staff’s
recommended return on equity is reasonable. Citing R 792.10428, Staff argues that this
is the type of information the Commission commonly relies on when approving ROE’s
for utilities and when setting other rates, like depreciation rates. Staff cites, for example,
the Commission’s June 7, 2012 order in a Consumers Energy rate case, Case No.
U-16794, and its March 18, 2010 order in a Michigan Consolidated Gas Company
depreciation case, Case No. U-15699, to show that the Commission has relied on Fitch
ratings before. On this basis, Staff argues that the document constitutes technical
information within the agency’s specialized knowledge.
Staff further indicates in its motion that while it learned of the press release
shortly after its release, it believed that the information was not public and could not be
disclosed without Fitch’s permission. On this basis, Staff did not seek to introduce the
document during the hearings in this case. Staff acknowledges that this document is
“arguably hearsay,” but argues it falls within an exception in MRE 803(17) as a market
report or commercial publication.
Further, Staff argues it is reasonable for the
Commission to rely on this document under R 792.10427.
In response to Staff’s request, in its reply brief, DTEE argues that it is not proper
to take official notice of this document.4 DTEE argues that the reference in the Fitch
document to a 10% ROE is not a statement of fact that should be judicially noticed.
Instead, DTEE argues, the Fitch ratings are opinions, not facts, “and therefore cannot
be described as being accurate or inaccurate,” citing cautionary information on Fitch’s
4
See DTEE reply brief pages 18-22.
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webpage. DTEE argues that official notice should be limited only to facts, and further
argues that the Fitch press release does not qualify as an exemption to the hearsay
rule. Regarding the hearsay exception cited by Staff, DTEE cites a treatise on the
Michigan Rules of Evidence:
The rule has an easy application to such compilations as stock exchange
price listings, bond prices and treasury bill prices. Application of the rule is
somewhat more problematic when the source in question is a publication
such as an investor’s newsletter disseminated by a private service to a
select group of persons, or other publications where there may be a
pecuniary interest in promulgating data that does not have the reliability of
generally published data. In less clear cases, the court should evaluate
the publication in light of the requirement that the material be, in fact,
‘generally used and relied upon.’ James K. Robinson et al., Michigan
Court Rules of Practice: Evidence § 803.17 (2d ed 2002).5
DTEE also cites Morales v State Farm Mut Auto Ins Co, 279 Mich App 720, 735; 761
NW2d 454 (2008).
In its reply brief, ABATE also opposes Staff’s request.6 ABATE takes issue with
Staff’s explanation for not raising this issue earlier, arguing that Staff did not explain why
it could not make arrangements to include a document it believed to be confidential in
the confidential portion of the record. Indicating its belief that the document contains
hearsay, ABATE also argues that the report does not contain fact, citing the same
disclaimers on Fitch’s webpage also identified by DTEE. Further, ABATE argues that
the press release does not contain Fitch’s actual analysis, but is merely a summary of
the analysis, “lack[ing] a full picture reflecting the analysis allegedly performed, including
models, financial statements or other reports.”7
5
See DTE reply brief, page 21.
See ABATE reply brief, pages 11-14.
7
See ABATE reply brief, page 13.
6
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The RCG also opposes Staff’s request, objecting that no witness sponsored the
Fitch document and “no witness filed an affidavit to attest or explain its relevance or
significance.” The RCG also argued that the report is from only one rating agency and is
presented after the close of the record, further arguing that it adds nothing to the record
that justifies the grant of an extraordinary request.8
The second document Staff seeks official notice for is a report by the staff of the
Texas Public Utilities Commission addressing low-level radio frequency. Staff cites the
Commission’s June 7, 2012 order in Wisconsin Electric Power Company’s rate case,
Case No. U-16830, to show that the Commission has taken official notice of information
prepared for other state commissions before. In support of its motion, Staff states: “The
Texas Public Utility Commission Staff issued its report well before the record was
closed in this case. Unfortunately, there were no witnesses in the case with personal
knowledge of the report that could sponsor it as an exhibit.” Staff further cites MRE 602:
“A witness may not testify to a matter unless evidence is introduced sufficient to support
a finding that the witness has personal knowledge of the matter.”9 Staff indicates this
document is “arguably hearsay,” but argues it falls within an exception in MRE 803(17)
as a public report. Further, Staff argues it is reasonable for the Commission to rely on
this document under R 792.10427.
The RCG opposes Staff’s request, and in the alternative “requests . . . that the
ALJ and Commission take official notice of RCG’s rebuttal documents, attached hereto
as Appendix A and B, and . . . schedule contested case hearings regarding the health,
8
9
See RCG reply brief, pages 24-25.
See Staff’s Request, page 4.
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safety, and privacy issues associated with the AMI/Smart Meter program.”10 The RCG
characterizes the request as “even more egregious” than the Fitch request, arguing that
it is “intolerably late” given that Staff knew about the report and did not provide the other
parties an opportunity to rebut the report. RCG also argues that the document is
hearsay, is not “evidence of a type commonly relied upon by reasonably prudent
persons in the conduct of their affairs,” and does not meet the standards for scientific
evidence established in Daubert v Merrell Dow Pharmaceuticals, 509 US 579 (1993).11
Mr. Meltzer also objects to official notice of the Texas report, noting that it existed
well before the record closed in this case, characterizing it as “essentially a rehash” of
the MPSC report issued in Case No. U-17000, and not more than a literature review.12
This PFD finds that both requests to take official notice should be denied.
Fundamentally, the ALJ recognizes that the time limit on rate cases contained in
MCL 460.6a limits the ability to consider late-filed evidence. Neither of these proffered
documents contains mere updates of market prices or published indices, which the
Commission routinely considers at the time of its final decision, and which are
particularly appropriate for official notice. As is clear from the responses in opposition to
the request, each of these documents contains material that the some of the parties
believe they should have had the opportunity to address.
The Fitch report is the sort of document that the Commission would ordinarily
consider along with other credit rating agency reports regarding DTE Energy and DTE
Electric in a rate case, and the Commission itself has been asked to consider credit
10
See RCG reply brief, page 24.
See RCG reply brief, page 25.
12
See Meltzer reply brief, pages 2-3.
11
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agency reports issued after the close of a rate case record.13 Recognizing that the
opinions of recognized rating agencies have independent significance regarding how
risks are viewed in the marketplace without regard to the particulars of their analysis, it
is also true that the various analysts generally have the opportunity to comment on or
put in perspective these reports, just as a dispute has arisen in this case regarding the
significance to attach to credit ratings. On this basis, since it is not possible to reopen
the record in this case, this PFD denies the request to take official notice of the Fitch
report.
The Texas staff report may also be the sort of document that the Commission
would consider in evaluating the appropriate regulatory policies to adopt for Advanced
Metering Infrastructure. Indeed, in this proceeding, the ALJ granted Staff’s request to
take official notice of the Staff report referenced in the Commission’s order in Case No.
U-17000, although that request pertained to a Commission record, and was made prior
to the close of the evidentiary record.14 The Commission does consider the actions of
other utility regulatory commissions in formulating policy, and the Texas document is
potentially useful to explain such action. The ALJ finds Staff’s rationale for not offering
this document sooner than July 30, 2015, to be particularly troubling, however. Staff
points to the lack of a sponsoring witness, but documents that can be authenticated do
not require a sponsoring witness or “shepherd”, as the Commission has recognized in
the past.15 If Staff believed the document met the requirements for official notice, or
otherwise met the evidentiary standards for this proceeding, it should have offered the
document as soon as possible. Again the RGC in its objections makes clear that it
13
See, e.g., the Commission’s June 30, 2005 order in Case No. U-13808.
See 8 Tr 2205.
15
See, e.g., January 15, 1991 order, Case No. U-7830 et al; also see MRE 901 and 902.
14
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would have wanted the opportunity to provide evidence addressing or rebutting the
report. This controversy illustrates why it is not appropriate to take official notice of this
document at this late stage of this proceeding. Since it is not possible to reopen the
record in this case, this PFD denies Staff’s request to take official notice of the Texas
staff report.
IV.
TEST YEAR
A test year is used to establish representative levels of revenues, expenses, rate
base, and capital structure for use in the rate-setting formula. The parties and the
Commission may use different methods in establishing values for these components,
provided that the end result is a determination of just and reasonable rates for the
company and its customers. DTEE filed its rate application using the projected test year
July 1, 2015 to June 30, 2016. DTEE also testified that in presenting projections for this
test year, it was using the 2013 historical test year, adjusted for known and measurable
changes.16 While some parties dispute various components of the company’s
projections, no party proposed using a different test year to set rates. In the absence of
dispute, this PFD recommends that the Commission adopt the July 1, 2015 to June 30,
2016 test year, also referred to in this PFD as the 2015/2016 test year.
16
See Stanczak, 4 Tr 147.
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V.
RATE BASE
Rate base consists of the capital invested in used and useful utility plant, less
accumulated depreciation, plus the utility’s working capital requirements.
DTEE presented testimony on its projected capital expenditures broken down
into the following categories: production plant (including steam, hydraulic, other, and
MERC), nuclear (including nuclear fuel), distribution, customer service and regulated
marketing, corporate staff, automated metering infrastructure (AMI), Customer 360
Project, and new plant acquisitions. Also, the company’s filing includes in rate base the
unamortized balance of its licensing expenses for a potential Fermi 3 nuclear plant,
which DTEE proposes to recover over a twenty-year period, and the acquisition of two
new gas-fired power plants. The disputes among the parties involve several of the
company’s projected capital additions for the test year, which are addressed in
connection with Net Plant in section A below. Disputes involving the appropriate working
capital amount, reflecting disputes regarding the treatment of the Fermi 3 licensing
expenses (COLA), certain non-qualifying benefit plans, and a negative expense
attributable to DTEE’s modifications to its non-pension retiree benefits (Other PostEmployment Benefits or OPEB expenses), are addressed in section B below.
A.
Net Plant
Net plant is the primary component of rate base, and its key elements are total
utility plant--plant in service, plant held for future use, and construction work in progress
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(CWIP)--less the depreciation reserve, which includes accumulated depreciation,
amortization, and depletion.
1. Non-nuclear generation
The company projected total capital expenditures for its non-nuclear generation
plant of approximately $1 billion from the end of the historical test year through the end
of the projected test year, or for 2014 through the first six months of 2016.17 Mr. Warren
presented DTEE’s fossil, hydro, and other generation capital requirements, including
planned capital expenditures summarized on Exhibit A-9, Schedule B6.1. Mr. Warren
reviewed DTEE’s fossil-fueled generation assets in terms of capacity and fuel type,
recent and planned retirements, and planned capacity reductions and increases,
summarized in his Exhibit A-6, Schedule F1.18 He also explained how his workgroup
monitors plant performance, discussing major drivers of unit unavailability, performance
statistics for 2013, and projections for the years 2014 through 2019.19
Mr. Warren testified that DTEE’s efforts to maintain overall fossil generation
availability place a priority on maintaining Monroe and Belle River units to sustain high
levels of performance, while minimizing future investments in units at Trenton Channel,
River Rouge, and St. Clair plants.20 He discussed the planning process used for capital
expenditures, testifying that “[e]conomic evaluation includes a rigorous review of the
estimated implementation costs and ongoing benefits.” He identified the Fossil
Generation Capital Governance Board as the last step in project approval, testifying that
projects are approved if they are required to meet regulatory requirements related to
17
Based on the projections in Exhibit A-9, Schedule B6.1, the total is $998.261 million.
See 4 Tr 211-216.
19
See 4 Tr 217-220.
20
See 4 Tr 220-221.
18
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safety and environmental compliance, or are justified by economics.21 Mr. Warren also
testified regarding DTEE’s plans to acquire the Renaissance Power Plant and another
simple-cycle gas-fired peaking plant, referencing Ms. Dimitry’s testimony for details.22
Drawing a distinction between routine and non-routine capital investments
projected for the test year, he explained that the majority of routine investments to
maintain safe and efficient operations are directed at Monroe and Belle River, and are
estimated at $160-175 million per year. Non-routine expenditures include plant
upgrades and retirements, the Ludington Pumped Storage Plant upgrades, and new
environmental control equipment.23 He testified that the largest investments are related
to the installation of new environmental compliance equipment, including $256 million
for Flue Gas Desulphurization (FGD) and Selective Catalytic Reduction (SCR)
equipment at Monroe, and $239 million for Activated Carbon Injection (ACI) and Dry
Sorbent Injection (DSI) equipment at Belle River, Trenton Channel, St. Clair and River
Rouge plants to meet the federal Mercury and Air Toxics Standards (MATS)
environmental rules. He testified that without these expenditures, these four plants with
a total of 3,000 MW in capacity would not be able to operate after April 2016.24 He
referred to Ms. Dimitry’s testimony for an analysis of the economics of these projects
and their alternatives.
As shown in Mr. Warren’s Exhibit A-9, Schedule B6.1, DTEE’s cost projections
are broken down by plant type, and are broken down into “routine”, “non-routine”, and
21
See 4 Tr 223.
See 4 Tr 214.
23
See 4 Tr 224.
24
See 4 Tr 224-225, 228-229.
22
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“non-routine environmental” categories. Mr. Warren provided descriptions of each of the
categories and a review of the supporting pages of this schedule.25
In addition to the $238 million capital expenditure for ACI/DSI, Mr. Warren
identified proposed expenditures of $110.6 million to complete FGC at Monroe, $147.8
million for the last SCR at Monroe, and $13 million for a proposed cooling water intake,
piping modifications for wet ash disposal, the conversion of the Monroe fly ash disposal
system from wet to dry transport, as well as other small environmental projects. As
discussed in section a below, M/N/S take issue with the expenditures for ACI/DSI; as
discussed in section b below, Staff proposes three adjustments to DTEE’s
environmental capital expense projections, while the Attorney General proposes an
adjustment applicable to Mr. Warren’s overall generation capital expense projection.
Disputes regarding DTEE’s proposed new East China plant are discussed in section 2
below.
a. ACI/DSI
Ms. Dimitry explained DTEE’s strategy to comply with the MATS air quality
regulations, including the mercury control requirements adopted by the Michigan
Department of Environmental Quality. She testified that DTEE considered three options
for compliance with the MATS requirements: 1) installation of Dry Sorbent Injection
(DSI) equipment along with Activated Carbon Injection (ACI) equipment; 2) installation
of scrubber or Flue Gas Desulfurization (FGD) technology, along with a method of
removing mercury, either ACI or Selective Catalytic Reduction (SCR); 3) retirement of a
25
See 4 Tr 229-242.
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unit with replacement energy and capacity through market purchases or a new plant.26
She testified that DTEE has adopted the following compliance strategy:
The Monroe units will be fully compliant with MATS based on the
installation of FGD and SCR technology. Trenton units 7 and 8 will be
retired on coal. St. Clair, Belle River, and Trenton 9 will be getting DSI/ACI
installation. River Rouge units will be getting a modular DSI/ACI
installation. After the installation of DSI/ACI, St Clair, Belle River, Trenton
9 and River Rouge will be fully compliant with MATS requirements.27
She also testified that DTEE has obtained an extension of the compliance date until
April 2016 for Belle River, St. Clair, River Rouge, and Trenton Channel.28
Mr. Warren’s Schedule B6.1, page 2, shows ACI/DSI capital costs totaling
$238.277 million for the historical test year through the end of the projected test year,
with a breakdown for Belle River units, St. Clair units 1-4, St. Clair units 6-7, Trenton
Channel unit 9, and River Rouge units 2-3. Ms. Dimitry testified that these represent the
total installation costs for the ACI/DSI project. She generally identified the following
benefits associated with the ACI/DSI installations: lower capital costs; the ability to keep
the units running; and “flexibility to retire [DTEE’s] fleet in an orderly manner.”29
Ms. Dimitry testified that DTEE conducted an economic evaluation of the ACI/DSI
installations in comparison to retiring the units and replacing with new generation and
market purchases.
She testified that the analysis was performed for St. Clair and
Trenton Channel in 2013, and for River Rouge in 2014. These analyses are generally
referred to by the parties and in this PFD as the “2013 analysis” and the “2014
analysis.” Schedules M1 and M2 of her Exhibit A-21 identify assumptions regarding
load growth, power prices, commodity prices, and capacity prices. She testified that
26
See 5 Tr 615-616.
See 5 Tr 616.
28
See 5 Tr 615.
29
See 4 Tr 617.
27
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DTEE analyzed the revenue requirements of the alternative scenarios, based on the
capital costs to install ACI/DSI and additional capital and operating and maintenance
(O&M) costs as shown in Schedule M3 of Exhibit A-21, and based on an estimated
period of market purchases followed by new construction as shown in Schedule M4 of
Exhibit A-21, the costs and parameters of new construction as shown in Schedule M5 of
Exhibit A-21, and the financial assumptions shown in Schedule M6 of Exhibit A-21. She
testified that DTEE’s analysis showed the following benefits, presented in Schedule M7
of Exhibit A-21: the installation of ACI/DSI on the St. Clair units resulted in a Net
Present Value Revenue Requirement (NPVRR) over the time period 2014-2035 of $105
million less than the revenue requirement for the alternative over the same period; the
installation of ACI/DSI on Trenton Channel 9 resulted in a NPVRR of $83 million less
than the revenue requirement for the alternative over the same period; the installation of
modular ACI/DSI on River Rouge units 2 and 3 resulted in a NPVRR of $16 million less
than the revenue requirement for the alternative over the same period.30
Ms. Dimitry also explained that Belle River was analyzed separately because it
had not been identified as a candidate for early retirement, so the analysis compared
the installation of FGD in 2016 to the installation of ACI/DSI in 2016, followed by FGD
installation in 2020. She testified that this study showed a $40 million lower NPVRR
using the later FGD installation.31 Ms. Dimitry also testified to the following additional
elements of DTEE’s analysis. First, she testified that DTEE did consider 1-hour SO2
National Ambient Air Quality Standard (NAAQS) and the designation of a nonattainment area in Wayne County, and testified “DTE Electric believes at this time that
30
31
See 5 Tr 620-621.
See 5 Tr 622.
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there is no additional sorbent needed in order to comply.”32 Second, she testified that
the implementation of proposed federal 111(d) CO2 rules would not impact the analysis
of the benefits of the ACI/DSI installations:
The Company has addressed the uncertainty of potential future CO2
regulation in its analysis. By implementing a plan that minimizes capital
expenditures while fully meeting EPA MATS regulation, the DSI/ACI
installation generates the “lowest cost” for our customers, even if the
plants were subsequently shut down for any reason (e.g. future CO2
regulations, other legislation/regulation, economics, etc.) in the early
2020s.”33
M/N/S took issue with the portion of DTEE’s proposed MATS compliance plan
that relies on installing ACI/DSI technology at St. Clair, Trenton Channel, and River
Rouge. They presented the testimony of three witnesses critiquing various aspects of
the Commission’s analysis.
Dr. Sahu reviewed one of the key inputs to DTEE’s analysis, the variable O&M
costs, including the quantities and unit cost of sorbents that will be required to operate
the ACI/DSI technology to meet emission limits. Powdered Activated Carbon (PAC)
and Bromated PAC (BrPAC) are the sorbents used in the ACI system; trona is the
sorbent used in the DSI system. Dr. Sahu testified that he reviewed DTEE’s estimates
dating back to 2012, and found wildly varying, inconsistent estimates of the required
quantities of trona, PAC, and BrPAC. He presented numerous exhibits to support his
testimony, including Exhibits MEC-18 through MEC-69. He noted significant variation
between the estimates DTEE presented to the MDEQ and the various estimates it
presented in cases before the MPSC, including plan case filings and discovery
responses.
32
33
Dr. Sahu presented a chart in his Exhibit MEC-29 comparing DTEE’s
See 5Tr 622-623.
See 5 Tr 623.
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sorbent usage projections from its PSCR plan cases and material submitted to the
MDEQ in support of DTEE’s February 2014 Air Pollution Control Permit to Install (PTI)
Application for MATS Compliance at the Belle River and St. Clair plants, Exhibit
MEC-18.
His testimony also reviewed some of DTEE’s discovery responses to
interrogatories seeking explanations of the basis for the different estimates.
Dr. Sahu concluded that DTEE does not have a good grasp of the factors that
affect sorbent usage. He explained the chemistry underlying his concerns that potential
sorbent interactions have not been fully analyzed by DTEE, including the interactions
between the ACI/DSI sorbents and the treated (Reduced Emission Fuel or REF) coal
DTEE intends to burn at most of its units, and that DTEE’s cost estimates do not
consider the potential variability in the chemical composition of the predominantly lowsulfur western (LSW) coal it will burn at these units.
Dr. Sahu reviewed a study on DSI costs, known as the Sargent & Lundy study
(Exhibit MEC-59), which DTEE relied on in its April 2014 Reasonably Available Control
Technology Analysis for the Control of SO2 Emissions for the Rouge River and Trenton
Channel Power Plants (RACT analysis) for the MDEQ. The RACT analysis is Exhibit
MEC-19. Dr. Sahu updated the Sargent & Lundy study inputs using DTEE’s per-ton
trona cost projections from its 2014 PSCR plan case (Case No. U-17319), an SO2
removal rate of 25%, and the actual capacity and heat rates of DTEE’s units, along with
the variable O&M rates for ACI that DTEE used in its Levelized Cost of Electricity
(LCOE) analysis ASI/DSI in that case, escalated to 2016 dollars. He presented this
calculation of variable O&M costs in his Exhibit MEC-62. He testified that his results
show significantly higher variable O&M costs than DTEE used in its 2013 and 2014
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NPVRR calculations, but he believes that these cost estimates provide a solid
benchmark for estimating sorbent costs, with the results well within the range that
others in the industry have projected. He cited Exhibit MEC-36 to show Edison Electric
Institute (EEI) estimates ranging from $4/MWh to $15/MWh.
Dr. Sahu testified that the variable O&M costs could be significantly higher if
DTEE is required to remove SO2 at a higher rate, or if the fly ash disposal costs exceed
the $10 per ton assumed in his analysis. He also testified that the use of trona will
increase carbon dioxide emissions, citing DTEE’s PTI Application, Exhibit MEC-18, and
he testified that higher variable operating costs can affect the dispatching of the units.
And he testified regarding the potential for DTEE to incur additional capital and
operating and maintenance costs at the units to maintain its electrostatic precipitators
(ESPs) and potentially from using the REF coal. He concluded that DTEE has
significantly understated the expected sorbent costs in its ACI/DSI analysis.
In his analysis, Dr. Sahu also noted differences in DTEE’s projected capacity
factors for these units, comparing discovery responses in this case in Exhibit MEC-48 to
those used in DTEE’s LCOE analysis, and with the capacity factors used in DTEE’s
RACT analysis (Exhibit MEC-19).34 He testified that the difference may be attributable
to increased reliance on low-sulfur coal to meet emission limits.
Mr. Chernick reviewed DTEE’s analyses and conclusions, taking issue with its
modeling assumptions including its modeling of replacement power costs for the
potential unit retirements evaluated in the analysis. He testified that he reviewed the
cost-effectiveness of continued operation of the St. Clair, Trenton Channel, and River
Rouge units slated for ACI/DSI installation, and testified that DTEE’s analysis overstates
34
See 7 Tr 1755-1756.
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the cost-effectiveness of the proposed retrofits by understating variable O&M costs for
the systems, overstating the likely prices of market energy purchases and sales,
overstating the likely market price of capacity, overstating the cost of new gas-fired
plants, failing to adjust the timing of replacement resources for River Rouge in the
retirement case, failing to consider other resources as an alternative or supplement to
new gas-fired capacity, and failing to account for the addition of two new gas-fired
plants. He also testified that DTEE’s analysis contains errors in the treatment of capital
additions in its revenue requirements analysis, fails to account for the further aging of
plants that are already quite old, and limited its consideration of the effects of other
environmental requirements. He testified that with more realistic assumptions,
retirement of each of these units would have been the least cost option, even when
limited to information known at the time DTEE made its analysis. 35
Mr. Chernick reviewed DTEE’s gas price projections, market capacity and energy
price forecasts, and emission allowance price forecasts, and testified to the projections
he used in his modeling. He testified that he reviewed a range of resources as potential
replacements for the modeled unit retirements, including the purchase of existing
capacity, renewables, energy efficiency and “demand-side options” in addition to new
plant construction. Mr. Chernick testified that DTEE used the Stragetist models to
decide whether to purchase energy and capacity from the market or add new combinedcycle or combustion-turbine plants for its 2013 analyses and used Promod for this
determination in its 2014 analyses.36 He testified that DTEE’s new combined-cycle and
combustion-turbine plant cost assumptions used in the Strategist modeling were
35
36
See 7 Tr 1666-1668.
See 7 Tr 1665-1666.
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“significantly more expensive than any reasonable estimate” while those in its NPVRR
calculations are roughly consistent with EIA estimates.37 He also testified that
combined-cycle and combustion turbine plans have generally been less expensive than
DTEE or EIA estimates, presenting FERM Form-1 data showing the cost of recent
plants in Table 10 at 5 Tr 1688, with a cost summary in Table 11 at 5 Tr 1689, noting
substantial variability in price, and showing an average combined-cycle plant cost of
$782/kW and an average combustion turbine plant cost of $594/kW.
Mr. Chernick also testified that DTEE did not use Strategist in its 2014 analysis of
the economics of installing ACI and modular DSI at River Rouge, so it did not evaluate
the best replacement alternatives for River Rouge. He testified that a Strategist run
would almost certainly have called for timely replacement of River Rouge in the
retirement case.38 He also noted that DTEE is acquiring two new gas-fired plants. He
testified that DTEE should have included them in its analysis, arguing they would
reduce the incremental revenue requirements for fuel and purchased power in
retirement.39 Mr. Chernick testified that in addition to energy market purchases and new
gas plants, DTEE should have considered other options to reduce the cost of power
supply and maintain reliability following the retirement of its units. He provided a report
on the cost of utility-scale wind farms in Exhibit MEC-12, and he testified to the potential
contributions of energy efficiency and dynamic pricing:
The alternative resources could have been reflected in various ways,
including adding some to the list of options that Strategist could select,
exogenously adjusting loads (e.g., for demand-side alternatives) in all
cases or in the retirement cases, or exogenously adjusting loads and
resources in specific test cases.
37
See 7 Tr 1686.
See 7 Tr 1691.
39
See 7 Tr 1692-1693.
38
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The important point is this. If DTE thought that gas-fired replacement
resources were more expensive than the retrofits, it should have
considered alternative replacements before deciding that the retrofits were
the least-cost options.40
Mr. Chernick also took issue with DTEE’s NPVRR model, arguing that it does not
recover the full capital costs of the retrofit plants, testifying that DTEE uses a
depreciation life of 46 years to recover the incremental capital costs of the ACI/DSI
additions, while its analysis only runs to 2035, omitting a significant portion of the
costs.41 He testified that DTEE leaves $220 million in capital costs unrecovered for St.
Clair, $75 million for Trenton Channel, and $18 million for River Rouge, as shown in his
Table 14. He testified that he computed tax benefits associated with writing off the
investment at a 39% tax rate, and subtracted that from the remaining plant value, and
used a net present value calculation to determine the additional amount that should be
added to the NPVRR for the retrofit case or subtracted from the retirement case to
reflect this cost.42
Based on the estimated variable O&M costs identified by Dr. Sahu, and the
revised assumptions regarding market capacity and energy prices, allowance costs, and
cost of new generation identified by Mr. Chernick, Mr. Evans ran revised analyses using
the PROMOD model to account for each hour. Mr. Evans testified that he reviewed the
Strategist and PROMOD modeling underlying DTEE’s revenue requirements analysis.
He explained how DTEE’s analysis was performed, including the use of the Strategist
model to evaluate the economics of the ACI/DSI installations at St. Clair and Trenton
Channel as well as a retirement alternative, and PROMOD to evaluate the economics of
40
See 7 Tr 1698.
See 7 Tr 1700.
42
See 7 Tr 1701-1702.
41
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the ACI/DSI installation at River Rouge, as well as a retirement alternative.43
He
testified that DTEE used the Strategist and PROMOD results with a revenue
requirements spreadsheet to compute net present value revenue requirements for all
costs. Mr. Evans also confirmed some of Mr. Chernick’s concerns with DTEE’s analysis,
explaining the following as a result of his review:
1. The Company used much higher construction cost for new generating
capacity in its Strategist modeling than the Company used in its revenue
requirements spreadsheets.
2. In certain Strategist studies, the Company placed uneconomic
limitations on the resources that the modeling could select.
3. In the River Rouge PROMOD study, the Company assumed that
replacement capacity will not be acquired until 2020, even if the plant is
retired in 2016.44
He also testified that he provided Mr. Chernick with the modeling outputs under two sets
of assumptions, “historical” and “current”, as determined by Mr. Chernick.
From these analyses, Mr. Chernick testified that the economics of ACI/DSI
installations were not favorable. Presenting a chart summarizing results for the units of
each plant, he testified none of the River Rouge, St. Clair, or Trenton Channel retrofits
appear to be cost-effective, given current conditions and reasonable forecasts of future
conditions, and he testified that an unbiased analysis in 2013 and 2014 would very likely
have found that the retrofits were uneconomic. He recommended that the Commission
not allow recovery in rates of the ACI/DSI installation costs.45
Mr. Chernick also addressed Ms. Dimitry’s reference to the expected MISO
market capacity shortfall as a benefit to keeping DTEE’s generating units in service. He
43
See 7 Tr 1649-1650.
See 7 Tr 1650-1651.
45
See Tr 1724-1725.
44
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reviewed subsequent MISO analyses, including a filing in Case No. U-17751 (Exhibit
MEC-14), as well as statement made by MISO’s Executive Vice President of
Transmission and Capacity.
46
He summarized his conclusions regarding the available
resources:
The 3,0000 MW shortfall reported by MISO appears to reflect a peculiarity
in MISO’s method for accounting for resources, which is based on surveys
of its members. Even though Renaissance and Jackson [plants] have
been operating in Zone 7 since 2002, MISO had ignored them as late as
October 2014. Contracts with existing capacity resources that have not
been counted by MISO can avoid the shortage, which appears to be an
artifact of MISO’s process rather than a real problem.47
Even if DTE immediately retires all of the capacity at River Rouge, Trenton
Channel, and St. Clair, 2,170 MW in total UCAP, in addition to the
retirements and transfer listed in Table 24 [at 7 Tr 1721], Zone 7 would still
have at least a 2,000 MW surplus of capacity resources in 2016/17.48
He testified that the MISO report is not a sufficient justification for DTEE’s uneconomic
ACI/DSI installations.
DTEE presented three rebuttal witnesses responding to this testimony. Ms.
Dimitry presented the principal rebuttal testimony disputing Mr. Chernick’s overall
analysis.49 She took issue with his revisions to DTEE’s projected commodity and electric
market costs, and with other inputs to his modeling. First, she objected that Mr.
Chernick used lower market prices for electricity than DTEE used in its analyses, while
leaving the natural gas and coal price forecasts unchanged. She testified that DTEE
used an “integrated forecast” based on “market fundamentals”, explaining “this means
that the gas, coal and power price projections were derived by reaching the equilibrium
points (or balance) between gas supply and demand . . . coal supply and demand . . .
46
See 7 Tr 1711 to 1723.
See 7 Tr 1723.
48
See 7 Tr 1723.
49
See 5 Tr 631-650.
47
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and electric power supply . . . and demand.”50 She presented a revised analysis that
also adjusted forecast coal prices using the same smoothing method Mr. Chernick used
for the energy price forecasts.
Second she objected to Mr. Chernick’s use of a 2015 model, characterizing it as
based on hindsight.51 She also testified that if other updated market prices are used,
coal price projections should also be updated. She presented Schedule O1 of Exhibit
A-25 to reflect lower coal prices she believes should be used if updated gas and market
prices are to be used in the analysis.
Third, she objected to Mr. Chernick’s reliance on PJM capacity market prices to
establish a reference for MISO market prices. In this regard, she reiterated that DTEE
used an integrated forecast. She also testified there are many differences between
MISO and PJM, including the use of different demand curves. She testified that the PJM
market provides very different, often much higher, energy revenues to new generation
plants, so the capacity prices required to induce new entry in the PJM market can be
lower than the MISO market. She presented Schedule O2 of her Exhibit A-25 to show
higher PJM prices than the PJM-based cap used in Mr. Chernick’s analysis.52
Fourth, she objected to Mr. Chernick’s revised assumptions regarding the cost of
a new gas plant, testifying that his use of cost estimates in the Strategist model that
were 34% to 37% below DTEE’s estimates ignore the costs associated with DTEE’s
revenue requirements, including AFUDC, taxes, insurance, and a return on its
investment.53 She testified that Mr. Chernick’s use of construction costs as shown in his
50
See 5 Tr 636.
See 5 Tr 636-637
52
See 5 Tr 633, 637-639.
53
See 5 Tr 640-642.
51
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Table 10 are not comparable because many of those plants were built in warm weather
states, and thus do not include cold-weather protections required in Michigan. She
testified DTEE relied on Black & Veatch for a detailed cost estimate. She presented
Schedule O4 of Exhibit A-25 to show the new build and retirement schedules resulting
from M/N/S’s gas plant cost assumptions.
Fifth, she testified that Mr. Chernick also underestimated the time to build a new
plant, testifying that from the time of DTEE’s analysis in 2014, with a 5 to 7 year
development and construction period, it would be highly unlikely DTEE could complete
a plant by 2018.
Sixth, she took issue with Mr. Chernick’s testimony that DTEE should have
considered other options to constructing a new gas fired plant, including purchasing a
plant, or exploring alternatives such as renewable energy or energy efficiency. She
testified that the lack of response to DTEE’s recent RFPs shows no additional plants
were available for DTEE to purchase, and she testified that renewable energy and
demand-side options would not be equivalent to a baseload plant, and would take years
to develop.54
Ms. Dimitry also testified that DTEE disputes the variable O&M cost estimates
used in the M/N/S analyses, referencing Mr. Marietta’s testimony. Regarding potential
additional capital costs associated with the plants, given their age, she testified that
DTEE is committed to maintaining reliability of the plants and is confident that the plants
will continue to demonstrate reasonably reliable performance with proper O&M
54
See 5 Tr 643-645.
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practices. She testified that DTEE included increased maintenance capital and
increased random outage rates in its analysis.55
Ms. Dimitry also addressed the time frame of DTEE’s analysis and the
corresponding unrecovered capital balances. She testified that DTEE believes it is
reasonable to look at a 20-year time horizon, testifying that “the uncertainties introduced
by regulatory, economic, and commodity market conditions are probably beyond
anyone’s control and comprehension” beyond that period. She also testified that to
consider the full value of the undepreciated investment remaining at the end of the
period, the correct calculation would subtract the book depreciation from the tax
depreciation before applying the tax rate. She provided this calculation in Schedule O3
of her Exhibit A-25.56 Ms. Dimitry also presented revised analyses in Schedule O5 of
Exhibit A-25 to show the significance of changing certain disputed assumptions in the
M/N/S analysis, including revising coal prices and revising the variable O&M costs.57
Mr. Marietta also presented rebuttal testimony on this issue, primarily addressing
Dr. Sahu’s sorbent cost analysis. He disputed Dr. Sahu’s testimony that DTEE has
provided varied estimates of the amount of sorbents that will be needed, contending
that the varied projections were made at different points in time, with different
assumptions and for different purposes. He testified that the most current projections
are those that were provided in discovery and that are included in Exhibit A-28,
Schedule R1. He further characterized Dr. Sahu’s references to the earlier projections
as “misguided”, testifying that the projections have changed as information changes,
including better injection rate estimates developed with the project engineer, industry
55
See 5 Tr 645.
See 5 Tr 645-646.
57
See 5 Tr 647-650.
56
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discussion, and changing fuel blend and operational forecasts, and testifying that the
current projections are the most accurate projections. 58
Mr. Marietta disputed Dr. Sahu’s testimony that there is any uncertainty in the
chemical composition of the REF coal, asserting that it does contain approximately
51.5% CaBr with little fluctuation, and that the cement kiln dust used contains
significantly less calcium carbonate than indicated in the Material Safety Data Sheet,
with very low amounts of chlorine. He testified that this results in DTEE needing to
inject less trona than with higher chlorine concentrations. Further, he testified that all
projections relating to PAC and trona take the impacts of REF sorbents into account.59
He also testified that the information presented in Schedule R2 of Exhibit A-28 shows
the company’s current projected rates for sorbent injection with and without REF are
nearly the same, due to the low application rates of the REF sorbents.60
Mr. Marietta disputed that DTEE has not addressed how its use of sorbents may
impact the effectiveness of its other pollution controls, citing testing with PAC and trona
in 2011 and 2012, and citing the same testing as establishing that the required mercury
reductions for MATS compliance can be achieved with other emission limits.61 He cited
Schedules R2 and R3 of his Exhibit A-28 to show that DTEE has provided significant
documentation on the development of its sorbent injection rates.
Mr. Marietta also expressly addressed the Sargent & Lundy study, Exhibit MEC59, arguing that it is five years old and has inputs “completely different” from those
associated with DTEE’s DSI project, including the SO2 concentration and SO2
58
See 4 Tr 308.
See 4 Tr 304.
60
See 4 Tr 307-308.
61
See 4 Tr 305.
59
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reduction.62
Additionally, Mr. Marietta disputed that DTEE’s coal blend has been
modified to address sulfur-dioxide emission increases from the use of sorbents and
REF, testifying that DTEE intends to burn the coal that is most economical for its
customers and allows the plants to meet all applicable environmental regulations. He
also testified that variations in the mercury content of coal have been taken into account
in DTEE’s projections.63
Mr. Marietta also took issue with Dr. Sahu’s comparison of capacity factor
projections provided in prior cases to illustrate he concern regarding the impact of
sorbent use on the capacity factors of DTEE’s units. Mr. Marietta testified that the
projections were made at different points of time using different unit capacity values for
the purposes of DTEE’s LCOE study, citing Mr. Chreston’s testimony in Case No.
U-17319.64
In his rebuttal testimony, Mr. Warren responded to elements of Dr. Sahu’s and
Mr. Chernick’s testimony. Mr. Warren testified that he provided support for DTEE’s
capital cost projections for the ACI/DSI installations, providing Schedules Y1 through Y3
of Exhibit A-35 to support his testimony.65 Addressing Mr. Chernick’s testimony, Mr.
Warren testified that DTEE considered the “further aging” of its power plants in its
economic analysis of the ACI/DSI installation, asserting that the Fossil Generation
engineering staff completed a risk of failure analysis on the major equipment system for
the power generating units at Trenton Channel and St. Clair power plants, and that the
forecast investments to address any potential failures were included in Ms. Dimitry’s
62
See 4 Tr 311.
See 4 Tr 307.
64
See 4 Tr 309.
65
See 4 Tr 256-257.
63
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Exhibit A-21, Schedule M3, and were provided in discovery to MEC as shown in
Schedule Y5 of his Exhibit A-35.66
Mr. Warren also addressed Dr. Sahu’s stated concern that DTEE may not be
fully compensated by its affiliates for additional O&M expenses attributable to burning
REF fuel, presenting Schedule Y4 of Exhibit A-35, and further indicating that DTEE
receives additional reimbursement under its REF contract with the Monroe Fuels
Company.67
The parties’ briefs largely rely on the testimony of their witnesses. M/N/S make
clear they are not challenging the ACI/DSI installations at Belle River, but only the St.
Clair, Trenton Channel and River Rouge installations. M/N/S argue that DTEE did not
support the assumptions underlying its analysis, including operating cost and other
potential capital cost assumptions associated with the use of the ACI/DSI technologies,
inflated the cost of replacement generation while failing to consider alternatives to new
construction in its analysis, and made other unsupported assumptions regarding future
market prices. DTEE argues that its MATS compliance strategy is reasonable for the
reasons explained by Ms. Dimitry, and DTEE presents arguments objecting to the
alternative analyses presented by M/N/S, and arguing the Commission has previously
approved the company’s plans. Key disputed points are discussed below, followed by
recommendations to the Commission.
To formulate appropriate recommendations in this case, it is appropriate to
review the disputed analytical elements individually. The cost and timing of new
construction is discussed in section i, while alternatives to new construction are
66
67
See 4 Tr 263-264.
See 4 Tr 257-258.
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discussed in section ii; section iii reviews the disputes regarding commodity and electric
market cost projections; section iv reviews the variable O&M cost inputs; section v
addresses the methodological dispute regarding the treatment of undepreciated capital
costs at the end of the study period; sections vi and vii look at two other points of
dispute not directly reflected in the analysis, whether the MISO market capacity shortfall
supports DTEE’s decision-making, and whether DTEE’s analysis also excludes other
expected capital costs associated with the ACI/DSI installations.
i. cost and timing of new gas plants
M/N/S argue that DTEE’s 2013 analysis of the retirement option for the St. Clair
and Trenton units was based on a reliance on market purchases until its Strategist
model selected a new combined cycle or combustion turbine plant as an option for
replacement power. They argue that DTEE’s choices were biased by the use of new
plant costs in the Strategist model that were higher than reasonable, and higher than
the costs used in its NPVRR analysis. M/N/S present a comparison of the cost
assumptions in Table 8 of their brief at page 38.
Citing Ms. Dimitry’s testimony, DTEE argues that its cost estimates were based
on a study by Black and Veatch for both combined cycle and combustion turbine
technologies, while M/N/S understated the installation costs by ignoring AFUDC, taxes,
insurance and return on investment costs, resulting in a sub-optimal new build
recommendation. DTEE also takes issue with Mr. Chernick’s presentation of the cost of
other gas-fired plants, arguing that they are not comparable to the costs used in DTEE’s
evaluation.68
68
See DTEE brief, pages 55-56; see Dimitry, 5 Tr 640-41.
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M/N/S argue that DTEE’s rebuttal on this point, including Ms. Dimitry’s testimony
that DTEE relied on the Black & Veatch study for its cost estimates, ignores the different
costs used in the Strategist piece of its analysis. They argue that the Black & Veatch
study supports only the cost estimates DTEE used in its revenue requirements
spreadsheet,69 which are the same cost estimates that Mr. Chernick and Mr. Evans
used.70 M/N/S also dispute the contention that they ignored key cost elements, arguing
that their estimates properly reflect the elements considered in the Black & Veatch
study, citing Tables 6 -2 and 8-1 of that study, Exhibit MEC-80.71 They argue that the
overstated cost of construction in the Strategist model had multiple effects, including
increasing the fixed costs and choosing the less efficient replacement option with higher
energy costs in the retirement option, and causing overreliance on market purchases.
While obviously a question of great complexity, this PFD concludes that DTEE’s
use of the higher, seemingly-unjustified cost of new construction estimates in its
Strategist modeling in comparison to the estimates used in its NPVRR estimate
primarily altered the choice of timing of the construction of a new gas-fired plant as part
of the retirement option. That is, it affected the replacement parameters shown on
Schedule M4 of Exhibit A-21. DTEE’s analysis for St. Clair and Trenton thus assumed
market power purchases until 2020. Mr. Chernick acknowledges that the NPVRR
analysis itself used a reasonable cost estimate, consistent with EIA estimates.
Similarly, M/N/S also argue that because DTEE used PROMOD rather than
Strategist for the River Rouge plant in its 2014 analysis, it precluded the possibility of
69
Note that DTEE considers the Black & Veatch study (Exhibit MEC-80) to be confidential, and it is
subject to the protective order issued in this case.
70
See M/N/S brief, pages 39-40.
71
See M/N/S brief, pages 89-40.
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selecting new generation prior to 2020. Again, M/N/S argue that new generation as
early as 2018 would have been an economically superior alternative to waiting until
2020.72 Looking at the River Rouge analysis, M/N/S argue that even accepting all of
DTEE’s other assumptions, allowing the model to replace market power with new
construction by 2018 rather than waiting until 2020 transformed DTEE’s estimated $16
million net present value benefit from the ACI/DSI installation into a $38 million cost.73
Since the principal dispute in the case of both analyses comes down to a
question of the potential timing of new construction to replace reliance on market
purchases, and in the absence of definitive evidence, it is reasonable to defer to DTEE’s
more conservative estimate of the potential construction time. Ms. Dimitry testified that
an earlier date would not have been feasible, given the need for a 5 to 7 year
development and construction period.74 In response, M/N/S argue that DTEE had ample
opportunity since the MATS rule was announced in 2011, noting too DTEE’s 2013
PSCR plan identifying DSI for River Rouge, and could have conducted an economic
analysis earlier. Nonetheless, this PFD finds that DTEE’s estimates of the availability of
new construction are within the range of reasonableness. While a thorough analysis
would have considered a range of gas plant costs and time schedules, or relied on an
independent engineering analysis, the history of utility plant construction is fraught with
tales of unanticipated delays and cost overruns.75 It is difficult to fault DTEE for
assuming a longer time period for construction than it might have achieved.
72
See M/N/S brief, pages 41-42.
See 7 Tr 1692.
74
See 5 Tr 644.
75
See, e.g., Attorney General v Michigan Pub Service Comm, 412 Mich 385, 425-26 (1982)(“The Fermi 2
plant has experienced 14 cost overruns since its construction began in 1969. Originally it was projected
to cost $229 million, but in the last several years the cost estimates have multiplied to $1.8 billion.
Moreover, the utility has acknowledged that it cannot guarantee against further cost overruns, and it
73
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ii. alternatives to new gas fired plant
Related to DTEE’s formulation of its retirement option, M/N/S also argue that
DTEE should have considered alternatives to supplement or replace the new gas-fired
generation in its retirement scenarios. Mr. Chernick identified alternatives including
purchasing existing plants, utility-scale wind projects, and demand-side options
including increased energy efficiency and dynamic pricing programs. Mr. Evans also
made clear that the Strategist model can evaluate the economics of different choices.76
Ms. Dimitry testified in response that none of the generating units identified by
Mr. Chernick responded to DTEE’s RFPs, indicating that DTEE could not have
purchased them earlier.77 She also dismissed reliance on wind energy or demand-side
programs:
Regarding additional renewables, especially wind, further energy
efficiency efforts, additional demand response, and dynamic peak pricing,
none of these resource options are electrically comparable to existing
large base load coal-fired generation plants, which provide a large amount
of both capacity and energy. In addition, it takes years to develop these
programs, which makes it extremely challenging to meet the capacity
needs required in 2016 to meet the MATS compliance date.78
As M/N/S argue, nothing in DTEE’s response acknowledges that these
alternative resources could have been used in part rather than as full replacement for
new gas-fired generation, again reducing the reliance on market purchases:
Contrary to DTE’s assertion, there is no reason why renewables would
need to entirely replace all of DTE’s coal plants. Rather, proper use of the
economic dispatch models would have allowed the models to generate a
portfolio that may have included a mix of renewable energy, energy
admitted that the final costs of the plant may include an additional $200 million. Similarly, the Belle River
units have also experienced cost overruns. The most recent projected cost overrun was for $500
million.”)
76
See Chernick, 7 Tr 1698; Evans, 7 Tr 1653.
77
See 5 Tr. 644.
78
See 5 Tr 644.
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efficiency, demand response, market purchases, new gas plant builds,
and existing gas plant purchases, as well as retrofit of some of the coal
units.79
DTEE did not directly respond to this argument.
Again, however, while M/N/S make a reasonable point that a better analysis
would have considered additional alternatives, neither Mr. Evans nor Mr. Chernick
provided illustrative parameters for these alternatives, and did not show that DTEE had
the ability to determine reasonable parameters to include in its Strategist analysis. That
is, while it theoretically reasonable to consider alternatives to new generation or market
purchases, the record in this case does not show what practical alternatives DTEE
could have included. Other than increased energy efficiency and demand-side
management, it is plausible to assume that market prices roughly reflect the cost of
alternatives. Note that the level of capital expense proposed for the ACI/DSI
installations does not rise to the threshold level for a certificate of necessity under
MCL 460.6s, which would have required DTEE to evaluate its demand-side options.
iii. market energy, capacity and commodity costs
There is also a dispute between the parties regarding the commodity, energy and
capacity costs that have gone into DTEE’s analysis. Mr. Chernick revised two DTEE
forecasts in the 2013 and 2014 analyses, the electric energy and capacity price
projections.
DTEE’s 2013 forecast energy prices used Intercontinental Exchange market
forwards through 2018, followed by a long-term energy forecast developed internally by
DTEE for the following years, while its 2014 forecast used the same market forwards
79
See M/N/S brief, pages 45-46, also citing Evans, 7 Tr 1652.
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through 2019 and a PACE long-term forecast for the following years. Mr. Chernick
reviewed DTEE’s forecast and found the long-term forecasts high, with significant price
spikes occurring with each move from the market forwards to the long-term forecasts.
Mr. Chernick testified to his opinion that the forecast spikes could not be justified and
used revised forecasts based on the inflation rates in the long-term forecasts, applied to
the market forwards. As discussed above, DTEE argues that its forecasts of coal, gas,
and energy prices were “integrated” and “based on market fundamentals.” Ms. Dimitry
testified that the company’s energy price forecast should not have been modified
without also modifying the coal and natural gas price forecasts.
M/N/S note the spike in DTEE’s market energy cost projections beginning in
2019 and 2020 for the 2013 and 2014 analyses, respectively.
Responding to Ms.
Dimitry’s testimony that it used forecasts “not driven by market fundamentals,” M/N/S
argue that DTEE did not use the fundamentals forecast for the first several years of its
analysis, and also acknowledged that its original presentation of its price forecast in
Schedule M1 erroneously overstated the values used in DTEE’s actual analysis.
For capacity prices, DTEE’s capacity price projections were based on its longterm market fundamentals forecast. Mr. Chernick reviewed DTE’s capacity price
forecasts, taking issue with the capacity price level in DTEE’s 2013 forecast at the year
2021, and taking issue with the capacity price level in DTEE’s 2014 forecast from the
beginning. He testified that he developed a revised capacity price forecast based on
estimates of the prices at which new capacity has been added to the market, and
looking at the PJM market for those estimates. In rebuttal, Ms. Dimitry testified to
significant differences between PJM capacity and energy pricing in comparison to MISO
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pricing, arguing that Mr. Chernick “cherry-picked” a capacity price ceiling. M/N/S object
to this characterization, noting Mr. Chernick’s testimony that the results of his capacity
price modifications were quite small and tended to “balance out.”80
Another controversy related to the price projections arises from Mr. Chernick’s
analysis using updated (2015) information. Ms. Dimitry testified that although Mr.
Chernick updated the electric market energy and capacity forecasts, and the natural gas
forecast, he did not update the coal price forecast. She testified that updating that
forecast makes a significant difference in the outcome of the analysis.81
This PFD concludes that the 2013 and 2014 projections used by the analysts
were generally reasonable. DTEE did not establish that the only reasonable projects are
“integrated” projections. Indeed, DTEE did not make an effort to establish that the
internal long-term forecast in its 2013 analysis was a reasonable forecast, although
M/N/S did not take issue with the energy price forecast, but with the discontinuity of the
forecast joined with the market-forward forecast. Thus, Mr. Chernick’s adjustments were
reasonable because they focused only on smoothing the transition between the market
forwards and the subsequent long-term energy price forecasts by using the escalation
rates in the long-term forecasts.
Likewise, a review of Mr. Chernick’s capacity price forecasts shows his
reasonable concern with some of the near and mid-term projections in DTEE’s forecast.
While the PJM market capacity prices are likely not a perfect proxy for MISO market
capacity costs, Mr. Chernick’s use of the PJM capacity prices does not constitute
80
81
See M/N/S brief, page 49, citing 7 Tr 1681, Table 4.
See 5 Tr 637.
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“cherry-picking”. In his view, capacity can be added at lower prices in MISO than PJM.82
Indeed, it does not appear that the modeling results are significantly affected by the
choice among competing energy or capacity forecasts, with the possible exception of
River Rouge, for which the M/N/S analysis with the revised energy market projections
decreased the cost of the retirement option by approximately $23 million relative to the
ACI/DSI option.
Regarding the 2015 projections, however, DTEE did establish a significant
difference in the results produced if coal prices are updated as well as other market
costs.83 This significant effect should be taken into account in evaluating the 2015
results.
iv. variable O&M costs of ACI/DSI
Citing Dr. Sahu’s testimony, M/N/S argue DTEE had little certainty regarding its
sorbent use at the time it made its projections. They also argue that DTEE has no
clearer picture of its likely sorbent costs now than it did in 2013 or 2014, and no better
idea of what will be required to comply with the 1-hour SO2 standard, or what its
additional ESP costs may be. DTEE disputes M/N/S’s characterization, largely in
reliance on Mr. Marietta’s testimony.
This PFD finds that Dr. Sahu’s testimony is persuasive that DTEE has not
supported any of the various estimates it has provided regarding the sorbent
requirements needed to meet emission limits at its St. Clair, Trenton Chanel and River
Rouge units. Dr. Sahu presented Exhibit MEC-29 to show the range of sorbent
estimates DTEE presented in its recent PSCR plan cases, in discovery in those cases,
82
83
See 7 Tr 1678 n7.
See Schedule O5 of Exhibit A-25.
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and in its February 2014 PTI application to the MDEQ. He testified that the PTI
indicated trona usage could be as high as 196,240 tons per year, with “average
expected” usage of 130,080 tons per year. Dr. Sahu explained why he rejected DTEE’s
contention that the PTI application reflects higher trona usage because it is based on
the “potential to emit”:
DTE contends that the PTI Application trona usage amounts of
significantly higher than those used in the company’s economic analyses
because the PTI Application is purportedly based on a “potential to emit”
analysis that “requires projections to run units much more than PROMOD
projections used in forecasting sorbent injection. Exhibit MEC-31. But the
PTI Application explains that it is based on projected actual utilization
derived from PROMOD modeling. Exhibit MEC-18, PTI Application, 47.84
DTEE did not present any explanation for the vastly different trona usage estimates in
Exhibit MEC-29, and did not refute Dr. Sahu’s testimony that the PTI projections were
based on DTEE’s PROMOD projections.
Exhibit MEC-29 is just one set of comparisons showing the different estimates
DTEE has provided of the sorbent requirements. Dr. Sahu assembled and identified
multiple divergent estimates and inconsistent statements DTEE has provided. Dr. Sahu
testified that as of the time he prepared his testimony, Exhibit MEC-28 was the most
recent information DTEE had provided regarding the quantities of sorbents that might
be needed. After noting that the estimates were provided “without any explanation of the
basis,” Dr. Sahu testified:
As the upper of the two tables above [at 7 Tr 1740] clearly shows, the DSI
sorbent (trona) usage forecasts at this units range from 500 lb/hr to 7,500
lb/hr (a fifteen-fold range) depending on the fuel and the NSR ratio (which
refers to the quantity of sorbent needed as compared to the theoretical
quantity needed to remove the pollutant). The ACI usage forecast ranges
from 3.5 lb/hr to 42 lb/hr. Similarly, the lower table [at 7 Tr 1741] shows
that trona usage under various SO2 reduction scenarios is also quite
84
See 7 Tr 1742.
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variable, ranging from 1000 lb/hr to 23,000 lb/hr. The attachment to
discovery response MECSC/DE-5.5c (Exhibit MEC-28) shows similarly
large ranges in sorbent usage for each of the units at issue.85
Exhibit MEC-28 was provided in response to a question seeking “any calculations,
workpapers, or other documents used in developing such ‘best estimate.’” DTEE’s
rebuttal also did not present any explanation of this information for the record in this
case.
Dr. Sahu also looked at DTEE’s estimates of the total variable O&M (VOM) costs
of the ACI/DSI operations, which principally include the sorbent costs, stated on a
dollars-per-MWh basis.
In Exhibit MEC-54, DTEE provided variable ACI and DSI
estimates underlying its modeling in 2013 dollars. Dr. Sahu translated these into 2008
and 2016 dollars and presented them in his Table 1 at 7 Tr 1760. In Exhibits MEC-55
and MEC-56, Ms. Dimitry provided the ACI and DSI variable O&M costs used in DTEE’s
2013 and 2014 NPVRR analyses, and in its 2012 levelized cost analysis. Dr. Sahu
combined the ACI and DSI variable cost estimates into his Table 2 at 7 Tr 1761-1762.
The following chart shows the different variable O&M cost estimates presented in
Tables 1 and 2, with the headings revised for clarity:
Unit
MEC-55/56
2012 Analysis
(2008 dollars)
MEC 55/56
2013 Analysis
(2008 dollars)
MEC 55/56
2014 Analysis
(2016 dollars)
MEC 54
(2016 dollars)
MEC 54
(2008 dollars)
RR2
RR3
SC1
SC2
SC3
SC4
SC6
SC7
TC9
2.14
2.14
1.75
1.75
1.75
1.75
3.03
2.23
2.15
0.26
0.20
0.55
0.55
0.55
0.55
1.43
0.35
0.26
0.99
0.99
0.70
0.70
0.70
0.70
1.03
0.53
0.26
1.15
1.15
2.14
2.14
2.14
2.14
1.56
2.45
1.43
0.95
0.94
1.76
1.76
1.76
1.76
1.28
2.01
1.17
85
See 7 Tr 1741.
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Dr. Sahu testified that DTEE was asked to explain the basis for the differences in
these costs and provided only a nonresponsive answer. He also cited Exhibit MEC-58,
an additional discovery response from DTEE in this case, indicating that DTEE
“continues to work with potential vendors and our project engineer to develop cost
estimates.” Again, DTEE’s rebuttal presentation never offered any explanation for the
wide variation in these cost estimates. In the light of this history, Mr. Marietta’s
testimony that his Exhibit A-28 contains better or “the best” estimates of sorbent use is
wholly unpersuasive.
As discussed above, Dr. Sahu testified that in its April 2014 RACT analysis
(Exhibit MEC-19), DTEE relied on the Sargent & Lundy study to estimate the capital and
operating costs for the ACI/DSI installations, including a $7.92 per MWh variable O&M
cost. Dr. Sahu carefully updated this estimate and tailored it to DTEE’s units to produce
estimates that are significantly less than the more generic $7.92 estimate that DTEE
used in its RACT analysis. He also testified that his cost estimates are consistent with
EEI estimates, as shown in Exhibit MEC-36, ranging from $4 to $15 per MWh. In the
absence of any credible cost analysis from DTEE, this PFD finds that Dr. Sahu’s
estimate is reasonable, and consistent with industry guidance, and the minimum
estimate of DTEE’s likely variable O&M costs supported on this record. Given DTEE’s
failure to provide a credible basis for any of its projections, given DTEE’s own reliance
on the Sargent & Lundy study in April of 2014, and given Dr. Sahu’s careful efforts to
update the study, Mr. Marietta’s objection that the study is five years old is also
unpersuasive.
U-17767
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Mr. Marietta clearly understood Dr. Sahu’s concern that DTEE’s estimates were
not transparent and had not been explained.86 Disputing Dr. Sahu’s characterization of
DTEE’s estimates as not transparent, Mr. Marietta testified:
The Company has provided significant documentation on the
development of sorbent injections rates. This includes test data from the
testing done at our facilities in 2011 and 2012 as well as projections
developed by our project engineer, Black & Veatch and internal engineers
that were provided in Discovery in this case. The previously provided
project and internal engineer projections of the injection rates are attached
as Exhibit A-28, Schedules R-2 and R-3, respectively.87
Yet, a review of Exhibit A-28 shows that it is anything but transparent. It contains
several spreadsheets, with no dates, no explanation for the purpose of the compilation,
and nothing that would facilitate comparison with other DTEE estimates.
In cross-
examination, Mr. Marietta explained that he prepared the information in Schedule R1
from the spreadsheet in Schedule R3, while Schedule R3 was prepared by DTEE’s
“engineering team” based on the information in Schedule R2, which was provided by
Black & Veatch.88 He testified that he received Schedule R2 “sometime in the first half
of 2014”.89 Regarding Black & Veatch, he further testified that he is not directly involved
with the consultant, he has not spoken to them, he has seen previous versions of the
exhibit, and he understands that much of the data in Schedule R2 is data DTEE
provided to Black & Veatch. He also testified that he had not “seen anything from Black
& Veatch showing [him] how they come up with their final number.”90 And he claimed
that Black & Veatch used a proprietary model but he did not know what that model
86
See 4 Tr 305.
See 4 Tr 306.
88
See 4 Tr 324-326.
89
see 4 Tr 326.
90
See 4 Tr 325.
87
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involves.91 On top of that, Mr. Marietta acknowledged several errors in Schedule R2,
including the NOx emission rates, the particulate matter removal amounts, and mercury
emission rates shown as zero for Trenton Channel unit 9 and St. Clair units 1 to 4 and
6.92 He further testified that he did not do anything to verify the information on Schedule
R2, but dealt with DTEE’s engineers to get the data that he needed for Schedule R1.93
Additionally, he admitted that Schedule R2 contradicted his own rebuttal testimony
because it indicates that DTEE is planning to meet a 90% mercury reduction.94 Mr.
Marietta also acknowledged that the parties had not received any additional
documentation regarding the spreadsheets in Exhibit A-28.
v. capital cost recovery
DTEE used a twenty-year time frame for its revenue requirements analysis. Ms.
Dimitry testified that this takes into account the rate impact for customers and the limited
ability to make projections further into the future. M/N/S argue that this modeling
approach leaves over $300 million in unrecovered capital costs associated with ACI/DSI
installations and subsequent related capital expenditures.95
M/N/S persuasively argue that a reasonable analysis should consider the full
recovery of DTEE’s capital expenditures, which ratepayers would continue to pay for as
part of rate base, absent an alternative determination by the Commission. The method
of modeling the net present value of the undepreciated capital investment appears to
have been resolved. M/N/S do not object to Ms. Dimitry’s refinement to the tax
91
See 4 Tr 340.
See 4 Tr 331, 333, 334.
93
See 4 Tr 335.
94
See 4 Tr 337-338.
95
See 7 Tr 1700.
92
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consideration presented by Mr. Chernick. As discussed below, this adjustment
increases the net present value of the ACI/DSI installations.
vi. additional capital costs
M/N/S argue that DTEE has not fully identified the potential capital expenditures
associated with the ACI/DSI operation. Ms. Dimitry testified that DTEE’s analysis
included increased maintenance capital and increased random outage rates to account
for potential declines in plant reliability performance.96 DTEE’s analysis also included a
projected $15.7 million expenditure for the St. Clair unit 7 coal ash retrofit. M/N/S take
issue with DTEE’s assertion that only St. Clair unit 7 would be required to incur
additional capital costs for managing its coal ash to comply with applicable
environmental requirements. M/N/S cite the documents DTEE relied on for its $15.7
million cost estimate for St. Clair unit 7 coal ash retrofit, Exhibits MEC-76 through
MEC-78, and argue that these documents themselves include cost estimates for the
smaller units totaling $8.8 million. They note that in her testimony on this point, Ms.
Dimitry could not explain why DTEE concluded the smaller units did not require
retrofitting, and relied only on her recollection of what other DTEE employees had told
her.97 DTEE argues that it is reasonable for Ms. Dimitry to rely on her staff, but DTEE
does not identify any technical or legal basis for resolving the compliance cost issue for
the smaller units.
M/N/S also argue that DTEE also did not include in its analysis additional capital
costs to upgrade its electrostatic precipitators. Mr. Marietta testified in rebuttal: “This
[2011 and 2012] testing showed that overall electrostatic precipitator (ESP)
96
97
See 5 Tr 645.
See Dimitry, 5 Tr 672-678.
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performance increased. All of the ESPs [were] assessed with the scope of the DSI/ACI
project and found to be adequate for the project application.”98 M/N/S note Mr.
Marietta’s testimony on cross-examination that he did not know whether ESP
enhancements would be needed. They also note DTEE’s response in Exhibit MEC-65,
indicating DTEE is still working with plant and industry experts to identify any necessary
enhancements to its equipment.99 DTEE argues that there is no basis to conclude its
ESPs are inadequate. M/N/S did not build any additional capital costs into their model,
but recommend that the Commission consider this as an unresolved potential for
additional capital expenditures.
vii. MISO Zone 7 capacity shortfall
Among the benefits DTEE cites to its ACI/DSI strategy are keeping its generation
units in service to meet customers’ capacity needs, and providing DTEE with the
flexibility to retire its generation fleet in an orderly manner to maintain system grid
reliability.100 M/N/S cite Mr. Chernick’s testimony explaining and providing context to
MISO’s October 2014 report, which Ms. Dimitry cited. M/N/S also argue that this
information is out of date, citing MISO’s more recent June 2015 Update, which identifies
a smaller shortfall in Zone 7 (1.3 GW) and makes clear that the shortfall can be
addressed with imports from other regions through at least 2019.101
While it is reasonable for the Commission to be concerned with any MISO report
suggesting a potential diminution in supply reliability for Michigan residents, the MISO
shortfall identified in its recent reports is not an invitation to make uneconomic choices.
98
See 4 Tr 305.
See M/N/S brief, page 36.
100
See DTEE brief, pages 43-44.
101
See Exhibit MEC-73.
99
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Indeed, DTEE does not believe its ACI/DSI plans are uneconomic, so it is not asking the
Commission to approve economically-unjustified choices based on the potential MISO
shortfall. Thus, it is not clear there is any actual dispute between the parties to resolve
on this issue. Clearly, had DTEE chosen to retire any of the units, as shown in Exhibit
A-21, Schedule M4, it would have made plans to acquire additional capacity. And to the
extent that it depended on market capacity, its models predicted prices for that capacity.
No party has suggested that as a consequence of the MISO report, current capacity
prices are significantly higher than those reported in either DTEE’s or M/N/S’s analyses.
viii.
recommendation
This is not the first case in which the Commission has been confronted with a
dispute regarding DTEE’s proposed capital expenditures on older generating units, and
it is not the first case in which the Commission has addressed DTEE’s ACI/DSI plans.
In DTEE’s last rate case, Case No. U-16472, the Commission approved proposed
capital expenditures totaling $103 million. The Commission’s October 20, 2011 order
provided as follows:
The Commission notes that Exhibit A-9, Schedule B6.1, shows that Detroit
Edison’s proposed capital expenditures for its marginal generating units
are relatively modest and appear reasonable at this point. Nevertheless,
the Commission agrees with the Staff and the Environmental Coalition that
Detroit Edison should be on notice that any capital investments made in
the test year and beyond in its marginal generating plants will be subject
to particular scrutiny if a plant is subsequently shut down with a positive
plant balance.102
In its December 4, 2014 order in Case No. U-17097, the Commission addressed the
ALJ’s November 8, 2013 PFD recommending that the Commission caution DTEE that it
102
See October 20, 2011 order, page 10.
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had failed to support its plan to install ACI and DSI systems at River Rouge units 2 and
3, St. Clair unit 7, and Trenton Channel unit 9. The Commission found:
The Commission agrees with the Staff and Detroit Edison that contested
issues regarding capital costs must be litigated in a rate case. An Act 304
proceeding is not the appropriate forum to determine issues related to the
company’s long-term capital investment decisions. Therefore, the
Commission finds that a Section 7 warning is not warranted in this PSCR
plan proceeding.
Notwithstanding, the Commission agrees with the ALJ’s findings about the
limitations of Detroit Edison’s analysis to support these capital
investments. A comprehensive justification of the proposed project and
review of alternatives is needed to support recovery of any capital or
operating costs of these investments. As suggested by the ALJ, this
should include a sensitivity analysis related to key factors such as
retirement dates, load growth, fuel prices, and [capacity] factors.103
Then, in DTEE’s 2014 PSCR plan case, Case No. U-17319, the Commission’s
May 14, 2015 order acknowledged that the reasonableness of DTEE’s capital and
sorbent costs should be addressed in this rate case:
The Commission reiterates that the plan and forecast provisions of Act
304 refer to “existing sources of electric generation.” MCL 460.6j(3); MCL
460.6j(4). As such, the inclusion of sorbents in a plan and forecast is
appropriate. However, the Commission acknowledges that the costs for
sorbents and associated capital investments are included in DTE Electric’s
pending rate case, Case No. U-17767, and it is preferable to examine both
the operations and maintenance costs and capital costs for DSI and ACI in
that proceeding. Adjustments can be made in future PSCR proceedings
based on the Commission’s determinations in the rate case.104
Recognizing that the Commission called for these expenditures to be evaluated
in this case, at one level, DTEE’s proposed capital expenditures for its ACI/DSI
installations at the disputed units--approximately $180 million from 2013 through the
end of the projected test year, as shown in Schedule B6.1, page 2, of Exhibit A-9--are
not large in comparison to its total proposed capital expenditure in this case of
103
104
See December 4, 2014 order, Case No. U-17097.
See May 14, 2015 order, page 10.
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approximately $3.6 billion over the course of two and a half years from January 1, 2014
through June 1, 2016, as shown in Schedule B6 of Exhibit A-9. As the discussion of the
disputed issues regarding some of those capital expenditures will show, DTEE has
presented more analysis regarding the ACI/DSI capital spending than for other
proposed capital expenditures of relatively comparable amounts. In one key respect,
however, DTEE’s analyses are seriously deficient. DTEE has not established that its
analyses were based on reasonable estimates of the variable O&M costs,
predominantly sorbent costs, associated with the ACI/DSI installation.
For the reasons discussed above, while DTEE did not provide a thorough
analysis of the alternatives to its retirement scenario, it reasonably considered the costs
of new gas-fired plants and market purchases, given the limitation on its ability to
construct a new plant, and the lack of readily-available demand-side management
alternatives. While M/N/S offer reasonable alternative market cost projections, DTEE’s
projections have not been shown to be untenable, although a sensitive analysis should
have been presented to evaluate the extent to which the final results depend on these
forecasts. Additionally, while M/N/S reasonably argue that the full capital expenditure
associated with DTEE’s ACI/DSI installation should be considered in the analysis, it
does not dispute the revised computation provided by Ms. Dimitry to reflect this.
Although DTEE’s analysis was not ideal, this PFD thus concludes that the only
glaring error in DTEE’s analysis is the lack of a credible estimate of its variable O&M
costs. DTEE has had numerous opportunities over the course of multiple cases, as
shown by Dr. Sahu’s analysis, to explain its sorbent and variable cost estimation
procedure and identify the factors responsible for the different estimates. DTEE has
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failed to do so. Even given a chance to respond to Dr. Sahu’s testimony in its rebuttal
case, DTEE did not present a knowledgeable witness, and did not establish that even
its most current estimate was competently determined.
There is no doubt that the variable O&M cost estimate is a significant element of
any reasonable evaluation of ACI and DSI technologies, which have low capital costs
but relatively high ongoing O&M costs, including sorbent expense.105 DTEE did not
explain why it provided significantly different estimates in multiple filings and discovery
responses in MPSC cases, and did not explain why the sorbent use estimates
presented to the MDEQ in 2014 were so much higher than the myriad estimates it used
in its analyses in 2012, 2013, and 2014, and otherwise provided to the Commission and
the parties. Dr. Sahu’s carefully constructed estimate is at the low end of the EEIestimated range of costs, is based on a study DTEE itself relied on at least as recently
as last year, and shows the significant impact on the economics of the installations that
an alternate variable O&M cost estimate can have.
The following chart shows the impact on the net present value of the benefits
DTEE estimated from the ACI/DSI options, with Dr. Sahu’s revised base-case variable
O&M expense, and with Ms. Dimitry’s correction to reflect cost recovery of the
remaining capital balance at the end of the study period:
105
See, e.g., Exhibit A-21, Schedule M8.
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Units
DTEE
Estimated
Net Benefit106
Adjustments for VOM Cost
Adjustment108
remaining
capital
balance107
Net benefit
(loss)
St. Clair 1-4
$54 million
$10.5 million
$39 million
$4.5 million
St. Clair 1-4, and 6-7
$105 million
$21.9 million
$92 million
($7.9 million)
Trenton Channel 9
$83 million
$6.5 million
$42.7 million
$33.5 million
River Rouge 2-3
$16 million
$1.7 million
$17 million
($2.7 million)
These revised figures show that DTEE’s investment is clearly uneconomic for
River Rouge, and for St. Clair units 6 and 7, with little positive benefit shown for St. Clair
units 1-4. Using Dr. Sahu’s “medium case” variable operating costs or the variable
operating cost estimate in DTEE’s RACT analysis would have an even more significant
impact. Because DTEE failed to justify the economics of its ACI/DSI installations, and
in particular because of its significant lack of attention to the variable O&M cost
component of its MATS compliance strategy, this PFD recommends that the
Commission take some action to protect ratepayers. While a disallowance of the capital
expenditures for the River Rouge units and St. Clair units 6-7 is an option, it does not
reflect the significant deficiency in DTEE’s analysis, the sorbent expense. In lieu of
such a disallowance, recognizing that the major analytical failing on DTEE’s part was its
inability to provide a reasonable estimate of its variable O&M expense, this PFD
106
See Exhibit A-21, Schedule M7.
See Exhibit A-25, Schedule O3.
108
See Dimitry, 5 Tr 648; Chernick, 7 Tr 1684 (for River Rouge value).
107
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recommends that the Commission do both of the following: 1) limit DTEE’s variable
O&M cost recovery, including its sorbent cost recovery, only to amounts it can show
were included in its 2013 analysis for St. Clair units 1-4 and 6-7, and Trenton Channel
9, or included in its 2014 analysis for River Rouge units 2 and 3, adjusted for inflation;
and 2) initiate an investigation to determine how DTEE has been making its estimates,
and whether further action on the part of the Commission is warranted. While M/N/S
argue that DTEE’s analysis may also omit additional capital expenditures necessary to
operate these units, the record is inconclusive on this point and the Commission can
address any such capital expenditures if and when DTEE seeks to include them in rate
base.
b. Other non-nuclear generation adjustments.
While Staff does not dispute DTEE’s plans to retrofit its generating plants with
ACI/DSI technology as discussed above, Staff does recommend three adjustments that
reduce the capital expenditures included in rate base. Ms. Simpson testified that Staff
recommends reducing DTEE’s total projected environmental capital expenditure by
$22.4 million based on the results of Staff’s audit showing that DTEE spent $22.4 million
less than projected for 2014.109 She presented Exhibit S-8.1 to show DTEE’s actual
expenditures in 2014 for its air quality projects.
Ms. Simpson also recommended
reducing DTEE’s total projected environmental capital expenditure by an additional
$33.7 million to exclude contingencies included in DTEE’s expense projections. Ms.
Simpson explained:
Staff’s position is that it is inappropriate to earn depreciation and return on
projected contingency expenditures for four reasons: 1) contingency
109
See 8 Tr 2051.
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expenditures for projected years may not be incurred at all; 2) if some
contingency expenditures are incurred, the final amount could be anything
from $1 to the amount projected or possibly even more; while the final
amount that will be expended during projected years is inherently
unknown at the beginning of the test year for all cost categories, the fact
[is] that a projection of contingency expenditures is a range of possible
spending for money that by definition is not truly planned to be spent; 3)
Allowing projected contingency expenditures into rate base may reduce
incentives for cost control; and 4) the Company has a history of over
projecting environmental capital expenditures related to EPA compliance
in past cases including Case No. U-15768 and Case No. U-16472.110
She also explained that if DTEE does reasonably incur costs above the projected level,
Staff would recommend recovery. Staff’s third adjustment involves an additional
projected environmental compliance cost and is addressed below.
Mr. Coppola also recommended an adjustment to DTEE’s fossil generation
capital expense projections, also based on a comparison of 2014 projected capital
expenditures to actual capital expenditures, but unlike Staff’s adjustment, Mr. Coppola
looked broadly at the entire category of projected expenditures, including steam, hydro,
and other capital expenditures, both routine and non-routine. He recommended a total
adjustment of $32.6 million, reflecting the difference between the actual 2014 capital
expenditures as shown in Exhibit AG-9 and the 2014 projections as shown in Mr.
Warren’s Schedule B6.1, page 1, of Exhibit A-9.111
In his rebuttal testimony, Mr. Warren initially stated that both Staff’s adjustments
were inappropriate.112 Regarding the difference between the 2014 projected and actual
expenditures for 2014, he testified that $10 million of the difference is attributable to
DTEE’s ACI/DSI projects. He testified that a large portion of the work associated with
the ACI/DSI projects must be done during planned outages, resulting in less spending in
110
See 8 Tr 2051-2052.
See 9 Tr 2323 to 2324.
112
See 4 Tr 259.
111
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2014, but testified that the Mercury and Air Toxics Standard (MATS) will require
compliance by April of 2016. He testified that the remaining difference of $12.4 million
is associated with completion of the Monroe FGD and SCR “at costs less than
forecasted,” concluding “[I]t is improper to remove all of this forecasted expense and
that recommendation should not be adopted.” 113
Regarding the contingency expenses, he presented Schedule Y6 of Exhibit A-35
to show that “the contingency has been reduced on the ACI/DSI projects from $30.4
million to $4 million,” concluding “it is therefore inappropriate to reduce the project
investment recovery by the additional $33.7 million recommended by Staff Witness
Simpson because a material portion of the ACI/DSI contingency forecast is being spent
on these projects.”114 He further testified that some of the forecast spending was
associated with upgrades or partial replacements to existing plant equipment “to better
support the DSI/ACI operations”, including flyash transporter systems, plant duct work,
and precipitator systems. He testified that the scope of this work was not known in
specific detail when the project forecasts were developed in Exhibit A-9. Nonetheless,
in light of the lower overall ACI/DSI and Monroe project costs shown in Schedule Y6,
Mr. Warren testified that it is reasonable to reduce the forecasted cost of the ACI/DSI
projects by $15.1 and the Monroe FGD/SCR projects by $16.1 million.115
Regarding Mr. Coppola’s testimony, Mr. Warren testified that Mr. Coppola
effectively made the same argument as Ms. Simpson and was addressed in his
response as discussed above.116 In its brief, DTEE reduced its proposed rate base by
113
See 4 Tr 260.
See 4 Tr 260.
115
See 4 Tr 261.
116
See 4 Tr 261-262.
114
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half of the total $31.1 million capital expense reduction identified by Mr. Warren’s
testimony.
In its initial brief, Staff also reviews Mr. Warren’s rebuttal testimony regarding the
difference between projected and actual 2014 environmental capital expenditures and
acknowledges some merit in Mr. Warren’s statement that the ACI/DSI project must be
completed by April 2016, indicating its acquiescence in including $10 million of its $22.4
million adjustment in the capital expense projections.117 Staff’s briefs also make clear
that Staff opposes the inclusion of contingency amounts in the projected test year rate
base, emphasizing that if the contingencies do not occur, ratepayers provide DTEE with
depreciation and a return with no supporting investment, characterizing it as a “real
expense with a speculative benefit that may not exist at all.” Based on Schedule Y6 of
Exhibit A-35, Staff notes that the $33.7 million contingency amount in DTEE’s initial
projections compare closely to the $31.1 million reduction in the company’s revised
ACI/DSI and FGD capital expense projection and the new contingency amount of
$4 million.118
In its reply brief, Staff also argues that Mr. Warren’s explanation for the change in
its projections, and his suggestion that DTEE spent most of the contingency funds,
should be rejected: “This constitutes a flawed attempt at re-categorizing contingency
into non-contingency at the 11th hour with no concrete evidence to show an actual
change.
Staff continues to recommend the Commission disallow $33.7 million in
projected contingency costs.”119 Staff also argues that an additional adjustment should
117
See Staff brief, pages 16-17.
See Staff brief, pages 17-20.
119
See Staff reply brief, pages 8-9.
118
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be made to reflect the $31 million reduction in projected project costs presented in
Schedule Y6 of Exhibit A-35.
In his brief, the Attorney General argues that the Commission should adopt Mr.
Coppola’s adjustments. The Attorney General notes that Mr. Warren did not address
Mr. Coppola’s testimony directly, but did testify that the environmental air quality
projects needed to be completed by April 2016 to meet the MATS deadline.
The
Attorney General argues: “The MATs compliance [is] partially unknown as a result of
the U.S. Supreme Court’s ruling on MATs.”120 He argues that the Commission should
adopt Mr. Coppola’s adjustment. In his reply brief, the Attorney General states that he
also agrees with Staff’s adjustments in the alternative.
M/N/S also argue that contingency expenses should be removed from the fossil
generation environmental capital expenditure projections.
M/N/S endorse Staff’s
reasoning, and they also argue that Mr. Warren’s rebuttal testimony did not satisfactorily
reconcile the difference between DTEE’s initial projections, with the contingencies
initially identified by Staff, and its revised projections with the lower contingency. Citing
Mr. Warren’s testimony on cross-examination, M/N/S argue:
Mr. Warren did not know any specifics about what the contingency funds
have been used for. Moreover, Exhibit A-35, Schedule Y-6 does not
substantiate Mr. Warren’s rebuttal testimony. To document that some
projected costs were originally classified as contingency and then reclassified as they became better known, two things would have to be true
of the exhibit: (a) the contingency amounts would have to be presented
separate from – not included within – the general project costs, and (b) the
amounts added and subtracted as a result of the reclassification would
have to add up or at least be similar, to trace the movement of the dollars.
121
120
121
See Attorney General brief, page 40.
See M/N/S reply brief, page 59, citing Warren, 4 Tr 267-270.
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In its reply brief, DTEE denies the suggestion in Staff and M/N/S briefs that the
company’s revised environmental capital expense projection reflects additional
expenditures not contemplated in its plan. DTEE argues:
Staff also appears to misunderstand DTE Electric’s testimony and exhibits
in suggesting that “it looks like the Company is simply moving money from
one ‘bucket’ to another” (Staff Initial Brief, p 19). MEC/NRDC/SC similarly
asserts that “it is difficult to understand how the total project costs could be
going down when most of the contingency dollars are in fact being spent”
(MEC/NRDC/SC Initial Brief, p 60).
Staff and MEC/NRDC/SC fail to recognize that work was done over time,
resulting in both a decrease in the contingency and decreased project
costs. It should come as no surprise that more than one thing happened
as time passed. Exhibit A-35, Schedule Y-6 clearly shows that only $4
million of contingency remains (4 T 260-61; Exhibit A-35, Schedule Y-6).
The record also reflects DTE Electric’s $15 million ACI/DSI reduction and
a $16 million FGD/SCR reduction due to lower projected costs. (4 T 261,
270-71, 288) 122
DTEE also argues in its reply brief that incorporating both Staff’s $33.7 million
contingency adjustment and its $31.1 million reduction in projected costs would be
double-counting. DTEE addresses the Attorney General’s proposed adjustment based
on the difference between projected and actual 2014 expenditures by arguing that Staff
and DTEE are in agreement that the appropriate adjustment to reflect that difference is
$12.4 million, citing Staff’s agreement that the company will complete its ACI/DSI
spending by the end of the projected test year to meet the MATS compliance target.123
Despite the somewhat confusing rebuttal testimony presented by Mr. Warren,124
this PFD concludes that Exhibit A-35, Schedule Y6 contains DTEE’s most recent
projection for the total cost of its ACI/DSI and Monroe air quality environmental projects
through the projected test year.
122
A review of this projection shows that DTEE has
See DTEE reply brief, page 29.
See DTEE reply brief, page 28.
124
Also see his cross-examination, e.g., 4 Tr 266-271, 293.
123
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lowered its projection by $31.1 million for both projects, and that this revised projection
also contains a contingency amount, but a much smaller contingency amount totaling
$4.1 million. Thus, although Staff’s reply brief seems to recommend that both Staff’s
contingency adjustment ($33.7 million) and DTEE’s $31.1 million adjustment should be
made, DTEE’s revised lower projection no longer contains $33.7 million in
contingencies, but only $4.1 million.
There is no real dispute that DTEE’s environmental air quality capital expense
projections should be reduced by at least $31.1 million, since DTEE no longer projects a
greater cost. This PFD finds Staff’s testimony and arguments of Staff and intervenors
persuasive that projected capital expenditures that are included in rates should not
contain contingency amounts. Therefore, this PFD recommends that the Commission
also exclude the $4.1 million remaining contingency component of DTEE’s projections,
resulting in a total reduction of $35.2 million to DTEE’s projections as filed in Schedule
B6.1 of Exhibit A-9. Any further contingency adjustment would be double-counting, as
DTEE argues.
Turning to the question of whether the difference between DTEE’s projected and
actual 2014 environmental capital expenditures warrants an additional adjustment, as
noted above, Staff acknowledged that DTEE needs to complete its ACI/DSI spending by
the end of the projected test year to meet MATS requirements, and correspondingly
indicated that Staff’s $22.4 million adjustment should be reduced to $12.4 million.
DTEE has also indicated that a $12.4 million adjustment is reasonable to reflect the
difference in spending.
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While Staff and M/N/S are correct that they were not able to inquire into the
details of DTEE’s revised projections as contained in Schedule Y6 of Exhibit A-35, given
the significant expense reduction DTEE acknowledged in its revised projections, and
given Staff’s acceptance of the ACI/DSI project deadline, this PFD finds that it is
reasonable to accept the non-contingency elements of DTEE’s revised projection,
particularly given DTEE’s agreement to the further $12.4 million adjustment.
Turning next to the Attorney General’s proposed $32.6 million adjustment, DTEE
argues that by resolving the disputes on the air quality capital expenditures, it has fully
addressed Mr. Coppola’s recommendation. Instead, it largely but not completely
resolves Mr. Coppola’s adjustment. As noted above, Mr. Coppola looked at the
difference between projected and actual 2014 expenditures for DTEE’s entire fossil
generation capital expense budget. While $24.9 million of that is roughly attributable to
the environmental capital expenses discussed above, the remaining difference between
that $24.9 million and his total $32.6 million adjustment reflects the difference between
2014 actual and projected expense in the “hydro” and “other” budget categories as
shown in Schedule B6.1 of Exhibit A-9 and Exhibit AG-9. In these categories, an $8.7
million reduction in actual spending compared to projected spending in the “hydro”
category is offset by an increase in actual spending compared to projected spending in
the “other” category. As the Attorney General argues, DTEE did not specifically address
Mr. Coppola’s adjustments, treating them as equivalent to Staff’s recommendation.
Since Mr. Coppola identified a material difference between the actual spending
presented in his Exhibit AG-9 and the projections in Mr. Warren’s Schedule B6.1 of
Exhibit A-9, not attributable to the environmental projections discussed above, this PFD
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concludes that the capital expense projections for the fossil generation category should
also be reduced by an additional $7.7 million.
Finally, there is one additional adjustment that needs to be addressed in this
category. Ms. Simpson’s third recommended adjustment reduced DTEE’s projected
capital expenditure for amounts slated for the Monroe Dry Ash Conversion project
designed to comply with the Resource Conservation and Recovery Act (RCRA). Ms.
Simpson recommended removal of projected test year costs of $800,000 for 2015 and
$2,450,000 for the first 6 months of 2016.
She testified that the final rule was
promulgated after DTEE’s filing in this case, and other information she obtained from
the company indicated its plans were vague, so Staff is not certain that the construction
will take place during the projected test year.125 Staff argues in its brief that DTEE did
not present rebuttal testimony refuting this adjustment. This PFD finds Staff’s analysis
persuasive and recommends that the Commission adopt the additional RCRA-related
adjustment. As Ms. Simpson testified, if DTEE actually undertakes the project and its
expenditures are reasonable and prudent, it will be included in rate base.
Based on the foregoing analysis, the total adjustment this PFD recommends to
the fossil generation capital expense projection is $58.5 million.126
2. New generating plants
In its initial filing, and as explained by Ms. Dimitry, DTEE stated that it planned to
purchase the Renaissance Power Plant, and to purchase a 300 MW gas-fired peaking
plant. Regarding these planned purchases, Ms. Dimitry testified that DTEE identified a
need to purchase approximately 900 MW of capacity to meet its peak requirements.
125
126
See 8 Tr 2054-2055.
$31.1 + $4.1 + $12.4 + $7.7 + $3.2 = $58.5
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She testified that DTEE has historically relied on the Midcontinent Independent System
Operator (MISO) annual capacity auction, but MISO anticipates a reserve margin
shortfall beginning in 2016.127 She testified that DTEE retained an independent
consultant (Charles River Associates) to assist in the process of soliciting and
evaluating bids, and on June 2, 2014, DTEE issued a Request for Proposals to
potentially purchase 900 MW of Michigan-based gas-fired generation. She testified that
DTEE received three bids, and evaluated the bids using what she labeled a “least cost”
methodology focused on the lowest revenue requirement. She testified that based on
this analysis, DTEE selected the 732 MW Renaissance Plant with a purchase price of
$240 million, shown in Exhibit A-9, Schedule B6 as “acquisition 1”, with an additional
$25 million in spare parts included in the 2015 capital expense forecast in Ms. Dimitry’s
Schedule B5 of Exhibit A-9. She testified that DTEE expects to close the transaction
the first quarter of 2015, and further explained the benefits from the transaction. No
party challenged this acquisition.
Ms. Dimitry’s direct testimony included the statement that DTEE “intends to solicit
bids” to acquire an additional 300 MW of Michigan-based simple cycle gas fired
generation at a cost of approximately $100 million, basing the estimated $100 million
cost on the cost of the Renaissance Plant. She testified that this amount, with an
additional $10 million included in DTEE’s capital expense projection in Exhibit A-9,
Schedule B5, for spare parts, and an additional $1.1 million in O&M expenses, were
included in DTEE’s rate projections.128 She did not revise this direct testimony.129
127
See 5 Tr 601.
See 5 Tr 613.
129
On May 13, 2015, DTEE did file a revision to one of the schedules Ms. Dimitry sponsored, Schedule
M1 of Exhibit A-21.
128
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In his direct testimony, Mr. Coppola explained:
On May 18, 2015, in response to Staff data requests, the Company
announced that the qualified bid is an affiliated merchant plant owned by
DTE Energy Services. The DTE East China Power Plant is a 350 MW
generating facility and is located in southeast Michigan. The Company
estimates it will purchase the power plant for $68.2 million plus $4.7
million of spare parts. According to the Company, it will not know the exact
purchase price until after the closing of the transaction, because the
purchase price is calculated based on the plant’s book value after
depreciation. An added complication is the fact that the land on which the
plant was built was sold by DTEE to East China at a gain.130
Mr. Coppola recommended that the Commission not include the costs of the East China
plant in rates for the projected test year:
The information that the Company plans to purchase the East China
Power Plant was received four days before testimony was due in this
case. No realistic opportunity for discovery and investigation of the
acquisition has been accorded to the parties to this rate case. The fact
that this transaction is with an affiliate of the Company raises the level of
scrutiny needed to ensure the acquisition is an appropriate addition to rate
base. We do not know yet when the transaction will close and what the
final purchase price will be.
These are critical pieces of information that need to be nailed down before
any party can acquiesce to the inclusion of all or a portion of the plant cost
in rate base. My conclusion is that including any portion of the acquisition
cost of the second power plant in the rate base in this rate case is
premature. Therefore, I recommend that the original $100 million
forecasted capital acquisition cost and the related $10 million in spare
parts, or a total of $110 million, be removed from the Company projected
capital expenditures.131
In his brief, the Attorney General cites Mr. Coppola’s testimony, noting that DTEE
indicated it would not know the exact purchase price until after the closing of the
transaction, and noting that DTEE did not provide rebuttal to Mr. Coppola’s testimony.132
130
See 9 Tr 2325.
See 9 Tr 2326.
132
See Attorney General brief, pages 42-43.
131
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Staff, however, supported recovery of the estimated cost of the East China Plant.
In her initial testimony, Ms. Simpson reviewed DTEE’s Renaissance Plant acquisition in
some detail, and indicated that Staff was not taking issue with the proposed
expenditures for either of the two acquisitions as proposed by DTEE. She did not
mention the East China plant. In her rebuttal testimony, responding to Mr. Coppola’s
objection, Ms. Simpson testified that the company’s original estimate of $100 million
should be revised, presenting Exhibit S-13.1 to provide the cost details. She testified
that the $68.2 million estimated purchase price meets the requirements of the Uniform
System of Accounts, which requires that utility assets be recorded at the original cost of
the entity first devoting the asset to public service, as well as the Code of Conduct,
because the price is the book value after depreciation. She testified that the purchase
provides DTEE with the necessary resources to serve its bundled customer load, and
the price appears to be significantly below the current market price on a dollars per
kilowatt basis. She presented Exhibit S-13.2 to show DTEE’s “least cost” analysis of
the purchase. She also testified that DTEE had disclosed that the RFP for this project
had been issued on January 30, 2015 in its April 1, 2015 filing in Case No. U-17751.133
In its brief, Staff acknowledges Mr. Coppola’s testimony, and argues: “Although the late
nature of the information did present challenges, Staff nevertheless believes that the
acquisition of the East China Power Plant is reasonable and prudent.”134
In addition to providing no testimony specifically regarding the East China plant,
DTEE also did not address Mr. Coppola’s testimony in its initial brief, but does agree
133
134
See 8 Tr 2059-2061.
See Staff brief, page 24.
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with Staff that its $100 million-plus cost estimate should be revised.135
DTEE
recommends adopting Staff’s adjustment plus an additional $2.8 million for capital
maintenance expense for the plant.136 In its reply brief, DTEE argues that the purchase
should be approved, citing Staff’s testimony and Staff’s initial brief. DTEE then argues:
“The record further reflects that as a result of DTE Electric’s Request for Proposal
(“RFP”) process and due diligence effort, the Company selected the East China Power
Plant as the winning bid based on the “Least Cost” approach with its purchase resulting
in the lower revenue requirements for the Company’s customers.”137 The only portion of
the record DTEE cites in support of this testimony is Ms. Simpson’s rebuttal testimony
and her Exhibit S-13.2. DTEE goes on to argue: “Recent estimates suggest that the
cost to acquire the East China power plant will be lower than originally anticipated.”138
In their reply brief, M/N/S agree with the Attorney General’s recommended
adjustment, arguing that DTEE’s request to include the East China Power Plant in rate
base is untimely. M/N/S note that DTEE relies on Staff’s rebuttal testimony and exhibits
for the cost information and “least cost” evaluation that support its request for approval.
M/N/S also cite Mr. Chernick’s testimony that the RFP that was issued sought
combustion turbines physically located within MISO Zone 7, of about 300 MW in size,
such that the East China plant appeared to be the only facility that met that criteria.139
To M/N/S:
It is highly unusual, to say the least, to acquire an affiliate generating plant
halfway through a rate case, on the eve of Staff and Intervenor testimony,
135
See DTEE brief, pages 116-117.
This appears to be DTEE’s estimated adjustment to rate base, with the capital expense estimated at
$1.1 million in 2015 and $3.3 million in 2016.
137
See DTEE reply brief, page 109.
138
See DTEE reply brief, page 110.
139
See 7 Tr 1692.
136
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and then request that the plant be approved for inclusion in rate base.
That other parties were not able to adequately review and respond to this
evidence is an understatement. For the reasons articulated by the
Commission in Cases U-16034-R and U-16794, DTE’s request should be
denied, and the company should be encouraged to return in a future
proceeding and make the request as part of its specific, filed case.140
This PFD appreciates that Staff went to some effort to validate the
reasonableness of DTEE’s plan to acquire the East China plant from DTE Energy
Services, under a challenging time frame, and that no party directly challenged Staff’s
analysis. Nonetheless, Staff’s analysis can only be as reliable as the information it was
given. The information Staff was given, as shown in Exhibit S-13.1, indicates that the
pricing information is only an estimate, and indicates that as of the date provided, the
transaction has not closed. DTEE did not provide any evidence in this case to show
that the transaction would close before the end of the test year, let alone by the June
30, 2015 date assumed in its rate case filing, or establish what the final price would be.
As Mr. Coppola testified: “We do not know yet when the transaction will close and what
the final purchase price will be.” Neither DTEE nor Staff provided an answer to Mr.
Coppola’s statement. Additionally, while DTEE refers to a “due diligence” process, and
while DTEE’s “least cost” analysis is summarized in Exhibit S-13.2, there is no evidence
regarding any due diligence DTEE undertook, including efforts to assure itself that the
plant is in good condition with no material defects.
This PFD recommends that the projected expenses be excluded from rate base.
Because DTEE included these costs in its rate case projections, it was incumbent upon
DTEE to seek to correct its projections when it became clear they were no longer
accurate. This PFD finds that DTEE has not supported that it will incur this capital
140
See M/N/S reply brief, pages 25-26.
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expense within the projected test period. It is also reasonable to consider that DTEE is
purchasing this plant from an affiliate and as supported by Mr. Coppola’s testimony, the
intervenors were unable to review the proposed transaction within the framework of this
case. As M/N/S argue, the Commission should encourage DTEE to file for approval of
the costs associated with this projected acquisition in a future case.
Indeed, the
Commission may provide for an expedited single-issue proceeding.
3. Nuclear generation (Fermi 2)
Mr. Colonnello presented DTEE’s testimony regarding projected capital
expenses of $429,449,000 including nuclear fuel expense, for 2014 through the end of
the projected test year, detailed in his Schedule B6.2 of Exhibit A-9.141
Mr. Coppola took issue with DTEE’s projection of one component of its projected
capital expenditures for Fermi 2. He identified projected expenditures of $4.4 million for
2015 and $2.1 million for the first half of 2016 included in DTEE’s capital expense
projections for “emergent projects.” He further testified that DTEE’s response to the
Attorney General’s data request seeking additional information was a statement that no
additional information could be provided because the dollars represent contingency
amounts. He recommended that these contingency amounts be excluded from rate
base on this basis.142
In his rebuttal testimony, Mr. Colonnello testified to his opinion that additional
expenditures are highly likely to arise.143 In its brief, DTEE relies on this testimony in
arguing:
141
See 6 Tr 1171-1175.
See 9 Tr 2324-2325.
143
See 6 Tr 1185-86, 1199-1205.
142
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It is reasonable and prudent for DTE Electric to maintain a contingency
reserve in anticipation of emergent issues that will require funding.
Emergent conditions typically surface following scheduled inspections
during refueling outages, or from emerging regulations that are not
finalized prior to establishing the capital budget for a year (such as the
evolving NRC regulations associated with the Fukushima nuclear
incident). It is unreasonable to expect perfect foresight with regard to
such matters, so it is necessary to maintain contingency reserves to cover
these highly probably events of uncertain scope.
It would be
unreasonable to fund these events as they arise by shifting funds from
other projects that would have to be suspended. This would be inefficient
and disruptive, and also inappropriate because those projects are wellfounded, undisputed, and should be done without delay.144
This PFD recommends that Mr. Coppola’s minor adjustment to DTEE’s projected
nuclear expense capital budget be adopted. “Contingency” spending is not consistent
with the “known and measurable change” method DTEE claims it employed as the basis
for its projected test year capital spending. It is also inconsistent with guidance given by
the Commission regarding the reliability of future projections. Moreover, despite its
rhetoric, DTEE has not established that it has a “contingency reserve” earmarked for
nuclear capital expenditures that would provide protection for ratepayers in the event
the contingencies do not materialize. As it is, by including DTEE’s capital expense
projections for the upcoming test year in rate base, the Commission is providing both a
return on the anticipated but not yet actual capital investment, as well as a return of a
portion of that investment, with no safeguards for ratepayers in the event that DTEE’s
estimates for actual projections turn out to be erroneous. As concerns these specific
expenses, note that Mr. Colonnello testified in June of 2015, essentially only one year
out from the end of the projected test year. It is difficult to credit that any significant
capital investments will be required over that 12-month time period that cannot yet be
identified, or that DTEE does not have access to working capital or capital infusions to
144
See DTEE reply brief, pages 62-63.
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address those investments. As ratemaking works, even if the Commission included the
requested amounts in rate base, DTEE would only receive a portion of that capital
expenditure spread out over the course of the test year, and subject to rate revision
after that.
4. Electric Distribution System
The largest category of proposed capital expenditures is for DTEE’s distribution
system, with projected capital expenditures for 2014 through the first 6 months of 2016
totaling approximately $1.2 billion, as shown in Exhibit A-9, Schedule B6.3, presented
by Mr. Pogats.145
In his testimony and in Schedule B6.3, he broke the proposed
expenditures into the following categories: new business; “system strengthening and
reliability”--which includes reliability, vegetation management, general load growth, new
business specific projections, major equipment, substation improvements, and customer
advances for construction; and “system strengthening blanket”—which includes
increased loads, system improvements, relocations, normal retirement unit changeouts,
and emergency retirements and changeouts. Staff and the Attorney General take issue
with the level of these capital expenditures, and Staff takes issue with DTEE’s proposal
to capitalize a portion of its vegetation management expenses. The capitalization issue
is discussed in section a below, the disputed spending levels are discussed in section b.
a. Vegetation Management
Although the parties dispute the appropriate funding levels for DTEE’s vegetation
management activities, a key dispute involves DTEE’s request to capitalize the
145
The total is $1.179 billion.
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projected $45 million in annual expenses associated with its new Enhanced Vegetation
Management Program (EVMP) beginning in 2015.
As explained by Ms. Uzenski, DTEE has reviewed its capitalization policy and
has identified revisions.
DTEE proposes to capitalize certain storm-related or
restoration-related expenses that have previously not been capitalized. This proposal
was not opposed by any party. As part of its distribution system operations, DTEE also
proposes a new program to significantly expand its clearing activities within its
distribution right of way, and proposes to capitalize the $45 million expenditure planned
for this program. While there is a dispute among the parties (DTEE, Staff, and the
Attorney General) regarding the appropriate level of expenditure for this program, this
section of the PFD addresses whether those expenses should be capitalized and
included in rate base.
Mr. Pogats testified to the importance DTEE places on maintaining a reliable
distribution system, and identified the System Average Interruption Duration Index
(SAIDI), measuring the total time of all customer interruptions divided by the total
number of customers on the system, as the key measure of reliability DTEE uses.146
He explained DTEE’s proposed revision to its vegetation management program. He
testified that DTEE intends to clear one-third of its annual target area using “Enhanced
Vegetation Management Practice” (EVMP) under which all vegetation that has the
ability to grow into or overhang the power lines within five years is removed, while twothirds of DTEE’s effort will use the traditional method of line clearance based on 15 feet
from the centerline of the pole.147 Mr. Pogats testified that under the EVMP program,
146
147
See 6 Tr 363.
See 4 Tr 364-365.
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the clearing will be significant. He cited two prior occasions where DTEE had used this
technique and testified that the results were positive.148
Mr. Pogats and Ms. Uzenski testified that DTEE proposes to capitalize the EVMP
expenses. Ms. Uzenski explained that DTEE proposes to capitalize the EVMP costs as
the “first clearing and grading of land and rights-of-way”, characterizing the proposed
expenditures as an “expansion of the first clearing.”149
Mr. Derkos testified that Staff does not support capitalizing the EVMP expenses,
because it views the program as part of right-of-way maintenance and does not view the
program as right-of-way development or the “first clearing” of the right of way:
In late 2014, the Company created a new practice, in addition to the
Company’s normal vegetation management program, called the Enhanced
Vegetation Management Practice (EVMP). The Company now proposes
to capitalize $45 million of expenditures for this practice. The Company
argues that this is the first time this particular vegetation has been cleared,
so the expense should be capitalized. Staff does not support the moving
of dollars spent on vegetation management from Distribution O&M
expenses for the new EVMP to the distribution capital budget. Staff’s
position is that all vegetation management program expenses continue to
be included as part of Distribution O&M expenses. Staff’s position that the
Company’s EVMP expenses of $45 million not be capitalized is not based
on an accounting perspective, but an engineering opinion that costs
incurred in connection with this vegetation management program is not
the first time of such clearing on rights-of-way for the circuits in which the
clearing is going to be completed. Rather, it is a matter of expanded
routine maintenance.150
In his rebuttal testimony, Mr. Pogats disputed Mr. Derkos’s characterization of this as a
maintenance or O&M program, testifying that the program extends the life of the
distribution assets and reduces outage events. He presented a table at 4 Tr 394 and
presented Exhibit A-34, Schedules X1 and X2, to show the difference between the
148
See 4 Tr 366.
See 6 Tr 1031.
150
See 8 Tr 2087-2088.
149
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current method and EVMP in terms of the three-dimensional area cleared.
He
presented significantly greater detail on the EVMP than he presented in his initial
testimony, explaining that different clearing measures will be used for different zones,
and explaining how the different zones will be approached over the initial 10-year period
of the program.151
He also testified that customers would benefit from the program additionally
because DTEE was going to do community outreach to explain the extent of the
clearing to be undertaken:
Q. Will the additional level of expenditures associated with EVMP benefit
customers in ways other than improving the reliability of their electric
service?
A. Yes. One of the key processes in the Company’s EVMP is focused on
improving the vegetation management work and communications with
customers, property owners and other key stakeholders, such as
municipal officials prior to the work starting. DTEE’s customers will be
informed about the purpose of EVMP and have an opportunity for a faceto-face discussion with Company representatives about the scope of work
on their property. DTEE’s experience is that this results in much higher
community acceptance of EVMP and greater customer satisfaction with
the Company’s overall VM efforts (which will result in fewer MPSC outage
complaints). All of this forms a key foundation for the Company’s
educational programs aimed at encouraging customers to plant the “right
tree in the right place”.152
In its brief, Staff reiterates its objection to capitalizing this expense, arguing that
the EVMP is merely expanded routine maintenance, and is not the first clearing, arguing
that DTEE has had many chances to maintain its lines after the first clearing, and is now
covering the same mileage.153
151
See 4 Tr 392-396.
See 4 Tr 399.
153
See Staff brief at page 9, 12-13, citing 8 Tr 2085, 2088-2098.
152
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DTEE’s brief argues that the EVMP are a capital investment because the new
clearance corridor is substantially different than the traditional 15-foot clearance circuit,
and will have substantial long-term positive effects on equipment life and reliability.154
DTEE cites Mr. Pogats’s rebuttal testimony that DTEE’s historical practice was to trim
only the vegetation that was necessary to install the conductors and prevent any
interference with the pole-top equipment, arguing that “the first trimming to install new
overhead lines has never been performed to the extent and depth of the EVMP
clearing.”155 DTEE also argues that other utilities have been permitted to capitalize the
expenses associated with these efforts.156
Staff’s reply brief discusses this issue extensively, arguing that DTEE’s use of the
term “first-time expansion” to describe the clearing misleadingly equates it to the “first
clearing”, and arguing that DTEE’s proposed capitalization does not meet the
requirements of the Uniform System of Accounts, which permits capitalization of the
“first clearing and grading of land”.157 Staff argues: “The fact that the Company may
originally have chosen a practice less robust in scope does not mean that its expense to
maintain the [right of way], even in a more robust manner, may be categorized as a
capital expenditure.”158 Staff rejects reliance on Mr. Pogats’s testimony that certain
utilities in other states have been allowed to capitalize EVMP expenses, arguing that
DTEE has not described those programs in detail, and the facts and circumstances
presented in those cases are not before the Commission.
154
See DTEE brief, page 68-, citing 4 Tr 365, 414.
See DTEE brief, page 70.
156
See 4 Tr 397-398, 415.
157
See Staff reply brief, pages 4-5.
158
See Staff reply brief, page 5.
155
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Although there are differences in proposed expenditure levels for the EVMP
among the parties, this section addresses whether the EVMP should be capitalized.
This PFD finds Mr. Derkos’s testimony and Staff’s arguments persuasive that the
expanded clearing encompassed in the enhanced vegetation management program
does not constitute a “first clearing” of the right of way, and should not be capitalized.
While the extent of the clearing under the program is significantly expanded with the
EVMP, it is still part of an ongoing clearing effort. As Mr. Pogats described the program,
it removes all vegetation that could overgrow DTEE’s lines within a five-year period.159
Although Mr. Pogats testified that DTEE expects to obtain long-term benefits from this
level of clearing, DTEE made no effort to match the period over which benefits would be
received to the time period over which customers would be paying the clearing costs
through depreciation and return on rate base, if they are capitalized. Presumably, by
capitalizing the “first clearing” of a right of way, the capitalized expenses are
depreciated along with the improved right-of-way, which is typically a long period of
time.
If the Commission allows capitalization of this expense, ratepayers could be
paying both rate base and depreciation expense for many years, while continuing to pay
for the same recurring expenses once the initial round of EVMP clearing is
completed.160 At DTEE’s proposed level of expenditure of $45 million per year, rate
base would increase by approximately $450 million over that ten year period.
In his rebuttal testimony, Mr. Pogats repeatedly mischaracterizes Mr. Derkos’s
testimony, contending that Mr. Derkos testified that DTEE previously cleared the right of
way to the same extent. For example, Mr. Pogats testified at 4 Tr 394-5:
159
160
See 4 Tr 365.
“[T]he cost of the first implementation of this program in an area is a capital investment.” 4 Tr 365.
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Q. What justification does Witness Derkos provide that EVMP is an O&M
program?
A. On page 9 of his Direct Testimony, Witness Derkos states that “Staff’s
position that the Company’s EVMP expenses of $45 million not be
capitalized is not based on an accounting perspective, but an engineering
opinion that costs incurred in connection with this vegetation management
program is not the first time of such clearing on rights-of-way for the
circuits in which the clearing is going to be completed. Rather, it is a
matter of expanded routine maintenance.”
Q. Is this assertion above – that the rights-of-way for newly installed lines
were completely cleared of vegetation per the EVMP practice – generally
true?
A. No, it is not. Prior to EVMP, DTE Electric’s vegetation management had
no practice requiring complete clearing. Now, the practice for EVMP in
zone one calls for complete clearing within 15 feet from the center of the
pole-line. Zones two and three call for complete clearing except for
vegetation that will not exceed a height of 20 feet.161
Because this PFD finds that capitalization of these expenses is not appropriate, the
disputes over the funding levels are discussed below in conjunction with O&M
expenses.
b. Spending levels
In addition to the EVMP program, DTEE proposes substantial capital
expenditures for its distribution system. Mr. Pogats testified regarding DTEE’s efforts to
improve reliability:
There are four major efforts that the Company has underway to improve
overall reliability. First is an enhancement to the vegetation management
program to prevent outages. Second is a continuous improvement effort to
the Company’s Repetitive Outage Pocket Program. Third is a program to
reduce the number of customers affected and improve the restoration time
when outages do occur. Fourth is increasing the maintenance activity for
key distribution assets.162
161
Also see 4 Tr 395: “For newly installed lines the rights-of-way were not cleared to the EVMP practice
as Witness Derkos suggested.”
162
See 4 Tr 364.
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As shown in Schedule B6.3 of Exhibit A-9, putting aside the proposed EVMP capital
expenditures, DTEE is proposing capital expenditures totaling $1.1 billion for 2014
through the first six months of 2016.
Both Mr. Coppola and Mr. Dekos took issue with DTEE’s proposed expenditure
levels. Mr. Derkos testified that DTEE has significantly increased its distribution system
capital spending in recent years.
He presented information showing DTEE’s 2014
spending level is over 23% above the average of the prior five years, and indicating that
DTEE is proposing to increase spending significantly further, more than 26.6% from the
historical test year through the projected test year.163 In the last two years, he testified,
DTEE has already increased capital spending by 30%.164 Although acknowledging that
recent performance metrics are “starting to trend the wrong way”, he testified that Staff
does not believe DTEE has supported the additional level of capital expenditures
requested, reflecting a “further sharp increase” in spending.
He testified that Staff
believes that DTEE’s 2014 level of expenditure is reasonable, and recommends that the
Commission approve that level for the projected test year, adjusted for inflation each
year, resulting in a total capital expenditure of $454.382 million, or a reduction to
DTEE’s proposed capital expenditure of $42.830 million, as shown in Exhibit S-10.1.
He testified that Staff’s approach does not target any particular line item of spending,
but “Staff’s position is to arrive at a total Distribution Capital budget and allow DTE
Electric to make decisions on how to distribute the money to each category to maximize
the increase in reliability.”165
163
See 8 Tr 2085-86, Exhibit S-10.3.
See 8 Tr 2087.
165
See 8 Tr 2087.
164
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Mr. Coppola also expressed a concern with the proposed level of spending. He
looked specifically at two individual categories of expense, “new business” and
“reliability.” He testified that DTEE proposed capital budget for 2016 included a line
item “miscellaneous/undesignated new business” in the amount of $11.8 million, for
“unknown potential new business projects that may occur during the year.”166
He
testified that the level of expenditure for this category was only $2.9 million in 2014.167
He characterized this as a “catch-all of what may occur . . . not specific to any planned
project.” He recommended that the expenditure category be limited to the 2014 actual
level, excluding $8.8 million:
“The Commission should not approve unknown and
obscure capital expenditures for inclusion in rate base and rates. Such expenditures do
not pass the basic test of being used or useful if it is not known what they are for.”168
Under the “reliability” category, he testified that DTEE forecast a total of $122
million in capital expenditure for 2014 through the first six months of 2016 for “DurationEfficient Frontier.” He testified that Mr. Pogats did not specifically discuss this in his
testimony, and no justification was provided why this level of expenditure is needed.169
He testified that DTEE’s response to a data request indicated that the “Duration-Efficient
Frontier” is the same as the “Repetitive Outage Pocket Program,”170 which is a separate
line item in Schedule B6.3.
He testified that the 2014 expenditure reflects a 63%
increase over 2013 levels, and DTEE’s projections for 2015 and 2016 increase
additionally by 17% and 19%, more than doubling the 2013 levels. He recommended
that the Commission limit DTEE’s spending to not more than $40 million annually for
166
See 9 Tr 2320-2321.
See 9 Tr 2320.
168
See 9 Tr 2321.
169
See 8 Tr 2321-2322.
170
See 8 Tr 2321.
167
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this category, resulting in a $26 million recommended reduction in the total capital
expenditure for this category.
In his rebuttal testimony, Mr. Pogats testified that Staff’s five-year-average based
adjustment did not account for inflation or the impact of the EVMP, presenting Schedule
X8 in Exhibit A-34 to demonstrate his calculation of a 15% increase rather than a 36%
increase in capital spending over the five-year average. He also asserted that his direct
testimony described how reliability programs benefit customers, citing his testimony at 4
Tr 368-369 regarding repetitive outage pockets, and at 4 Tr 369-372 describing how
“Reducing the Scope and Restoration Time of Outages” improves specific circuit
performance and may reduce overall SAIDI by 45 minutes.171 Relying on a national
survey of 36 utilities showing DTEE’s 2014 SAIDI statistics in the fourth quartile—see
Exhibit A-34, Schedule X7-- he testified that effective investments can reduce SAIDI
and testified: “Michigan’s fourth quartile reliability status could impact the competitive
position of some businesses located in Michigan and could influence the decision
making of businesses considering locating to Michigan. A prime objective for DTE
Electric is to be a force of growth in Michigan, which requires improvements in
reliability.”172
Addressing Mr. Coppola’s testimony regarding the new business category of
expense, he testified that since DTEE filed its case, “several specific projects for 2016
have been requested by customers and plans are being developed for this work,” listing
171
172
See 4 Tr 405.
See 4 Tr 405.
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some projects at 4 Tr 411. Regarding the “Duration-Efficient Frontier”, he testified that
the program is not the same as the “Repetitive Outage Pocket Program”.173
Notwithstanding $1.2 billion in proposed capital expenditures for distribution
system operations ($1.1 billion not including a total of $67.8 million designated for the
EVMP for 2015 and the first six months of 2016), this PFD finds that DTEE’s evidentiary
presentation is minimal and does not include a cost-benefit analysis. There is no
testimony in this record to show how these programs are integrated, or how the
programs collectively are cost-justified or goal-oriented. Mr. Pogats’s entire financial
presentation regarding these costs in his direct testimony was limited to the single-page
schedule B6.3.
Mr. Coppola’s attempt to find out about the Duration Efficient Frontier is
illustrative.
Mr. Pogats took issue with Mr. Coppola’s understanding--based on
information supplied by DTEE—that the “Duration Efficient Frontier” program was the
same as the “Repetitive Pocket Outage Program”, testifying that the Duration Efficient
Frontier program is part of the “Reducing the Scope and Restoration Time of Outages”
effort, which “focuses on a systematic proactive approach to improve reliability and
restoration for all circuits in the service territory,”174 while the Repetitive Pocket Outage
Program “focuses on reactive reliability solutions for a section of a circuit.”175 A review
of Mr. Pogats’s direct testimony, however, shows that he testified that both programs
target parts of DTEE’s system that have demonstrated problems: the Repetitive Pocket
Outage Program looks at problems associated with customers with multiple outages in
173
See 4 Tr 411 to 412.
See 4 Tr 411-412
175
See 4 Tr 412.
174
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a calendar year,176 while the Reducing the Scope and Restoration Time of Outages
effort looks at circuits with the highest SAIDI.177 DTEE does not provide any examples
measuring the benefits of the Repetitive Pocket Outage Program, and does not explain
the overlap between the two programs, i.e., how often customers with multiple outages
in a calendar year are served by circuits with the highest SAIDI. Thus, Mr. Pogats’s
rebuttal testimony does not truly address Mr. Coppola’s concern.
Likewise, Mr. Pogats’s explanation of the “System Strengthening and Reliablity”
and “System Strengthening Blanket” categories of expense at 4Tr 378-381 is not clear.
Essentially, he testified that both are driven by load growth or reliability. Additionally,
while Mr. Pogats provided rebuttal testimony to substitute proposed “new business”
expenditures for 2016 in lieu of the “miscellaneous new business” category identified by
Mr. Coppola, he did not separately break down the dollar figures to show the amounts
likely to be spent in the first six months of 2016. Note that most of the specific projects
listed in his spreadsheet span multiple years, and the projects he has listed in his
rebuttal testimony are not recurring from prior years, thus begging the question whether
it is at all realistic to expect the listed sums to be spent in the first six months of 2016.
As noted above, Mr. Pogats took issue with Staff’s review of the company’s
capital expenditures in Exhibit S-10.3, presenting Schedule X8 to show historical capital
expense projections adjusted for inflation, and excluding the EVMP funding included in
the 2015 and 2016 projections.178 Even as adjusted, the figures on Schedule X8 show
increases in capital spending of 11% each of the last two years, from 2012 to 2013 and
176
See 4 Tr 368.
See 4 Tr 370.
178
This schedule also indicates that he has excluded “storm cap” from the adjusted figures. Although he
does not explain this adjustment in his testimony, it presumably adjusts for the change in capitalization of
storm labor as discussed above.
177
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from 2013 to 2014, clearly above the rate of inflation, and an increase of 15% measured
with reference to the five-year average. Staff and the Attorney General argue that
DTEE did not present any specific evidence or cost-benefit analysis to show that the
increased expenditures would result in a related increase in distribution reliability.179 As
Mr. Coppola’s uncontradicted testimony indicates, DTEE was asked to identify expected
improvements in its power outage metrics from its expanded vegetation management
program and did not identify any potential improvements.180
While Mr. Pogats testified that DTEE’s SAIDI index was in the fourth quartile
nationally, and had been so “consistently”,181 a review of the Commission’s order in
Case No. U-16472 shows that DTEE’s performance statistics then were in the first and
second quartile.182 The survey results in Schedule X7 of Exhibit A-34 are from 2014,
when Mr. Pogats explained that DTEE was not able to complete its planned vegetation
management miles due to high storm activity. Also, 2013 was the year in which a
severe ice storm caused significant outages.
As Mr. Wuepper testified, the
performance statistics are heavily influenced by variable storm activity.183 Moreover,
the SAIDI statistics themselves do not alone justify increased spending.
In its order in U-16472, the Commission addressed DTEE’s proposed $97.9
million in capital expenditures related to system reliability, primarily pole top
maintenance and repetitive customer outage projects:
179
See Staff brief, pages 9-11.
See 9 Tr 2295, Attorney General brief, page 11, Staff reply brief, pages 3-4.Exhibit S-10.7 is an audit
response from DTEE, indicating: “The cost benefit assessment undertaken by the Company focused on
increased customer satisfaction resulting from a decrease in outages, and overall process efficiency
improvement.” No supporting details have been provided on this record.
181
See 4 Tr 404.
182
See October 20, 2011 order, pages 11-12.
183
See 6 Tr 1290.
180
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The Staff recommended that this amount be reduced to $79.7 million,
which was the company’s actual 2010 expenditure level for this item. The
Staff pointed out that since 2005, all three reliability indices, the System
Average Interruption Duration Index (SAIDI), the System Average
Interruption Frequency Index (SAIFI), and the Customer Average
Interruption Duration Index (CAIDI) showed significant improvement,
indicating satisfactory performance by the company. The Staff contended
that the increase proposed by Detroit Edison was therefore excessive.
ABATE supported the Staff’s position, and the Attorney General supported
reductions in system reliability expenditures as discussed below.
The ALJ agreed with the Staff and ABATE and recommended that the
Commission adopt the Staff’s proposed $79.7 million for system reliability
capital expenditures. The ALJ found that Detroit Edison’s system reliability
had increased substantially since 2005 as demonstrated by the
improvements in SAIDI, SAIFI, and CAIDI. The ALJ added that the record
showed that from 2006 through 2008, Detroit Edison’s reliability was in the
first or second quartile for electric utilities of comparable size, and these
improvements had occurred with an average annual capital investment of
approximately $71.6 million from 2007 through 2010.
Detroit Edison takes exception and argues that a reduction in funding
would reduce customer satisfaction while not reducing overall costs.
According to Detroit Edison, the company’s system reliability projects,
specifically its PTM program, identifies and proactively replaces defective
or damaged poles and pole hardware in a cost-efficient manner, normally
with no interruption in customer service. Detroit Edison claims that if poles
or hardware must be replaced or repaired after damage has occurred,
customers are more likely to experience outages, and the work will require
additional costs, such as overtime for work crews. Detroit Edison adds that
a reduction in funding for PTM could result in an increase in the pole
inspection cycle to 14 years, rather than the recommended 10 to 12 year
cycle. In addition, Detroit Edison contends that the reduction could mean
that projects affecting approximately 37,000 repetitive outage customers
may not be funded, resulting in more frequent and longer outages and
ultimately higher costs.
The Commission finds the PFD well-reasoned and agrees with the ALJ’s
findings and conclusions on this issue. The Commission commends
Detroit Edison on its significant reliability improvements over the past
several years but finds that, in light of these improvements, the substantial
increase in system reliability capital expenditures proposed by the
company – far in excess of the historical 3-year average – is not justified
by the record in this case. If Detroit Edison finds that its reliability begins to
suffer for lack of funding, the company may file another rate case with
evidentiary support demonstrating the need for increased capital spending
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on system reliability. See October 20, 2011 order, Case No. U-16472
order, pages 11-12.
DTEE did not present an evaluation of the impact of its expenditure levels for these
programs. This is notwithstanding the clear direction from the Commission in its order
in DTEE’s last rate case, as shown above, that requests for increased capital spending
on system reliability should demonstrate a need for additional spending.
And it is
notwithstanding Mr. Pogats’s initial testimony indicating that “[e]ffective vegetation
management is the single largest driver of preventing outages.” 184
As described by Mr. Pogats, DTEE has overlapping programs for addressing
outages, all of which may have a significant impact, according to the company. Mr.
Pogats’s testimony identifies a 64% reduction in outages the year after vegetation
management is complete,185 and provides examples showing 59% fewer outages from
the hazardous tree removal program,186 and SAIDI reductions of 50% to 90% from the
Reducing the Scope and Restoration Time of Outages efforts.
DTEE’s evidentiary
presentation in support of these expenses is more akin to identifying a laundry list of
reliability tools, and throwing money at the problem by presenting its budgeted amounts,
without making an effort to demonstrate that the expenditures are part of a coordinated
effort designed to meet reasonable goals at a reasonable cost.
Because DTEE has failed to support the reasonableness of capital expense
projections, this PFD recommends that the Commission adopt Staff’s adjustment,
reducing projected expenditures by $42.83 million. While both Staff and the Attorney
General’s recommended adjustments target the same evidentiary failure by DTEE, the
184
See 4 Tr 364, 385.
See 4 Tr 364.
186
See 4 Tr 367.
185
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adjustments are not identical.
Nonetheless, this PFD finds that there is clearly an
overlap in concept, and recommends that the Commission adopt Staff’s proposed
adjustment, both because it is larger (putting aside the EVMP spending, which is
addressed below) and because methodologically, it does not address specific budgetary
line items, but broadly provides flexibility to DTEE to prioritize its capital spending. This
PFD further recommends that the Commission provide further guidance to DTEE
indicating that it expects a significantly more rigorous analysis the next time DTEE’s
reliability spending is called into question, whether in a rate case or other inquiry into the
utility’s distribution system maintenance.
5. Corporate Staff Group
Ms. Uzenksi presented testimony in support of the proposed capital expenditures
for the Corporate Staff Group within DTE Energy Corporate Services, LLC. She
explained the role of the group:
The CSG is a shared services organization, “DTE Energy Corporate
Services LLC” (LLC), which includes corporate staff functions. This
business model provides efficiencies, cost savings and enhanced
governance and internal controls. Each organization within the CSG
provides enterprise wide services.187
She further explained that the CSG functions include a variety of Administrative and
General (A&G) services including audit, accounting, finance, tax ,treasure, corporation
and governmental affairs, communications, corporate offices and services, human
resources, information technology (IT), legal, regulatory affairs, and “major enterprise
projects.” She testified that CSG also includes customer service.188 She explained that
capital expenditures incurred by CSG primarily relate to IT, physical infrastructure, and
187
188
See 6 Tr 1036.
See 6 Tr 1036-1038.
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fleet, and are generally recorded by DTEE and allocated to other affiliates through a
usage fee.
Ms. Uzenski specifically discussed certain capital expenditures projected from
2014 through the end of the projected test year, listed in Schedule B6.5 of Exhibit A-9.
She identified DTEE’s projected Workplace Transformation expenditures in line 11 of
her schedule and the Neighborhood Revitalization Initiative expenditures in line 12 of
her schedule as follows:
Workplace Transformation, reflects strategic space planning costs to
update DTE’s headquarters, service centers and power plants. These
renovations create energy efficient work spaces, facilitate more effective
collaboration and problem solving, and provide flexibility to accommodate
changing business needs. Line 12 reflects investments in buildings and
land. Expenditures include the land on Michigan Avenue that expands our
campus, helps revitalize our neighborhood, and provides enhanced safety
and security; the renovation of the former Salvation Army building that will
be used as a swing space to house DTE Energy employees during our
workplace transformation initiative; and the development of a public space
on Grand River as part of the Detroit Business Improvement Zone (BIZ)
activities. BIZ is a coalition of local businesses that provides services to
keep downtown Detroit clean, safe and beautiful. 189
Mr. Coppola took issue with these two expenditure categories. Regarding the
Workplace Transformation, he testified:
Between 2012 and 2014, the Company has spent approximately $61.7
million to transform its offices into a worker oasis with a centralized café
on each floor, central copy/print rooms, meeting spaces, updated
technology, fire suppression, LED lighting, low flow faucets and water
closets, and furniture and carpet made from recycled components, among
other improvements According to the Company, the objective is to
increase efficiency, reduce costs and attract a new generation of younger
worker after the older workers retire. For 2015 and the first six months of
2016, the Company is projecting to spend an additional $33.9 million on
Workplace Transformation, for a total of $95.5 million during a four-andhalf year period. The Company last made significant renovations to its
headquarters building in 2011. Although renovation to offices is expected
from time to time, the level of expenditures undertaken by the Company
189
See 6 Tr 1045.
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for the Workplace Transformation program seems excessive. Customers
should not be required to absorb more than $100 million in capital costs,
which will likely be the total cost by the time the program is completed.
This program comes on top of other capital expenditures to keep the
business functioning that are driving higher rates for customers.190
Regarding the Neighborhood Revitalization Initiative, he testified:
This project is in fact four projects: the Navitas House, Fed Park Place,
Grand River Public Space and the Crime Deterrence Initiative. The
Navitas House is an urban revitalization project and also functions as
temporary offices for employees during the workplace transformation
phase. The Fed Park Place is an office campus extension and
neighborhood beautification project. The Grand River Public Space project
is an additional expansion of the office campus area to transform the area
into a public space for employees and neighbors. The Crime Deterrence
Initiative is a vague security concept to reduce and prevent crime near the
Company’s headquarters building.191
Mr. Coppola testified that although both projects may have worthwhile objectives, “it is
not appropriate to expect customers to pay for the full cost of implementing programs
that are not directly connected to providing utility service.”192
Characterizing the
programs as “[tending] to enhance the Company’s image which benefits shareholders of
the Company”, he recommended that the Commission allow only half of the capital
expenditure to be included in rate base, $60 million through the end of the projected test
year, with the remainder segregated into a non-utility asset account.
In her rebuttal testimony, Ms. Uzenski testified:
The Workplace Transformation (WT) project is upgrading our
headquarters, service centers and power plants that exist to provide utility
service. Witness Coppola mentions [at 9 Tr 2329] that the Company made
renovations to its headquarters in 2011 but he excludes the fact that the
2011 renovations were related to updating the auditorium meeting space
and converting the old cafeteria to office space. The WT project was
started in 2012 to upgrade other building spaces. Approximately 80% of
our facilities are over 20 years old. Most have not been through a full
190
See 9 Tr 2329.
See 9 Tr 2329
192
See 9 Tr 2330.
191
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renovation and therefore do not meet current building codes. Upgrades
include bringing the spaces up to code, including fire detection and
suppression, and ADA compliance; and replacing furniture and fixtures
that are at the end of their useful life. In addition, the WT project uses a
more efficient design resulting in a reduction in average space used per
employee from 340 square feet to 283 square feet. The space design also
employs standardized layouts that are expected to reduce the cost to
relocate employees.193
Regarding the Neighborhood Revitalization Initiative, she testified:
One of the projects is the renovation of the Navitas House (formerly
known as the Salvation Army building) which is being used as a swing
space for over 140 employees during the workplace transformation
initiative described above. The Neighborhood Revitalization projects also
expand our campus footprint which helps protect the DTE headquarter
assets that are used in providing service for all our customers.194
In her cross-examination, Ms. Uzenski also testified:
I would say that there may be an extra benefit to the neighborhood by
having the -- our campus well maintained and usable, and so in addition to
benefits to the Company of having space to work and having office space
and parking, the fact that the neighborhood looks nicer I think is an
ancillary benefit, but it is not the -- it's certainly not the only benefit, that
the intention is to expand the campus and protect our assets, and have
spaces including additional office space for our employees that we're
using in providing utility service.195
Mr. Stanczak also addressed these expenses in his rebuttal testimony:
Company Witness Ms. Uzenski supports the reasonableness and
prudency of these investments in her direct and rebuttal testimony.
Specifically, the Workplace Transformation and Neighborhood
Revitalization initiatives reflect costs to update DTE’s headquarters,
service centers and power plants, enhance safety and security for
employees, and provide additional space to house DTE Energy
employees. Clearly these are prudent utility costs, therefore, establishing
an arbitrary 50/50 cost sharing treatment is entirely inappropriate, would
set a poor regulatory policy precedent, and should be rejected.196
193
See 6 Tr 1067.
See 6 Tr 1068
195
See 6 Tr 1086.
196
See 4 Tr 169-170.
194
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In his brief, the Attorney General argues that the expenditures are of
questionable value to customers and should be partially disallowed, citing Mr. Coppola’s
testimony and discovery responses from DTEE that he relied on. He argues that while
renovations should be expected from time to time, the $100 million workplace project
over the four year period from 2012 through 2016 appears excessive and unfair to make
customers absorb in the form of higher rates.197 The Attorney General also cites Mr.
Stanczak’s testimony on cross-examination, acknowledging that the plans for the vacant
lot as part of the Neighborhood Revitalization Initiative include a park, with concerts and
restaurants.198 In its reply brief, Staff argues that there is insufficient evidence on the
record that these expenditures are just and reasonable or used and useful to the
ratepayers. Staff recommends that the Commission disallow the expenditures.199
In its brief and reply brief, citing Mr. Stanczak’s and Ms. Uzenski’s testimony,
DTEE argues that the adjustment should be rejected because DTEE is prudently
incurring costs to update its headquarters, service centers and power plants, enhance
safety and security for employees, and provide additional space to house company
employees.200 DTEE asserts: “All of the costs related to these endeavors support the
provision of utility service and are therefore recoverable.”201
This PFD recommends that the Commission adopt Staff’s recommendation and
exclude the projected costs from rate base.
DTEE’s argument that the costs are
recoverable because they support the provision of utility service is not technically
correct.
197
Although DTEE did not establish that all of its contemplated activities do
See Attorney General brief, pages 44-45.
See Attorney General brief, page 45, citing 4 Tr 176-177.
199
See Staff reply brief, pages 10-11.
200
See DTEE brief, pages 84-85, DTEE reply brief, pages 79-80, citing 4 Tr 169-170, 177, 182.
201
See DTEE brief, page 85.
198
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support the provision of utility service, even marginally, a mere tangential relationship to
the provision of utility service is not sufficient. In seeking to include these projected
expenditures in rate base, DTEE needs to show that the level of the expenditure is
reasonable, that it is not “gold-plating” the faucets, or using ratepayer funds to enhance
the value of its real estate investments. Instead, DTEE made no effort to justify the
overall level of its proposed expenditure on either of these programs. In her crossexamination, Ms. Uzenski acknowledged that the neighborhood revitalization project
includes space that may be used by the public, but “plans for that have not been
finalized.”202 Mr. Stanckzak testified that he is “not an expert in terms of the projects
that are involved,”203 and did not know the specifics of what would be built.204 Regarding
the workplace transformation project, Ms. Uzenski made clear that the expenditures
projected in this case are part of a larger ongoing project. Because DTEE did not
provide an evaluation of the project in terms of total costs and benefits, as well as
alternatives considered, this PFD recommends that the Commission exclude the
projected costs from rate base, but give DTEE an opportunity in its next case to justify
the reasonableness and prudence of the expenditures. Note that some of DTEE’s plans
appear to be tenuous on this record—deferring a final ruling on whether the project
costs can be included in rate base should give DTEE an opportunity to refine its plans,
and prepare a more organized presentation. This PFD does not recommend adopting
the Attorney General’s proposed cost-sharing of the projected expenses, finding such a
conclusion premature given the paucity of information on the record.
202
See 6 Tr 1086.
See 4 Tr 177.
204
See 4 Tr 179-180.
203
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6. Customer 360
DTEE’s Exhibit A-9 reflects capital expenditures for DTEE’s Customer 360
project, including a total of approximately $93 million from the historical test year
through the projected test year.
Mr. Bridge, who is leading the development and
implementation of this projected by DTEE, testified in support of these expenses. He
described the project as follows:
Customer 360 is an implementation of SAP’s Customer Relationship and
Billing System (CR&B) at DTE Electric. It includes new hardware and
software designed to replace the Company’s existing Customer Service
Systems. Processes in scope include: 1) Customer Service, 2) Meter
Reading, 3) Billing and Invoicing, 4) Finance, 5) Credit and Collections, 6)
Marketing and Account Management, 7) Device Management, and 8)
Customer Choice.205
And he explained:
DTE Energy’s critical customer information systems have reached the end
of their useful lives. The current systems, which consist of the Customer
Service and Billing System (CSB) and Key Customer Service System
(KCS), are inefficient and expensive to maintain. KCS supports our
commercial and industrial customers. CSB supports our residential and
small business customers. The systems are “home grown” and were
implemented in 1994. These systems can no longer effectively support our
corporate priority of sustainable top decile customer satisfaction.
Customer 360 will provide a platform DTE can leverage to continue to
achieve its customer based goals.206
Mr. Bridge identified benefits to customers from enhanced interactions with DTEE,
increased communication efficiency, including outage management capability, and
increased ability to improve energy efficiency through product offerings or otherwise
market new customer products and services.207
205
See 5 Tr 852.
See 5 Tr 853.
207
See 5 Tr 853-854.
206
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The Attorney General took issue with the level of proposed expenditures for this
program, noting that DTEE significantly increased the total project cost provided by its
consultant. Exhibit AG-10 indicates that DTEE’s consultant, Accenture, presented a
cost estimate of $151 million, but DTEE increased it to $215 million. DTEE provided the
following explanation:
1) Accenture suggested a contingency level of 15%. Based on our experience
with large scale IT projects at DTE and the recommendation of our Major
Enterprise Projects Organization, we chose a contingency level of 23%.
2) As for labor, Accenture’s modeling tool assumes that DTE employees have
the same skill level as Accenture employees in implementing a CR&B system
We assumed we would need an additional 20% in labor above the Accenture
estimate. Accenture also assumed 85% of the work would be done with
Accenture employees and 15% with DTE. We chose a mix of 53% DTE and
47% Accenture which further drove up our projected labor costs.208
3) AFUDC was not in the Accenture estimate[.]
4) In order to mitigate project delivery risk, we our leveraging our Major
Enterprise Projects Organization.
5) The Accenture estimate cost does not include DTE training costs.
6) The Accenture estimate does not include post go-live support.
For this program, DTEE included a $24 million contingency, $9 million additional
labor, $12 million in AFUDC, $6 million for project management, $6 million additional
training, and $7 million in “post-go live support”. DTEE received Commission approval
for deferral and vintage accounting for the costs of this program in the Commission’s
September 26, 2014 order in Case No. U-17666. The Attorney General seeks only a
caution from the Commission that future cost overruns may not be allowed. While the
Commission does not need to caution DTEE that its future expenditures must be
reasonable and prudent, and while Mr. Bridge testified that DTEE has hired an
208
See Exhibit AG-10.
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additional consulting firm to assist with quality control, PriceWaterhouse Coopers, as
well as SAP consultants to assist with hardware and software requirements, it is
worthwhile for the Commission to require DTEE to provide periodic reporting to Staff
regarding the project costs and progress over the three-and-a-half year expected
course of the project implementation.
7. AMI
Mr. Sitkauskas testified in support of DTEE’s projected AMI capital expense as
shown in Exhibit A-9, Schedule B6.6, and O&M net savings as shown in Exhibit A-10,
Schedule C5.13, and in support of the cost-benefit analysis provided to meet the
Commission’s requirement in Case No. U-15768, presented in his Exhibit A-18. He
reviewed the company’s progress on AMI implementation, beginning with the pilot
programs in 2008, indicating that the company expects to complete installations by
2017. He reviewed the principal benefits of the AMI program, and testified that the
savings were determined based on the expected timing or “path to steady state” and
each category was reviewed with the business units impacted by the savings. Mr.
Sitkauskas testified that DTEE’s analysis shows the present value revenue requirement
(PVRR) of negative $87.2 million, indicating savings exceed costs over the life of the
project, and he testified to his opinion that the AMI investments are a reasonable and
prudent use of utility resources. As discussed below, noting that AMI installations are
more than 50% complete, Mr. Sitkauskas requested that DTEE be relieved of the
obligation to present further cost-benefit analyses.
Citing Exhibit S-7, Mr. Matthews testified that Staff excluded $1.498 million in
projected capital expenditures attributable to contingencies for the AMI project:
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On pages 10-11 of his pre-filed testimony, DTE witness Robert E.
Sitkauskas stated that contingency costs are “used to provide resources
for items that were underfunded at the onset [if any] or to provide
resources to address new issues that we are not aware of now [if any].”
Given this uncertainty and the nature of forward-looking test years, there
is no guarantee that the Company will incur contingency costs in full, if at
all.
Moreover, because these contingency costs are part of the Company’s
AMI capital expenditures, the Company can earn depreciation and return
on these expenditures. It is not just or reasonable for a utility to earn
depreciation and return on costs that it may not incur.209
Mr. Coppola took issue with DTEE’s cost-benefit analysis, testifying:
In this rate case, the Company updated its present value analysis of the
financial costs and benefits. The result is an expected net present value
benefit of $38.8 million for the electric meters and an overall net PV
benefit of $87.2 million for the entire project including gas meters. The
results from the current analysis are much higher that the PV analysis
performed about one-and-half years ago by the Company in conjunction
with testimony filed in case No. U-16472 (Remand). At that time the
Company reported a net PV analysis of $19.4 million for the electric
meters and $63.01 million for the entire program.
Going back to the original rate case No. U-16472, filed in October 2010,
the Company had calculated a net PV benefit of $34.7 million for the
electric portion and $82.9 for the entire program. As can be observed from
the three PV analyses, the net financial benefits can vary significantly from
one update to the next due to changing assumptions and updated
information. Such large variations do not inspire confidence that the
projected cost savings in particular are sufficiently firm to be relied on as
reasonably achievable.210
Citing a regulatory approach taken by the Maryland Public Service Commission to
completely defer all AMI costs until the benefits could be realized, Mr. Coppola
recommended that the Commission defer recovery of depreciation expenses for the
AMI program:
Under typical ratemaking practices, the Company requests recovery of all
its costs including depreciation expense. However, this approach lays all
209
210
See 8 Tr 2214-2215.
See 9 Tr 2332.
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the risk of the success or failure of the AMI program on its customers. For
a project of this size with highly speculative benefit projections, placing the
entire risk on customers is not acceptable. One way to share the risk is for
the Company to 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.211
Mr. Crandall testified to his concerns with Mr. Sitkauskas’s presentation of the
costs and benefits of the AMI project. He testified that DTEE is using a 30-year useful
life for its AMI meters and IT hardware and software, which is unrealistic in light of the
experience of other utilities.212 He also took issue with the line item in Exhibit A-9,
Schedule B6.6 labeled “Contingency, Corporate Overheads, Other,” which he identified
as totaling $49.4 million.213
In his rebuttal testimony, Mr. Sikauskas testified that Mr. Crandall’s analysis of
the cost-benefit was incorrect. He testified that the cost-benefit analysis assumes the
new meters have a 20-year life expectancy, and that IT costs are included in the
analysis over the life of the project. Regarding the “contingency” expense, he testified:
Notwithstanding this issue, the contingency is used to provide resources
for items that were underfunded at the onset or to provide resources to
address new issues that were unknown or that we were unaware of prior
to and throughout the project implementation cycle. The proposed
contingency covers hardware, staff, and IT components each of which are
areas with potential for cost over runs or unanticipated challenges to the
implementation of the project. Some examples of areas where cost
overruns may occur related to hardware include 1) Meter installation
challenges due to complexities at the site; and, 2) Potential damage to
property while removing old meters from the field, personnel damage to
homes. DTE electric’s Risk Management recommended the use of a 2%
multiplier of all hardware and installation costs on a yearly basis as
contingency. The 2% reflects an equal probability of cost overruns in each
of the four categories.
211
See 9 Tr 2334.
See 8 Tr 2260.
213
The additional capital spending in this line item from the historical test year to the projected test year is
$11.9 million. Staff, however, relied on Exhibit S-7 for a breakdown of the amount of “contingency”
included in the line item.
212
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The Staffing contingency element is required to address staffing
requirements that differ from what is in our current plan. Given the relative
infancy of AMI deployment contingency is necessary regarding IT costs.
Each of these is necessary to assure that the ultimate project goals are
met and implementation occurs as planned. See 5 Tr 741.
Mr. Sitkauskas also addressed Mr. Coppola’s testimony, explaining the change in NPV
calculations as follows:
The variance in the NPV analyses is driven by a change in the timing of
the AMI spend. Exhibit A-29, Schedule S-1, Comparison of AMI Spend,
shows that the total project spend has not changed from the NPV analysis
prepared in the U- 16472 AMI Remand filing. The exhibit illustrates how
the installation of meters has moved forward with a completion date of
2017 for electric meters versus the planned completion date of 2020. With
time the Company has gained experiences and efficiencies that have
allowed it to quicken the pace of AMI installations. The pace of meter
installation along with the realization of the benefits changes the NPV
results. 214
He objected to Mr. Coppola’s recommendation to defer depreciation expense,
distinguishing the Maryland Commission decision Mr. Coppola cited on the basis that
the utility in that case was projecting benefits based on supply-side savings, while DTEE
benefit projections are based on operational savings.215
In his briefs, the Attorney General urges the Commission to adopt Mr. Coppola’s
recommendations, arguing that the AMI program places the risk of success or failure of
the program on the customers.216 The RCG argues that DTEE has not supported its
cost-benefit analysis, claiming DTEE is inflating its rate base and depreciation expense
while obtaining tax benefits from the use of accelerated depreciation. The RCG argues
that DTEE has not performed an analysis of the benefits of alternative investments, and
has not shown benefits equivalent to costs over the more limited time rates are likely to
214
See 5 Tr 735.
See 5 Tr 736-373.
216
See Attorney General brief, pages 46-49, pages 3-4.
215
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be in effect.217 Mr. Sheldon asks the Commission to exclude AMI costs from rate base
and revenue requirements. In the alternative, he asks that the Commission condition
continued allowance of AMI costs on the utility’s willingness to come up with an opt-out
program that is acceptable to customers concerned with health or privacy issues.
In its brief, Staff argues in support of recovery of the AMI costs, with the
exception of the contingency amounts identified. Staff argues that the company’s costbenefit analysis shows significant benefits in excess of the costs, and argues that the
Commission has carefully evaluated smart meters, and authorized cost recovery in prior
cases.
Staff opposes the Attorney General’s request that depreciation expense be
deferred. Citing Mr. Sitkauskas’s rebuttal testimony, Staff argues that the Maryland
case cited by Mr. Coppola involved supply-side savings projections, i.e. less generation,
while DTEE’s cost-benefit analysis relies only on operational savings, i.e. reduced meter
reading, etc., to justify the costs.218 In its reply brief, Staff disagrees with the RCG that
DTEE should have performed an analysis of the benefits associated with alternative
investments of similar magnitude. Staff argues that investments in other technologies
such as renewable energy are not comparable to the AMI investment.219
DTEE argues that the Commission has reviewed AMI expenditures in several
cases beginning with the Commission’s December 23, 2008 order in Case No.
U-15244.
DTEE reviews the history of Commission orders addressing AMI cost
recovery, and argues that it has supported the net benefits of its AMI program
consistent with those prior orders.220 It also reviews Mr. Sitkauskas’s rebuttal testimony
217
See RCG brief, pages 26-28; RCG reply brief, pages 3-5.
See Staff brief, pages 99-100.
219
See Staff reply brief, pages 14-15.
220
See DTEE brief, pages 74-79.
218
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addressing the objections raised by Mr. Coppola and Mr. Crandall. DTEE also disputes
Staff’s adjustment for the contingency amount, citing Mr. Sitkauskas’s rebuttal
testimony.221
This PFD finds that the AMI costs should be included in rates, with the exception
of the contingency costs identified by Staff. The Commission has evaluated this project
in numerous orders and has found that the expected quantifiable and non-quantifiable
benefits exceed the costs, and the Commission has found that installed meters are
used and useful and appropriate for inclusion in rate base. This case does not present
the opportunity for review ab initio of the AMI project. No party has identified any
material changes in benefits or costs so as to alter the Commission’s prior rulings on
this issue.
The Commission has previously rejected the Attorney General’s request to defer
AMI costs. Moreover, the Commission put ratepayer protections in place in Case No.
U-16472. In its October 20, 2011 order in that case, the Commission explained:
As the Commission has previously determined in guidelines approved for
Consumers Energy Company’s (Consumers) AMI pilots and deployment:
1. Piloting phase expenditures are classified into two categories: a) those
directly related to the piloting function, e.g. testing, and b) those
actually related to the full deployment.
2. Direct pilot expenditures are deemed recoverable expenses
irrespective of whether or not the pilot indicates a go-forward decision.
3. A cost/benefit analysis is not required as a precondition for cost
recovery of direct pilot expenses. However, the utility must
demonstrate that the costs were reasonably required to fulfill the
objectives of the pilot.
4. Because the financial risk associated with the Smart Grid pilot is borne
by ratepayers, it is incumbent upon the utility to keep pilot costs as low
as reasonably possible.
5. Prior to the completion of the pilot, capitalized expenditures will be
included in utility rate base as Construction Work in Progress (CWIP)
221
See DTEE reply brief, pages 68-69.
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with an Allowance for Funds Used during Construction (AFUDC) offset.
Capitalized expenditures directly related to the pilot will not be reflected
in rates until the pilot phase is concluded.
November 4, 2010 order in Case No. U-16191, p. 16 (emphasis supplied).
The Commission agrees with the Staff’s observation that while the
decision to fully deploy AMI is the company’s alone, the Commission’s role
is to assure that ratepayers are protected from unreasonable or imprudent
costs that may be included in utility rates. As the Staff pointed out:
Because utilities earn a fixed rate of return on their capital
investments, there is an intrinsic incentive for a regulated utility to
overinvest in system reliability. This incentive has direct
implications with respect to Smart Grid cost recovery policy that
must be addressed. The construction of electric generation capacity
is the classic example of utility overinvestment. The Commission’s
dockets are replete with examples of controversy over the prudency
of constructing new generation plant proposed by utilities on the
basis of improved system reliability. Although opportunities to add
new generation capacity have waned in recent years, adding new
rate base remains a core strategic objective of all investor owned
utilities. Smart Grid has become the new battleground over the
wisdom of utility reliability investment.
Staff’s initial brief, p. 97 (emphasis in the original).
That being said, the Commission views Smart Grid as a whole
(considering AMI a part of that whole) as a potentially transformational
technology that will accommodate the incorporation of renewable and
distributed generation to replace the current fossil-intensive generation
system, provide customers with new and easier methods to manage their
energy usage and bills, and provide greater reliability and power quality,
along with a host of other possible benefits. At the same time, Smart Grid
(particularly AMI) could also prove to be an expensive form of metering
with few, if any, customer benefits beyond what the current metering
technology provides. Thus, the Commission finds that the Staff’s
recommendation to cap Detroit Edison’s recovery of cumulative historical
and projected capital expenditures at the level of projected lifecycle
benefits is a reasonable one, providing an effective means of cost control
and a meaningful way to incentivize the company to assure that the
benefits of AMI to ratepayers are maximized.222
222
See October 20, 2011 order, pages 22-24.
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The RCG objects to the cost-benefit study on the basis that it covers a time
period longer in duration than the period for which rates will be in effect. This argument
in unpersuasive: it is reasonable for the Commission to consider both the long-term
costs and benefits to ratepayers, as well as to consider the short-term rate impact.
Thus, for example, the Commission recognizes that a utility’s capital investments are
financed by a mix of debt and equity capital, while customers pay a rate of return on the
investment as well as depreciation, thus roughly but not precisely spreading cost
recovery over the useful life of the plant.
Before providing for rate recovery, the
Commission also reviews utility capital expenditures for long-term reasonableness and
prudence.
The RCG characterizes the cost-benefit analysis as a “black-box” analysis
“controlled by DTEE alone” and “not compiled by an objective team of experts.”223 This
argument wholly ignores the prior cases in which not only the elements but the structure
of DTEE’s cost-benefit analysis have been reviewed, not only by Staff and the
Commission but by all the parties to the company’s rate cases who have had the
opportunity to present evaluations for the record. One of the benefits of the contested
case process, with broad discovery opportunities for all parties, is that the Commission
does not need an “objective team of experts” to perform every analysis in the first
instance, but can rely on the contested case process with the participation of its Staff
and other parties to provide the facts necessary to make an informed decision.
The RCG’s arguments that DTEE should have considered alternatives to the AMI
program, such as delaying purchases to obtain “better technology or experience,”224
223
224
See RCG reply brief, page 4.
RCG reply brief page 4
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ignores that the Commission has already reviewed DTEE’s implementation of its AMI
program from the pilot phase through the present time, when the project is almost
complete. This is not the appropriate time to raise concerns with how those earlier
decisions were made. While it is reasonable for the Commission to require DTEE to
present cost-benefit analyses to show that the implementation of the project continues
to show positive benefits for ratepayers, the Commission’s review of the company’s
analyses must start from the premise that the Commission has substantially approved
past expenditures for this program in prior rate cases.
Contingencies, however, should be excluded for the reasons explained above.
8. IAC
In his testimony regarding the benefits of demand response programs, Mr.
Matthews identified DTEE’s proposed capital expenditure of $7.5 million to upgrade the
cycling devices and software used in its interruptible air-conditioning (IAC) program. He
recommended that DTEE transition to updated technology such as Intelligent
Communicating Thermostats (ICTs). He reviewed programs adopted by other utilities
and the results of DTEE pilot programs to support his recommendation.225
In her
rebuttal testimony, Ms. Dimitry objected to any disallowance on this basis. She testified
that the updated switches DTEE intends for its IAC program will be two-way ZigBeeenabled switches that will work with the AMI meters. She testified that DTEE is also
evaluating an ICTs for use in a whole-house dynamic peak pricing program, but at this
point in time, cannot completely replace the IAC program.
225
See 8 Tr 2218-2228.
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In its brief, Staff agrees that DTEE’s expenditures as outlined in Ms. Dimitry’s
testimony are reasonable, but recommends that the company transition to ICTs as the
current switches fail. Staff disputes that customers would have to transition to a wholehouse program to take advantage of the ICTs.226 In its reply brief, DTEE indicates that
given Staff’s willingness to include the $7.5 million as requested, there is no longer any
dispute.227 Since the parties seem to be in agreement, this PFD merely recommends
that the Commission encourage DTEE to keep Staff informed of its ongoing efforts to
evaluate the ICT technology and compatible programs.
9. CWIP
Mr. Chriss took issue with DTEE’s inclusion in rate base of Construction Work in
Progress (CWIP). At 8 Tr 1824-1826, he explained his concerns, including the concern
that the use of CWIP shifts risks to ratepayers that are traditionally borne by
shareholders. He recommended that if the Commission determines it should allow rate
base treatment of any such amounts, the Commission should consider this allowance in
evaluating DTEE’s authorized return on equity.
Ms. Uzenksi testified in response to Mr. Chriss’s concern:
First, CWIP is included in this rate filing as required by the
Commission’sMay 10, 1976 Order in Case No. U-4771. Second, CWIP
that is not related to environmental projects accrues an Allowance for
Funds Used During Construction (AFUDC) based on the Commission
authorized return on rate base. (This applies to projects exceeding
$50,000 and under construction for at least six months.) The AFUDC
included in CWIP is credited to the income statement in both the historical
and projected periods. See Exhibit A-10, Schedule C1, line 12. This
increase to income is reflected in this case as a reduction to the revenue
226
227
See Staff brief, pages 100-102.
See DTEE reply brief, pages 110-111.
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requirement. Thus, for AFUDC eligible CWIP, the net revenue requirement
is effectively zero.228
She explained the background of the different treatment for environmental expenses:
In its March 14, 1980 Order in Case No. U-5281, a generic proceeding on
the Commission’s own motion to examine the accounting treatment of
CWIP and AFUDC, the Commission required that pollution related CWIP
should not accrue AFUDC but instead be included in rate base. This
position was affirmed in the Commission’s August 16, 2011 Order in Case
No. U-15244. Page 72 of the order states: “The Commission is not
persuaded that it should waive the effect of determinations made in Case
No. U-5281, which require the recognition of CWIP for environmental
related construction costs in rate base, with no offset for AFUDC.229
This PFD concludes that DTEE is proposing to treat CWIP in this case
consistently with what the Commission has determined is appropriate, relying on an
AFUDC offset except for environmental-related construction, so no general adjustment
to rate base is required.
B.
Working Capital
The Commission has explained working capital as follows:
For ratemaking purposes, working capital is a measure of investor funding
of daily operating expenditures and a variety of non-plant investments that
are necessary to sustain ongoing operations of the utility. The ratemaking
measure of working capital is designed to identify these ongoing funding
requirements on average over a test period. Working capital requirement
is determined by “an analysis of all the assets of the utility to determine
which are used to provide service and an analysis of all of the utility
liabilities to determine the extent to which assets are funded by capital that
is tied to the earnings of the utility.” June 11, 1985 order in Case No. U7350, p. 4. See October 20, 2011 order, Case No. U-16472, page 26.
The disputed issues that impact the calculation of working capital are the
treatment of DTEE’s Combined Operating License Application (COLA) expense for a
potential Fermi 3, DTEE’s request to recover certain non-qualified benefit costs, and the
228
229
See 6 Tr 1069.
See 6 Tr 1069-1070,
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treatment of its projected negative Other Post-Employment Benefit (OPEB) expense.
These are addressed below.
1. COLA
Ms. Dimitry provided the initial testimony presenting DTEE’s proposal to recover
the costs of obtaining a license for a Fermi 3 nuclear power plant. She testified that
DTEE is proposing to recover deferred COLA and holder costs totaling $101.9 million
over a 20-year amortization period and that Ms. Uzenski included the amortized portion
of this amount in projected test year expenses. She testified that DTEE believes the
20-year period is necessary to allow the license to be fully amortized before the plant is
put into service. Further, she testified that due to the existing site, DTEE’s licensing
expenses have been the lowest in the industry, that the license can be held indefinitely,
and that the license is transferable.
She testified that DTEE has not determined
whether to construct the plant, and may try to sell the license.
Mr. Coppola testified that it is premature to begin to amortize any of the deferred
costs, characterizing the proposed time period as arbitrary, and testifying that the costs
should be amortized once the plant begins operation. Mr. Coppola testified that it is not
fair or reasonable to have current customers pay for costs not related to productive
generating assets. 230
Staff witness Mr. Krause testified that Staff supports DTEE’s pursuit of the
license, “given the level of uncertainty in the electric generation industry,” and testified
that Staff is not recommending adjustments to the filed expenditure level. Staff witness
Mr. Welke testified that Staff is recommending a 10-year amortization, with the
230
See 9 Tr 2304-05.
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unamortized balance excluded from ratebase until DTE makes a decision whether to
proceed with the project. He testified that this approach had been used in prior orders
to address canceled projects, and testified that although this is not a canceled project,
DTEE has not decided whether to build the nuclear plant.
Ms. Dimitry, in her rebuttal testimony, objected to Staff’s analogy to the recovery
of costs associated with failed nuclear power plants, and further testified that DTEE
obtained the license on May 15, 2015, and that it is a valuable asset with a market value
substantially higher than the $96 million expended to date, and therefore appropriate for
DTEE to include it in working capital and earn a return on it. She further testified that
the license reduces the risks from nuclear construction work, shortens the time horizon
to have a plant in service, and provides flexibility to Michigan customers.231
Ms. Uzenski’s rebuttal testimony addressed Mr. Coppola’s recommendation that
no further cost recovery be permitted at this point in time.
She testified that she
disagreed in part that the COLA costs should be amortized over the life of the plant:
I agree that assets should be amortized over the period they provide
benefit, which is generally when the related revenue is earned. However,
if the Commission grants recovery of the COL over 20 years, or some
other period that is different from the life of the plant, the recoverable COL
would be viewed as a regulatory asset. . . amortized over the period
consistent with their recovery in rates. See Tr 1068-1069.
In his rebuttal testimony, Mr. Coppola took issue with Staff’s proposal to amortize
the COLA expenses over 10 years.
He also distinguished the treatment of these
expenses from those of the canceled power plants, asserting that it is premature to
provide for recovery of the deferred COLA costs:
The unamortized costs for the two cancelled power plants were stranded
and had no residual value. At that point, the only options left for the
231
See Tr 650-651.
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Commission were to disallow recovery of those costs or bite the bullet and
amortize them over some reasonable timeframe. In contrast, the Company
received the Fermi 3 operating license only a month ago and the license
has value which will be extracted once the Company decides to build the
plant or enters into other business arrangements to extract value from the
license.
In the current case with the COLA expenses, the situation is very different.
The investment in the COL has value as long as it can be used or sold.
Therefore, these 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 the amortization
of costs that are not related to productive generating assets or assets that
are not creating value currently.232
In its briefs, DTEE argues that the license is a valuable asset for ratepayers “with
a relatively low price.”233 As DTEE explains its position:
“The COL has no expiration for the start and completion of construction,
so the license can be maintained indefinitely. It is the only active license
in the Midwest region. It could provide greater than 1,500 MW of carbonfree generation for Michigan. The license is also transferrable, so there
are a number of possible ownership and partnering options.” See DTEE
brief, page 111; also see DTEE reply brief, page 104. DTEE argues that
the license allows new base-load nuclear to remain a viable option as part
of its long-term generation strategy, further arguing that having the license
reduces significant risks from nuclear construction work and provides
DTEE with tremendous flexibility to serve Michigan customers under
rapidly changing environmental, regulatory and economic conditions.234
Staff’s brief cites the Commission’s October 20, 2011 order in Case No.
U-16472, acknowledging that the Commission has not considered the licensing asset
“used and useful,” and explaining that this is the reason why Staff does not recommend
including the unamortized balance in ratebase.
Staff specifically addresses Ms.
Dimitry’s rebuttal testimony, acknowledging a difference between costs written off in
232
See 9 Tr 2371-72.
See DTEE brief, page 110; also see DTEE reply brief, pages 103-106.
234
See DTEE brief, page 112, also see DTEE reply brief, page 104.
233
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prior cases and COLA expenses in this case, but arguing that the costs share the
important similarity of not reflecting assets that currently generate power or
providebenefit to utility customers. Staff also argues that it is not prohibiting DTEE from
earning a return on its licensing expenses, just adopting a “wait and see” approach.235
The Attorney General cites Mr. Coppola’s testimony, and addresses Ms.
Uzenksi’s rebuttal testimony, arguing: “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.”236 The Attorney General argues that DTEE
has not met the burden of proof to show that its request is reasonable and prudent, and
recommends that the Commission maintain the normal accounting principles in setting
rates in this case.
M/N/S also argue that the Commission should deny DTEE’s request to recover
the COLA costs because DTEE has not made a decision to build the plant, and the
license alone is not used and useful. M/N/S argue that DTEE has other options to
recover these funds, citing the certificate of need process established in 2008 PA 286,
MCL 460.6s. In their reply brief, M/N/S also address the distinction DTEE presented in
its initial brief between a plant and a license. M/N/S argue that the license itself is not
used and useful, citing Staff’s brief, and arguing that DTEE’s position is unprecedented.
M/N/S further argue that in Case No. U-16472, the Commission cautioned DTEE not to
interpret its allowance of partial COLA cost recovery as an invitation to continue
235
236
See Staff brief, pages 52-54.
See Attorney General brief, page 21.
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expenditures without making progress toward constructing or deciding to construct a
new plant, but DTEE has ignored the caution.
237
Staff and DTEE both address the argument that DTEE could seek recovery of
COLA funds using the certificate of need statute. Staff argues that the statutory process
is “entirely optional” and does not preclude a utility from seeking cost recovery through
traditional methods.238 Staff also emphasizes that if the Commission were to deny a
certificate of need, DTEE could still seek recovery, citing MCL 460.6s(8).
In its reply brief, DTEE characterizes M/N/S’s disagreement as “unsupported
rhetoric”, arguing that Ms. Dimitry’s testimony is legally sufficient to support a
Commission decision in DTEE’s favor under the standards of judicial review.239 DTEE
further argues that the license itself is a “useful and valuable asset”, and that it has
“made substantial progress toward a proposed plant that is useful as an option to
potentially build or sell.” DTEE further argues that the Commission is not legally bound
to follow the “used and useful” test in setting rates, citing ABATE v Public Service
Comm, 208 Mich App 248, 258-59; 527 NW2d 533 (1994); Detroit Edison Co v Public
Service Comm, 127 Mich App 499, 524; 342 NW2d 273 (1983); Residential Ratepayer
Consortium v Public Service Comm, 239 Mich App 1, 6; 607 NW2d 391 (1999).240
Addressing the Attorney General’s argument that cost amortization should match
the plant’s useful life, which is the 40-year operating period following completion of
construction, DTEE argues that it is important to distinguish the license from the plant,
arguing that by definition, if the Commission grants recovery over a 20-year or other
237
See MEC-NRDC-SC reply brief, pages 22-24.
See Staff reply brief, pages 28-30.
239
See DTEE reply brief, page 105.
240
See DTEE reply brief, pages 105-106.
238
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period, the license would be viewed as a regulatory asset and the costs would be
recovered over the period that revenues are provided to cover those costs. DTEE reply
brief, page 106.
This PFD finds that the Commission should reject DTE’s request to recover the
COLA expenses through a current amortization of those expenses. The Commission
has already determined that further recovery of these costs is premature. In its October
20, 2011 order in Case No. U-16472, the Commission explained:
On September 18, 2008, Detroit Edison filed a COLA with the NRC
regarding the potential construction of a nuclear generating plant.
Although Detroit Edison indicates that it has not made a decision if or
when this new plant will be constructed, it nevertheless filed the
application to start the process. In defense of filing the application, Detroit
Edison stated that the application has no expiration date, energy supply
and demand forecasts continue to change, and environmental concerns
regarding the use of fossil fuels are increasing. Thus, according to Detroit
Edison, starting the application process and incurring costs to prepare for
the possible construction of a nuclear plant are reasonable and prudent
decisions in the best interest of ratepayers. Detroit Edison projects $25.7
million in COLA-related expenditures in its working capital account for the
test year and requests the Commission allow recovery of these costs.
The Attorney General argued that the COLA-related expenditures are not
legally recoverable because the proposed plant is not in use or benefitting
ratepayers.
The ALJ noted that the Commission approved these costs in previous rate
cases, and therefore found Detroit Edison’s COLA-related costs
reasonable.
In his exceptions, the Attorney General points to several reasons why the
COLA-related projections should not be included: Detroit Edison’s current
excess generating capacity, declining sales, the questionable economic
viability of constructing a nuclear plant, the lack of a concrete plan for
when construction will occur, and no comparative analysis of the costs
and benefits of a nuclear plant compared to other generating possibilities.
In its replies to exceptions, Detroit Edison argues that the Commission has
the authority to consider whether costs are recoverable without ruling on
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whether the construction of a plant is necessary, and that the Commission
should adopt the ALJ’s recommendation to include these costs.
In its replies to exceptions, ABATE supports the Attorney General’s
argument that, at this time, COLA costs are not legally recoverable from
ratepayers. ABATE suggests that the costs should be capitalized and
collected from ratepayers when the new nuclear plant is providing service
to ratepayers.
The Commission recognizes that in prior rate case orders, it allowed at
least a portion of COLA-related costs to be recovered in rates. In the
January 11, 2010 order in Case No. U-15768, after considering the
Attorney General’s argument that the plant was not in use, the
Commission ultimately included $19 million in Detroit Edison’s working
capital account for COLA-related costs. In this case, the Commission finds
that $19 million in COLA-related costs should be included in Detroit
Edison’s working capital account, but finds that the additional $6.7 million
should be excluded from rate base and accounted for as a deferred credit
until the proposed nuclear generating plant in the NRC application can be
considered “used and useful” to Detroit Edison’s ratepayers. The
Commission notes that Detroit Edison should not interpret its allowance of
cost recovery as an invitation to continue to project costs and make
expenditures in large amounts without making progress toward
constructing or deciding to construct a new plant. Order, pages 71-72.
It is thus appropriate to retain the traditional ratemaking approach and deny recovery of
these expenses consistent with this decision, until DTEE builds the plant, unless DTEE
wants to seek advance recovery under the statutory certificate of need process, which
was not foreclosed by the Commission’s decision in Case No. U-16472.
DTEE argues that it has met the criteria identified by the Commission by
obtaining the license, but this is clearly not what the text of the Commission’s order
states. As quoted above, the Commission deferred costs over the amount it initially
approved “until the proposed [plant] can be considered “used and useful” to Detroit
Edison’s ratepayers.” The Commission cautioned DTEE not to consider the initial cost
recovery as “an invitation to continue to project costs and make expenditures in large
amounts without making progress toward construction or deciding to construct a new
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plant.” Nothing in DTEE’s evidentiary presentation establishes that DTEE has either
made progress toward construction or decided to construct a new plant, since it has
merely a license and has not decided whether to construct a plant, and has not even
provided a timeframe within which that decision will be made. Moreover, while DTEE
views the license as providing “flexibility” for current customers, current customers will
not receive any benefit from that flexibility unless and until a nuclear plant is built,
perhaps 20 years down the road when many of them may no longer be customers. This
potential benefit is not a basis to ignore the directions in the Commission’s order.
2. Non-qualified benefits
DTEE seeks to include the cost of certain employee benefits that are considered
non-qualifying under the Internal Revenue Code.
DTEE has four non-qualifying
employee benefit plans: the Supplemental Savings Plan (SSP), the Supplemental
Retirement Plan (SRP), the Executive Supplemental Retirement Plan (ESRP), and a
Deferred Compensation Plan that has been discontinued.
Mr. Wuepper described these programs as providing deferred compensation
over and above the amounts provided under DTEE’s qualifying plan. Mr. Wuepper
testified that the Executive Supplemental Retirement Plan expenses are not qualifying
because the plan is limited to key executives and is in addition to the traditional qualified
defined contribution plan. He explained that the ESRP benefits are 5% to 10% of the
executive’s total compensation, including any incentive payments.241
241
The incentive payments have traditionally not been approved by the Commission, and are again
disputed as discussed in section VII below. Mr. Wuepper subsequently testified that the portion
attributable to incentive payments had been removed from DTEE’s ESRP expense projection.
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Mr. Wuepper explained that the SSP and SRP expenses are considered nonqualifying because they reflect payments above the qualified plan expenses:
As Restoration Plans, the savings and retirement benefits provided in the
SSP and SRP are no different than those provided in the traditional
qualified savings and qualified retirement plans, except the contributions
or benefits they provide exceed the IRC limitations that govern traditional
qualified plans. For example, the compensation used to determine the
contributions to the SSP or the benefit under the SRP may exceed the
IRC Section 401(a)(17) maximum annual compensation limit, which is
$260,000 for 2014; the annual benefit provided under the SRP may
exceed the IRC Section 415(b) limit, which is $210,000 for 2014; the total
annual contribution provided under the SSP may exceed the IRC Section
415(c) limit, which is $52,000 for 2014; and employee pre- tax employee
contributions to the SSP may exceed the IRC Section 402(g) maximum,
which is $17,500 for 2014. Thus, eligible employees with compensation in
excess of $260,000, benefits or total compensation in excess of IRC 415
limitations, or employee pre-tax contributions in excess of $17,500, may
participate in the SSP and/or the SRP as a means to maintain the same
savings and retirement benefits available to all other non-represented
employees. See 6 Tr 1246-1247.
Mr. Wuepper testified that the expenses are reasonable and prudent because they are
part of DTEE’s overall compensation package and many other employers provide these
types of benefits to their highly compensated employees. As support for this testimony,
he cited a study performed by Aon Hewitt.242
Staff objected to providing rate recovery for the Supplemental Employee
Retirement Plan (SERP) and the Executive Supplemental Retirement Plan (ESRP),
citing the Commission’s orders in Case Nos. U-15244 and U-15768.243 Although DTEE
projects test year O&M expenses of $6.2 million for these plans, Ms. Uzenski testified
she included a $50.6 million total liability in working capital for these plans. Staff agrees
242
243
See 6 Tr 1247-1248.
See Welke, 8 Tr 1952.
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that if the Commission adopts its recommendation to exclude these benefit costs from
O&M, the liability should also be excluded from the working capital calculation.244
The Attorney General objects to all of the non-qualified benefit plans, including
the Supplemental Savings Plan and the discontinued Deferred Compensation plan.
Although no party has identified a corresponding working capital component associated
with these non-qualified benefit plans, the arguments are discussed together in this
section.
Regarding the SRP and ESRP, Mr. Coppola raised the same general
objections as Staff, and argued the remaining non-qualified employee benefit plans
should be excluded on the same basis.245 In his brief, the Attorney General argues that
the Commission has been consistent in disallowing recovery of non-qualified benefit
plan costs that benefit executive level employees, that other regulatory commissions
frequently exclude these costs as well, and that DTEE has not shown how these plans
directly benefit customers.
Mr. Wuepper presented rebuttal testimony to distinguish the SRP benefits from
the ESRP benefits:
While the benefits provided under the ESRP are to a select group of
employees, the benefits provided under the SRP are the exact same
benefits provided to all other participants in the Company’s pension plans.
The only reason these benefits are provided through the SRP is because
of the arbitrary limits imposed by the Internal Revenue Code (IRC). Thus,
since there is no reason to conclude the Company’s pension benefits are
unreasonable, there is no basis to conclude that the benefits provided
employees under the SRP are unreasonable.246
And he testified as following regarding both programs:
Staff Witness Welke’s proposed exclusion of the SRP and ESRP
expenses based on his conclusion that the “benefits are not
244
See Bankapkur, 8 Tr 2034.
See 9 Tr 2314-2315.
246
See 6 Tr 1299.
245
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commensurate with the costs” represents a conclusion without any factual
basis. As already mentioned, the benefits provided within the SRP are the
same for the plan participants as any other employee, so there are no
incremental costs of providing the SRP. As to the ESRP, the Company
and its customers benefit from the ability to offer competitive total
compensation programs that allow the Company to successfully attract
and retain highly skilled and competent employees. The benefits to
customers of the ESRP are no different than the benefits customers derive
from the salaries of these employees. Absent a determination of excessive
compensation, which has not and could not be made in this instance,
there is no basis for excluding a component of the compensation for the
plan participants. This is especially apt given that the Company has
already excluded from the SRP and ESRP expenses related to both the
Top Five Executives as well as the impact of the Company’s incentive
compensation programs.247
Ms. Uzenski asked the Commission to reverse its early decision requiring these
expenses to be recorded in account 426.5, Other Deductions, and allow them to be
recorded in account 926, Employee Pensions and Benefits.248 In its brief, DTEE argues
that it would be pointless for it to provide a cost-benefit analysis of these compensation
elements because they are part of the company’s total compensation package.249
In several rate cases, the Commission has made clear that the expenses of the
ESRP and SRP compensation programs should be excluded from rates. A review of
the Commission’s decisions in those cases shows that the Commission rejected the
same arguments DTEE advances in this case. In Case No. U-15244, the Commission
explained:
The Commission finds that Detroit Edison’s request for projected 2009
stock option expenses, performance share expenses, restricted stock
expenses, and executive deferred compensation – gains expenses should
be rejected. These expenses are used to encourage executives to
promote the financial performance of Detroit Edison, which mainly benefits
the company’s shareholders, not its ratepayers. Therefore, Detroit Edison
shall not recover from ratepayers any expenses for stock options,
247
See 6 Tr 1299.
See 6 Tr 1023,1058.
249
See DTEE brief, page 95.
248
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performance shares, restricted stocks, and executive deferred
compensation – gains. See December 23, 2008 order, Case No. U-15244,
page 35.
And in Case No. U-16472, the Commission found:
Detroit Edison has not sufficiently differentiated these costs from the ones
disallowed in the previous rate case. As noted by the ALJ, these costs are
non-qualified plan costs . . . attributable to the company’s supplemental
executive retirement plan (SERP) and the executive supplemental
retirement plan (ESRP), which the Commission disallowed in the
December 23, 2008 order in Case No. U-15244 . . . . The Commission
agrees with the ALJ that the SERP and ESRP appear to be substantively
the same as those costs which the Commission previously rejected.
Detroit Edison has failed to persuade the Commission that these plans are
now redesigned to benefit ratepayers rather than shareholders. Without
such a persuasive analysis, the Commission concludes Staff’s
disallowance should be adopted.250
Contrary to DTEE’s arguments, the Commission is not limiting the total
compensation that can be paid to DTEE employees. Instead, the Commission has
determined that the more expensive form of compensation reflected in the nonqualifying plans have not been shown to be cost-justified for the ratepayers, as
explained above. While DTEE argues that Staff should have the burden to prove these
expenses should be disallowed, this PFD concludes that the Commission has already
given DTEE direction regarding these expenses, and the burden is clearly on DTEE to
respond to the Commission’s prior decisions to establish that a change should be made
in the characterization of these expenses as not recoverable. Instead, DTEE has not
refuted the Commission’s prior findings: it acknowledges that these are the same plans
for which costs were disallowed in the last cases, and has not claimed they have been
redesigned to benefit ratepayers rather than shareholders.
DTEE remains free to
continue the non-qualifying compensation programs for its highly-compensated
250
See October 20, 2011 order, Case No. U-16472, pages 66-67.
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employees without ratepayer funding, or restructure its compensation to an alternate
form consistent with the Commission’s prior decisions if it believes its employees are
undercompensated.
On the other hand, it appears that the Commission has allowed DTEE to recover
the expenses associated with the SSP. In his rebuttal testimony, Mr. Wuepper cites the
Commission’s October 20, 2011 order in Case No. U-16472, and DTEE cites this order
in its brief. As the Attorney General argues, however, a review of that order shows that
although it references the SRP and ESRP, it also indicates that “all” non-qualifying
benefit costs were to be excluded; there is nothing in the text of the Commission’s order
that distinguishes the other non-qualified plans.251
The Commission’s order states:
“The ALJ recommended that the Commission adopt the Staff’s proposal to exclude all
non-qualified pension and deferred compensation costs, thereby reducing expenses by
$7,255,000. . . . The Commission finds that Detroit Edison’s exception is without
merit.”252 In Case No. U-15244, however, the Commission did expressly permit rate
recovery for the SSP. Under the heading “Other Employment Benefits”, the Commission
provided the following background:
The historical 2006 other employee benefit expenses were $10,789,000.
Detroit Edison reported that it had historical 2006 expenses of $3,369,660
for Supplemental Employee Retirement Plan (SERP); $902,410 for
Executive Supplemental Retirement Plan (ESRP); $1,356,100 for
performance shares – dividends; $1,532,890 for non-qualified savings
plan expenses (SSP); and $427,420 for executive benefits – other
expenses. Historically, the Commission has not allowed Detroit Edison to
recover from ratepayers the SERP, ESRP, performance shares –
dividends, or non-qualified savings plan and executive benefits – other
expenses.253
251
See Attorney General brief, pages 31-32.
See October 20, 2011 order, page 66.
253
See December 23, 2008 order, Case No. U-15244, page 33.
252
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After some discussion of the arguments of the parties, the Commission explained that
Staff subsequently determined that the SSP should be included in expenses
recoverable from ratepayers. The Commission found this expense to be reasonable,
stating:
The Commission finds the Staff’s projected 2009 other employee benefit
expenses to be reasonable. Detroit Edison shall be permitted to recover
from ratepayers $4,733,410 in other employee benefit expenses. In
addition, the Commission finds that Staff’s projected 2009 inflation
calculation for the SSP and executive benefits – other of $381,865 is
reasonable, and Detroit Edison may recover this amount from
ratepayers.254
Thus, in Case No. U-15244, the Commission permitted DTEE to recover the SSP
expenses. This order does not cite the discontinued Deferred Compensation Plan,
although it could fall within the category of “executive benefits – other” mentioned in that
order. Given that the projected test year expenses are $152,000 for the discontinued
Deferred Compensation Program, DTEE believes it has authority to recover these
expenses, and the Commission did not require those expenses to be included in a
separate account as it did with the SRP and ESRP expenses, it is reasonable to allow
DTEE to include the discontinued Deferred Compensation Plan expenses in rates as
well.
For these reasons, this PFD recommends that the Commission adopt Staff’s
adjustments regarding the SRP and ESRP.
3. OPEB
Beginning in 2012, DTEE made changes to its retirement health care benefits.
Mr. Wuepper explained the changes that took place in 2012 and 2013. As a result of
254
See December 23, 2008 order, Case No. U-15244, page 34.
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these changes, DTEE booked a negative OPEB expense for 2013 and 2014, and is
projecting a negative expense for the projected test year. DTEE proposes to treat the
negative OPEB expense as a regulatory liability. As Ms. Uzenski testified:
The Company will fund $117 million for 2014 OPEB costs included in rates
as mandated by the Commission in its Order in Case No. U-16472, based
on $120 million reduced for $3.0 million of the Company’s contributions to
its New Hire Retirement VEBAs. The OPEB costs reflected in the
Company’s revenue requirements for the first half of 2015, net of the
prorated $4.3 million of 2015 contributions to the New Hire Retirement
VEBAs, result in a funding requirement before the self-implementation of
new rates of $57.9 million. If the Commission adopts the Company’s
proposal and the projected negative OPEB costs are deferred, then the
net OPEB expense will be zero for the second half of 2015, and DTE
Electric will fund the $57.9 million at the end of 2015. There will be no
OPEB expense reflected in the revenue requirement in 2016 and
subsequent years; thus there will be no external OPEB funding
requirement.255
As explained by Mr. Welke, Staff endorses DTEE’s request. Mr. Welke testified that the
regulatory liability should accrue annually by the same amount until adjusted in DTEE’s
next rate case. With this treatment, the liability amount would be included in working
capital.
The Attorney General opposes this treatment. Mr. Coppola testified that because
DTEE recorded a total of $74.9 million of negative OPEB expense in 2013 and 2014, its
request to defer $53.6 million in negative expense that would otherwise decrease its
2015/2016 test year revenue requirement should be rejected and instead the negative
OPEB cost should be reflected as an offset to O&M expenses:
First of all, the Company should have proposed such a deferral in
conjunction with the restructuring of the plan that occurred in 2013. If
deferred from the beginning, the amount accumulated in the deferral
account would have been $74.9 million as of the end of 2014 and the
additional projected negative expense for 2015 and 2016 would have
grown the deferral to $182.1 million by the end of 2016. Instead, the
255
See 6 Tr 1027-1028.
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Company chose to stay silent on the changes and flow the benefit of
$102.2 million for the first two-and-half years to its bottom line. Although
the negative expense may have offset some cost increases the Company
experience in its business, it is not a convincing argument to now change
approaches at mid-stream.256
He also pointed out that DTEE’s rate filing proposes a significant increase in rates. In
his rebuttal testimony, Mr. Coppola responded to Staff’s recommending, noting that
Staff agreed to a different treatment for a similar expense in Consumers Energy’s rate
case, Case No. U-17735, only a month earlier.257
He testified that he would have
expected Staff to criticize DTEE’s delay in establishing the deferral on its books.
Ms. Uzenski addressed Staff’s interpretation of DTEE’s proposal in her rebuttal
testimony:
The Company is proposing that negative OPEB expense be offset with a
regulatory liability, and did project the expense before the offset at $53.6
million. But to clarify, including the impact of the regulatory liability offset,
base rates would reflect a net amount of zero OPEB expense. Therefore,
to maintain a net zero expense until rates are adjusted in our next rate
case, the regulatory liability should be accrued at an amount equal to the
actual expense recorded in future periods.258
She also provided an updated expense projection in Schedule U1 of Exhibit A-31.
In its brief, DTEE cites this testimony to clarify its proposal.259 DTEE argues that
its proposal parallels the Commission’s treatment of this expense in its April 28, 2005
order in Case No. U-13898, pages 31-32, for Michigan Consolidated Gas Company. It
also argues that an update as of February 2015 shows a negative $46.1 million
256
See 9 Tr 2317.
See 9 Tr 2373-74
258
See 6 Tr 1065.
259
See DTEE brief, page 93.
257
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expense instead of a negative $53.6 million. Staff’s brief acknowledges Ms. Uzenski’s
clarification and adopts it.260
DTEE addresses Mr. Coppola’s objection by arguing that customers have
already received the benefit of the OPEB savings because those savings helped DTEE
delay its present application for a rate increase. DTEE also argues that the OPEB
savings are amortized over four to five years, with the majority of savings recognized by
the end of 2016, and further arguing that it would not be prudent or reasonable to
reduce its rate request based on a non-recurring credit: “OPEB costs will increase
significantly in 2017 as the temporary credit expires. If the projected 2016 credit were
used to reduce rates as proposed by the AG, then there would be a revenue shortfall of
almost $48 million, and the Company would presumably need to file another rate case
to address this mismatch between costs and rates.”261
In its reply brief, the Attorney General addresses this argument:
“DTE’s
argument is similar to many of its contingency money requests such as for the AMI and
Air Quality Capital Projects. . . The Commission should not allow DTE to retain this
credit on the argument that it may have to come back for another rate case unless DTE
agrees to a rate moratorium for some period of time in return for the credit.”262
While it is regrettable that DTEE did not seek to defer the negative OPEB
expense in 2012, electing to reap the benefits during the time period between rate
cases, this PFD recognizes that if DTEE had sought deferral in 2012, the deferral would
have been granted, and further, that DTEE’s proposal is a reasonable one to address
such a limited-time cost reduction.
260
See Staff brief, page 57.
See DTEE brief, page 94.
262
See Attorney General reply brief, page 8.
261
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On this basis, this PFD recommends that the
Commission grant the deferral as explained by Ms. Uzenski. Note that in making this
recommendation, this PFD is not endorsing DTEE’s claim that ratepayers benefitted
while DTEE was recognizing the negative OPEB expense as current income because
doing so deferred a rate increase.
C.
Rate Base Summary
Staff’s rate base as filed is $13,456,612,000. Consistent with the discussion
above, this PFD recommends that that Commission adopt Staff’s rate base with the
following additional adjustments: 1) Staff’s adjustment to DTEE’s generation expense
projections in Exhibit A-9, Schedule B6.1 should be modified to reflect the adjustments
in section A1b above; 2) capital expenses for the East China plant should be removed
from the projected rate base as explained in section A2 above; 3) projected nuclear
generation contingency spending should be removed as explained in section A3 above;
4) projected Neighborhood Revitalization and Workplace Transformation expenditures
for 2015 and 2016 should be removed from projected rate base as explained in section
A5 above. Staff estimates the impact of these adjustments as a reduction in rate base
of approximately $105.4 million, resulting in a rate base of $13,351,237,000.
VI.
RATE OF RETURN
The rate of return component of the revenue requirements determination is
designed to meet the constitutional and statutory standards entitling the utility to a fair
rate of return on its investment. The Commission in its past decisions and the witnesses
testifying in this case recognize as controlling precedent, the U.S. Supreme Court cases
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Bluefield Water Works Co v Public Service Comm of West Virginia, 262 US 679; 42 S
Ct 675; 67 L Ed 1176 (1923) and Federal Power Comm v Hope Natural Gas Co, 320
US 591; 64 S Ct 281; 88 L Ed 333 (1944).
DTEE’s initial filing calculated an overall rate of return of 5.96% on an after-tax
basis, but DTEE reduced its calculated overall rate of return to 5.87% in its briefs by
updating its estimated cost of debt in accordance with Mr. Solomon’s rebuttal testimony,
and by incorporating an increased deferred income tax balance. The company bases its
request on its expected permanent actual capital structure of 50% equity and 50% longterm debt for the 2015/2016 test year, and a cost of equity of 10.75%. Staff
recommends an overall rate of return of 5.58%, based on a cost of equity of 10.00%
and a 50/50 capital structure. Staff’s recommendation also reflects an adjustment from
its initially-filed recommendation due to an update to the deferred income tax balance.
The Attorney General recommends an overall rate of return of 5.53% based on a capital
structure with 52% debt and 48% equity, and a cost of equity of 9.75%. ABATE takes a
position only on the cost of equity portion of the rate of return calculation,
recommending a return on equity of 9.5%. Kroger takes a position only regarding the
amount of the deferred income tax balance in the capital structure. Walmart takes a
position only regarding certain factors that the Commission should consider in setting
DTEE’s authorized return on equity.
To determine the rate of return to use in setting rates, it is customary to start with
the development of an appropriate capital structure, and then to evaluate the
appropriate costs to assign each element of the capital structure. The appropriate
capital structure is discussed in subsection A below, the cost of long-term debt is
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discussed in subsection B, and the cost of equity capital is discussed in subsection C.
The overall rate of return recommendation is presented in subsection D.
A.
Capital Structure
The capital structure used for ratemaking includes as its components long-term
debt, preferred stock, and common equity capital, and in addition includes short-term
debt and other items such as deferred taxes that reflect sources of financing available to
the company. Only long-term debt, preferred stock, and common equity capital are
considered part of the utility’s “permanent” capital, and it is common for capital
structures to be shown in exhibits on both a “permanent” basis and on a ratemaking
basis. DTEE does not have preferred stock, so discussions of its permanent capital
structure refer only to long-term debt and equity ratios.
Based on their briefs, Staff, DTEE and Kroger now agree to the capital structure
that should be used for the projected test year, including the balances for each element
of that capital structure. The Attorney General recommends an alternate debt-to-equity
ratio as discussed below.
Mr. Solomon testified that DTEE’s projected cost of capital is based on a
permanent capital structure of 50% long-term debt and 50% equity, shown in Exhibit A11, Schedule D1. He acknowledged that in DTEE’s last rate case, Case No. U-16472,
the Commission used a debt ratio of 51%, but testified that DTE’s debt ratio as of
December 31, 2013 was 50% as shown in his Exhibit A-17, Schedule I3. He also
testified to the importance of the capital structure in determining a fair and equitable rate
of return, and to allow DTEE to raise the funds necessary to operate its business at
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reasonable costs and terms, especially since DTEE will be financing and funding
significant capital investments.263
Staff adopted the same ratios of debt and equity for DTEE’s permanent capital
structure, but recommended lower balances of debt and equity in the ratemaking capital
structure. Ms. Sandhu testified that the deferred tax balances should be increased by
$111 million, due to the federal bonus depreciation tax extension included in the Tax
Increase Prevention Act of 2014 not reflected in DTEE’s capital structure. She explained
that although the updated figure of $111 million should be used in the cost of capital
calculation, Staff’s Exhibit S-4, Schedule D1 reflects only a $97 million adjustment
because that was the most recent information Staff had available when it prepared the
exhibit.264 The more recent information was obtained by Kroger through discovery.
Kroger’s witness, Mr. Townsend, also recommended that the deferred income tax
component of the ratemaking capital structure be increased to reflect the bonus tax
depreciation, with corresponding decreases to the equity and long-term debt balances.
DTEE did not address this adjustment in its rebuttal testimony, but in its initial brief,
adopts the full amount of the adjustment recommended by Ms. Sandhu and Mr.
Townsend.265
Mr. Coppola recommended that the Commission adopt a permanent capital
structure with 52% long-term debt and 48% equity as shown in his Exhibit AG-13, to
reflect the percentages in the historical test year.266 He testified that DTE’s 50/50
proposal is an increase in equity over the historical test year percentage of 47.97%
263
See 7 Tr 1574.
See 8 Tr 2006-2007.
265
See DTEE brief, page 17, and Attachment A, page 4, and as further revised in the DTEE reply brief,
Attachment A, page 4.
266
See 9 Tr 2337-2338.
264
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shown in Exhibit A-4, Schedule D1, and further elaborated: “It is difficult to image 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.”267 He
acknowledged DTEE’s representation in discovery that DTE Energy would issue $200
million in equity in 2015 but testified that DTE Energy’s recent Form 10-K indicates that
the $200 million will be issued through employee benefit plans and makes no mention of
any additional equity issuances. Mr. Coppola also testified that DTEE’s Exhibit A-11,
schedule D2 shows $500 million more in debt than the level used in Exhibit A-11,
Schedule D1 to compute the overall cost of capital.
In his rebuttal testimony, Mr. Solomon testified that he disagreed with Mr.
Coppola’s recommendation, distinguishing the 13-month average debt and equity
balances of 52% and 48% for the historical test year presented in Exhibit A-4, Schedule
D1, from the December 31, 2013 year-end actual balances of 50% debt and 50% equity
that he cited in his testimony. He further testified that DTEE has maintained a 50/50
capital structure through 2014 and is forecast to be at a 50/50 capital structure for the
test period.268 He testified that it is not unrealistic for DTEE to increase its equity
balance from $4.2 billion to $5.2 billion over a two-and-a-half year timeframe, explaining
that DTE Energy can increase its equity infusion in DTEE through retained earnings as
well as additional stock issuances, and further testified that DTEE does plan to issue
$800 to $900 million in new equity over the 2015-2017 timeframe. Finally, Mr. Solomon
testified that the over $600 million difference between the long-term debt balance of
$5.88 million in Schedule D2 of Exhibit A-11 and the long-term debt balance of $5.22
267
268
See 9 Tr 2338.
See 6 Tr 1592-1593.
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million in Schedule D1 of that exhibit is attributable to the regulatory adjustments
reflected in Schedule D1 to exclude such items as renewable energy, the rabbi trust,
and unamortized debt issuance costs.269 Under cross-examination from the Attorney
General, Mr. Solomon explained DTEE’s dividend policy, under which 70% of DTEE’s
earnings are dividended to the parent,270 and explained how DTE Energy manages the
balance sheets of the utilities and the company as a whole.271 He explained that the
difference between the historical test-year average balance and the year-ending
balance is attributable to a large end-of-the-year equity infusion, and reiterated DTE
Energy’s intent to maintain the 50/50 capital structure for DTEE.
In its brief, DTEE argues that the company needs a capital structure with a strong
equity ratio to offset other risk and maintain access to capital at the lowest possible
cost.
272
In his brief, the Attorney General merely quotes Mr. Coppola’s testimony to
support his argument that DTE’s proposed capital structure is unreasonable, but does
not address Mr. Solomon’s rebuttal testimony or testimony on cross-examination.273
While Mr. Solomon did not claim that 50/50 debt and equity ratios are optimal, he
did testify persuasively that DTE Energy intends to manage DTEE’s capital structure to
retain the 50/50 ratios, and that it is appropriate to use these ratios in setting rates for
the 2015/2016 test year. On this basis, this PFD recommends that the Commission
adopt the capital structure balances as set forth in page 4 of Attachment A to DTEE’s
reply brief, reflecting 50/50 debt and equity ratios for DTEE’s permanent capital
structure, debt and equity balances of $5,165,318,000 and $5,164,758,000 respectively,
269
See 6 Tr 1594.
See 6 Tr 1595.
271
See 6 Tr 1599.
272
See DTEE brief, pages 20-23.
273
See Attorney General brief, pages 49-50.
270
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and undisputed balances for the other elements of the ratemaking capital structure,
including the revised balance of $2,926,181,000 for deferred taxes, $299,475,000 for
short-term debt, and $25,770,000 for JDITC.
B.
Debt Cost
The only parties to address long-term debt costs, Staff and DTEE, are now in
agreement on the appropriate cost rates to use in calculating the cost of long-term debt.
In its initial filing, DTEE projected a weighted cost of long-term debt of 4.65%, based on
three anticipated new issues of debt beginning in March of 2015. This was presented in
Mr. Solomon’s Exhibit A-11, Schedule D2.
Staff, relying on updated information regarding the March 2015 issuance amount
and cost, used a weighted cost of long-term debt of 4.54%, as explained by Ms. Sandhu
and presented in Exhibit S-4, Schedule D2.
In his rebuttal testimony, Mr. Solomon incorporated the more recent information
to calculate a weighed cost of long-term debt of 4.56%, shown in his Exhibit A-30. He
explained that because DTEE’s debt issuance in March of 2015 was larger than
originally planned, its July 2015 debt issuance would be $90 million smaller, or $75
million, thus accounting for the remaining difference between DTEE’s long-term debt
cost estimate and Staff’s. In its initial brief, Staff indicates that it agrees with Mr.
Solomon’s revised calculation of 4.56%, noting that the cost difference does not affect
Staff’s overall weighted cost of capital estimate.
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C.
Equity Cost (Return on Equity)
As discussed below, four of the witnesses testifying on the appropriate rate of
return on equity for DTEE employed a variety of models using proxy groups of
companies intended to be comparable to DTEE, resulting in a range of estimates of the
cost of equity capital. The analysts make their final recommendations by reviewing the
range of costs produced by the models, along with their judgment and experience. In
the discussion that follows, the analysis and recommendations of DTEE, Staff, the
Attorney General, ABATE, and Walmart are reviewed, including a review of the rebuttal
testimony and briefs, followed by a discussion of the key disputed points.
1. DTEE
Dr. Vilbert established a proxy group of regulated companies whose primary
source of revenues and majority of assets are in the regulated portion of the electric
industry.274 Beginning with all publicly traded electric utilities as classified by Value
Line, he identified the following additional criteria for the proxy group:
The companies must own substantial regulated assets, must not exhibit
any signs of financial distress, and must not be involved in any substantial
merger and acquisition (“M&A”) activities that could bias the estimation
process. In general, this requires that over a five year study period and up
to the date of the analysis, the sample companies have an investment
grade credit rating, a high percentage of regulated assets (greater than 50
percent), no significant merger activity, no dividend cuts, and no other
activity that could cause the growth rates or beta estimates to be biased. I
also require that each of the sample companies has more than $300
million in reported revenue over the last four quarters of available financial
data. Finally, I require that data from S&P or Moody’s, Value Line, and
Bloomberg—each widely known and utilized by investors—be available for
all sample companies.275
274
275
See Tr 1464.
See Tr 1463 (footnotes omitted).
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Information on the resulting 28 proxy companies is presented in Table 2 in his
testimony,276 and in Schedules D6.2 and D6.3 of Exhibit A-11. He compared the sample
companies to DTEE, discussing some financial metrics and discussing DTE’s business
risk, and concluded that DTEE has higher than average business risk relative to the
sample companies. 277
Dr. Vilbert performed two types of analyses to estimate the cost of equity for the
proxy companies, a discounted cash flow (DCF) analysis and a “risk positioning”
analysis, which included variations of the Capital Asset Pricing Model (CAPM). For his
CAPM analysis, Dr. Vilbert determined a risk-free rate as follows:
Modern capital market theories of risk and return (e.g., the theoretical
version of the CAPM as originally developed) use the short-term risk-free
rate of return as the starting benchmark, but regulatory bodies frequently
use a version of the risk positioning model that is based upon the longterm risk-free rate. In this proceeding, I rely upon the long-term version of
the risk positioning model. Accordingly, the implementation of my
procedures requires use of long-term U.S. Treasury bond interest rates.
Normally, I obtain this information from the 15-day average yield on 20year Treasury bonds as reported by Bloomberg for the period ending on
the date of my analysis. However, it is my understanding that the test
period for this proceeding is such that although the Company will be
allowed to self-implement any potential rate increase subject to refund
effective July 1, 2015, the final tariff rates will not go into effect until
December 2015. As such, I do not believe the current yield on the longterm Treasury bond is a good estimate for the risk-free rate that will prevail
over the relevant time period. For this reason, I use a risk-free rate based
on the forecasted value from Consensus Forecast®. Specifically, I use the
3.4 percent yield on the 10-year U.S Treasury bond forecasted to be in
effect in September 2015, and adjust it upward by 33 bps, which is my
estimate of the representative maturity premium for the 20-year over the
10-year Treasury Bond. The resulting value for the unadjusted risk-free
rate is 3.73 percent.278
He further explained why he did not use a short-term risk-free rate:
276
See Tr 1465.
See 7 Tr 1464-1471, 1487-1488.
278
See Tr 1472-73.
277
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Short-term Treasury bill yields remain at artificially low levels due to the
efforts of the Fed to stimulate the economy. As a result, the risk
positioning required ROE estimates using the short-term Treasury bill
yields as the risk-free interest rate are unreasonably low. For example,
the estimates are sometimes less than the corresponding company’s
current market cost of debt, which is unreasonable.”279
And Dr. Vilbert testified regarding the choice of a market risk premium (also referred to
as an MRP) for the CAPM analysis:
Historically, much of the controversy over market risk premium centered
on various reasons why it may not be as high as frequently estimated.
Although none of the arguments was completely persuasive in and of
itself, I generally gave some weight to these issues in past testimony and
reduced my estimate of the MRP. Conversely, recent events have strongly
suggested an increase in the MRP from its previous levels. I would
typically consider an MRP of 6.5 percent over the long-bond rate as
reasonable based on my review of the relevant academic literature.
However, current market conditions suggest that a value of 7.5 percent
could be more appropriate at this time. Therefore, I include two analyses:
one using an MRP of 6.5 and the other using an MRP of 7.5 percent.280
The risk-free rate of 3.73% and the market risk premium of 6.5% were the
starting point for his subsequent adjustments, including a derivation of the 7.5% market
risk premium value referenced above. He adjusted each of these starting values using
two different scenarios. He testified that the motivation for the two scenarios is the
empirical observation that the yield spread is higher than normal:281
Table 1 [at 7 Tr 1435] shows that yield spread for A-rated utility debt has
increased by about 31 bps for 20-year maturities. This means that
investors require a higher return on investment grade utility debt relative to
the return on U.S. Government debt than before the credit crisis. Some of
the increase in yield spread for A-rated debt may be due to an increase in
default risk, but this is more likely to be a factor for BBB-rated utility bond
yields. The increase in the default risk premium for A-rated debt is
undoubtedly very small because A-rated utility debt has not been at the
center of the wave of defaults based upon collateralized mortgage debt.
This means that the vast majority—if not all—of the increase in A-rated
279
See 7 Tr 1473.
See Tr 1474-75.
281
See 7 Tr 1480.
280
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yield spreads is due to a combination of the increased systematic risk
premium and the downward pressure on the yields of government debt
caused by the flight to safety. In other words, either the market risk
premium has increased or the risk-free rate is underestimated, or both.
Therefore, I consider possible allocations of the approximately 30 bps
increase in A-rated utility spreads between an increase in the MRP (which
drives the increase in systematic risk premium on A-rated debt), or
downward pressure on the risk-free rate.282
The two scenarios he used provide for a 30 basis point increase to the return otherwise
predicted for a security with a beta of .25, to reflect an A-rated utility bond:
For the risk positioning method, I recognize the unusually large yield
spreads on utility debt by adding a “yield spread adjustment” to the current
long-term risk-free rate. This has the effect of increasing the intercept of
the Security Market Line displayed in Figure 1 [at 7 Tr 1435]. I also
present results from the risk positioning model by increasing the MRP over
the 6.5 percent that I normally use. This has the effect of increasing the
slope of the Security Market Line displayed in Figure 1. I present
sensitivity tests of the effect of an increase in the MRP to 7.5 percent and
yield spread adjustments to the risk-free rate of 5 and 30 basis points
(“bps”).283
In Scenario 1, Dr. Vilbert posited that the 30 basis point yield spread should be
attributed entirely to an underestimate of the risk-free rate, “temporarily depressed
government bond yields caused by the actions of the Fed and the “flight to safety” in the
wake of the financial crisis.”284 He therefore derives an adjusted risk-free rate of 4.03%
for this scenario. In Scenario 2, he posited that a reasonable estimate for the beta of an
A-rated utility bond is .25, and reasons that an increase of 25 basis points in the yield
for an investment with a beta of .25 translates into an increase the market risk premium
of 1%. His scenario 2 thus uses a market risk premium of 7.5% with the remaining .05
basis point increase in yield spread attributed to an increase in the risk-free rate, or
282
See 7 Tr 1458-1459.
See 7 Tr 1457-1458.
284
See 7 Tr 1460.
283
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3.78%.285 He presented a diagram illustrating the adjustments underlying these two
scenarios relative to the “security market” line representing the return for each level of
risk as measured by beta.286 Dr. Vilbert used the adjusted risk-free rates and market risk
premium values from each of these two scenarios in the traditional CAPM model, using
adjusted betas from Value Line.287 The results for each scenario are presented in
Schedule D6.10 of Exhibit A-11, pages 39 and 40, column 4.
Dr. Vilbert also testified that it is preferable to use a different version of the
Capital Asset Pricing Model, the Empirical Capital Asset Pricing Model (or ECAPM), to
reflect empirical observations regarding the relationship between risk and return:
The CAPM has not generally performed well as an empirical model, but its
shortcomings are directly addressed by the ECAPM. Specifically, the
ECAPM recognizes the consistent empirical observation that the CAPM
underestimates (overestimates) the cost of capital for low (high) beta
stocks. In other words, the ECAPM is based on recognizing that the actual
observed risk-return line is flatter and has a higher intercept than that
predicted by the CAPM. The alpha parameter (α) in the ECAPM adjusts
for this fact, which has been established by repeated empirical tests of the
CAPM.288
Dr. Vilbert presented another drawing of the security market risk line to illustrate the
relationship between the CAPM and ECAPM.289 As he explained and as shown on this
drawing, using his ECAPM has the effect of increasing the indicated return for lower-risk
securities, those with betas less than one, and decreasing the indicated return for
higher-risk securities, those with betas above one. In order to reflect the empirical
observations, he testified that he used two different values of alpha in the equation for
the ECAPM, .5% and 1.5%, deriving two sets of results that he labeled ECAPM (0.5%)
285
See 7 Tr 1460-1461.
See 7 Tr 1461, Figure 7.
287
See 7 Tr 1475-1478 for Dr. Vilbert’s discussion of betas.
288
See 7 Tr 1479. The ECAPM equation is: rs = rf + α + βs x (MRP - α).
289
See 7 Tr 1480.
286
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and ECAPM (1.5%), with each set of results including estimated returns for each proxy
company under each of the two scenarios discussed above. The results are presented
in Schedule D6.10 of Exhibit A-11, pages 39 and 40, columns 5 and 6.
After obtaining the CAPM and ECAPM results for Scenarios 1 and 2, Dr. Vilbert
adjusted these results using what he labeled the After-Tax Weighted Average Cost of
Capital or ATWACC approach. He testified that this adjustment is necessary:
The ATWACC is one of several procedures in my analysis; it is important
because it allows a comparison between the sample companies’ costs of
capital estimates and the cost of capital for DTE. Two otherwise identical
companies with different capital structures will typically have different
costs of equity because the risks to equity holders depend on the financial
leverage (i.e., the amount of debt in the capital structure of the company).
This makes it difficult to compare cost-of-equity estimates among
companies that have different capital structures. The effect of varying
financial leverage on the risk-return tradeoffs of companies means that
simply averaging individual cost-of-equity estimates across a sample
generally does not provide meaningful information about an appropriate
representative cost of capital for the industry. Thus it is generally incorrect
to compute a sample average return on equity when estimating the cost of
capital. However, two otherwise identical companies with different capital
structures will generally have comparable ATWACC values. The “apples
to apples” comparability of ATWACC across companies with different
capital structures makes it a consistent measure of the representative cost
of capital in an industry.290
In making this adjustment, he posited that the weighted market cost of capital for DTEE
should be equal to the average of the after-tax weighted cost of capital for each of the
proxy companies, where the after-tax weighted cost of capital is computed using each
proxy company’s market-value capital structure based on a five-year average, the
equity returns developed using the CAPM, ECAPM (0.5%), and ECAPM(1.5%) models
for each of the two scenarios, and a cost of long-term debt based on each proxy
290
See 7 Tr 1438.
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company’s Standard & Poor’s bond rating.
291
These values, along with averages, are
presented in Schedule D6.11 of Exhibit A-11, pages 41 and 42.
Once the proxy group average ATWACC is computed for each model and each
scenario, for a total of six averages, Dr. Vilbert determined a corresponding cost of
equity that would be required to be applied to DTEE’s book value capital structure to
produce the same overall weighted average cost of capital. To perform this calculation,
he used a market cost of debt of 4.6% for DTEE, based on a BBB bond rating from S&P
and a yield from Bloomberg as of September 22, 2014.292 The results are presented in
Schedule D6.12 of Exhibit A-11, page 43.
In his DCF analysis, Dr. Vilbert used two DCF models labeled “simple” and
“multistage.” He used the following inputs: for the growth rates he looked a sample of
investment analysts’ forecasted earnings growth rates from Bloomberg and Value Line.
For the long-term growth rates used in final stage of his multistage DCF model, he used
the long-run GDP forecast from Blue Chip Economic Indicators. His results are
presented in Schedule D6.6, pages 33 and 34, for each of the proxy companies.
Dr. Vilbert testified to the following advantages of the DCF model:
The DCF approach is grounded in solid financial theory. It is widely
accepted by regulatory commissions and provides useful insight regarding
the cost of capital based on forward-looking metrics. DCF estimates of
the cost of capital complement those of the CAPM and ECAPM because
the two methods rely on different inputs and assumptions. The DCF
method is particularly valuable in the current economic environment,
because of the effects on capital market conditions of the Fed’s efforts to
maintain interest rates at historically low levels which bias the CAPM and
ECAPM estimates downward.
291
See Schedules D6.11, D6.4, and D6.7 of Exhibit A-11. Dr. Vilbert includes a tax rate of 38.9% as part
of the cost of equity, and he also recognizes that some of the proxy companies have preferred stock.
292
See Exhibit A-11, Schedule D6.12, n4.
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However, I recognize that the DCF model, like most models, relies upon
assumptions that do not always correspond to reality. For example, the
DCF approach assumes that the variant of the present value formula that
is used matches the variations in investor expectations for the growth of
dividends, and that the growth rate(s) used in that formula match current
investor expectations. Less frequently noted conditions, such as the value
of real options incorporated in a company’s market price, may create
issues that the DCF model does not incorporate. Nevertheless, under
current economic conditions, because of its forward looking nature, the
strengths of the DCF method far outweigh any weaknesses the method
may have.293
Dr. Vilbert also adjusted his DCF results using the ATWACC approach described
above, except that in determining each proxy company’s weighted average cost of
capital for this analysis, he uses the market value capital structure for that company that
he used in the DCF analysis, based on balance sheet information as of the second
quarter of 2014, and a 15-day closing price ending on September 22, 2014, as shown in
Schedules D6.3 and D6.4 of Exhibit A-11. The weighted average cost of capital for each
proxy company using the DCF results and this market value capital structure data is
presented in Schedule D6.7 of Exhibit A-11, pages 35 and 36, for the simple and
multistage models respectively. Table 7 at Tr 1486 also presents his average adjusted
DCF estimated rates of return for the simple and multi-stage versions.
Dr. Vilbert’s overall recommendation of 10.75% is based on his adjusted DCF,
CAPM and ECAPM results, his analysis of the respective merits of each, and his
opinions regarding the relative riskiness of DTEE in comparison to the proxy group. In
making this recommendation, Dr. Vilbert testified that he relied more heavily on the DCF
estimates than he would in normal times, for the reasons noted above; he testified that
the CAPM results are less reliable than the ECAPM results, because the ECAPM
results account for the empirical observation that low beta stocks have higher costs of
293
See 7 Tr 1484.
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capital than estimated by the CAPM and high beta stocks have lower costs of capital;
and he testified that the Scenario 2 results are more reliable “because Scenario 1
ignores the increased MRP resulting from the ongoing uncertainty in the capital
markets.” From his range of results, he recommended that the cost of equity be within
the range of 9.5% to 10.8%, and further recommended that the Commission use the
upper end of the range, based on the DCF model, because he judges DTEE to be of
higher risk than the sample companies on average.
Dr. Vilbert’s rebuttal testimony addressing the analysis of other witnesses is
discussed below.
2. Staff
On behalf of Staff, Ms. Sandhu recommended that the Commission authorize a
return on equity of 10% for DTEE, based on a range of 9.75% to 10.25%. To determine
Staff’s recommended cost of equity, Ms. Sandhu performed DCF, CAPM, and traditional
risk-premium analyses. She began with the selection of a proxy group of companies
meeting the following criteria: an SIC code 4911 (electric services) or 4931 (electric and
other services); at least 50% of the average operating revenues from regulated electric
operations; net plant between $5 billion and $25 billion; S&P and Moody’s investment
grade bond ratings; and none of the companies currently involved in a merger or
buyout. The proxy companies and information regarding the companies is presented on
Schedule D5, page 1, of Exhibit S-4.
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For her DCF analysis, she used both a simple model and a DCF model she
labeled a “semi-annual compounding model.”294 She testified that the adjusted model
recognizes the timing of dividend payments:
At any point in time during a twelve-month period, some companies will
increase dividends during the next few weeks, others during the final few
weeks of the year and the remainder spread out over the year. Therefore,
for any one-year period, an investor can expect dividends for the proxy
group to increase at the midpoint of the year.295
Under this version of the DCF, the current dividend is adjusted by half of the annual
growth rate to arrive at the expected dividend payment over the year.
Ms. Sandhu calculated the dividend yield for her proxy group using a 3-month
average of high and low stock prices from the February-April 2015 period. For the
simple model, she used the annual dividend rate estimated from the most recent
quarterly dividend; for the semi-annual model, the current dividend was adjusted by half
the annual growth rate. Ms. Sandhu used growth rates based on an average of Yahoo
Finance, Zacks, and Value Line projections for growth in earnings and book value.
296
The results of her DCF analysis are presented in her Schedule D5, page 5, including
results for each proxy company, as well as median and average results.
For Staff’s CAPM analysis, Ms. Sandhu used forecast yields on 30-year Treasury
securities for the test year ending June 30, 2016, as published by both Value Line and
Global Insight, averaging the two values to derive a risk-free rate of 3.46%.297 She used
the betas from Value Line shown on page 6 of her Schedule D5, with a proxy group
average beta of .79. For the market premium, she looked at Ibbotson’s publication of
294
See 8 Tr 2015-2016.
See 8Tr 2016.
296
See p 4 of Schedule D5, and 8 Tr 2016.
297
See 8 Tr 2018.
295
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market results over the time period 1958-2013. Over that time period, the average
return on common stocks was 11.9%, and the average return on long-term government
bonds was 6.43%, producing a risk premium of 5.48%.298 Ms. Sandhu testified to the
range of results, the average, and the median for the proxy group, and presented the
results for all the proxy companies in Schedule D5, page 6.
Regarding Staff’s risk-premium analysis, Ms. Sandhu testified that Staff looked at
bond yields for A-rated and BBB-rated utility bonds for the 3-month period ending April
2015 as reported by Value Line. Comparing long-term average market returns and bond
yields, Ms. Sandhu derived a risk premium of 3.98%. She presented the results of
summing the historical risk premium and current bond yields for A and BBB-rated
companies in Schedule D5, page 7, and she testified:
The results of the Risk Premium analysis are lower than one would
typically expect when taking a long-term perspective because current
bond yields for both A-rated and BBB-rated utility bonds are at historically
low levels.299
Ms. Sandhu presented a summary of her results in Schedule D5, page 8,
including the adjusted DCF, CAPM, and risk-premium results. She also compared her
recommendations with information regarding the average authorized returns for the
electric utility industry over 2013 and 2014, and the authorized returns for the proxy
group companies, shown in Schedule D5, page 8. She testified that the average return
on equity awarded over the two-year time period was 9.96%, and the proxy group
companies have authorized returns on equity ranging from 9.38% to 11.00%.300 She
additionally explained Staff’s recommendations as follows:
298
See 8 Tr 2019.
See 8 Tr 2021.
300
See 8 Tr 2021.
299
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The proxy group fashioned in Staff’s study closely resembles DTE Electric
in several very important characteristics, including risk and permanent
capital mix. Staff’s recommendation is based on the results of the cost of
equity studies for the proxy group of companies as previously discussed
and on the application of professional judgment. In addition, Staff’s
recommendation considered all factors and each request and issue
contained in the Company’s application.301
3. Attorney General
Mr. Coppola also performed a DCF, CAPM, and risk-premium analysis. He
began his analysis with the proxy group used by Dr. Vilbert, and excluded DTE Energy
and smaller companies with market capitalization levels of $3.5 billion or less, which he
characterized as far below DTE Energy’s level of capitalization.302
His Exhibit AG-15 presents the results of his DCF analysis.303 For stock prices,
he used the average high and low values over the March 4 to April 15 2015 period. Mr.
Coppola used the annual dividend projected by Value Line for April 2015 to March
2016. He also used growth rates based on Value Line and Yahoo Finance analysts’
projections for 2014-2019. Mr. Coppola testified that the average return on equity
derived from this study is 8.44%. He testified that lower costs of equity estimated in his
DCF study reflects lower dividend yields attributable to the increase in the price of stock
since Dr. Vilbert’s analysis.304 He also commented on the higher growth rates forecast
for some proxy group companies:
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
301
See 8 Tr 2022.
See 9 Tr 2341.
303
See 9 Tr 2342-44.
304
See 9 Tr 2343.
302
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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.305
Mr. Coppola’s CAPM results are presented in Exhibit AG-16. Mr. Coppola used
a 4% risk-free rate. He testified that normally he would use a risk-free rate of 2.9%
based on 30-year Treasury yields, but recognizes “sentiment in the market” that interest
rates will rise. He testified that he finds Dr. Vilbert’s risk-free rates of 3.78% and 4.03%
to be reasonable estimates, and testified that his choice of 4% is based on Value Line.
Regarding the CAPM, he also testified that it should be given less weight:
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.306
For his risk premium analysis shown in Exhibit AG-17, Mr. Coppola used a riskfree rate of 4% as he did in his CAPM, and estimated the historical spread between
electric utility stocks and bonds to be 4.4%, with a 1.02% spread of bond yields over
Treasury yields for A-rated bonds and 1.57% for BBB-rated bonds.307 Mr. Coppola also
looked at returns on equity authorized by other regulatory commissions over the last
year, and since 1990, as shown in Exhibit AG-18. His results are summarized on Exhibit
AG-14. He recommended a 9.75% return on equity, notwithstanding that a weighted
305
See 9 Tr 2344.
See 9 Tr 2347.
307
See 9 Tr 2349-2350.
306
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average of his results, favoring the DCF results, produces a return on equity of 8.92%,
which he rounded up to 9.5%:
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 . . . 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.308
Mr. Coppola also took issue with Dr. Vilbert’s ATWACC approach and recommended
that the Commission give it no weight.309 He further characterized Dr. Vilbert’s 10.75%
recommendation as unsupportable.310
4. ABATE
Mr. Walters recommended an authorized return on equity of 9.5% for DTEE.
Mr. Walters testified that the market costs of capital are lower than in DTEE’s last rate
case.
He illustrated this by a comparison of bond yields today to the bond yields
presented in Case No. U-16742, DTEE’s last rate case. He also illustrated this by
showing the reductions in the average authorized rate of return for electric utilities for
308
See 9 Tr 2353-2354.
See 9 Tr 2347-2349.
310
See 9 Tr 2352.
309
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each year from 2010 to 2015, testifying that “[r]egulators have appropriately captured
the electric utility industry and capital market trends in authorizing lower returns on
equity.”311
Mr. Walters also provided information on credit outlooks for the utility industry
from S&P, Fitch, and Moodys.312 He testified that utilities currently have strong access
to capital at attractive pricing. Additionally, he presented a comparison of utility stock
price performance in comparison to the market over the 2004-2014 time period.313 He
testified that the Edison Electric Institute (EEI) utility index has outperformed the market
in downturns and trailed the market during a recovery, and testified: “This supports the
continued believe that utility investments are generally regarded as safe-haven or lowrisk investments.”314 Mr. Walters also reported that averages of authorized rates of
return on equity for electric utilities have been below 10% since 2012, with the 2012
average only slightly above 10% at 10.1%.315 As to DTEE specifically, Mr. Walters cited
positive credit rating reports from S&P, concluding that S&P views DTEE as a low-risk
utility.
In his Exhibit AB-1, he presented a chart showing credit ratings for DTEE
compared to the proxy group, concluding that DTE is lower risk than the proxy group. 316
Mr. Walters did not conduct an independent DCF, CAPM, or risk-premium
analysis, but he reviewed and revised Dr. Vilbert’s analysis to form his recommended
return on equity. Mr. Walters characterized Dr. Vilbert’s recommended 10.75% return
on equity as unsupportable. Mr. Walters’ principal objections to Dr. Vilbert’s analysis
311
See Table 2, 9 Tr 2420.
See Tr 9 2421-2423.
313
See Figure 1, 9 Tr 2424.
314
See 9 Tr 2424.
315
see 9 Tr 2420.
316
See 9 Tr 2426.
312
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were to his use of the ATWACC adjustment and to his use of the ECAPM model in
conjunction with adjusted betas.
Regarding the ATWACC adjustment, Mr. Walters characterized it as severely
flawed. He testified that it increases his market cost of equity by 0.5 to 1.3 percent:
“Excluding this ATWACC ROE adder, Dr. Vilbert’s ROE range would be approximately
8.6% to 9.7% based on the DCF and risk positioning analyses.”
317
After reviewing the
mechanics of the adjustment, Mr. Walters concluded that Dr. Vilbert’s adjustment
increases the return on equity based on DTEE’s book value capital structure because
book value has more financial risk than the market value of common equity. He testified
that investors do not assess a different financial risk for market value and book value
common equity, but that financial risk “is a singular risk factor which describes [a]
financial capital structure, cash flow strength to support financial obligations, and default
provisions in its financial obligations.”318 Mr. Walters testified that the ATWACC
adjustment is poor regulatory policy because management decisions regarding capital
structure, and regulatory commission reviews of those decisions, can be skewed by
changes in market value.319 He explained that using book value capital structure
weights permit the utility to lock-in a large portion of its capital costs in the rate of return
calculation, helping to stabilize utility rates, while the ATWACC adjustment will produce
overall rates of return that change based on both changes in market value capital
structure and changes to market capital costs.320 Finally, Mr. Walters viewed the
adjustment as an unnecessary increase in return to investors that is not just or
317
See 9 Tr 2431.
See 9 Tr 2432.
319
See 9 Tr 2433.
320
See 9 Tr 2434.
318
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reasonable. He testified that this methodology has been consistently rejected in state
jurisdictions, providing citations to support his testimony.
Regarding Dr. Vilbert’s use of the ECAPM, Mr. Walters testified that Dr. Vilbert’s
use of the ECAPM provided estimated rates that were 60 to 70 basis points above his
CAPM estimates, before the ATWACC adjustment. He testified that Dr. Vilbert
incorrectly used an adjusted beta in that analysis, characterizing this as doublecounting. He testified he is not aware of any research that was subject to peer review
supporting the use of an adjusted beta in an ECAPM study.321
Reviewing Dr. Vilbert’s results without the adjustments, as shown in Mr.
Walters’s Table 3,322 with the ATWACC adjustment and ECAPM results isolated, Mr.
Walters testified that all Dr. Vilbert’s model results fall below 10% and are primarily in
the range of 9.3% to 9.7%. He views these results as consistent with the rates of return
currently being authorized for electric utilities in the country. Based on his analysis, he
recommends an authorized return on equity of 9.5%.323 Mr. Walters also presented
rebuttal testimony addressing Staff’s recommendations, as discussed below.
5. Walmart
Mr. Chriss testified regarding the authorized return on equity, addressing the
risks faced by DTEE rather than performing an analysis of comparable returns. He
testified to the importance of considering the impact on customers in setting the return
on equity, and to ensure that the amount authorized is the minimum necessary to
provide adequate and reliable service, while affording the utility an opportunity to earn a
321
See 9 Tr 2436.
See 9 Tr 2430
323
See 9 Tr 2437.
322
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reasonable return. He expressed a concern that the rate of return requested by DTEE
is excessive, citing the impact on customers, the use of a projected test year, the
inclusion of Construction Work in Progress (CWIP) in rate case, and returns on equity
approved by other state regulatory commissions.324 He presented authorized returns
reported by SNL Financial, and focusing specifically on vertically-integrated utilities.325
6. Rebuttal
DTEE and ABATE both provided rebuttal testimony regarding the cost of equity.
a. DTEE
In his rebuttal testimony, Dr. Vilbert acknowledged that interest rates had
declined since he performed his analysis, but testified that he was still recommending
an authorized return on equity of 10.75%, also noting that the lower interest rates would
result in at most a .25% reduction in his recommendation.
He also reiterated his view that DTEE is riskier on average than his sample
group, and asserts: “In spite of their poorly supported statements to the contrary, the
intervenors seem to agree with that assessment because their ROE recommendations
are all at the high end of the range of their estimates, just as mine was.
If they
implemented the corrections to their methodologies I identify below, presumably their
recommendations would also reflect the resulting higher estimates.”326
Dr. Vilbert took issue with Mr. Coppola’s exclusion of DTE Energy as well as
seven smaller companies from the proxy sample group, contending that it is reasonable
to include DTE Energy in the group even though its subsidiary is the target of the
324
See 8 Tr 1822-1824.
See 8 Tr 1826.
326
See 7 Tr 1510.
325
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analysis, and contending that the smaller companies excluded are not small relative to
the stock market, the other companies in the sample group, or DTEE.327 He testified
that while predicting the rate of return for smaller companies may require an upward
adjustment to the CAPM prediction, the adjustment he has not made could not bias his
results.328
Dr. Vilbert also took issue with the DCF models used by Mr. Coppola and Ms.
Sandhu. He testified that their models delayed recognition of the growth and delivery of
dividends in comparison to his use of quarterly dividends and a quarterly compound
growth rate, characterizing their models as “artificially lower[ing] the ROE estimate.”
329
He also took issue with Mr. Coppola’s elimination of high and low growth rates from his
averages, contending this is not based on any “well-explained principle of financial
theory.”330 He also took issue with Ms. Sandhu’s growth rate estimates, contending that
her use of Zacks and Yahoo Finance “consensus” numbers might include the opinions
of some analysts more than once, which “may bias the growth rate inputs up or
down”,331 and contending that she should not have used book value growth rates,
because earnings and dividends need not grow at the same rate as the book value of
assets.332 He testified that eliminating the book value growth rates from Staff’s analysis
would increase the DCF results by approximately 30 basis points.
Turning to the CAPM analyses, Dr. Vilbert objected to Staff’s use of a market risk
premium of 5.48%.
327
See 7 Tr 1512-1515.
See 7 Tr 1513.
329
See 7 Tr 1516.
330
See 7 Tr 1517.
331
See 7 Tr 1518.
332
Id.
328
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He testified that Staff reasonably relied on Ibbotson data, but
testified that Staff should have used all data available from 1926 forward rather than
from 1958 forward.333 He presented a chart showing historical averages over multiple
periods, and testified that his own choices of 6.5% and alternative 7.5% are reasonable,
concluding that if Ms. Sandhu had used those values in her analysis, her results would
have been 80-160 basis points higher.
Dr. Vilbert also objected that Mr. Coppola and Ms. Sandhu did not use the
ECAPM model. Reviewing his earlier testimony on the basis for this model, he also
presented in Schedule V1 of his Exhibit A-32 what he described as a “discussion of the
academic tests of the CAPM that provides an estimate of the size of the adjustment that
resulted from the tests.”334 He acknowledged that the articles were “older”, but testified
that “repeated tests have generated the same result so current research has turned to
developing a replacement model that better fits the empirical data.”
In this context, Dr. Vilbert disputed Mr. Walters’s testimony that Value Line
adjusted betas should not be used with the ECAPM model, characterizing them as two
fundamentally different and complementary adjustments.335
He asserted that the
backward-looking empirical tests of the CAPM that led to the ECAPM did not require
adjusted betas, and asserted that the beta adjustments are forward looking based on
the empirical observation that historical measurements of a firm’s beta are not the best
predictor of what that firm’s systematic risk will be going forward, and presented a
drawing to illustrate his testimony regarding the backward nature of the ECAPM
adjustment and the forward nature of the beta adjustment.
333
See 7 Tr 1518-1521.
See 7 Tr 1521.
335
See 7 Tr 1522-1526.
334
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Dr. Vilbert testified that
making an ECAPM adjustment with alphas of 0.5% and 1.5% would add 12.5 to 37.5
basis points to Mr. Coppola’s and Ms. Sandhu’s CAPM results.
Dr. Vilbert also addressed criticism of the ATWACC by Mr. Coppola and Mr.
Walters. He reviewed his direct testimony regarding this adjustment, testifying:
I use the ATWACC to recognize differences in financial risk among the
sample companies. When estimating the ROE using either the DCF model
or the CAPM, the ROE estimate is the result of the sample company’s
business risk and its financial risk. The more debt in the capital structure
the more financial risk the equity holders of that company must bear. The
capital structures of the sample companies differ so it is necessary to
calculate the overall cost of capital, the ATWACC, which is a measure of
the business risk of the underlying assets of the company. Companies
choose different capital structures depending upon how they wish to divide
the risk of the assets between debt holders and equity investors. A
company choosing a capital structure with more debt increases the
allocation of risk to equity holders. This is in part because debt holders are
paid before anything is paid to equity holders, and in part because
increased financial leverage increases the variability of equity returns for
the same level of variability in cash flows (i.e., returns to the company’s
assets).336
Further, he testified:
Financial risk affects the estimated cost of equity, and financial risk is
affected by the market value capital structure of the sample firms. The
ATWACC approach allows apples-to-apples comparisons among the
returns of the sample companies which may have quite different capital
structures even though they are in the same industry. If the sample’s
average cost of equity is used to estimate the cost of equity for the
company in question, inconsistencies are likely to arise, because this
method makes no adjustment for any differences among the capital
structures of the sample firms used to estimate the cost of equity and the
regulatory capital structure used to set rates. Consequently, the sample’s
estimated return on equity does not necessarily correspond to the financial
risk faced by investors in the subject company, in this case DTE Electric. If
the sample’s estimated cost of equity were adopted without consideration
of differences in financial risk, it could lead to an unjust and inappropriate
rate of return.337
336
337
See 7 Tr 1534-1535.
See 7 Tr 1536.
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He disputed Mr. Coppola’s characterization of his adjustment as unorthodox because
the weighted-average cost of capital is presented in every corporate finance textbook.
And in response to Mr. Walter’s testimony that it has not been adopted by state
regulatory commissions, he presented Schedule V2 in Exhibit A-32 to show the
countries and other regulatory bodies using his adjustment. 338
Responding to Mr. Walters’s testimony, he disputed that he believes there are
two levels of financial risk, testifying that there is only one measure of financial risk, but
“noting that the financial risk of a company with 60 percent equity . . . is different from
that of a company with 50 percent equity.”
Further responding to Mr. Walters, he
testified that Mr. Walters’s view of financial risk is really “default risk”: “Financial risk is
the additional variability of return for equity investors due to the use of debt and other
fixed payment sources of financing.”339
Dr. Vilbert’s rebuttal testimony also addressed the appropriate use of credit
ratings, testifying that Mr. Walters and Ms. Sandhu rely on credit ratings to indicate that
DTE Electric’s equity is less risky than the proxy group, and further testifying that their
interpretations are flawed and misleading.340 He testified that debt investors are
concerned with a company’s total risk, systematic and diversifiable, while equity
investors are only concerned with systematic, i.e. non-diversifiable, risk of the kind
measured by a company’s beta.341 He testified that the goal of credit rating agencies is
not to measure the systematic risk of a company’s equity, but rather to evaluate the
338
See 7 Tr 1536-1537.
See 7 Tr 1538.
340
See 7 Tr 1526-1531.
341
See 7 Tr 1528.
339
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probability of default on its debt.342 He views default as a manifestation of extreme
financial distress, testifying that for healthy companies such as DTEE and the sample
companies, the probability of default is quite low as shown by their investment grade
credit ratings.
Specifically addressing Mr. Walters’s use of credit ratings, he testified that Mr.
Walters references Moody’s credit ratings, testifying that Moody’s and S&P do not
measure the same thing, “because Moody’s adjusts its rating based upon an
expectation of the amount of recovery in the event of default whereas S&P does not
consider the likely amount of recovery in the event of default in establishing its
rating.”343 Nonetheless, he testified that the fact that DTE’s Moody’s rating is higher
than the sample average is not meaningful in terms of relative risk.344
Specifically
addressing Ms. Sandhu’s testimony regarding secured credit ratings, he further testified
that “secured credit ratings are especially inappropriate for judgments of relative risk. If
Ms. Sandhu had looked at company/issuer ratings instead, she would likely have found
. . . that DTE Electrics [sic] company credit rating of BBB+ is average for the sample.”345
Finally, Dr. Vilbert addressed Mr. Chriss’s testimony regarding the cost of equity,
asserting that whether CWIP is included in rate base or not does not affect risk,
characterizing it as “pay me now or . . . pay me later,” with the caveat that a company’s
credit rating could be adversely affected by the lack of current cash flow, which in turn
could affect the cost of equity or risk if the financial burden to service the additional debt
342
See 7 Tr 1527.
See 7 Tr 1529.
344
See 7 Tr 1530.
345
See 7 Tr 1531.
343
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became large enough to generate a concern that cash flows would be inadequate to
pay interest and expected dividends.346
b. ABATE
Mr. Walters also presented rebuttal testimony, in which he took issue with Staff’s
recommended return on equity of 10% as being too high. He presented a table showing
the mean results of each of Ms. Sandhu’s analyses, and testified that he believed Ms.
Sandhu had disregarded the lower results of her market models in reliance solely on
historical authorized returns.347 Looking at those returns, he testified that her
measurement of authorized returns over the 2013-2014 time period is inaccurate and
does not consider authorized returns for electric utilities for 2015. He testified that
national average returns were 9.8% in 2013 and 9.76% in 2014, and were 9.67%
through the first quarter of 2015. To Mr. Walters, this indicates that commissions across
the country have determined the cost of equity for electric utilities is less than 10%.348
Mr. Walters also testified that the authorized returns for the proxy group as
presented by Ms. Sandhu are based on stale data and should not be relied on. He
presented Exhibit AB-10 to show that three of the ten returns she cited were authorized
in 2010 or earlier, while six were authorized in 2013-2014. He also testified that a
recent change in the authorized return for Ameren’s subsidiary Union Electric from 9.8%
to 9.53% should be considered.349
346
See 7 Tr 1533.
See 9 Tr 2443, 2446.
348
See 9 Tr 2444.
349
See 9 Tr 2445.
347
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7. Briefs
The briefs of the parties largely state the positions taken by their witnesses in
testimony.
DTEE argues that the Commission should adopt Dr. Vilbert’s
recommendation, arguing that Staff and intervenor recommendations are understated
due to sample selection and failure to make appropriate adjustments, and arguing that
uncertainty in the capital markets, the more challenging Michigan economic
environment, and the differences in financial risk for DTEE compared to the sample
companies justifies an increase in the recommended return on equity for DTEE relative
to the sample companies.
Staff’s brief explains Staff’s approach and modeling results, and argues that
DTEE’s rebuttal testimony addressing Ms. Sandhu’s analysis lacks merit. Staff argues
that it has consistently used the disputed inputs to its DCF and CAPM models, and
argues that contrary to DTEE’s characterizations, Staff views credit ratings as one
measure of risk, not the only measure of risk.
The Attorney General’s brief presents a review of Mr. Coppola’s testimony and
asks the Commission to adopt his recommendations. ABATE’s brief argues in favor of
Mr. Walters’ recommendations, reviewing his analysis of the current market and credit
agency reports, and arguing that the Commission should reject Dr. Vilbert’s
recommendations including his ATWACC adjustment. Walmart argues that a 10.75%
return on equity is excessive for the reasons explained in Mr. Chriss’s testimony.350
Only DTEE and ABATE address the cost of equity in their reply briefs, and
DTEE’s reply brief principally reprises its initial brief, while ABATE focuses on the
ATWAAC and the riskiness of DTEE.
350
See Walmart brief, pages 4-5.
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8. Discussion
From a review of the testimony and briefs, there are analytical and
methodological disputes between the parties, as well as a more generalized dispute
over how to consider the riskiness of DTEE.
The following disputed issues are
discussed: the selection of the proxy group sample; the formulation of the DCF model
and the growth rate assumptions used in that model; the ECAPM; the estimate of the
market risk premium for use in the CAPM; and the ATWACC approach.
a. Sample selection
One topic of dispute involves the appropriate companies to include in a sample
group. The purpose of the proxy group is to evaluate the expected return for a group of
comparable companies.
Dr. Vilbert’s proxy group of 28 companies included DTE Energy and several
small companies, as well as companies that are significantly larger than DTEE. Mr.
Coppola excluded DTE Energy and the seven smallest companies in creating his own
proxy group, as explained above, while Dr. Vilbert objected to the exclusion of the small
companies, arguing that the smaller companies are closer to DTEE in size than to some
of the large companies that he included in his sample. Dr. Vilbert also testified that
CAPM returns may understate returns for smaller companies, i.e. there may be a size
premium not captured by a CAPM analysis, while arguing that he did not make such an
adjustment so his results could not be biased.
In its brief, DTEE argues that Mr.
Coppola had no justification for excluding the smaller companies.
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Staff’s proxy group contained only companies with $5 billion to $25 billion in net
plant, and Staff’s proxy group did not contain DTE Energy.
This PFD finds that Mr. Coppola’s choice to exclude smaller companies is
reasonable. The smaller companies he excluded are less than half the size of DTEE.
This PFD notes that the two smallest companies, Otter Tail and MGE Energy, each
have a book value of assets about one-tenth the size of DTEE.351 Otter Tail has a beta
of .95, significantly different from other proxy group companies. Nonetheless, some
leeway for judgment should be afforded to each analyst to vary the size parameters of a
proxy group. Dr. Vilbert’s proxy group also includes significantly larger companies than
DTEE. On the basis of size alone, this PFD does not recommend rejecting either Mr.
Coppola’s or Dr. Vilbert’s proxy group results. The comparability of the proxy groups to
DTEE can be taken into account in evaluating the model results. It bears emphasis,
however, that Staff’s approach in defining an upper and lower size boundary for its
comparables analysis provides a sample that is overall more comparable to DTEE in
size than either the sample used by Dr. Vilbert or Mr. Coppola, because Staff’s analysis
also excludes companies that are more than twice the size of DTEE.
Turning to the issue of the inclusion of DTE Energy in the proxy group, Dr. Vilbert
defended his choice to include DTE Energy because it meets his selection criteria and
“there is no reason to exclude it.”352
Similar to the discussion above, this PFD
concludes that while it is not unreasonable to evaluate the expected return on equity for
DTE Energy in evaluating the cost of capital for DTEE, clearly DTE Energy’s historical
and expected returns are or have been heavily influenced by the utility’s previous
351
352
See D6.3 of Exhibit A-11, panels J and L.
See 7 Tr 1512.
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operations and by the Commission’s prior decisions, and do not provide an independent
estimate of the cost of capital the way a proxy group of companies independent of
DTEE’s operations could be expected to do. More commonly in rate cases before the
Commission, the utility’s parent corporation is analyzed using the same models applied
to the proxy group, with the results stated separately from the proxy group. This is
indeed what Mr. Coppola has done in his presentation. Nonetheless, given the detailed
presentation of results by Dr. Vilbert, it is fairly easy to see how the analytical results for
DTE Energy compare to the analytical results for the proxy group on average.
Therefore, on this basis, this PFD concludes that Dr. Vilbert’s results should not be
rejected because his proxy group includes DTE Energy.
b. DCF model and growth rates
DTEE also takes issue with the DCF model and growth rate inputs used by Staff
and the Attorney General. First, as discussed above, Dr. Vilbert testified that the Staff
and Attorney General DCF models artificially lower the ROE estimate by using
annualized dividend yields and growth rates, whereas he uses quarterly dividends and
growth rates.353 This PFD finds that Staff’s model does not “artificially lower Staff’s ROE
estimate“, but is one realistic interpretation of the projected dividend and growth
information available. No analyst has a crystal ball, and nothing in the projections relied
on by the analysts appears to contradict the assumptions in any of the models. Thus,
while Dr. Vilbert asserts that his use of quarterly dividends and the quarterly compound
growth rate “matches the actual payment of dividends reflected in stock prices”, this is
only true for the historical quarter he relied on for his growth rate estimates, and that
353
See 7 Tr 1515-1516.
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dividends are paid quarterly does not determine how best to model the growth in
dividends. As Mr. Coppola testified:
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.354
Dr. Vilbert also objected to Staff’s reliance on multiple sources of growth rate
estimates, including both Zacks and Yahoo Finance, arguing that using two sources of
“consensus” estimates could double-count the recommendations of some of the same
analysts.355 And he argued that projected growth in book value as provided by Value
Line should not be considered.356 DTEE advances this argument in its brief. Staff
argues that DTEE is incorrect, explaining:
Staff averages the book value growth rate and [earning per share (EPS)]
growth rate from three different sources to remove any biases that could
result from using information from a single source. These growth rates
provide a reasonable estimate of what investors’ expectation[s] are for the
proxy group. Staff has used this method for several years in several rate
cases and there has been no change in circumstances that warrants a
change to Staff’s established method.357
This PFD concludes that Staff reasonably uses multiple sources to avoid bias. There is
no reason on this record to conclude that the group of analysts who may be contributing
354
See 9 Tr 2344.
See Vilbert, 7 Tr 1518.
356
See Vilbert, 7 Tr 1518.
357
See Staff brief, page 33.
355
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estimates to more than one source is itself biased. Likewise, Staff’s reliance on a book
value growth rate is not improper and is consistent with Staff’s past practice.
Dr. Vilbert also objects to Mr. Coppola’s exclusion of the highest and lowest
growth rate estimates from his DCF analysis, as discussed above.358 Again, there is no
reason to believe this produces a biased result, but is an even-handed technique to
exclude extremes from his analysis. Indeed, Mr. Coppola only excluded two values
from his analysis as too high, and excluded eight values as too low, as shown in Exhibit
AG-15. As the Commission has recognized, and as DTEE recognizes in its reply brief,
there is no single formula, and analysts should be given some leeway to formulate their
analyses.
c. ECAPM and CAPM
While ABATE takes issue with Dr. Vilbert’s reliance on the ECAPM models in
conjunction with his use of adjusted betas, DTEE faults the Attorney General and Staff
analysts for not relying on an ECAPM model. As discussed above, the ECAPM model is
an equation that modifies the CAPM using a parameter α to increase the indicated
return for securities with betas below one, and decrease the indicated return for
securities with betas above one. This PFD concludes that Dr. Vilbert has failed to justify
his use of the ECAPM model with adjusted betas.
Dr. Vilbert acknowledges that the ECAPM is based on empirical observations
only. He also acknowledged that adjusted betas are based on empirical observations.
He characterized the empirical observations giving rise to the ECAPM as backward
looking, and the empirical observations giving rise to the adjusted betas as forward
358
See 7 Tr 1517.
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looking. Beyond his mere assertion, there is no basis to conclude that simultaneously
using the backward-looking CAPM adjustment and the forward-looking beta
adjustments are two independent and appropriate adjustments. By definition, neither of
the “empirical” adjustments are supported by theory, let alone a unified theory.
In his
direct testimony, Mr. Walters pointed to Dr. Vilbert’s failure to cite any peer-reviewed
published paper concluding that adjusted betas should be used in an ECAPM model.359
In his rebuttal testimony, Dr. Vilbert acknowledged that the empirical tests to measure
alpha used unadjusted or raw betas.360
And while Dr. Vilbert’s rebuttal testimony
discusses the ECAPM at length, he failed to cite any peer-reviewed paper supporting
his use of both adjusted betas and the ECAPM approach. Moreover, use of adjusted
betas in an ECAPM model has been rejected by at least one other state commission.
As the Illinois Commerce Commission held in In re MidAmerican Energy Company,
Docket No. 01-0444 (March 27, 2002 order):
[W]e agree with Staff’s criticism of MEC’s ECAPM analysis. It seems that
Dr. Morin mixes apples and oranges. Dr. Morin applies adjusted Value
Line betas to his empirical CAPM model when unadjusted betas are
appropriate. We agree that this departure from the methodology required
by the model results in an overstated cost of equity.361
Another striking feature of Dr. Vilbert’s ECAPM model is that it relies on the
assumption that rates of return predicted by the CAPM for stocks with betas above 1 will
be overstated. This appears fundamentally at odds with the adjustments Dr. Vilbert
made to the other CAPM inputs, to reflect his view that the market risk premium has
increased. Dr. Vilbert testified:
359
See 9 Tr 2436.
See 7 Tr 1523-1524.
361
See In re MidAmerican Energy Co., 2002 WL 1306035 (Ill.C.C. Mar 27, 2002) (NO. 01-0444).
360
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Regulated companies are of lower relative risk than the average company
in the market, and so investors may prefer to invest in them rather than in
riskier companies during bad times. However, the required return for all
types of risky investments, including regulated utilities, increases during a
time of flight to safety, since corporate and (especially) “risk free”
government bonds are in turn much less risky than even the equity of
regulated companies. This was borne out amidst the recent turmoil: prices
of regulated companies fell along with the broader market. However, they
did not fall as far (in percentage terms) as the market; this is as expected
because regulated companies are of lower risk than the market as a
whole. Risk-positioning models predict that companies with lower betas,
i.e., companies with lower risk relative to the market, will move with the
market, but with lower volatility. The prices of regulated companies
recovered faster than the market, in part because of the flight to safety,
but have now been surpassed by the general market, again as expected
according to the predictions of risk-positioning models.362
And after reviewing current bond and stock market movements, he testified:
In general, these [market] trends are consistent with my observation that
the average investor’s risk aversion remains elevated. Additionally, the
particular set of circumstances leading to the current low bond yields may
be a short-term phenomenon, suggesting that current yields may
underestimate the long-term risk-free interest rate. As discussed in greater
detail below, a higher-than-normal equity risk premium and an
underestimated risk-free rate may lead to a downward bias in cost of
capital estimates based on the CAPM and ECAPM.363
Based on this testimony, he adjusted his risk-free rate upwards in each of two
scenarios, and increased the slope of the market security line in his Scenario 2 to reflect
his opinion that current economic conditions required a greater return for any level of
risk, as shown in his Figure 7 at 7 Tr 1461. While the ECAPM adjustment further
increases the risk premium for stocks with betas below one, it also decreases the
required return for stocks with betas above one, as shown in Dr. Vilbert’s Figure 8 at 7
Tr 1480 and Figure R-1 at 7 Tr 1523. This layering of adjustments moving in opposite
directions based on empirical results from backward-looking studies and forward-
362
363
See 7 Tr 1447.
See 7 Tr 1450-1451.
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looking studies, and based on Dr. Vilbert’s belief about the market’s response to current
economic conditions, should require greater justification to avoid the appearance of
being merely self-serving. This PFD recommends that the Commission place no
reliance on the ECAPM results.
d. Market risk premium
DTEE also challenges Staff’s use of Ibbotson data for the time period 1958
forward, arguing that Staff’s results should be increased by 80 to 160 basis points.364
DTEE cites Dr. Vilbert’s rebuttal testimony suggesting that Staff’s analysis was biased
and produced a risk premium that was too low, because Staff did not use all available
data dating to 1926.365 In its brief, Staff explained that Staff has consistently used this
time period and cited the Commission’s November 4, 2010 order in Case No. U-16191.
DTEE’s reply brief acknowledges that the Commission has endorsed Staff’s consistent
use of this data set, but argues that more than one approach is acceptable:
Staff witness Ms. Sandhu developed a 5.48% MRP using the 1958-2013
time period (Staff Initial Brief, p 34). Dr. Vilbert questioned Staff’s use of
the 1958-2013 time period because regulatory cost of capital experts in
the U.S. commonly base the MRP on the historical average MRP going
back to 1926, which is the first year when high quality data on market
returns is available. Currently, the long-term historical average is 7.0% (7
T 1519).
Staff disagrees, citing the Commission’s November 4, 2010 Order in Case
No. U-16191 to suggest that the 1958-present time period is the only
appropriate time period to use (Staff Initial Brief, p 34). However, what the
Commission actually stated is that: “The Commission agrees with the Staff
that the 1958-present time period is more appropriate for use in
calculating the historical risk premium component of the CAPM analysis.
Although parties are not bound to perform any particular analysis, in any
specific manner, to avoid some degree of controversy in future rate cases,
the Commission will give greater weight to historic market risk premium
364
365
See DTE brief, page 27-28.
See 7 Tr 1518-1521.
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analyses using more recent data” (November 4, 2010 Order in Case No.
16191, pp 27-28). Thus, there is more than one acceptable way to
calculate the historical risk premium, and the issue is really a matter of
weighting.366
Nonetheless, despite making this acknowledgement, DTEE goes on to argue that
Staff’s results should be adjusted to reflect the higher market risk premium: “[Using] an
appropriate MRP in the 6.5% to 7.5% range . . . would raise [Staff’s] CAPM cost of
equity estimates by approximately 80-160 basis points.”367 This PFD finds that Staff’s
use of the Ibbotson risk premium data for the time period 1958 forward has been
thoroughly vetted by the Commission and used consistently by Staff, so that no further
adjustment as called for by DTEE is appropriate.368 The analytical results produced by
all models are further evaluated in the recommendation section below.
e. ATWACC
ABATE and the Attorney General criticize Dr. Vilbert’s ATWACC adjustment to
the otherwise-determined cost of capital for the proxy companies. DTEE argues that
the results relied on by Staff, the Attorney General, and ABATE are understated
because they do not add an ATWACC adjustment.369
To understand the disputes over Dr. Vilbert’s ATWACC adjustments to his DCF
and CAPM return on equity results, it is necessary to understand the arithmetic
underlying these adjustments. As described in section a above, Dr. Vilbert uses his
equity cost estimates for each proxy company, and an assumed market debt cost for
366
See DTEE reply brief, page 12.
See DTEE reply brief, pages 12-13.
368
Staff has consistently used the shorter time period, with Commission approval. In addition to Case No.
U-16191, also see Case No. U-10755 (March 11, 1996 order); Case No. U-6923, May 18, 1983 order;
Case No. U-7298, November 9, 1983 order.
369
See DTEE brief, page 26, DTEE reply brief, pages 10-11.
367
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each proxy company based on an S&P bond rating, to calculate an “after-tax weighted
cost of capital for each proxy company based on that company’s market value capital
structure.370 Positing that DTEE should face the same overall (after-tax) weighted cost
of capital as the average of the sample companies, Dr. Vilbert then backs out the return
on equity to be applied to DTEE’s book value equity ratio that is required to generate
the constructed sample average cost of capital, assuming a 4.6% current market cost of
debt based on a BBB bond rating.
The adjustments for his CAPM results are in
Schedules D6.11 and D6.12 and the adjustments for his DCF results are in Schedules
D6.7 and D6.8 of Exhibit A-11.
Both Mr. Coppola and Mr. Walters testified that the Commission should give no
weight to the ATWACC, characterizing the adjustment as reflecting the high market
value of utility stock relative to book value, at odds with the utility’s efforts to maintain a
particular capital structure and control its costs, and producing higher than required
rates of return. Although Dr. Vilbert addressed his ATWACC adjustments extensively in
his rebuttal testimony, this PFD finds that his explanations do not squarely refute the
testimony of Mr. Coppola or Mr. Walters and do not support the ATWACC adjustments,
and these adjustments should be rejected.
Mr. Coppola’s testimony explains both the mechanics of the adjustment and his
concern that it generates a higher rate of return for DTEE based on a significant
difference between market value and book value equity percentages. Mr. Coppola also
believes this significant difference between market value and book value equity can be
explained by a decline in interest rates causing authorized returns for utilities to be
370
He uses two different market value capital structures, a current estimate and a five-year average
estimate. He also assumes all companies face the same tax rate as DTEE.
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higher than required and thus driving up the market prices of utility stock relative to book
value. Mr. Coppola testified:
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.371
Mr. Walters expressed a similar concern that this method would drive up returns on
equity.
A review of Dr. Vilbert’s ATWACC adjustments and the data in Schedule D6.3
confirms Mr. Coppola’s testimony that market-value equity ratios have increased
significantly over the last six years. Dr. Vilbert uses the most current information on
market-value capital structures in adjusting his DCF results, with the proxy group
average equity ratio at 60%. This produces an increase in the otherwise-determined
average rate of return on equity of 1.3%, or 130 basis points, for his simple DCF result.
Dr. Vilbert uses a five-year average market value capital structure to adjust his CAPM
results, with a proxy group average equity ratio of 55%.
This produces an increase in
the otherwise-determined average rate of return on equity of .5% or 50 basis points in
his CAPM results.372 The earliest information Dr. Vilbert presents is from 2009, with an
average equity ratio for the proxy group of only 50%.
371
See 9 Tr 2348.
The reported increases range from .5% to .7% for his ECAPM results, using the mean sample returns
calculated by Mr. Walters at 9 Tr 2430.
372
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Dr. Vilbert did not address Mr. Coppola’s testimony, including his explanation for
the differences between market-value and book-value equity ratios, although he
characterized Mr. Walters’s concern with the level of the return as “not a principled
objection.” Moreover, no party challenged Mr. Coppola’s explanation for the increase in
market value equity ratios.
Mr. Walters also expressed a concern that because this approach relies on the
average market value capital structure of the proxy group as the basis for the average
over-all weighted cost of capital, it does not recognize the efforts of utility management
to manage the utility’s capital structure:
[It] does not produce clear and transparent objectives for management to
use that will accomplish the objective of minimizing its overall rate of
return while preserving its financial integrity. Therefore, a regulatory
commission cannot oversee the reasonableness and prudence of
management decisions in managing its capital structure. Under the
ATWACC theory, management’s decisions to manage its capital structure
can be skewed by changes in market value which change the market
value capitalization mix. Management simply has no control over the
market value capital structure, but it does have control over the book value
capital structure. As such, setting the rate of return and measuring risk
based on book value capital structure creates a more transparent and
clear path for regulatory oversight of management’s effort to maintain a
balanced and reasonable capital structure.373
Dr. Vilbert’s response disputes that Mr. Walters’ comment has any applicability to his
adjustment, noting that the rate of return he derives is the rate of return he recommends
be applied to DTEE’s book value capital structure:
Mr. Walters claims that use of the ATWACC is not transparent and that
regulators cannot oversee the “reasonableness and prudence of
management decisions in managing its capital structure.” I do not know
what Mr. Walters has in mind here, but it is not related to the ATWACC
method I use to recognize differences in financial risk. As noted above, the
373
See 9 Tr 2433.
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ATWACC is applied to the book value capital structure which is clearly
observable.374
Clearly, however, Mr. Walters’s concern is that management and Commission efforts to
maintain a balanced capital structure for DTEE are eroded by this adjustment. Mr.
Solomon, for example, testified to his efforts to set an appropriate capital structure for
DTEE:
Q. What are some of the factors considered in determining the appropriate
capital structure?
A. Some of the factors considered in determining the appropriate capital
structure are:
• The basic risk inherent in the company’s line of business –
to offset greater business risk, a more conservative capital
structure (i.e., less leverage), is required.
• The level of capital required, both now and in the future – to
maintain the appropriate level of service to the Company’s
customers.
• The general economic, financial and business environment
– weaker economic conditions require a greater degree of
firm-specific financial strength.
• The certainty of the company’s earnings, capital
expenditure requirements and cash flow – less certainty
implies more risk; thus to counteract the higher risk, a more
conservative capital structure is required. This last factor is
critical for two reasons. First, it determines the general
availability of capital, and secondly, it determines the cost of
capital. 375
In the same vein, Mr. Walters testified:
Second, book value capital structure weights permit the utility to hedge or
lock-in a large portion of capital market costs in arriving at the rate of
return used to set rates. This rate of return cost hedge stabilizes the
utility’s cost of service, which in turn helps stabilize utility rates. A stable
method of setting rates also allows investors to more accurately assess
374
375
See 7 Tr 1545.
See 7 Tr 1576.
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the future earnings and cash flow outlooks for the utility, which will reduce
the business risk of the utility. The ATWACC, on the other hand, will
produce an overall rate of return which will change based on both changes
to market value capital structure weights and also based on changes to
market capital costs. Hence, a major component of the cost structure of
the utility (i.e., the overall rate of return) will vary based on market forces
from rate case to rate case. This rate of return variability will introduce
significant instability in the utility’s cost of service (via rate of return
changes) and hence instability in tariff rates. Introducing additional
instability in the utility’s cost structure and rates will not benefit either
investors or ratepayers. See 9 Tr 2434.
Dr. Vilbert’s subsequent response simply denied that his adjustment would make
cost of service rates more variable:
None of the concerns mentioned in his second reason are valid. As noted
above, every cost of capital witnesses use current market data to estimate
the appropriate ROE. There is nothing in the use of the ATWACC that
would make the estimated ROE more variable in one proceeding to the
next. See 7 Tr 1546.
This response ignores the significant discrepancy of 50 to 80 basis points in Dr. Vilbert’s
own results, depending on whether the most current or a five-year-average capital
structure is used. Dr. Vilbert does not discuss the choice of market capital structure
values in his testimony. As Mr. Walters’s testified, the ATWACC results depend on
changes to market value capital structure weights as well as market capital costs.
One of the market capital costs that also affects the resulting return on equity
using the ATWACC adjustment is the assumed market cost of debt, since the market
cost of debt assigned to each proxy company is used to calculate the overall cost of
capital, and DTEE’s assigned market cost of debt is used to extract the adjusted return
on equity from this overall cost of capital. Although the adjusted return on equity is
significantly dependent on these choices, Dr. Vilbert does not even discuss the basis for
his debt cost assumptions in his testimony.
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To see the significance of the debt cost assumptions, note that Dr. Vilbert
assigns a cost of debt of 4.6% to DTEE, which is higher than the average cost of debt of
4.4% he calculates as the proxy group average. He uses this 4.6% debt cost, for
example, and an overall average cost of capital of 6.8%, to estimate a required return
on equity of 10.8% for DTEE using his simple DCF analysis. His Schedule D6.8 of
Exhibit A-11 indicates that his choice of the 4.6% debt cost is based on a bond rating of
BBB from S&P, but DTEE’s S&P bond rating is BBB+ for senior unsecured debt.
Comparing DTEE to the proxy group, there is no reason DTEE should have a market
cost of debt that is higher than the proxy group average. The proxy group has an
average rating of BBB+, and a book value capital structure of 47% equity and 52% debt,
with somewhat more leverage than DTEE’s 50/50 capital structure.376
Dr. Vilbert
testified: “[DTEE] has a credit rating (BBB+) that is comparable to those of the sample
companies.”377 Thus, there is no reason why DTEE should not have been assigned the
sample average cost of debt, 4.4%, or less.
Paradoxically, however, using the lower proxy group average cost of debt has
the effect of requiring a higher rate of return on equity for DTEE, to produce the same
overall weighted average cost of capital. Thus, DTEE’s required rate of return would
increase from the 10.8% indicated for the DCF model (Panel A) to 10.9%, and would
increase from the 9.4% indicated for the CAPM model (Scenario 1) to 9.5%. This
example further shows that this method does not reward DTEE’s efforts to control or
manage its capital structure to keep its cost of capital down. Even if DTEE’s efforts to
manage its capital structure can influence only its cost of debt, under the ATWACC
376
377
See 7 Tr 1471.
See 7 Tr 1466.
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approach, the lower its market cost of debt relative to the group average, the higher its
required return on equity, all else equal.
Dr. Vilbert did not support his claim that DTEE’s rate of return on equity should
be set based on the ATWACC of the proxy group. While it may theoretically be the case
that firms with otherwise identical risks will face the same overall cost of capital
regardless of their capital structure, Dr. Vilbert did not establish that it is reasonable to
assume that the overall estimated average weighted cost of capital of the proxy
companies should be the same. He himself rejects the notion that these companies are
equally risky, in claiming that DTEE is riskier than the sample on average. And he
implicitly acknowledges differences between the companies in assuming that they face
different market costs of debt, which he then estimates in his analysis.
Note that there is a significant variation in the calculated overall costs of capital
for the sample companies, ranging from 4.7% to 9% for the DCF model (Panel A), not
noticeably more uniform than the rates of return resulting from the DCF and CAPM
analyses for these companies. A review of the data in Schedules D6.7 and D6.11
shows that companies with the highest average equity ratios have higher than average
overall costs of capital (and with two exceptions, companies with the highest indicated
returns on equity from the DCF and CAPM models have above average overall costs of
capital). Thus, both high returns and high equity percentages appear to contribute to
high overall costs of capital.
Dr. Vilbert’s claim that his adjustments are necessary to evaluate financial risk
appears to be based on a rejection of the proxy group approach. At 7 Tr 1536, he
testified:
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Simply put, a sample company with higher business risk and lower
financial risk may yield exactly the same investor-required cost of equity
as a lower business risk/higher financial risk company. However, an
average of the two will not produce an accurate cost of equity for the
Company except by accident. This remains true no matter how large the
sample group of companies unless the Company has exactly the same
capital structure as the average of a statistically large sample.378
This is actually refutation of the proxy group approach to estimating a cost of equity,
disputing that returns can be developed from proxy group averages.
Even though
statistically large samples are not typically used in proxy group analysis, the approach
contemplates that the similar companies have myriad but not identical sources of risk,
and by looking at the average and median results for the group of similar companies,
and the modeled returns for those companies, the Commission can make a reasonable
choice for the regulated utility. Ineluctably, Dr. Vilbert’s concern that each of the proxy
companies will have different financial risk is also true of any risk that affects the
variability of returns, including myriad business risks, and the resulting average will not
produce a result with an exact specification of each particular risk. Note that even after
making his “financial risk” adjustment, Dr. Vilbert still argues that DTEE is “riskier” than
the proxy group, as discussed in section f below, but does not try to separately “adjust”
for each of the potential differences in other elements of risk.
Dr. Vilbert testified:
[C]omputing the ATWACC for the sample companies allows the analyst to
isolate the contribution of non-diversifiable business risk to the cost of
capital from the confounding influence of financial risk, thus allowing for an
“apples to apples” comparison of required overall returns among the
sample companies and the subject companies.379
378
379
See 7 Tr 1536.
See 7 Tr 1536.
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At 7 Tr 1545, he testified that the ATWACC is not just an adder, but an “adjustment . . .
to compare the [return on equity] at different capital structures.” Although Dr. Vilbert
claims his adjustment is a way to compare the estimated returns on equity among the
different sample companies, and to isolate the contribution of non-diversifiable business
risk from financial risk, in fact Dr. Vilbert does not compare the estimated returns among
sample companies, and does not isolate non-diversifiable business risk from financial
risk. Instead, he merely increases the average return on equity otherwise determined
for the proxy group so that the increased return when applied to DTEE’s book value
capital structure and assumed cost of debt will generate the proxy group average cost
of capital as a return to the average market value capital structure.
The use of the proxy group average cost of capital can produce some unusual
results. Consider the cost of equity that would be derived for CMS Energy, one of the
proxy companies, if CMS Energy were assumed to face the average overall cost of
capital of the proxy groups. Using the average after-tax weighted cost of capital of 6.8%
from Dr. Vilbert’s simple-model DCF study as a metric for CMS Energy, in conjunction
with its current market value capital structure, produces an estimated cost of capital for
CMS Energy of 11.1%, although the pre-adjustment return on equity estimated by Dr.
Vilbert is only 9.9%, and the proxy group average return indicated by that analysis is
9.5%. Similarly, using the average after-tax weighted cost of capital from Dr. Vilbert’s
CAPM analysis (Scenario 1) and the five-year average capital structure he used to
compute the after-tax weighted cost of capital of 6.1%, produces an adjusted cost of
capital for CMS Energy of 11.2%, although the pre-adjustment return on equity
indicated for CMS Energy in this analysis is only 8.9% and the proxy group average
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return is only 8.9%. The estimated return for CMS Energy using the CAPM overall cost
of capital places the estimated return for this company well outside the range of
estimated returns estimated by the CAPM model, as shown in column 1 of Schedule
D6.11. This reinforces Mr. Walters’s concern for the stability of the results produced by
this approach.
Fundamentally, Dr. Vilbert did not explain why financial leverage is not just
another factor causing variation in returns, adequately captured by the returns on equity
otherwise estimated from a properly selected proxy group. Note that Dr. Vilbert’s proxy
group has an average book value capital structure of 47% equity and 52% debt,
somewhat more leveraged than DTEE’s 50/50 capital structure.380 DTE Energy is one of
the proxy companies, as discussed above. DTE Energy’s book value capital structure is
also 50/50, and its market value capital structure models the proxy group average, thus
begging the question why is it necessary to adjust the average return from Dr. Vilbert’s
proxy group to produce a significantly higher return on equity for DTEE (10.8% for the
DCF simple model, and 9.4% for the CAPM (Scenario 1)) in comparison to the proxy
group average (9.5% for the DCF simple model, and 8.9% for the CAPM (Scenario 1))
or to DTE Energy (9.1% for the DCF simple model and 8.9% for the CAPM (Scenario
1)) in any of Dr. Vilbert’s analyses.
Dr. Vilbert acknowledged that financial leverage increases the variability of equity
returns and is reflected in systematic risk, and is therefore presumptively reflected in the
betas used in the CAPM analysis, and in other measures of return, along with other risk
380
See 7 Tr 1471.
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factors.381 Mr. Solomon explicitly stated his opinion that there is an interrelationship
between financial and business risk:
Q. How do companies mitigate business risk?
A. A company with higher business risk must reduce its financial risk. That
is, the company must improve its capital structure by reducing debt and
increasing equity. The greater the volatility and uncertainty of cash flows,
the greater the pressure on the company to respond by improving its
overall capital structure.
Q. How does the current financial and business environment affect
business and financial risk?
A. Companies do not operate in a vacuum. External events affect
perceived risk. When business risk increases the capital structure must
be adjusted to offset this risk. This is done by reducing leverage and
increasing equity relative to overall capital.382
This is consistent with the traditionally-employed proxy group concept of considering all
risks captured by the rate of return analyses for a group of relatively similar companies.
Indeed, in discussing his proxy company selection, Dr. Vilbert testified:
“S&P
characterizes DTE’s Business Risk as Excellent and its Financial Risk as Significant,
which is consistent with most regulated utilities in the U.S.”383
While Dr. Vilbert expressed dissatisfaction with relying on an averaging of risks in
the absence of a statistically valid sample with exactly the same leverage, he has not
established that the averaging inherent in his own approach is preferable: that is, if it is
not acceptable to look at the average estimated equity returns over a multitude of risks
for a group of generally comparable companies, how can it produce a better result to
look at the average hypothetical overall cost of capital incorporating those same
381
See 7 Tr 1528, 1535.
See 7 Tr 1579-80.
383
See 7 Tr 1464-65.
382
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average estimated returns, as well as estimated debt costs and market value capital
structures? Dr. Vilbert’s testimony is not persuasive on this point.
Dr. Vilbert in his rebuttal testimony insists that financial leverage is a function of
the market value capital structure, yet he simultaneously acknowledges that DTEE does
not have a market value capital structure. He also acknowledges that there is a contrary
view, and he cites a well-known 1958 paper by Franco Modigliani and Merton Miller as
“academic evidence” favoring his use of the market value capital structure in his
analysis. However, he explains that the authors of that paper used the market value
capital structure because they did not believe that the market value of a firm would be
increased by leverage, which they were studying, and for practical reasons.384 This
testimony does not establish a compelling basis for his adjustment. And as ABATE
argues, Dr. Vilbert’s approach has not been adopted by utility regulatory commissions in
the United States.
After careful examination, this PFD finds that Mr. Coppola’s and Mr. Walters’s
objections to the ATWACC are valid, and recommends that the Commission find the
adjustment unsupported and reject its use in estimating the appropriate return on equity
for DTEE. Dr. Vilbert has not established that his adjustment produces a more accurate
or reliable estimate of the cost of equity capital for DTEE. Instead, it appears his
adjustment only inflates the otherwise indicated rates of return relative to the modeled
returns for DTE Energy and the proxy group average because DTEE does not have a
market value capital structure, when DTEE is otherwise comparable to the proxy
companies, including possessing a book value capital structure that is somewhat less
leveraged than the proxy group on average.
384
See 7 Tr 1540-1541.
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f. Riskiness of DTEE compared to proxy companies
The parties dispute the riskiness of DTEE relative to the proxy companies.
DTEE and Dr. Vilbert believe that DTEE is riskier than the proxy companies. As
discussed above, Dr. Vilbert identified the following factors: DTEE’s lack of a revenue
decoupling mechanism, the Michigan and Detroit economy, the choice program,
DTEE’s planned capital spending for environmental compliance and new generation,
and DTEE’s nuclear ownership to conclude that DTEE is more risky than the proxy
companies. Mr. Solomon also identified these factors in his testimony.385
Ms. Sandhu testified: “The proxy group fashioned in Staff’s study closely
resembles DTE Electric in several very important characteristics, including risk and
permanent capital mix.”386 Mr. Coppola explained that he did consider that DTEE’s
“unique risks and circumstances” in rounding up his otherwise determined cost of
equity.387 He considered that DTEE’s service territory is highly dependent upon the
automotive industry, and acknowledged some uncertainty in whether investors
anticipate higher interest rates.
ABATE’s brief cites Mr. Walters’s testimony extensively to show that credit
agencies consider DTEE to be low risk, and that its bond ratings compare favorably to
the proxy group. ABATE cites DTEE’s six-month self-implementation of rates, forwardlooking test year, and automatic adjustment clauses as regulatory advantages. In its
reply brief, ABATE argues that aside from the unavailability of a revenue decoupling
mechanism prohibited by Michigan law, none of DTEE’s concerns justify considering
DTEE to be more risky. ABATE argues that S&P, Moody’s, and Fitch all consider the
385
See 7 Tr 1589.
See 8 Tr 2022.
387
See 9 Tr 2339-2354.
386
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utility sector to be stable, and S&P characterizes DTEE’s particular circumstances as
reflecting a “positive” outlook, with excellent business risk, and a “’strong’ regulatory
advantage assessment.” ABATE also argues that DTEE’s need for capital spending is
not different from other utilities, citing S&P reports. In addition, ABATE argues that
DTEE’s bond rating compares favorably with the proxy group.
Walmart identifies as a factor favoring a lower return on DTEE’s ability to earn a
return on CWIP, at least for environmental capital expenditures for which CWIP
amounts are not offset by AFUDC. In his rebuttal testimony, Dr. Vilbert testified that
allowing DTEE to earn a return on CWIP does not reduce its risk, characterizing it as
“pay me now or pay me later.”388 While the COLA discussion above shows that DTEE
would rather receive a return on its investment as soon as it is made, rather than waiting
for it to be considered used and useful, it is also worth noting that under Michigan law,
DTEE can seek a certificate of necessity under MCL 460.6s for certain categories of
expenditure, reducing any risk associated with the uncertainty of regulatory treatment.
In his rebuttal testimony, Dr. Vilbert contended that Staff and intervenor
witnesses were wrongly using credit ratings as a measure of risk. To Dr. Vilbert, default
risk is separate from financial risk, and only systematic or nondiversifiable risk is
relevant to determining the cost of equity. He also expressly objects to Staff’s use of
credit ratings in its analysis, asserting that Staff erroneously looked at ratings for
secured debt.
ABATE argues in its reply brief that Dr. Vilbert is alone in his view that rating
agency evaluations should be disregarded. ABATE argues that the use of Moody’s
bond ratings is an industry standard to measure risk comparability in proxy group
388
See 7 Tr 1533.
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analyses, and ABATE points out that Dr. Vilbert required that data from “S&P or
Moody’s, Value Line, and Bloomberg—each widely known and used by investors—be
available for all sample companies.”389 Staff argues that it considers the credit ratings as
a measure of risk, not the sole measure of risk, citing Ms. Sandhu’s testimony at
8 Tr 2012.390 Staff also argues that it is appropriate to consider DTEE’s secured credit
ratings because the vast majority of DTEE’s debt is secured. Staff argues many of the
factors considered by rating agencies affect the risk assessment of a company, and
cites Dr. Vilbert’s testimony acknowledging this at 7 Tr 1527.
Dr. Vilbert’s discussion of the role of credit rating agencies is confusing. First, he
indicates that credit rating agencies are concerned with default risk:
Contrary to Mr. Walters’ claim that “[t]he market assessment of DTE’s
investment risk is best described by the credit rating analysts’ reports,” the
goal of the credit rating agencies is not to measure the systematic risk of a
company’s equity, but rather to evaluate the probability that a company
will default on its debt.391
But he acknowledges that default risk for utilities with an investment grade bond rating
is quite low.392 Then he acknowledges that debt investors are concerned with total risk,
including systematic risk and diversifiable risk:
Debt investors are therefore concerned with a company’s total risk (i.e.,
the sum of systematic and diversifiable risk), whereas equity investors are
concerned with systematic (i.e. non-diversifiable) risk of the king
measured by a company’s beta.393
Note that in adjusting the market risk premium for his CAPM analyses, Dr. Vilbert
relies on the systematic risk associated with utility bonds to adjust the market-return
389
See ABATE reply brief, citing 7 Tr 1463.
See Staff’s brief, page 35.
391
See 7 Tr 1527.
392
See 7 Tr 1527.
393
See 7 Tr 1528.
390
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line, as discussed above.394 In making this adjustment, he relies on a paper
characterizing corporate bond yield spreads as a combination of a default premium, a
tax premium, and a systematic risk premium. He uses the result from this paper that
BBB-rated corporate bonds have a beta of .26 as the basis for his adjustment.395 Thus,
Dr. Vilbert’s own analysis shows that even if credit rating agencies are only concerned
with bond holders, they are concerned with systematic risk. Additionally, Dr. Vilbert’s
distinction between systematic risk and total risk is the fundamental basis for the CAPM,
but it is worth noting that in this case, and generally in evaluating the cost of equity in
Commission cases, the CAPM is only one of the models relied on by analysts. Thus, as
Staff argues, it is reasonable to consider credit rating agency reports in evaluating the
rate of return for equity investors.
This PFD finds that by any objective measure, DTEE is not more risky than the
proxy groups. DTEE’s bond ratings for secured and unsecured debt are consistent with
or better than the proxy group averages, presumably reflecting the “strong” capital
structure Mr. Solomon is maintaining. Notwithstanding Michigan’s economic challenges
and DTEE’s nuclear plant ownership, note that DTE Energy’s stock has an adjusted
beta of .75, the sample average for Dr. Vilbert’s proxy group, below the sample average
for Staff’s proxy group, and just slightly above the sample average for Mr. Coppola’s
proxy group. As cited by Mr. Walters, S&P characterized DTEE as “lower risk” than DTE
Energy.396 As ABATE and Walmart argue, and as discussed above, DTEE also has
many regulatory advantages. DTEE has not shown any reason to conclude that it is
more risky than any of the proxy groups used by the analysts in this case.
394
See 7 Tr 1458.
See 7 Tr 1459 at n33.
396
See 9 Tr 2425.
395
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While DTEE faces risks, as do all companies, no party presented an analysis of
these risks relative to other utilities in the proxy groups. Although Dr. Vilbert identifies
risks facing DTEE, he does not compare these risks to the risks facing the sample
companies in any systematic or organized way. Dr. Vilbert also does not align his risk
assessment with his view that equity investors are only concerned with systematic, nondiversifiable risk. For example, he cites and then discounts empirical evidence indicating
that nuclear generation and the lack of a decoupling mechanism do not increase the
cost of capital.397 His discussion of nuclear generation is particularly problematic and
calls into question his judgment and objectivity. He testified:
First, the Commission should recognize that the risk of nuclear power
plants is asymmetric. The Commission should remove the asymmetric risk
if there is an event at the plant because the Company has not been
previously compensated through its cost of capital for the potential loss.398
DTEE does not actually ask the Commission to make any special provision in this case
regarding future risks associated with Fermi 2, but Dr. Vilbert’s assertions that past
compensation has been inadequate, and that the Commission can or should make
special provisions now to alleviate DTEE’s risk “if there is an event at the plant,” are
wholly unsupported on this record.
In its brief, DTEE also cites its book value capital structure as a source of risk,
but as discussed above, DTEE’s book value capital structure is better than the proxy
group average, and DTEE’s arguments are otherwise encompassed in its arguments
regarding the ATWACC. Note that Dr. Vilbert’s use of the higher range of his cost of
equity estimates are based on the cost of equity estimates adjusted, i.e. increased, in
397
398
See 7 Tr 1467, 1470.
See 7 Tr 1470.
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order to account for DTEE’s financial risk, although, as discussed above, this PFD does
not find that such an adjustment is warranted.
g. overall recommendation
Reviewing the different analyses presented by the witnesses, it has long been
recognized that there is no precise mathematical formula to determine the appropriate
return on equity. Citing Bluefield and Hope, supra, the Commission has explained:
The Supreme Court has made clear that, in establishing a fair ROR,
consideration should be given to both investors and customers. The ROR
should not be so high as to place an unnecessary burden on ratepayers,
yet should be high enough to ensure investor confidence in the financial
soundness of the enterprise. Nevertheless, the determination of what is
fair or reasonable, “is not subject to mathematical computation with
scientific exactitude but depends upon a comprehensive examination of all
factors involved, having in mind the objective sought to be attained in its
use.” Meridian Twp v City of East Lansing, 342 Mich 734, 749; 71 NW2d
234 (1955).399
The following tables summarize the recommendations of the analysts. The results from
the analytical models are shown here, with DTEE’s ECAPM and AWACC results
shaded:
399
See October 20, 2011 order, Case Nos. U-16472, U-16489, page 30.
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Model
Average
Results
DTEE
and
ABATE
STAFF
Attorney
General
DTEE
with
ATWACC
DCF
9.5%
(simple)
8.69%
8.44%
10.8%
(ATWACC)
CAPM
8.6%
(multi-stage)
8.9%
(Scenario 1)
7.78%
9.11%
9.4%
(Scenario 2)
9.6%
(ATWACC)
9.4%
(ATWACC)
9.9%
(ATWACC)
DTEE
With
ECAPM
(.5%)
DTEE
With
ECAPM
(1.5%)
9.0%
9.3%
9.5%
(ATWACC)
9.8%
(ATWACC)
9.5%
10.1%
(ATWACC)
Risk
Premium
7.88%
9.7%
10.4%
(ATWACC)
9.7%
In reviewing these results, for the reasons discussed above, this PFD concluded
that the ECAPM and ATWACC adjustments recommended by DTEE should not be
considered. Additionally, as explained above, there is no objective basis on which to
conclude that DTEE is riskier than the proxy groups. As ABATE argues, none of the
estimates produced by the traditional methods derive a return on equity above the
range of 9.5% to 9.75%. DTEE’s recommended 10.75% is clearly excessive and should
be rejected.
Several of the witnesses also presented information regarding authorized rates of
return adopted by other regulatory Commissions. The following table summarizes that
information:
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Authorized
Return
Information
Staff:
Authorized
ROEs
(Proxy Group)
Staff:
Authorized
ROEs
(EEI)
Attorney
General
Authorized
ROEs
ABATE
Authorized
ROEs
Walmart
Authorized
ROEs
2012-2015
mean
range
10.2%
9.38% - 11.0%
9.96%
9.77% - 10.23%
9.79%
9.66%9.87%
10.34% (2010)
10.30% (2011)
9.88%
8.72% 10.95%
10.01% (2012)
9.80% (2013)
9.76% (2014)
9.67% (2015)
In formulating its recommended 10% return recommendation, Staff considered
the authorized returns for its proxy group, and considered recent returns authorized by
other regulatory commissions, as shown in the chart above. Mr. Walters pointed out
that several of the proxy companies have authorized rates of return that were not set
recently,400 and also presented information regarding returns recently adopted by
regulatory commissions:
[T]he average authorized returns on equity for electric utilities nationally
for 2013 and 2014 were 9.80% and 9.76%, respectively. If we take into
consideration the average return on equity authorized through the first
quarter of 2015, which was 9.67%, it is easy to see that commissions
across the country have determined that the cost of equity for electric
utilities has been, and continues to decline, below 10.0%.401
While Staff’s recommendation is above the range of average equity cost estimates
produced by the models, reasonably stated, that does not make Staff’s recommendation
incorrect or unreasonable. As shown from the chart above, average authorized returns
are near 10%.
While this PFD finds that the cost of equity capital has decreased
significantly as Mr. Coppola, Mr. Walters, and Mr. Chriss testified, this PFD finds that
Staff’s recommended return on equity of 10% is reasonable and consistent with
principles of gradualism and the Commission’s previously stated concerns to ensure
400
401
See 9 Tr 2445.
See 9 Tr 2444.
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that DTEE has continued access to capital given the significant capital expenditures
facing the company.
D.
Overall Rate of Return (Summary)
Based on the foregoing discussion, this PFD recommends that the Commission
adopt a 50/50 capital structure, adjusted for bonus tax depreciation, with a long-term
debt cost of 4.56% and a return on equity of 10%, resulting in an estimated overall
weighted cost of capital of 5.58% as shown in the attached Appendix A.
VII.
ADJUSTED NET OPERATING INCOME
Net operating income constitutes the difference between a company’s operating
revenue and its operating expenses including depreciation, taxes, and allowance for
funds used during construction (AFUDC). Adjusted NOI includes the ratemaking
adjustments to the recorded NOI test year for projections and disallowances. In this
case, there are no disputes regarding the calculation of the revenue at current rates,
including DTEE’s sales forecasts. The disputed issues involve the specific expense
categories of generation and distribution O&M, employee benefits, corporate service
group expense, uncollectible expense, and injuries and damages, as well as inflation
and DTEE’s overall cost-reduction program, items of depreciation and amortization
expense, and taxes.
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A.
Sales Forecast and Revenue Projection
Mr. Leuker presented the company’s sales forecast for the projected test year,
presented in Schedule E1 of his Exhibit A-12. He testified that the forecast values are
based on DTEE’s current official load forecast, and are broken down into the four major
customer classifications: residential, commercial, industrial, and other.402
presents separate forecasts of bundled sales and choice sales.
He also
He testified that
DTEE’s forecast projects increased sales of 0.4% through the projected test year, and
projects sales to increase about 0.3% annually through 2024.403 He contrasted this to
an average annual 0.6% decrease over the last five years.
Ms. Uzenksi explained the calculation of projected test year revenues based on
Mr. Leuker’s projected sales volumes and existing tariff rates, calculated by Messrs.
Williams and Bloch and Ms. Holmes.404
She presented the forecast revenues in
Schedule C1 of Exhibit A-10, with supporting information in Schedule C3 of that exhibit.
Mr. Isakson presented Staff’s calculation of present and proposed revenue by
rate schedule in his Schedule F-2, Exhibit S-6.
He testified that Staff accepts the
company’s revenue projections.405 No other party objected to or addressed DTEE’s
sales projections. This PFD recommends that they be adopted.
B.
Fuel, Purchase and Interchange Expense
Ms. Holmes testified to the company’s projected fuel, purchase, and interchange
power expense for the test year, presented in Schedule C4 of Exhibit A-10.
She
testified that DTEE is not proposing to reset the PSCR base cost in this case, retaining
402
See 4 Tr 472-473.
See 4 Tr 475.
404
See 5 Tr 1019-1020.
405
See 8 Tr 1977.
403
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the base factor of 33.39 mills/kWh, including a loss factor of 6.8%, set in Case No.
U-15244.406 Staff does not oppose DTEE’s projection, but as noted below, adjusted an
element of the O&M expense to be consistent with the base factor.407 No party objected
to DTEE’s proposal.
C.
Operations and Maintenance Expenses
DTEE’s projected $1.285 billion in O&M expenses for the 2015/2016 test year
are presented in Schedule C5 of Exhibit A-10, with additional detail in subsequent
schedules and as discussed by the supporting witnesses.
1. Inflation
For many cost categories, DTEE uses an inflation rate to project costs from the
historical test year to the projected test year, a 30-month adjustment, based on an
inflation forecast presented by Mr. Leuker.408 Mr. Leuker testified that the Consumer
Price Index for All Urban Consumers is forecast to increase by 1.5% in 2015 and 1.4%
in 2016. As shown in Mr. Leuker’s Schedule E4 of Exhibit A-12, DTEE also used an
inflation forecast for 2014 of 2%. Ms. Uzenksi also presented Schedule C15 of Exhibit
A-10 to show DTEE’s actual O&M expenses measured against an inflation-adjusted
expense level from 2009 forward. She testified that applying inflation rates to the 2009
expense level would result in annual expenses of $1.458 billion by the end of the
projected test year, while DTEE’s projected test year O&M expenses are $173 million
below that level.409
406
See 6 Tr 959.
See Kindschy, 8 Tr 2042.
408
See 4 Tr 481.
409
See 6 Tr 1036.
407
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In Staff’s filing, Ms. Sandhu presented Staff’s inflation estimate of 0% for 2015
and 2.27% for 2016. She testified that Staff’s estimates represent CPI-All Urban
estimates and were developed using a combination of forward-looking estimates
provided by Value Line, Global Insight, the International Monetary Fund and the Energy
Information Administration.410 Mr. Welke testified that use of Staff’s inflation estimates
reduces DTEE’s revenue requirement by approximately $15.1 million.
Mr. Welke also explained that Staff had identified more recent, and lower, O&M
expense projections that DTEE had made to its Board of Directors, in conjunction with a
cost reduction program at DTEE labeled the Competitive and Affordable Rates Strategy
(CARS). Staff also adjusted DTEE’s projected O&M costs to account for this program.
In its brief, Staff indicated that it believes that adjusting DTEE’s inflation projections for
updated CPI information would double count some of the cost savings DTEE projects
from its CARS program. Staff is recommending that the Commission adopt its CARS
adjustment.
Mr. Coppola testified that DTEE’s O&M expense projections reflect a $35 million
increase from the historical test year, with a $54.3 million increase attributable to
inflation from the historical to the projected test year partly offset by other expense
adjustments.411 He took issue with the presentation in Schedule C15, expressing his
view that the company’s history of O&M expense reductions shows that the inflationary
increases it is now seeking are not likely to occur. He also recognized DTEE’s costcutting efforts identified as CARS, testifying:
Apparently aware of the high and increasing cost structure it has created,
primarily driven by ever-increasing capital expenditures, the Company has
410
411
See 8 Tr 2007-2008, and Exhibit S-4, Schedule D1.
See 9 Tr 2290-2292.
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begun an internal initiative called the Competitive and Affordable Rate
Strategy (CARS) in an effort to lower its cost structure and dampen rate
increases to customers.
In this rate case, I recommend that the Commission set recoverable cost
levels that challenge the company to significantly modify its existing cost
structure and help it achieve its CARS objective. Whether it is in
employee levels, pay levels, benefit levels or other basic operating and
maintenance costs, there is a need for the Company to cut its costs. 412
In his brief, the Attorney General urges the Commission to consider the CARS program
in conjunction with the Attorney General’s recommended adjustments to specific
expense categories.413
Mr. Townsend also testified regarding DTEE’s inflation estimates. After stating
that DTEE has applied a generic inflation adjustment to its labor and non-labor O&M
expenses, he addressed the use of a generic inflation factor for labor expense as
follows:
Even though DTE applies its generic inflation adjustment indiscriminately
to labor expense, I recognize that labor agreements may contain
escalation clauses. Therefore, I will not offer an inflation adjustment to
labor expense, although for ratemaking purposes, it is strongly preferable
that the specific escalators in labor agreements be used for determining
projected test year labor expense rather than a generic inflation rate as
DTE has proposed.
And he took issue with the use of a generic inflation factor for non-labor expenses,
explaining first:
From a ratemaking perspective, I have two serious concerns with DTE’s
inclusion of inflation in its forecasted test period revenue requirement.
First, at a broad policy level, I have concerns about regulatory pricing
formulations that reinforce inflation. This occurs when projections of
inflation are built into formulas that are used to set administrativelydetermined prices, such as utility rates. Such pricing mechanisms help to
make inflation a self-fulfilling prophecy. As a matter of public policy, this is
a serious concern. It is one thing to adjust for inflation after the fact; it is
412
413
See 9 Tr 2291.
See Attorney General brief, pages 7-8.
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another to help guarantee it. For this reason, I believe that regulators
should use extreme caution before approving prices that guarantee
inflation before it occurs.414
And explaining his second concern that the inflation estimate builds a “cost cushion” into
the test period costs:
The best evidence of what it costs DTE for non-labor O&M is the
Company’s actual costs recorded in the historical period, adjusted for
certain known and measurable changes. The cost increases represented
by DTE’s inflation assumption may or may not come to fruition. In any
case, DTE should be expected to strive to improve its O&M efficiency on a
continuous basis, and thereby lessen the net impact of inflation on its
O&M costs. It is not reasonable to simply gross up the Company’s
historical period costs by an inflation factor and pass these costs on to
customers.415
He recommended that $24 million in non-labor inflation projections be excluded from the
projected test year O&M, presenting Exhibit KC-2 in support of his calculation. Kroger
urges the Commission to adopt Mr. Townsend’s recommendations.
DTEE argues that inflation is a standard component of cost projections, and
disputes that any adjustment to reflect future cost savings is appropriate.
In light of the existence of DTEE’s CARS program, Staff’s recommended
adjustment, and its abandonment of its initial inflation adjustment, this PFD is organized
so that Staff’s recommended CARS adjustment is discussed in section 10 below,
following a review of the specific disputed expense categories. In the intervening
sections, the presumption is that DTEE’s inflationary projections are acceptable, subject
to further adjustment, and Staff’s inflation adjustment will not be discussed in the
context of any of the specific categories. Likewise, Mr. Coppola’s and Mr. Townsend’s
objections that inflationary projections mask potential savings due to efficiency or
414
415
See 9 Tr 2457.
See 9 Tr 2458.
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productivity and other potential cost reductions are considered as part of the discussion
regarding whether or to what extent a CARS-based adjustment is appropriate.
2. Steam Power Generation
Mr. Warren testified in support of DTEE’s steam power generation O&M expense
projections of $321,498,000, as shown in his Schedule C5.1 of Exhibit A-10, with the
exception of fuel supply and MERC fuel handling expense projections of $11,775,000,
which were presented by Mr. Schoen, as shown in his Schedule C5.2 of Exhibit A-10.
The only issues raised by any party regarding the total test year expense projections
included on these schedules were Staff’s adjustment for the trona and limestone
expense, and the Attorney General’s adjustment to the maintenance category of Mr.
Warren’s schedule.
a. Limestone and trona
Mr. Warren testified that DTEE is requesting to include limestone and trona
expenses in its PSCR costs. As shown in page 2 of Schedule C5.1, DTEE has also
included projected expenses for these sorbents in its O&M expense projections. Ms.
Kindschy testified that because DTEE is not proposing to reset its PSCR base factor in
this case, in order to provide for recovery through the PSCR process, the costs need to
be removed from the projected test year expenses, to avoid double-counting.416
In its initial brief, DTEE adopted Staff’s recommendation. Citing Mr. Warren’s
testimony at 4 Tr 250, DTEE further explains that it included the costs as a placeholder,
416
See 8 Tr 2041-2042.
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in the event the Commission did not approve its request.417 No other party objected to
DTEE’s request or Staff’s adjustment.
b. Other generation O&M expenses
As reflected in lines 13 to 19 of Mr. Warren’s Schedule C5.1 of Exhibit A-10,
DTEE is projecting maintenance costs for the steam generating units of $169.7 million
for the 2015/2016 test year. Mr. Coppola testified that expenses in this category
declined from 2013 actual expenses of $165.9 million to $150.9 million in 2014, as
shown in Exhibit AG-4. He testified that although increases in the operation cost
component of the steam generation O&M expenses over that time period partly offset
the decline in maintenance expenses, he recommends the use of the 2014 actual
expenses as the basis for the maintenance cost projection. With inflation from 2014
through the first half of 2016, his recommended expense projection is $15.4 million
below DTEEs.
In rebuttal, Mr. Warren testified that the projections for planned maintenance
reflect variations in the maintenance needs of the plants from year to year and should
not be projected to be constant. He also objected that Mr. Coppola’s approach ignored
the increase in operating costs in adjusting the maintenance cost component:
First AG Witness Coppola recommends that future O&M forecasts related
to “Maintenance” be reduced by $15.4 million because this spending
category had an actual spend in 2014 less than the level experienced in
2013. This is inappropriate because maintenance expenses, by their very
nature, are not constant over time. Planned and forced maintenance
outages occur on different units, requiring different work efforts to
complete the maintenance repairs and can either be accounted for as
capitalized maintenance or maintenance expense (O&M) depending on
the nature of the expenditure. It is therefore not appropriate to assume
that maintenance O&M or capital, for that matter, will be consistent from
417
See DTEE brief, page 40.
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one year to the next. The second inappropriate forecasting methodology
Witness Coppola proposes to employ on this same general topic relates to
the “Operations” portion of the Fossil Generation O&M expense. Rather
than proposing the methodology he used for the maintenance portion
fossil O&M, he ignores the fact that the operations actual expenses
increased by $5.5 million between 2013 and 2014. Witness Coppola uses
a new methodology to discount this increase because this increase is
allegedly due to inflation. Witness Coppola provides this data in Exhibit
AG-4. In fact, the increased operations expense in 2014 compared to
2013 is not based on the alleged impact of inflation; it is in fact due to an
actual change in operations expenses between 2013 and 2014. Thus, AG
Witness Coppola ignores situations where O&M changes from one year
increase future expenditure levels and reduces them where changes from
year to year will not be perpetuated.418
In his brief, the Attorney General argues these criticisms are unwarranted,
contending that Mr. Warren used only 2013 expenses to create the forecast for the
projected year.419 This PFD recommends that Mr. Coppola’s adjustment be rejected. A
review of Exhibit AG-4 shows that Mr. Warren provided the information requested—he
did not indicate that 2013 expense levels were the basis for his projections.
3. East China Plant
DTEE’s O&M expense projections in Schedule C5 include $1.1 million for
maintenance for the assumed 300 MW generating plant that had not been identified at
the time DTEE filed its rate case. For the same reasons he objected to including the
capital costs for this plant in rate base, Mr. Coppola testified that he objected to
including the $1.1 million O&M expense.
Consistent with the recommendation in
section IV above, this PFD recommends that the O&M expense projection be excluded
because it is not clear that DTEE has purchased this plant or when that purchase will be
effective.
418
419
See 4 Tr 262-263.
See Attorney General brief, pages 14-15 citing Coppola at 2297.
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4. Nuclear Power Generation
Mr. Colonnello sponsored the projected O&M expense projections for Fermi 2.
He testified that the projected expense amounts were reasonable and prudent and
reflected normalizing adjustments appropriate to synchronize expenses for the next
refueling outage. He testified that DTEE levelizes its incremental refueling outage
expenses so that the differences in expenses between outage and non-outage years do
not create financial swings for DTEE and ratepayers.420
Mr. Coppola testified that he recommends a reduction of $4.7 million to reflect
that 2014 actuals were less than 2013 expenses.421
In his rebuttal testimony, Mr. Colonnello explained that the costs result from
DTEE’s accounting for the refueling outage accrual expense:
An accounting accrual is recorded each month that represents the
projected cost of the next refueling outage divided by the number of
months between outages. The accounting accrual is recorded in FERC
accounts 520 and 530. When the outage occurs, the accounting accrual is
reversed in account 530 resulting in a credit which offsets expenses
incurred during the refueling outage. However, actual expenses incurred
during a refueling outage are charged to the appropriate FERC accounts
for the component/system being worked on (many accounts other than
520 and 530).422
He testified that simply comparing accounts 520 and 530 does not provide an accurate
representation of the outage expenses, accrued and actual:
Since 2014 was an outage year, actual outage expenses were incurred in
addition to the reversal of accumulated outage accrual expenses. As
stated above, the actual expenses incurred during an outage are charged
to the appropriate FERC accounts for the component/system being
worked on, not only to accounts 520 and 530. This means that Witness
Coppola’s analysis includes the effect of the accrual reversal (reduction of
expense) in account 530 but does not include all of the actual expenses
420
See 6 Tr 1164.
See 6 Tr 2299.
422
See 6 Tr 1182.
421
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that were incurred in accounts other than 520 and 530. Because Witness
Coppola’s analysis does not include all the refueling outage actual
expenses beyond accounts 520 and 530, his conclusion is flawed.423
He also explained that the 2014 refueling outage expense used an extended 22-month
cycle rather than the typical 18-month cycle, making the monthly costs associated with
that outage not a good basis for projecting the monthly expense for the next refueling
outage. Mr. Colonnello testified that he agrees that the approach can be confusing and
indicated that he will consider refining the method to spread the reversal or credit
booked during the outage window among all related accounts.424
In his brief, the Attorney General rejects Mr. Colonnello’s explanation, claiming it
lacks credibility.425 The Attorney General faults DTEE for not providing this explanation
in direct testimony. Nonetheless, this PFD finds that Mr. Colonnello has satisfactorily
explained the difference in 2013 and 2014 refueling expense amounts. This PFD finds
that DTEE’s nuclear expense projection of $136.844 million is reasonable for the
projected test year, and appreciates Mr. Colonnello’s intention to improve the clarity of
the fuel expense synchronization adjustment.
5. Electric Distribution
As shown in Exhibit A-10, Schedule C5.6, DTEE projects a total $289 million for
electric distribution system O&M expense. These amounts reflect various normalizing
adjustments, including adjustments to reflect DTEE’s updated capitalization policies, as
described by Mr. Pogats and Ms. Uzenski. As discussed in section IV above, this PFD
recommends that the Commission reject DTEE’s proposal to capitalize expenses
423
See 6 Tr 1183.
See 6 Tr 1192-1195.
425
See Attorney General brief, pages 15-18.
424
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associated with its new vegetation management program, EVMP. Staff and the Attorney
General dispute both the amount of funding that should be provided in rates for DTEE’s
EVMP program, as well as funding for its ongoing vegetation management, while the
Attorney General also looks at the overall distribution operations budget and
recommends an additional adjustment. Section a discusses the appropriate O&M
expense projection for that program, while section b discusses the appropriate O&M
expense projection for DTEE’s traditional vegetation management program, while
section c addresses the remaining distribution expense projection disputes.
a. EVMP
Staff recommended that the Commission authorize funding for one-quarter of the
proposed EVMP program, to be in the nature of a pilot program with data collection and
reporting requirements, and also recommended an adjustment to the O&M expense
projection for DTEE’s traditional vegetation management program. Mr. Derkos testified
that he had reviewed an example of DTEE’s EVMP during a field visit, and explained
the difference, noting that DTEE is proposing to spend $450 million on this program
over 10 years. He testified that DTEE has not provided a cost-benefit analysis in
support of this expense, and he noted DTEE’s response to Staff’s audit question,
Exhibit S-10.7, cited only “increased customer satisfaction resulting from a decrease in
outages, and overall process efficiency improvement.” Mr. Derkos acknowledged that
Mr. Pogats presented examples showing decreased outages from EVMP, but did not
find those examples sufficient justification for the proposed expenditure:
The results of a small trial basis show promise, but it is too early to tell
from just the two examples of reliability improvement. Staff is not certain if
these two circuits, described on [4 Tr 366] of DTE Electric’s witness R.J.
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Pogats’ testimony, would have shown similar results if they were done
with normal vegetation management. The first example given showed an
improvement only six months following vegetation management “similar to
the EVMP”. The second example is for a longer period. For this example,
vegetation management was done in 2008 “to support other work”. Staff
believes that this is too small of a sample to be able to conclude
unequivocally that EVMP has an impact on reliability greater than the
normal practice.426
The Attorney General recommends a 50% reduction in the expense projection for
the EVMP program, and a 50% reduction in the expense for the company’s traditional
vegetation management program, for a total reduction of $46.5 million. Mr. Coppola
testified that DTEE’s proposal nearly doubles the expense approved in Case No.
U-16472, “without a well defined plan and clear objectives to be achieved.”427 He
testified that DTEE’s spending had varied from year to year, while the percentage of
power outages caused by trees was 57.5% in 2014, up from 39.8% in 2013,
acknowledging however that DTEE attributes the higher number to better reporting.428
He testified that Consumers Energy uses a 7-year cycle for its vegetation management,
based on a study performed by an outside expert, at a projected cost of $50 million
annually. He testified that he had asked DTEE to identify improvements in its power
supply metrics associated with the expanded program, but DTEE did not provide any.429
Mr. Pogats provided rebuttal testimony to support DTEE’s proposed EVMP
spending. He took issue with Mr. Derko’s statement that DTEE does not have sufficient
experience with the program to demonstrate performance. He presented Schedules X3
and X4 of Exhibit A-34 to show savings benchmarks expected and testified:
426
See 8 Tr 2096.
See 9 Tr 2294-2296.
428
See 9 Tr 2294.
429
See 9 Tr 2295.
427
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DTEE expects to see reductions in the length of time customers
experience outages of up to 40% by the time steady state of the EVMP
program is reached. DTEE expects to see avoided annual restoration
costs of up to $45 million by the time steady state of the EVMP program is
reached. DTEE has gained experience from both our recent work in the
field coupled with industry benchmarking permitting us to develop the cost
savings and reliability improvements as presented in Exhibit A-34,
Schedule X-3.430
He testified that he expected savings to increase linearly over two cycles. Mr. Pogats
characterized Mr. Coppola’s recommendation as without analysis and customer
considerations.
This PFD recommends that the Commission adopt Staff’s adjustment to the
proposed EVMP expenditure. Although Staff recommended a smaller EVMP program
than DTEE requested, and smaller than the 50% expenditure level Mr. Coppola
recommended, as Staff argues, DTEE has not supported the EVMP program in terms of
costs or results. Mr. Derkos’s testimony is persuasive that the two examples cited by
DTEE from 2008 and 2014 are not sufficient justification for the proposed $45 million
annual and $450 million ten-year expenditure level. The 2014 example is too recent,
and neither the 2008 nor the 2014 example was accompanied by any detail such as the
length of the circuit, the number of customers served by that circuit, the history of
storms or the history of other maintenance on that circuit.
Also, as Staff argues in its brief at page 3, the Attorney General asked DTEE in
discovery to identify improvements in power outage metrics associated with its
increased spending proposal and DTEE declined to do it. The sketchy presentation as
part of Mr. Pogats’s rebuttal testimony, Schedule X3, is not a cost-benefit analysis, does
not explain the basis for the projected savings or SAIDI reductions, and does not relate
430
See 4 Tr 397.
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the listed benefits to the benefits that would otherwise be obtained from DTEE’s
ongoing vegetation management efforts, including the hazardous tree removal program,
and its other significant capital reliability expenditures as discussed above.
Mr. Pogats’s references to the experiences of other utilities are not reliable. He
presented as his Schedule X4 two Potomac Edison press releases regarding that
utility’s tree trimming program, labeling it “Example of another Utility Successfully
Implementing Similar Program.” What the press releases actually describes is a fiveyear tree-trimming cycle, within which the utility announces plans to spend $36 million in
2015 to clear 2600 miles of line,431 indicating a 50% reduction in the number of
customers experiencing a tree-related outage from 2011 to 2013, and indicating a 40%
reduction in the number of customers experiencing a tree-related outage over the time
period 2011 to 2014. The press releases also describe the utility’s tree trimming:
Vegetation is inspected and trees are pruned in a manner that helps
preserve the health of the tree, while also maintaining safety near electric
facilities. Trees that present a danger or are diseased may also be
removed.
On paper, this resembles DTEE’s standard vegetation management practice, not its
proposed EVMP. Moreover, even if Potomac is using the same program, nothing in
these press releases indicate whether Potomac also has other significant programs
targeted at outage reduction or how its programs interrelate. Note that in its April 14,
2014 order in its Case No. 13-1064-E-P, the docket number cited by Mr. Pogats, the
West Virginia Public Service Commission addressed Monongahela Power Company’s
and the Potomac Edison Company’s request for approval of a vegetation management
program targeted at Zone 3 of its distribution system, which the companies
431
The 2014 press release indicates that Potomac Edison will spend $18 million in 2014 to clear 2600
miles.
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acknowledged had not been adequately maintained. While they proposed a five-year
ramp-up followed by a four-year maintenance cycle, with the five-year ramp-up to be
funded by a surcharge, the Zone 3 focus of their efforts only called for trees to be
removed from the corridor if they had the potential to interfere with the line.432 DTEE’s
proposal focuses its first five-year effort on Zones 1 and 2 of its distribution system, for
which it proposes to remove all trees from the floor of the corridor. In its December 13,
2013 order in Case No. 9326, the Maryland Public Service Commission addressed
Baltimore Gas and Electric Company’s request for approval of its “Increased Blue Sky
Trim Standards” program. The Maryland Commission found that “[v]egetation
management is entirely an O&M expense, providing no capital infrastructure
improvement.” Further, the Maryland Commission called for further investigation before
it would approve the program:
[There] has not been a full examination of the impact of the Company’s
proposed expanded vegetation management procedures on the tree
canopy in its service territory. We hesitate to essentially revise the RM 43
standards for a large portion of Maryland without first garnering input from
a variety of stakeholders . . . and considering that information in
establishing a balance between reliability improvement and the impact of
enhanced vegetation management practices. Additionally, we would like to
understand how the Company intends to manage community input on the
impacts of its expanded vegetation management.433
In short, Staff’s proposal to include in DTEE’s rates funding for a pilot program at
one-quarter of the size proposed by DTEE, with data collection and reporting
obligations, appears reasonable on this record. As Staff argues, if DTEE can establish
that the program is a cost-effective means to reduce interruptions and outage duration,
funding for the program can be increased in a subsequent rate case.
432
433
See Re Monongahela Power Company and the Potomac Edison Company, 2014 WL 5212947.
See Re Baltimore Gas and Electric Company, 311 PUR 4th 29, 2013 WL 6980080.
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b. Traditional vegetation management
In addition to the EVMP funding request, Mr. Pogats testified that DTEE is
projecting vegetation management expenses of $49 million for the projected test year to
pursue its traditional vegetation management practices, based on 2013 spending
adjusted for inflation.434 He also testified that DTEE has expanded its removal of
hazardous trees outside the typical clearance zone.435 DTEE is projected an additional
$2 million for this program. These amounts are shown in Exhibit A-10, Schedule C5.6.
As indicated above, Mr. Derkos and Mr. Coppola both recommended
adjustments to the level of DTEE’s proposed O&M expenditures for vegetation
management. Mr. Derkos testified that based on Staff’s reduction of the EVMP, Staff
recommends that projected test year expenses for the traditional vegetation
management be established based on the five-year historical average spending,
adjusted for inflation, plus the additional $2 million for the hazardous tree removal
program.436 Consistent with his recommendation that DTEE’s proposed EVMP spending
be reduced by 50%, Mr. Coppola recommended that DTEE’s traditional vegetation
management spending be reduced by 50% or $24 million. His Exhibit AG-2 shows
DTEE’s annual spending since 2008.
Regarding Staff’s proposed spending level for DTEE’s traditional vegetation
management program, Mr. Pogats objected that Staff’s method of using the five-year
average did not fully consider the effects of inflation from year to year. He presented
Schedule X5 to show an alternate inflation adjustment “to bring all dollar values to the
434
See 4 Tr 383-384.
See 4 Tr 367-368.
436
See 8 Tr 2085, 2098-2099.
435
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mid-2016 equivalents.”437 This exhibit calculates an increase of $7.2 million above
Staff’s recommendation. He also objected that Staff’s proposal would significantly limit
the miles DTEE is able to clear.438 As discussed in connection with the capital
distribution system expenditures requested by DTEE, Mr. Pogats also discussed a
national survey, presented in Schedule X7 of Exhibit A-34, that shows DTEE in the
fourth quartile of 36 utilities nationwide by SAIDI, asserting that DTEE has been in this
fourth quartile position consistently in similar national benchmarking surveys.439 In
responding to Mr. Coppola’s adjustment, Mr. Pogats testified that this adjustment would
reduce the miles cleared per year from approximately 6,200 to 3,200, and cause
customers to experience outage volumes 500% to 600% greater, presenting Schedule
X6 of Exhibit A-34 to show his projected outage increases.440
In its brief and reply brief, Staff argues that it is not proposing specific mileage
clearing targets for DTEE, although it believes it has provided sufficient funding for
DTEE to continue its vegetation management program at a five-year cycle, plus funding
for the EVMP pilot program and funding for the hazardous tree removal program. Staff
further argues that DTEE has not established that a doubling of its vegetation
management expense is warranted. The Attorney General argues that DTEE’s proposal
including the EVMP amounts to a doubling of its expense with no study or analysis. The
Attorney General notes that Consumers Energy proposed to spend only $57.7 million
annually, with a 7-year cycle, and supported its proposal with an outside expert.441
437
See 4 Tr 402.
See 4 Tr 402-403.
439
See 4 Tr 404.
440
See 4 Tr 410.
441
See Attorney General brief, pages 10-13; Coppola, 9 Tr 2295.
438
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This PFD recommends that the Commission adopt Staff’s projected vegetation
management expense with one adjustment. A review of the expenditures in schedule
X5 of Exhibit A-34 shows that DTEE has generally spent the approximate amount it is
projecting to spend for the test year. The Attorney General also acknowledges that
DTEE’s expenditures in this category have ranged from $42.3 million to $56.9 million
over the period 2008 to 2014. Mr. Pogats testified that the low expenditures in 2014
were attributed to additional storm activity in that year, and in anticipation of the
EVMP,442 and no one expressly challenged that explanation. It bears emphasis, as
noted above in section IV, that vegetation management is the most significant driver of
reduced outages, and it does not make sense to target what appears to be the most
cost-effective driver of reduced outages.
Mr. Pogats objected to Staff’s use of the five-year average in part because it did
not reflect inflation over the entire period. A review of Exhibit S-10.2 shows that Staff’s
inflation adjustment to the five-year average only accounted for inflation from 2014 to
the projected test year.
While Mr. Pogats presented a revised calculation in his
Schedule X5 of Exhibit A-34, this calculation was comingled with his revision of the
underlying annual expenditures to reflect 6200 miles cleared per year. Note that he
increased the annual expenditure levels only in the two years (2012 and 2014) that
DTEE did not meet its 6200 mile target: thus, his average expenditures reflect an
average of over 6500 miles cleared per year.443 It is also worth noting that the basis for
his adjustments are unclear, since the cost per mile varies significantly from year to
year, from $101 per mile cleared to $141 per mile cleared. And Mr. Pogats’s exhibit
442
See 4 Tr 401.
Based on Schedule X5, the average miles cleared per year without adjustment would be 6,079, which
is much closer to DTEE’s target than the 6,555-mile average reflected in the adjusted figures.
443
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does not include Staff’s actual inflation adjustment of $566,000 as shown in Exhibit S10.2. Revising Mr. Pogat’s Schedule X5 by eliminating the mileage adjustments in
columns (d) and (f) results in an inflation-adjusted five-year average expense of
$53,060,000, which is $2,593,200 more than Staff’s expense allowance, including its
inflation adjustment. On this basis, this PFD recommends that the Commission adopt
Staff’s vegetation management expense projection plus an additional $2.6 million to
fully account for inflation.
In making this recommendation, this PFD does not find persuasive Mr. Pogats’s
estimate of the impact of reducing vegetation management expense as shown in
Schedule X6 of Exhibit A-34. The upper projection uses an exponential model based
only on five data points, with no theoretical justification presented, and the lower
projection uses a linear model, but with only two data points.444
c. Other distributions operations expense
Mr. Coppola also looked at the overall distribution operations expense projection.
He testified that the projection is based on 2013 expenditures for the supervision and
engineering category that were usually high. He testified that DTEE attributed the higher
expense level to storm activity, but used the 2013 expenditures as the basis for its
projection anyway.445 He recommended that DTEE’s 2015/2016 test year projection be
reduced by $16.4 million, to reflect the lower 2014 actual expenditure level as a starting
point, and by an additional $5.9 million to eliminate the 2013 to 2014 inflation
adjustment.
444
445
See 4 Tr 442-444.
See 9 Tr 2292-2293.
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In his rebuttal testimony, Mr. Pogats testified that Mr. Coppola’s adjustment
incorrectly incorporates adjustments DTEE made to the 2013 historical test year to
reflect changes that are already reflected in the 2014 data:
Said another way, Witness Coppola is incorrectly mixing 2014 as the
historical test year with adjustments for 2013 as the historical test year.
The AT&T pole rental adjustment was in effect for all of 2014 and
restoration capitalization was in effect for most of 2014, therefore, the
normalizing adjustments for 2013 are not required when starting with 2014
as the historical test year. Additional adjustments to 2013 are required for
vegetation management and breaker maintenance due to the fact that
vegetation management was reduced in 2014 due to the transition to
EVMP and breaker maintenance was less than needed due to the high
volume of restoration activity in 2014.446
He presented Schedule X9 of Exhibit A-34 to restate the projected expenses using 2014
as the base. He also testified that the 2013 reported spending levels for FERC account
580 were higher in part because DTEE erroneously included expenses that should have
been reported in account 593. He testified that looking at both accounts together would
therefore be appropriate.
In his brief, the Attorney General argues that DTEE’s “newly found mistakes” do
not seem credible. He argues that DTEE did not support its adjustments to the 2014
actual expense level in Schedule X9. He requests that Mr. Coppola’s $22 million
adjustment be adopted, or at the least, the $3 million difference between DTEE’s
adjusted 2014 actual and its initial expense projection.
While the Attorney General is correct that DTEE did not explain the basis for the
erroneous accounting complicating the analysis of this expense category, this PFD
concludes that Mr. Pogats did establish a reasonable basis for the company’s
projection, when the combined accounts are considered, and did establish that the
446
See 4 Tr 408.
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“normalizing adjustments” DTEE made to 2013 are not applicable to 2014 actuals. On
this basis, this PFD recommends rejecting the Attorney General’s adjustment for this
category of distribution O&M expense.
6. Pension and Benefits
Mr. Wuepper presented the company’s expense projections for employee
benefits and pension expense, as shown in his Schedule C5.9 of Exhibit A-10. He
explained the employee retirement and insurance benefits, including changes the
company has made to control costs. No party disputed DTEE’s projected pension
expenses.447 The disputed issues discussed below include other benefit items, including
other post-retirement benefits, active employee health care, as well as DTEE’s other
benefit programs for active employees, the savings plan, the non-qualified benefit plans,
and the incentive compensation plans, discussed in sections a through e.
a. Other Post-Retirement Employee Benefits (OPEB)
For OPEB expense, DTEE explained its projected negative expense and its
proposal to defer this item. As discussed above, Mr. Coppola opposed the ratemaking
treatment DTEE proposed, and recommended that the Commission include the
negative OPEB amount of $53.6 million as an offset to the other O&M expenses
447
DTEE argues in its brief , page 91, that its pension expense should be increased by $6.3 million, citing
Ms. Uzenski’s rebuttal exhibit, Exhibit A-31, Schedule U1, presented to support the flexibility DTEE
requested regarding its proposed negative OPEB expense deferral at 6 Tr 1064-1065, and Exhibit A-36, a
Staff discovery response. Since Mr. Wuepper, the witness on pension expense, did not revise his
testimony or his exhibit, Exhibit A-10, Schedule C5.9, and since he acknowledged the interrelationship
between retirement assumptions and active employee costs—see, e.g., 6 Tr 1305-1306 –this PFD finds
DTEE’s request unsubstantiated and inappropriate.
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included in rates.448 As discussed above, this PFD recommends that the Commission
accept DTEE’s proposed accounting treatment for this expense.
b. Active employee health care
Mr. Wuepper testified regarding DTEE’s projections for health care for active
employees. He testified that active health care costs are projected to increase 6.5% in
2014, and 7.5% annually in 2015 and 2016, based on information from Aon Hewitt.449
Mr. Coppola recommended that the health care benefits (including vision and
dental) be estimated using a 3% rate of inflation. He testified that although DTEE is
using inflation rates of 6.5% and 7.5% applied to 2013 expense levels in making its
projections for the 2015/2016 test year, a review of the actual cost changes in this
category over the last five years shows the inflation rate has been 0.6%. He
acknowledged that the costs increased by 3% in 2014, but testified that 3% is a much
more reasonable level of increase. He recommended a total reduction of $10 million in
these health care line items.450
In his rebuttal testimony, Mr. Wuepper contended that the Attorney General’s
adjustment contained technical errors including ignoring the impact of the lower
healthcare escalation assumptions for retiree benefits, which are subtracted from the
total projected costs to determine the active health care costs. He presented Schedule
W4 of Exhibit A-33 to show the cost components and his correction. Mr. Wuepper also
448
See 9 Tr 2316-2317; Exhibit AG-8.
See 6 Tr 1233-1234.
450
See 9 Tr 2313-2313.
449
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objected to the use of a 3% inflation factor based on historical rates of increase as
shown in his Schedule W5 of Exhibit A-33.451
This PFD finds that DTEE’s use of the higher inflation rates is reasonable, based
on an actuarial analysis, and the potential for DTEE to keep costs in line with lower
inflation rates can be considered further in section 10 below.
c. Employee Savings Plan
The Attorney General also took issue with DTEE’s projected savings plan costs
for active employees.452 He testified that in calculating the projected costs of the
employee savings plan, DTEE forecast a rate of increases in wages of 4.2% for 2014,
and 4.65% for 2015 and 2016, based on wage information gathered by Aon Hewitt. He
testified that these increases seem excessive during a period of economic stagnation,
and recommended that the Commission hold the line on future pay increases. He
recommended that the Commission approve a 2% increase in expenses for this
category, in line with wage increases over the last three years, resulting in a $2.1 million
expense reduction.
DTEE argues that its inflation projections were validated by its consultant, Aon
Hewitt, and that inflationary salary changes alone ignore pay increases from employee
promotions and progress through pay grades.453 Consistent with the discussion above,
this PFD recommends that the Commission accept DTEE’s cost projections for this
category.
451
See 6 Tr 1305-1309; DTEE brief, pages 94-95.
See 9 Tr 2313-14.
453
See Wuepper, 6 Tr 1309-10.
452
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d. Non-qualified benefit plans
Schedule C5.9 of Exhibit A-10 includes projected costs for DTEE’s non-qualified
benefit programs. As discussed above, the $6.2 million costs associated with DTEE’s
Supplemental Retirement Plan and Executive Supplemental Retirement Plan costs
should be excluded from projected test year O&M expenses. Also as discussed above,
the Attorney General recommends excluding the entire amount of non-qualified benefit
expense, which would also include $1.9 million for the Executive Savings Plan and the
erstwhile Deferred Compensation Plan, for a total adjustment of $8.1 million. Consistent
with prior orders, and in the absence of any new information, this PFD finds that those
costs may be included in the projected benefit costs.
e. Incentive Compensation
Mr. Wuepper presented testimony describing DTEE’s incentive compensation
plans and recommending that the Commission approve approximately $40 million in
funding for the plans. Mr. Wuepper testified that DTEE compensation for nonrepresented employees has two components, a base pay component and a variable
pay component. He testified that DTEE’s base pay is targeted at the median base pay
for a group of comparable companies, but may be increased to reflect the skill or
experience of an employee.454 He testified that the variable pay consists of three
different incentive programs, the Long Term Incentive Plan (LTIP), applicable to
executives, directors and managers and an additional 10% of employees “eligible for
discretionary awards”,455 and two annual programs, the Annual Incentive Plan (AIP) for
executives including vice Presidents and directors, and the Rewarding Employees Plan
454
455
See, e.g. 6 Tr 1253, 1256.
See 6 Tr 1251.
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(REP) for non-represented employees. In support of the annual plans, he testified:
“Annual incentives ensure that individuals have an element of ‘at risk’ compensation
that allows DTE to differential pay based on performance and allocate compensation to
those most deserving.”456 In support of the long term plans, he testified these programs
provide “retention or performance based rewards delivered via shares of DTE Energy
common stock”.457 Each of these programs is applicable to three different sets of
employees: DTE Energy Corporate Services, LLC employees, DTEE employees, and
DTEE employees who are part of the Nuclear Generation business unit.
Mr. Wuepper described the metrics used for each program. For the LTIP, all the
metrics are financial metrics, and include a 60% weighting of DTE Energy’s financial
performance as measured by the total return to DTE Energy’s shareholders, capital
appreciation and dividends, a 20% weighting of DTE Energy’s financial performance as
measured by the Funds for Operations (FFO) to Debt ratio, and a 20% weighting of
DTEE’s financial performance as measured by its actual return on equity.458 The plan is
“long-term” because it looks at a three-year average. The incentive payments are in the
form of “Performance Shares” or “Restricted Shares”, with costs measured based on
the market value of DTE Energy stock at the date of the award.
For the AIP and REP, the metrics for 2014 include a mix of 50% financial
measures and a combination of metrics under the labels “customer satisfaction,”
“employee engagement”, and “operational excellence,” with approximately equal weight
for each of these groupings. He identified the following financial measures from the
2014 plan for the AIP: a 10.5% return on equity, adjusted cash flow, and DTE Energy
456
See 6 Tr 1254.
See 6 Tr 1269.
458
See 6 Tr 1270-1271.
457
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earnings per share.459 He identified customer satisfaction metrics as including survey
results and customer complaint levels.460 He identified employee engagement metrics
as including Gallup survey results, OSHA incident rates, and National Safety Council
survey results. He identified operational excellence measures as specific operating
priorities for 2014, including a target of 416 million minutes of outages for customers
with at least four outages, a 7.9% target random outage rate for the fossil-fuel
generating plants, and nuclear power plant metric. He identified slightly different metrics
for the REP, and testified that the nuclear generation business unit has only a 25%
weight given to the financial metrics. The metrics and weightings for the 2014 programs
are listed in his Exhibit A-20, Schedules L1 through L4, including the AIP and REP
metrics for each employee group, and the metrics for the LTIP program. A chart
showing the 2013 payout amount of $39 million, by program and employee group, and
split between financial and operating metrics, is presented in his testimony at 6 Tr 1272.
Mr. Wuepper acknowledged that the Commission has not approved the
expenses associated with these programs in past rate cases. He recommended that the
Commission adopt the test he attributes to the Indiana Utility Regulatory Commission:
Specifically, the IURC has consistently allowed the recovery of incentive
compensation costs, based both on financial and operating measures
when, 1) the incentive compensation is not a pure “profit-sharing plan”
driven exclusively by financial results, 2) the incentive compensation does
not result in excessive levels of total compensation, and 3) when
shareholders absorb a portion of the cost of the incentive compensation
programs.461
He testified that DTEE’s incentive compensation programs meet these criteria. He also
cited the Commission’s order in Case No. U-16472, and testified that DTEE is able to
459
See 6 Tr 1265.
See 6 Tr 1266.
461
See 6 Tr 1273.
460
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demonstrate that the benefits from the programs exceed the costs of the programs. He
presented a cost-benefit analysis in Schedule L5 of Exhibit A-20, identifying benefits of
$143.1 million relative to the program cost of $39 million.
Regarding the benefits assigned to the financial metrics, he testified:
The primary observable customer benefits of the financial measures relate
to the O&M savings created through a workforce motivated to improve
operating efficiencies, which is the focus of the metrics related to DTE
Electric earnings (as measured through DTE Electric’s Average Return on
Equity and DTE Electric Operating Earnings) and the avoided interest
costs by the Company maintaining its existing debt ratings, which is the
focus of the cash flow related metrics (as measured through FFO to Debt
and Adjusted Cash Flow).462
He assigned as a benefit of the financial metrics the annualized “savings” reflected in
the $173 million difference between DTEE’s projected O&M costs and its 2009 costs
adjusted for inflation, from Schedule C15 of Exhibit A-10.463 And he assigned as another
benefit the estimated interest cost difference between DTEE’s BBB+ bond rating and a
BBB- bond rating.464 He allocated these benefits based on award amounts assigned to
the financial measures within each category.
Regarding the operating measures, he testified that he computed benefits “based
either on the avoided cost to the Company . . . or based on the value to customers of
improved performance.”465 For the Customer Satisfaction category, he identified savings
of $1.83 million attributable to reduced call volume and the reduced time of addressing
complaints filed with the MPSC.466 For the employee engagement category, he testified
that benefits include reduced absenteeism and increased productivity and safety. He
462
See 6 Tr 1276.
See 6 Tr 1276.
464
See 6 Tr 1277.
465
See 6 Tr 1278.
466
See 6 Tr 1279.
463
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equated achievement of the target Gallup survey results as equivalent to $6.6 million in
O&M savings, the OSHA goal to a savings of $5.3 million, and the nuclear industry
safety accident-ranking goal to a savings $1 million.
The bulk of his estimated savings were in the category of electric reliability. He
testified that the benefits of reducing the outage minutes for customers with four
outages or more from 485 million minutes in 2013 to the target of 416 million minutes is
based on the value of one hour of electric service, which he estimates at $71.25 per
hour based on a composite of estimates for residential, commercial, and industrial
customers, with 69 million minutes of service interruption equal to 1.15 million hours or
$81.9 million.467 He also computed PSCR savings attributable to the target random
outage rates for fossil plants and for Fermi 2, at $3.7 million and $8.2 million
respectively.468
Witnesses for Staff, the Attorney General, and Energy Michigan took issue with
DTEE’s request to recover these costs. Mr. Welke testified that Staff excluded the
requested incentive compensation expense based on prior Commission orders:
Numerous prior orders have excluded all incentive compensation from the
cost of providing service to ratepayers on the grounds that any purported
ratepayer benefits are not commensurate with the cost of the program.
Likewise, the Commission has repeatedly found that utilities must quantify
the benefits to ratepayers of employee incentive compensation plans that
are tied to non-financial metrics and demonstrate that the benefits to
customers of such plans outweigh the costs, (Case No. U-15244,
Commission Order dated December 23, 2008, page 38.) In addition, the
Commission has found that incentive compensation plans that are tied to
company earnings and cash flow, financial considerations that largely
benefit shareholders, should not be paid for by ratepayers. (Case No. U14347, Commission Order dated December 22, 2005, page 35.)469
467
See 6 Tr 1281.
See 6 Tr 1282.
469
See 8 Tr 1954.
468
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He further testified that Staff reviewed DTEE’s cost-benefit analysis and a substantial
portion of the benefits are attributable to the electric distribution system reliability target
that DTEE did not meet in 2013. After discussing the metrics for the different programs,
Mr. Coppola recommended that the costs be excluded from rates:
My overall assessment is that the three incentive plans are too heavily
skewed toward measures that directly benefit shareholders and not
customers. Additionally, 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.470
Mr. Zakem also testified on this subject, explaining his concerns that some of the
operational metrics would not benefit choice customers, and further recommending that
any incentive payment tied to financial metrics be rejected. He explained:
Regarding the failure to tie performance to customer benefits, Exhibit A20, Schedule L5 shows that 62.8% of the incentive expense is tied to
various financial goals (column k, line 14 / line 52), including return to
shareholders, balance sheet “health,” return on equity, DTE Electric
operating earnings, earnings per share, operating cash flow, and DTE
Energy corporate operating earnings per share.
For any rate-paying customer to pay a bonus to a utility for increasing
earning per share, total return to shareholders, and the other financial
goals is illogical and violates the principle of paying for a shared benefit.
Such a system forces ratepayers to reward the utility for making them pay
more, as the earning are earned on the ratepayers backs, so to speak.
Moreover, increased earning per share benefits stockholders, not
customers. Therefore, if there is to be a payment to utility employees for
meeting financial goals that benefit stockholders, the payment should
come out of stockholder earnings, not customer rates.471
In its brief, Staff argues that many of the plan metrics relate to the achievement
of certain financial goals that benefit shareholders rather than ratepayers. Staff also
argues that the non-financial measures depend on reliability criteria that may not be
met, further arguing that benefits from achieving reliability criteria account for a
470
471
See 8 Tr 2307.
See 8 Tr 1891.
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substantial portion of the projected benefits in DTEE’s Exhibit A-20 analysis. Staff
responds to DTEE’s argument that the metrics are not strictly financial by citing Mr.
Wuepper’s acknowledgement that DTEE did not achieve the reliability metric,472 and his
acknowledgment that “there is always a risk that the Company’s actual revenues and
expenses will not match the levels inherent in the revenue requirement adopted by the
Commission.”473 The Attorney General makes similar arguments.474
Energy Michigan objects to the use of financial metrics, arguing that it is not
reasonable to ask DTE’s customers to pay increased rates to reward the Company for
increasing revenue for its shareholders, when that revenue increase has come from the
customers themselves. Energy Michigan also argues that distribution benefits should be
separated from power supply benefits in any approved plan, to avoid charging choice
customers for programs that benefit power supply customers.475
This PFD recommends that the Commission continue to exclude the incentive
compensation expenses. In several ways, DTEE has failed to show that the benefits of
the program to ratepayers justifies the cost.
First, as Staff and the Attorney General argue, the program expenditures are all
contingent on performance meeting the target levels. For example, the reliability target
of total outage minutes for customers with four or more outages in a year was not met in
either 2013 or 2014. Mr. Coppola testified:
First of all, the results of [Mr. Wuepper’s] calculation are based on the
premise that the target level of performance is achieved. The largest
contributor to the total net benefit, representing 77% of the total, is the
benefit to customers from fewer service interruptions from power outages.
472
See 6 Tr 1290.
See 6 Tr 1289; see Staff brief, pages 46-48.
474
See Attorney General brief, pages 21-27.
475
See Energy Michigan brief, pages 3-5.
473
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Aside from the faulty assumptions about what customers really save by
fewer interruptions, the basic premise to this calculated benefit is that the
target measure will be achieved. As pointed out earlier, the Company has
failed to achieve this measure, even at the lowest threshold level, during
the past two years. The Commission should be very 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.476
Additionally, there are other uncertainties in the amount of the potential payout. For the
AIP and REP, payments to individuals may vary significantly, and is not clear how the
individual payments line up with the general schematic matching dollars to target levels
in the different performance categories. Mr. Wuepper testified regarding the AIP:
Performance less than Target but above a minimum threshold results in a
payout between 25% of Target and Target, and performance up to a
maximum results in a payout of up to 175% of Target. Actual payouts to
individual employees is based both on the performance against the
Targets but also may be modified by a factor of 0% to 150% based on
individual performance.477
And he testified regarding the REP: “The REP is identical to the AIP except that the
maximum performance payout is 150% of Target.”478 DTEE is only asking to recover in
rates the total dollar amount it associates with Target performance, excluding the
payments to the top five DTEE Energy executives, but it appears that actual awards
may not be based on the metrics, but can be modified for other reasons. Even the
metrics themselves can be modified. The performance parameters, including weights
and metrics, that have been presented here are the 2014 parameters. Mr. Wuepper
presented some discussion of the metrics that have been used in prior years, but there
476
See 9 Tr 2310.
See 6 Tr 1263.
478
See 6 Tr 1268.
477
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is nothing in this record establishing what the performance weights and metrics are
going to be in the projected test year.479
Second, DTEE has not shown that the benefits outweigh the costs of the
program. The financial metrics make up all of the LTIP, 50% of the AIP and REP
programs for DTEE and DTE Corporate Services employees, and 25% of the AIP and
REP programs for the nuclear group. In its cost-benefit analysis, DTEE assigns the
financial benefits from maintaining a BBB+ credit rating compared to a BBB- credit
rating, which DTEE estimates at $21 million based on information from Mr. Solomon, to
the financial metrics.480 It is not fair or reasonable to assign all the financial benefits of
maintaining a BBB+ versus a BBB- credit rating to the effects of DTEE’s incentive
program. DTEE’s argument ignores the expense the ratepayers have borne and the
efforts the Commission has undertaken to promote a strong capital structure for DTEE.
For example, rates for DTEE have been set using generally increased equity ratios over
time. In Case No. U-8789, the Commission set rates based on a capital structure with
34% equity. In Case No. U-10102, the Commission set rates based on a capital
structure with 40% equity. In Case Nos. U-15244 and U-15768, the Commission set
rates based on a capital structure with approximately 49% equity. This PFD is
recommending that the Commission use the balanced 50/50 capital structure requested
by DTEE. Some other contributing factors have been identified by the rating agencies,
including strong ratings for the Commission. For example, Mr. Walters quotes an S&P
report as follows, under the heading “business risk”:
479
See, e.g. Mr. Wuepper’s testimony at 6 Tr 1255: “For 2014, the annual incentive plan component of
variable pay has goals, or metrics, of which 50% are financially focused, 20% are customer service
focused, 10% are employee engagement focused, and 20% pertain to Operating Excellence.”
480
See 6 Tr 1277-1278.
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We view the Michigan regulatory jurisdiction as "strong" (see "Utility
Regulatory Assessments For U.S. Investor-Owned Utilities," Jan. 7, 2014)
and we view DTEE's management of regulatory risk as average compared
with peers, resulting in a "strong" regulatory advantage assessment. This
reflects DTEE's ability to earn, on average, its allowed ROE by managing
costs, filing forward-looking rate cases, using a six-month selfimplementation, and various riders that enhance cash flow
predictability.481
DTEE also includes as a benefit of the financial metrics in its incentive program
the $173 million difference between DTEE’s projected test year O&M expense level and
the expense level derived by starting with its 2009 O&M expense level and adjusting it
for inflation. The benefit is shown graphically and quantitatively in Schedule C15 of
Exhibit A-10. On an annualized basis, DTEE derives an annual savings of $26 million
dollars over the six-and-a-half year period. Again, DTEE has not shown that its cost
reduction efforts should all be attributable to its incentive plan. DTEE of course has a
powerful incentive to reduce costs below projected levels once its rates are set,
because all of the benefit of those savings go to the stockholders until DTEE’s rates are
revised. The Commission has frequently recognized that productivity increases and
other cost-savings measures will permit a utility to reduce its costs below the rate of
inflation.482 Mr. Townsend also emphasized this concept in his testimony.483
In addition, as with the credit rating example above, DTEE’s claims that these
savings should be attributed to its incentive program ignore the many dollars ratepayers
481
See 9 Tr 2425.
See, e.g., the Commission’s November 21, 2006 order in Case No. U-14547 at page 47 (“The
Commission agrees with the ALJ and Staff that some O&M expenses will likely increase at a higher rate
than inflation, and others will increase at a lower rate, or may even decrease due to productivity increases
or cost reductions. Thus, considering the offsetting effects of lower than average increases for some
O&M expense components and productivity increases, there is no need to provide additional revenue for
every component of O&M that is expected to increase at a higher than average rate.”) Also see the
Commission’s March 11, 1996 order in Case No. U-10755, page 50 (“Using an escalation rate of ½ of
inflation is reasonable in this case because it is recognized that Consumers’ obligation to contain costs
prudently and strikes an appropriate balance between inflationary pressures and expected increases in
productivity and efficiency.”)
483
See 9 Tr 2457-2458.
482
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are spending to finance the company’s operations. Mr. Coppola points out, for example,
the significant increases in capital expenditures DTEE has requested in this case. And it
has significantly increased capital expenditures in recent years. Exhibit AG-11 shows
increases in Corporate Support Group capital spending on items such as software and
computers, reflecting a 375% increase from $44.8 million in 2010 to $168.2 million in
2014, or approximately 40% per year annualized. These figures do not include AMI
capital spending or Customer 360 costs, stated separately in Exhibit A-9, Schedule B6.
DTEE’s claims also ignore that utility incentives to reduce its current costs are
not always clearly beneficial for ratepayers. For example, DTEE’s changes in its
capitalization policy allowed the company to shift dollars from O&M to capital, but these
cost shifts do not represent real savings or benefits for ratepayers. Likewise the
Commission has frequently allowed DTEE to defer certain capital costs, and other
expenses such as taxes. Note, too, that DTEE did not seek to defer recognition of its
negative OPEB expense until it filed this rate case, as discussed in section IV above.
Looking next at the operational benefits DTEE attributes to the incentive plan, the
primary driver of DTEE’s claimed savings is the $80 million it estimates from attaining its
target outage minutes. Mr. Wuepper testified:
The benefit of reducing CEMI4 from 485 million minutes in 2013 to the
Target of 416 million minutes is based on the average value of service to
customers of a one hour electric service interruption, as developed by the
Ernest Orlando Lawrence Berkeley National Laboratory (Berkeley), of
$71.25/hour. A reduction of 69 million minutes of service interruption
equates to 1.15 million hours or a total annual benefit to customers of
$81.9 million.
***
The Berkeley study was based on the analysis of 28 customer value of
service reliability studies conducted by 10 major electric utilities from 1989
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through 2005. Value of service refers to the costs incurred by customers
as a result of the loss of electric service by each major customer class.
The values used in the determination of customer benefits reflect
interruption costs incurred per incident in the residential, small commercial
& industrial and large commercial & industrial customer classes of $3.30,
$619 and $12,287 respectively. These values were weighted by the
Company’s customer composition to determine the $71.25 weighted
average value of the avoidance of a one-hour interruption.484
Again, and most importantly, this calculus ignores the significant O&M and capital
expenditures funded by the ratepayers, who have the right to expect the utility’s best
efforts to provide high quality reliable service without being charged additionally based
on the “value” to the customers of reduced minutes of outage. A similar conclusion can
be drawn regarding the benefit DTEE calculates from a reduced Random Outage
Factor. The utility is required to be reasonable and prudent in the operation of its plants,
and the utility and its employees should not require supplemental payments to provide
their best service to the ratepayers.
Mr. Coppola also testified that the targets are not sufficiently well-chosen to be
achievable, which corresponds to Mr. Wuepper’s own opinion that whether the outage
reliability target is met or not is largely a function of storm activity.485 And note again the
significant capital expenditures for distribution reliability that have been funded by
ratepayers, as shown by Exhibit S-10.3.
Third, DTEE has not shown that the metrics are consistent with the ratepayers
interests. Mr. Coppola, for example, strongly objected to the LTIP program:
The LTIP is a plan strictly designed to induce management to create
shareholder value. According to Mr. Wuepper’s testimony: “These
measures…[are]…intended to motivate employees…to keep in mind the
484
See 6 Tr 1281-1282.
See 6 Tr 1290 (“[A]ctual Electric Distribution Reliability performance varies significantly from year to
year, based primarily on the number and severity of storms in the Company’s service area.”)
485
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role of their own contribution in the overall success of DTE [Energy].”
DTEE customers should not pay for the overall success of DTE Energy.486
A focus on the success of DTE Energy, which is the parent company of other
companies with whom DTEE interacts with, appears on its face inconsistent with
ensuring that the separate interests of DTEE are respected and affiliate transactions are
scrutinized for the best interests of the ratepayers and compliance with the Code of
Conduct.
Because the expenditures are contingent on uncertain future performance and
standards, because DTEE has not shown a net benefit to customers from the plan over
and above the rates customers already pay DTEE for performance, and based on prior
Commission orders, this PFD recommends that the Commission reject DTEE’s request
for funding for this plan.
7. Corporate Staff Group
Mr. Coppola took issue with the O&M expense projection for the Corporate Staff
Group. He noted that DTEE’s projected test year expense of $165.4 million is below the
2013 actual level of $168.8 million. He testified that the projected level reflects a change
in the accounting for performance shares under DTEE’s Savings Plan and
Supplemental Savings Plan that reduced O&M expense by $17.2 million, offset by an
inflationary increase of $6.4 million, a $2.3 million injuries and damages expense
normalization, and $5 million in incremental Information Technology costs. He testified
that he asked for detail regarding DTEE’s plans and learned that DTEE had no defined
plan, but expects to replace its email and calendar system by the second half of 2015.
486
See 9 Tr 2309.
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On this basis, he characterized DTEE’s plan as a “vague idea” and recommended
excluding the $5 million expenditure.487
In her direct testimony, Ms. Uzenski had explained this expenditure as follows:
The forecasted increase on line 13, column (j) is due to the structural
change in the way software technology is packaged, purchased, and
deployed. The pace of change in computing and data technology,
hardware and applications is causing a shift to leasing technology support
instead of purchasing it. For example, we are planning to use more cloudbased solutions for applications such as Microsoft Office and e-mail.
These applications are designed for web deployment where users share
processing power and space that is managed by the vendor. Most often
these programs are leased as part of a pay-as-you-go subscription model
instead of purchasing user licenses.488
DTEE did not present rebuttal testimony responding to Mr. Coppola’s analysis. In its
reply brief, DTEE argues in support of these expenses in its reply brief at page 81,
essentially repeating Ms. Uzenski’s testimony on direct that the expenses are
attributable to a change in the way software is acquired, through leases rather than
purchases. In his brief, the Attorney General notes that DTEE did not file rebuttal to this
recommendation and urges the Commission to adopt the $5 million reduction.
This PFD finds that DTEE has not established that it has a plan for the
incremental $5 million expenditure above its normalized and inflation-adjusted
projection for the test year, and recommends that Mr. Coppola’s adjustment be adopted.
8. Uncollectibles Expense
For uncollectible account expenses, Ms. Tomina testified that DTEE is
forecasting uncollectible expenses of $52.8 million, based on the 2013 expense levels.
Staff recommends that the Commission move to a three-year average method for
487
488
See Coppola, 9 Tr 2302-2303.
See 6 Tr 1039-1040.
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projecting uncollectible expense, acknowledging that the three-year average of $56.6
million Staff includes in rates for this category is higher than DTEE’s projection of $52.8
million, which in turn is higher than the $42 million projection DTEE provided to its
shareholders. Staff’s three-year average method applies the three-year average
percentage of net writeoffs to forecast revenues. Mr. Welke testified that the mechanism
only works if it is used consistently, and noted that in DTEE’s last rate case, the
Commission used 2010 actuals, citing the Commission’s October 20, 2011 order in
Case No. U-16472, page 56.489 In the alternative, Mr. Welke testified, the Commission
could use DTEE’s actual 2014 uncollectible expense of $49.5 million, which would be
consistent with the methodology DTEE used, but update; or the Commission could use
DTEE’s more recent projection of $42 million that was provided to its shareholders.
Mr. Coppola also recommended an adjustment to DTEE’s uncollectible expense
projection. He considered the recent history of DTEE’s uncollectible expense and the
improving economy in concluding that DTEE’s $52.8 million forecast is too high. He
presented the revised forecast DTEE presented to its Board of Directors in Exhibit
AG-6, and recommended that the Commission adopt this revised forecast of $41.8
million.
He testified that he rejects the use of a three-year average under the
circumstances, arguing that an average ignores trends and would be “grossly
inaccurate.”490 He also presented rebuttal testimony expressly addressing Staff’s
recommendations, asserting that the Commission should adopt the second alternative
489
490
See Welke, 8 Tr 1952-1953.
See 9 Tr 2302.
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Mr. Welke identified, which matches Mr. Coppola’s recommendation. This is the position
the Attorney General argues in his brief.491
In its brief, Staff addressed Mr. Coppola’s rebuttal testimony, acknowledging that
Staff’s method is imperfect, but arguing that a three-year average mitigates potential
forecast error.492 Staff further argues that using the 2014 actual uncollectible expense of
$49.512 million is an acceptable alternative, $3.287 million below DTEE’s requested
allowance, and $7.107 million below Staff’s three-year average method. Staff also
argues that it would be acceptable to use the $42 million estimate DTEE is providing to
stockholders, consistent with Mr. Welke’s testimony.
In its brief, DTEE accepts Staff’s higher projection, although it does not endorse
the methodological consistency that is the hallmark of Staff’s recommendation,
asserting instead that “DTE Electric agrees with the Staff recommendation for only this
particular case.”493
This PFD recommends that the Commission adopt the 2014 uncollectible
expense level of $49.5 million as the projection for the test year. As Staff notes, this
approach is consistent with the approach DTEE used in its rate filing, but with updated
information. This PFD does not recommend using Staff’s three-year average, in part
because DTEE did not endorse this method in adopting the higher resulting projection.
In addition, the Attorney General has identified a significant concern with the use of the
three-year average, that it masks trends. Since it appears DTEE has taken steps to
reduce the level of its uncollectible expense,494 including an increased use of
491
See Attorney General brief, page 18.
See Staff brief, pages 44-46.
493
See DTEE brief, page 89.
494
See Tomina, 7 Tr 1403, 1412.
492
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technology, and since the economy appears to be improving, it is appropriate to use the
most recent annual value.
9. Injuries and Damages
Ms. Uzenski testified that she used a five-year average consistent with the
methodology used by the Commission in Case Nos. U-15244, U-15768 and U-16472.495
She testified that she summarized the development of the forecast O&M expenses in
Schedule C5 of Exhibit A-10, but the detail showing DTEE’s injuries and damages
projection of $20.3 million is presented in Schedule C5.8, which she also discusses in
her testimony.496 Staff used a five-year average that it calculated to be $20.622 million
for the projected test year. As Mr. Welke testified, the Commission has consistently
used a five-year average to estimate this category of expense, given its volatility.497 In
its brief, Staff recommends that the Commission adopt DTEE’s injuries and damages
calculation, arguing that its initial calculation contained a double-counting error that
cannot readily be straightened out on the record, and arguing that DTEE’s calculation of
record, which it identifies as $17.996 million, should be used instead.
In the meantime, in its brief, DTEE adopted Staff’s original calculation of $20.622
million.498 In its reply brief, Staff acknowledges that it misstated DTEE’s projection in its
initial brief, and that DTEE’s injuries and damages projection was $20.3 million. Staff
argues DTEE’s projection is similar to Staff’s projection and should be adopted. Staff
495
See 6 Tr 1022; also see 6 Tr 1038.
See 6 Tr 1037-1038.
497
See 8 Tr 1956.
498
See DTEE brief, page 12.
496
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cites Attachment B, note 2 to DTEE’s initial brief.499 DTEE does not further discuss this
issue in its reply brief.
Since Staff believes its calculation contains an error, and since Ms. Uzenski
clearly testified that she performed the calculation according to the five-year average
method the Commission has consistently used, this PFD recommends that the
Commission use DTEE’s filed projection of $2.3 million, as shown in Schedule C5.8 of
Exhibit A-10. Although DTEE adopts Staff’s slightly higher projection in its briefs, DTEE
does not indicate any error in its original calculation.
10. Competitive Affordable Rates Strategy (CARS)
As noted in section 1 above, Staff’s initial filing contained an inflation adjustment
based on Ms. Sandhu’s use of updated inflation estimates from those used in DTEE’s
cost
projections.
Staff
subsequently
withdrew
this
adjustment.
Staff
instead
recommends a $59 million adjustment attributable to DTEE’s “Competitive Affordable
Rates Strategy” or “CARS”. Mr. Welke explained that CARS refers to a cost reduction
program underway at DTEE, which Staff learned of in the course of its audit.500
Mr. Welke testified that DTEE’s internally-developed O&M expense projections
included projected cost reductions of $59 million. He testified that Staff believes the
cost reductions are achievable. He explained that in making this assessment, Staff
compared DTEE’s internally developed projections to projections DTEE provided to its
investors, which are approximately $78 million less than the O&M expense projections
DTEE presented in this case, as shown in Schedule C5.1 of Exhibit S-3. Mr. Welke
testified that Staff is recommending only a $59 million adjustment to O&M expense 1) to
499
500
Also see Attachment A, page 3 of DTEE’s reply brief.
See 8 Tr 1956-1958.
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reflect the fact that Staff has projected some cost categories using averages and wants
to retain methodological consistency for those categories, and 2) because Staff
recognizes DTEE’s concern that some cost reductions ultimately may not be
achievable.
In rebuttal, Ms. Uzenski testified that she does not believe Staff’s adjustment is
appropriate.501 She testified that the $59 million savings was targeted for all of 2016,
broken down into three pieces: $22 million for DTEE’s updated capitalization policies;
$20 million for “aspirational” cost reductions; and $17 million for inflation. She further
testified that implicit in the CARS reduction is an inflation offset, but Staff has
additionally proposed an inflation-based reduction, double-counting the projected
savings. She acknowledged DTEE’s current O&M cost projections are $78 million less
than its O&M expense projections in this case, and testified that $30 million of the
difference reflects the use of different projection methods to conform to ratemaking
practice, citing as an example the use of historical data in the rate case filing. She
testified that an additional $11 million is attributable to the limestone and trona to be
recovered from PSCR customers, $20 million is projected CARS savings excluding
inflation, and the remaining $23 million is decreased inflation, including $17 million from
CARS offset by $6 million in miscellaneous increases.
Ms. Uzenski testified that if the Commission chooses to include additional
expense reductions attributable to CARS, a reasonable amount would be $14 million to
reflect $20 million of CARS targets not including inflation, offset by $6 million.
As also quoted above, the Attorney General and Kroger presented testimony and
arguments related to the use of inflation in O&M expense projections.
501
See 6 Tr 1062-1064.
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While Mr.
Coppola’s specific adjustments were discussed above, his more general testimony and
Kroger’s arguments were deferred to this section.502
In its brief, Staff argues that CARS was one piece of a larger cost-savings
projection presented to investors, citing Exhibit S-3, Schedule C-5.1, line 17, reflecting a
$78 million reduction over rate case projections.503 Staff acknowledges Ms. Uzenski’s
rebuttal testimony, and argues that her issue-by-issue approach distracts from the
bigger picture. Staff also emphasizes that DTEE acknowledged that $78 million
projected reduction, and argues that Staff is generously only recommending a $59
million expense reduction. Nonetheless addressing Ms. Uzenksi’s breakdown of the
projected savings, Staff argues that although Ms. Uzenski cited in part DTEE’s updated
capital expenditure for the EVMP, a policy that Staff does not support, Staff has
compensated for its rejection of the capitalization program by providing $15 million more
in O&M for vegetation management than DTEE requested. Regarding the $20 million in
projected savings DTEE claims are aspirational, Staff cites Mr. Welke’s testimony to
show that Staff reviewed the projected savings and found them achievable. Staff further
argues that if the savings were illusory, DTEE would not have presented them to its
investors. Regarding the inflation element, Staff again notes that it has avoided doublecounting by withdrawing its separate inflation adjustment.
In its initial brief, DTEE cites Ms. Uzenksi’s testimony.504 It also argues: “Staff
essentially took issue with different numbers being presented to DTE Electric’s Board of
Directors, but if different numbers are to be considered, then all of the numbers and the
underlying bases should be considered. It would be inappropriate to just cherry-pick
502
See Kroger brief, pages 7-8.
See Staff brief, pages 49-51.
504
See DTEE brief, page 113.
503
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certain numbers that weigh towards a particular outcome.”505 In its reply brief, DTEE
takes issue with Staff’s response regarding the EVMP capitalization, arguing that Staff’s
reduction in DTEE’s EVMP proposal provides inadequate funding for vegetation
management.506 DTEE acknowledges that Staff withdrew its inflation adjustment, but
“maintains that Staff never should have considered any CARS reduction in the first
place.” DTEE also notes Kroger’s objection to inflation-based expense projections, and
argues that inflation is well-recognized and quantifiable. DTEE argues in this regard
Staff agrees that inflation is appropriate to include.507
This PFD finds Staff’s recommended adjustment well-supported and reasonable.
As Staff argues, it reviewed the proposed cost-savings underlying DTEE’s CARS
program and found those savings achievable. DTEE is actually projecting greater O&M
savings, $78 million rather than $59 million, which gives it considerable flexibility. The
Attorney General’s arguments regarding the individual expense categories have been
evaluated in the various sections above, and while his concerns regarding DTEE’s
projections for those categories may be covered by the CARS targets, Staff’s approach
of a single adjustment seems preferable to provide the flexibility as Staff argues. While
this adjustment also does not directly adopt Kroger’s recommendation, it is consistent
with the idea that inflationary pressures are often offset by productivity increases.
DTEE’s presentation of alternative projections to its investors and to its Board of
Directors while this case was pending undermines its claim that its expense projections
are based on known and measurable changes, since it is clearly no longer supporting
these projections. Staff’s adjustment is a reasonable reflection of the uncertainty in
505
See DTEE brief, page 113 at n97.
See DTEE reply brief, page 107.
507
See DTEE reply brief, page 108.
506
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DTEE’s costs projections. Regarding DTEE’s suggestion that this is “cherry-picking”,
other than the inflation adjustment that Staff withdrew, and DTEE’s objection to Staff’s
recommended level of vegetation management expense, DTEE does not identify any
offsetting cost increases that should be considered.
Regarding the EVMP spending, noting that DTEE’s request for additional
vegetation management expense was separately addressed above, this PFD sees no
relation between DTEE’s projected O&M savings and the amount it included in this case
for capitalized EVMP spending, unless DTEE is suggesting that it had no intention of
spending all the money slated for that program. DTEE’s request for additional
vegetation management expense for the proposed capitalized EVMP spending was
separately addressed above and is not related to the appropriate amount of CARS
savings to include in this case.
D.
Depreciation and Amortization Expense
1. COLA
The issue regarding DTEE’s request to amortize COLA expenses over a twenty-
year period, and Staff’s corresponding recommendation to amortize the expenses over
a ten-year period were addressed above in connection with the Working Capital
expense. For the reasons discussed above, this PFD recommends that COLA
expenses continue to be deferred, consistent with the Commission’s most recent order
on this topic, and thus this PFD does not recommend any amortization expense for the
COLA licensing.
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2. AMI
As discussed above, the Attorney General proposed to defer DTEE’s recovery of
depreciation to reflect Mr. Coppola’s concern that the benefits of the AMI project were
uncertain. For the reasons discussed above, this PFD recommended that the
Commission reject the Attorney General’s requested ratemaking treatment, recognizing
that the Commission put ratepayer protections in place in its October 20, 2011order in
Case No. U-16472.
3. Detroit Corporate Tax
Ms. Lewis explained DTEE’s request to amortize deferred tax balances arising
from the change in the City of Detroit’s corporate tax rate from 1% to 2% effective
January 1, 2012. She testified:
The MPSC has historically accepted the establishment of income tax
regulatory assets or liabilities for the impacts of the re-measurement of
deferred taxes due to tax laws. Therefore, the Company recorded the
impact of the rate change in Miscellaneous Deferred Debits. I have
included in the Municipal Income tax expense an annual amortization of
$0.5 million of the Miscellaneous Deferred Debit for the City of Detroit tax
rate change.508
She further testified that DTEE requests that the Commission approve “full
normalization ratemaking for the law change over a period reasonably related to the
reversal of the underlying book tax basis differences consistent with the [Commission’s]
February 15, 2012 order in Case No. U-16864.”509
508
509
See 6 Tr 1339.
See 6 Tr 1339-1340.
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The RCG opposes DTEE’s request to amortize $12.7 million attributable to the
City of Detroit’s January 1, 2012 increase in the municipal income tax rate.510 RCG
argues:
[T]he tax change occurred effective January 11, 2012, and DTE did not at
that time (or previously) file a special accounting case, or otherwise seek
the advance approval of the Commission. DTE also apparently did not
obtain approval of this expense item in a past DTE rate case
contemporaneous with or in advance of the tax rate change.
The RCG argues DTEE’s request constitutes retroactive ratemaking, citing Michigan
Bell Telephone Co v Michigan Public Service Comm’n, 315 Mich 533 (1946), and
Michigan Bell Telephone Co v Mich Public Service Comm’n, 85 Mich App163 (1978).
In its reply brief, DTEE argues that its request for full normalization ratemaking
for the law change over a period reasonably related to the reversal of the underlying
book tax basis differences is consistent with the Commission’s February 15, 2012 Order
in Case No. U-16864. It disputes that the prohibition against retroactive ratemaking is
applicable in this context.511
This PFD finds that DTEE’s tax deferral was appropriate based on the authority
granted in the Commission’s February 8, 1993 order in Case No. U-10083, which
appears to have provided such general authority, although neither of the parties discuss
this case in their briefs. The reference to Case No. U-10083, however, in the February
15, 2012 order in Case No. U-16864, which DTEE did cite, and a review of the
comments filed in that docket, confirms that Case No. U-10083 can be relied on as
general authority for both the deferral and DTEE’s requested ratemaking treatment. On
510
511
See RCG brief, pages 58-59.
See DTEE reply brief, p 111.
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this basis, DTEE is not proposing retroactive ratemaking, and this PFD recommends
that its request as presented by Ms. Lewis be granted.
4. Plug-in Electric Vehicle
As explained by Ms. Uzenski at 6 Tr 1023-1024, DTEE also requests to amortize
its deferred electric plug-in vehicle costs over five years. No party opposed this request
and this PFD recommends that it be granted.
E.
Allowance for Funds Used During Construction
Other than Mr. Chriss’s concern with the level of CWIP in rate base, as
discussed above, no party raised any issues regarding DTEE’s accounting for AFUDC.
PFD recommends that the Commission calculate AFUDC consistent with the CWIP
balances and rate of return it adopts in setting final rates in this case.
F.
General Taxes
The only issue that arose regarding taxes was Staff’s recommendation that the
property tax calculation be revised to reflect the Renaissance Zone designation
associated with DTEE’s Renaissance power plant acquisition. Ms. Talbert testified that
the tax designation reduces DTEE’s property tax projection by $800,000.512 In its brief,
DTEE states that it agrees with Staff’s adjustment.513
G.
Income Taxes
The only dispute between the parties regarding income tax is the dispute
between the RCG and DTEE discussed in section D. above.
512
513
See 8 Tr 2108.
See DTEE brief, page 109.
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H.
Adjusted Net Operating Income Summary
Based on the foregoing discussion, this PFD recommends the following
adjustments to Staff’s filed Adjusted Net Operating Income of $645,389,000: 1) reverse
Staff’s $15 million inflation adjustment as discussed in section C1 above; 2) remove the
projected O&M expenses for the East China plant as discussed in section C3;
3) increase the expense allowance for DTEE’s traditional vegetation management by
$2.6 million as discussed in section C5; 4) reduce the Corporate Support Group
expense allowance by $5 million as discussed in section C7; 5) reduce Staff’s
uncollectible expense allowance to the 2014 actual level of $49.5 million as discussed in
section C8; 6) reduce the injuries and damages expense projection to $20.3 million as
discussed in section C9; 7) eliminate the COLA amortization expense as discussed in
section D1. As shown in Appendix B attached, Staff estimates the Adjusted Net
Operating Income resulting from these adjustments to be $648,398,000.
VIII.
OTHER REVENUE RELATED ISSUES
A.
Nuclear Surcharge
The nuclear decommissioning surcharge currently includes funding for
decommissioning Fermi 2 as well as costs for site security and radiation protection, and
low level radioactive waste disposal. Mr. Colonnello testified that the current amount of
the surcharge should be reduced in light of assumptions regarding decommissioning
presented in his Exhibit A-19, Schedule K1. He also recommended that the name of
the surcharge be changed to the “nuclear surcharge”. Ms. Sandhu testified that Staff
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had reviewed the recent decommissioning funding report and agreed with DTEE’s
recommendation.
Citing Mr. Selecky’s testimony at 9 Tr 2398-2400, ABATE argues that the site
security and radiation expenses should not be included in the nuclear surcharge,
arguing that these components are solely related to Fermi 2 as an ongoing expense,
and placing them in a surcharge unfairly saddles choice customers with this expense.514
DTEE responds that the Commission previously rejected this suggestion in its
December 22, 2005 order in Case No. U-14399, pages 36-37. DTEE argues there is no
basis to revisit this matter.515
This PFD recommends that ABATE’s request be rejected on the basis that DTEE
has not proposed a change in surcharge, but merely a name change. Mr. Colonello
clearly testified that the site security and radiation protection were included in a single
surcharge in Case No. U-14399: “This reduction [to historical test year site security
costs] is necessary since costs associated with site security (security and radiation
protection services) were removed from base rates and recognized in the Nuclear
Surcharge established in DTE Electric Case No. U-14399.”516 Mr. Colonnello further
testified:
As mentioned previously in my testimony, security and radiation protection
expenses are collected under the Nuclear Surcharge mechanism as
established in Case No. U-14399 where nuclear site security costs were
moved from base rates to a surcharge for bundled customers. Also, as
previous mentioned, security and radiation protection expenses were
removed from the historical test year on exhibit A-10, page 1 of Schedule
C5.3. Line 2 simply reflects the level of expenses for the projected test
year that was derived based on annual inflation adjustments shown on line
12, columns (f) through (h). Again, recognition of security and radiation
514
See ABATE brief, pages 3, 24-25.
See DTEE reply brief, page 56.
516
See 6 Tr 1162; also see 6 Tr 1176.
515
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protection expenses captured on line 2 is no change in practice from prior
DTE Electric rate cases.517
While Mr. Selecky recommended that “site security and radiation protection
remain in base rates,”518 he did not contradict Mr. Colonnello’s clear direct testimony on
this topic that these costs had been removed from base rates in a prior order. On this
basis, this PFD concludes that the Commission has considered the nuclear surcharge
as recently as Case No. U7689 and ABATE has not provided a sufficient basis to
reconsider that determination. Note that DTEE’s proposal in this case results in a
reduction in the surcharge.
B.
AMI tariff and charges
The Attorney General, the RCG, Mr. Sheldon, and Mr. Meltzer take issue with the
adequacy of DTEE’s opt-out tariff for customers who do not want the AMI meter
installed on their house. Because the objections in part involve the opt-out charges,
which are reflected as a revenue item in the rate calculations, the parties’ objections are
discussed collectively in this section, beginning with a review of the history of some of
the Commission’s prior decisions on this topic, then addressing the arguments
regarding the opt-out program, and then addressing the arguments whether the opt-out
charges should be revised.
1. History
A review of the Commission’s prior decisions, and the court orders affirming
those decisions is appropriate to provide context for this dispute. The Commission first
approved pilot-program expenditures for DTEE to evaluate the benefits of an AMI
517
518
See 6 Tr 1176.
See 9 Tr 2399
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system in Case No. U-15244.519 In its January 12, 2012 order initiating Case No. U17000, the Commission directed all regulated utilities to submit information regarding
their AMI deployment plans:
In the past several months, the Commission has become aware of
concern on the part of some individuals in this state and an increasing
number of municipal officials regarding the deployment of smart meters by
electric utilities operating in Michigan. During the Commission’s annual
consumer forums conducted at various locations during the fall of 2011,
individual Commissioners on several occasions encountered vocal
opponents to the deployment of smart meters in their communities. More
recently, through direct submissions, media reports, and by other means,
the Commission has learned that the elected governing bodies of at least
nine local communities across Michigan have by resolution implored the
Commission to either (1) make information about smart meters available
to the public, (2) investigate the safety of the physical attachment of a
smart meter to a residential dwelling house, (3) halt ongoing efforts by
regulated electric utilities to deploy smart meters throughout their service
territories, or (4) force these electric utilities to allow concerned customers
to “opt out” of having a smart meter attached to her or his own dwelling
house.1
In hopes of increasing the Commission’s and the public’s understanding of
smart meters, the Commission opens this docket for the purpose of
addressing these concerns to the degree possible in light of the limits of
the Commission’s statutory authority and expertise.520
The Commission required the utilities to provide the following information:
(1) The electric utility’s existing plans for the deployment of smart meters
in its service territory; (2) The estimated cost of deploying smart meters
throughout its service territory and any sources of funding; (3) An estimate
of the savings to be achieved by the deployment of smart meters; (4) An
explanation of any other non-monetary benefits that might be realized
from the deployment of smart meters; (5) Any scientific information known
to the electric utility that bears on the safety of the smart meters to be
deployed by that utility; (6) An explanation of the type of information that
will be gathered by the electric utility through the use of smart meters; (7)
An explanation of the steps that the electric utility intends to take to
safeguard the privacy of the customer information so gathered; (8)
Whether the electric utility intends to allow customers to opt out of having
519
520
See April 22, 2008 order.
See January 12, 2012 order, pages 1-2.
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a smart meter; and 9) How the electric utility intends to recover the cost of
an opt out program if one will exist.521
It was in that case that Staff submitted a detailed report addressing the information filed
by the utilities and comments from the public; the Commission adopted the Staff Report
in its September 11, 2012 order in that case.
At Staff’s request, the ALJ took official notice of this report, which is also
discussed in subsequent Commission decisions. In its September 11, 2012 order in
Case No. U-17000, the Commission also required Consumers Energy to file a costbased opt-out tariff, and directed other regulated utilities deciding to implement AMI
infrastructure to file to provide an opt-out option or an explanation for why an opt-out is
unnecessary or cost-prohibitive. DTEE was not addressed in the Commission’s ordering
paragraph because DTEE had already filed for an opt-out tariff in Case No. U-17053, as
expressly noted by the Commission in its order at page 5.
In Case No. U-17053, the Commission reviewed the opt-out plan and tariff DTEE
proposed for customers who want a non-transmitting meter. The Commission explained
its role as follows:
The Commission approved the pilot program in Case No. U-15244, and
approved rate base treatment of the reasonable and prudent costs in that
case; and has continued to review expenditures according to that standard
in each subsequent rate case. In the September 11 order [in Case No. U17000], the Commission adopted the Staff’s report as “thoughtful and
comprehensive” and as a point of departure for further discussion, singling
out the continuing review of expenditures in rate cases, opt-out options,
and privacy concerns for further action. September 11 order, p. 4. As has
been noted repeatedly in the various AMI-related proceedings, while the
Commission may not encroach on the managerial decision to commence
the AMI program and to select the equipment attendant thereto, it will
continue to protect the interests of ratepayers through review of the
521
Id. page 2.
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expenditures associated with the program for reasonableness and
prudence.522
The Commission rejected DTEE’s proposed opt-out fees in favor of lower fees based on
Staff’s higher estimate of the number of customers likely to participate in the opt-out
program:
While DTE Electric’s method of calculation is conservative (in that it
considers every expression of concern to result in a decision to opt out),
such expressions appear to be on the rise as the program expands, and
the Staff’s proposed participation rate is more credible. Real world
experience will help with refining this calculation in the future; for the
present the Commission rejects the utility’s exceptions and adopts the
Staff’s number as well as the tariff language in Exhibit S-2 (NonTransmitting Meter Provision), with the minor change to the final
paragraph as outlined in the PFD. Although the opt-out mandate set in the
September 11 order was not limited to residential customers, the
Commission is unaware of any evidence showing that commercial and
industrial customers seek an opt-out option, and finds that DTE Electric’s
residential non-transmitting meter option satisfies the requirement of the
September 11 order.523
The Court of Appeals affirmed the Commission’s order in Case No. U-17053,
holding that the choice of meter equipment is a managerial prerogative:
Appellants correctly point out that the PSC has no statutory authority to
enable DTE to require all customers to accept an AMI meter, even if some
customers choose to opt-out of the AMI program. However, no such
statute exists because the decision regarding what type of equipment to
deploy can only be described as a management prerogative. DTE applied
for approval of its AMI program, but that fact does not mandate a
conclusion that DTE’s decision regarding what meters to use is not a
management decision. Appellants’ suggestion that the PSC could order
DTE to allow customers who wish to do so to retain analog meters is
clearly the type of action found invalid in Union Carbide. Appellants clearly
do not wish to accept AMI meters, but they have cited no authority that
supports their argument that the PSC erred in approving DTE’s AMI
program with its requirement that all customers accept AMI meters, even if
522
523
See May 15, 2013 order, page 18.
See May 15, 2013 order, page 18.
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those meters are rendered incapable of transmitting. The PSC’s order is
not unlawful in this regard.524
The Court of Appeals also declined to require the Commission to consider health or
privacy concerns in Case No. U-17053, precluding the appellants from collaterally
attacking the Commission’s order in Case No. U-17000:
Appellants’ argument that the PSC’s order was not supported by the
evidence because no evidence showed that customers who wished to optout of the AMI program would benefit from receiving a non-transmitting
AMI meter is simply another way of asserting that issues regarding health
concerns, etc., surrounding AMI meters should have been addressed in
this case. However, the PSC addressed those concerns in Case No. U17000 when it adopted the Staff report that found that the concerns were
minimal and should not be an impediment to implementation of the AMI
program. Appellants’ arguments are an attempt to collaterally attack the
PSC’s decision in Case No. U-17000. Such an attack is precluded. See
Kosch v Kosch, 233 Mich App 346, 353; 592 NW2d 434 (1999). The
PSC’s order in Case No. U-17000 found that the AMI program benefitted
customers; therefore, no cost/benefit analysis was needed in this
proceeding. The PSC’s order is not unlawful or unreasonable.525
In its October 21, 2012 order in Case No. U-17102, the Commission outlined a
framework for the development of customer privacy policies and directed the utilities to
address additional Commission questions and provide comments. Approximately one
year later, the Commission’s October 17, 2013 order concluded:
In summary, the Commission has determined that an acceptable data
privacy policy should limit the collection, use, or disclosure of any
customer information to accomplishing primary utility purposes only.
Primary utility purposes should encompass not only traditional utility
service but should also include all other regulated programs including
energy efficiency, demand management, renewable energy, and lowincome programs. However, should a utility wish to collect, use, or
disclose customer information for a secondary (i.e., non-utility) purpose,
the utility must obtain informed consent from the customer in advance. In
addition, the privacy policy should assure that all customer information is
protected from unauthorized use or disclosure by utility affiliates and
524
In re Application of Detroit Edison Company To Implement Opt Out Program, unpublished opinion per
curiam of the Court of Appeals, issued February 19, 2015 (Docket Nos. 316728, 316781), page 5.
525
Id., page 6.
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contractors or agents. And a utility privacy policy must ensure that a
customer, or a third-party authorized by that customer, is not impeded in
accessing the customer’s information in accordance with the customer’s
request. Finally, while the Commission briefly discussed the Code of
Conduct in the June 28 order, it should be clarified that a data privacy tariff
that applies to regulated utility service does not supersede the Code of
Conduct.526
The Commission directed DTEE and Consumers Energy to file conforming tariffs, and
to display links to the tariffs prominently on their webpages.
2. Opt-out program
DTEE’s opt-out program is set forth in its tariff, Rule C5.7, Sheet Nos. C-24.00
and C-24.01. In addition to specifying the charges, it provides:
A Customer electing to have a non-transmitting meter(s) and who already
has a transmitting meter installed at their premise will have their meter
changed to a non-transmitting meter. A Customer, who has not had their
current meter replaced by a transmitting meter at the time they request to
have a non-transmitting meter, will temporarily retain their current meter
until such a time as transmitting meters in their area are installed and
subsequently will receive a non-transmitting meter. A Customer who has
not had their current meter replaced by a transmitting meter and requests
a non-transmitting meter will pay the initial fee at the time they request this
option but will not pay the monthly charge until transmitting meters are
installed in their area.
Customers electing this provision will be physically unable to access all of
the benefits of having a transmitting meter. All charges and provisions of
the customer’s otherwise applicable tariff shall apply.
As noted above, the Commission approved this tariff in its May 15, 2013 order in Case
No. U-17053. Also, of longer standing, and as background to understanding some of the
arguments presented, Rule C5.4 of DTEE’s tariff provides:
As a condition of taking service, authorized employees and
agents of the Company shall have access to the customer’s
premises at all reasonable hours to install, turn on,
disconnect, inspect, read, repair or remove its meters, and to
526
See order, Case No. U-17102, pages 3-4.
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install, operate and maintain other Company property, and to
inspect and determine the connected electrical load.
Authorized employees and agents shall carry identification
furnished by the Company and shall display it upon request.
Several witnesses testified in the instant case regarding DTEE’s opt-out program
and its administration of that tariff, and the parties have provided substantial briefing on
this topic. Testifying for the RCG, Mr. Crandall recommended that the Commission
adopt an “opt-in" approach, testifying that current tariff does not require notice or
consent prior to installing an AMI meter.527 He testified that this would provide regulatory
benefits by avoiding controversies with customers and gradually transitioning to the AMI
program.528 He testified that numerous other utilities have an opt-in program, providing
an example in Exhibit RCG-2.529 He presented Exhibit RCG-3 as an example of a utility
with an opt-out program with no fee. He also objected that DTEE’s tariff empowers
DTEE to cut off electric service or not provide service after due notice, asserting that
because DTEE has not substantiated its opt-out charges, these provisions are
unreasonable and should be modified by the Commission. He presented Exhibit RCG-4
as a marked-up version of the access provision of DTEE’s tariff as quoted above, to
limit access to customer premises. Mr. Crandall recommended this revision “to avoid
misuse, abuse as applied to dealings between customers and DTE, and in particular
with respect to legitimate disputes concerning the installation of a smart meter.”530 Mr.
Crandall also testified that the smart meters permit substantial data collection that “will
exist in the data universe where it is inherently subject to security breaches, misuse,
527
See 8 Tr 2261-2262.
See 8Tr 2262-2263.
529
See 8 Tr 2265-2266.
530
See 8 Tr 2268.
528
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manipulation or abuse.”531 The RCG also presented numerous additional exhibits
containing Staff and DTEE responses to interrogatories.
Following an exhaustive review of the record evidence relating to DTEE’s AMI
program in its brief, the RCG urges the Commission to adopt the recommendations
presented by Mr. Crandall in his testimony.532 In support of its requests, the RCG
argues that certain tariff modifications proposed by DTEE are vague or legally
questionable, that the opt-out provisions violate the 4th Amendment of the U.S.
Constitution and similar provisions of the Michigan Constitution of 1963, that the MPSC
does not have the jurisdiction or authority to waive ratepayers’ constitutional rights, that
the MPSC may not lawfully rely on its decisions in Case No. U-17000 and U-17102, and
the Commission lacks the authority to impose an opt-out requirement on nonparticipants.
Testifying on behalf of Mr. Sheldon, Dr. Carpenter testified to his concern with
“the health costs imposed on customers in consequence of the radio transmitters in
smart meters and also in consequence of the power quality issues, sometimes called
“dirty electricity” generated by the power supplies used in these meters.” He testified to
his opinion that widespread deployment of smart meters “cannot be justified at this time
based on the peer-reviewed research we have.” He testified that he was not referring to
research regarding smart meters per se:
While smart meters are too new for there to be human health studies
specifically on exposure from smart meters, there is a strong body of
evidence that demonstrates a variety of adverse human health effects,
531
See 8 Tr 2268.
Note that in its brief at page 32, n1, the RCG asserts that the ALJ ruled portions of Mr. Crandall’s
testimony should be stricken. Instead, counsel for the RCG, Staff, and DTEE amicably resolved the
issues identified in Staff’s and DTEE’s motions to strike portions of Mr. Crandall’s testimony, without the
need for the ALJ to rule on those motions. See 8 Tr 2251-2252.
532
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including cancer and effects on brain and behavior, coming from exposure
to radiofrequency radiation like that generated by wireless smart
meters.533
He presented Exhibit DS-1 in support of this testimony, which is entitled: “2012
statement of David O. Carpenter, M.D. and 45 other scientists and health professionals
concerning the hazards of radiation from smart meters.” He acknowledged that there is
no data on smart meters to determine the long-term effects of such meters, but he
testified:
[U]ntil more data becomes available we have to make inferences based
on longer term data that we do have concerning use of cell phones and
people living near to radio transmission towers. These studies show that
increased radiofrequency exposure increases risk of cancer, and that the
most vulnerable parts of the population are children and teenagers.534
He also identified potential health problems with non-transmitting smart meters due to a
“switched mode power supply” that may cause low frequency interference with the
electric current in a home.535 He described his efforts to persuade the Portland, Oregon
School District not to install Wi-Fi in schools, attaching his testimony in that case as his
Exhibit DS-2, acknowledging that the district did not adopt his recommendation. He
testified that in this case, he recommends that it would be good public policy for the
Commission to allow customers to opt-out of having a smart meter.536
He further
testified that this would not entirely address the exposure risk he is concerned about:
Not having a smart meter on one’s own home will reduce the potentially
harmful exposure, but the customer opting out is still going to be exposed
to a whole blanket of electromagnetic radiation from the smart meters of
immediate neighbors and from all the transmitting and receiving devices
533
See 10 Tr 2500.
See 10 Tr 2503.
535
See 10 Tr 2502.
536
See 10 Tr 2503.
534
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and repeaters the utility must install to allow all these meters to report their
data, as well as other sources of radiofrequency radiation.537
Dr. Carpenter also recommended that wired technology be used instead of wireless,
using cable or fiber optics. Over DTEE’s and Staff’s continuing objection, Dr. Carpenter
also testified in response to questions from Mr. Meltzer to explain some of the
references he cited in his Exhibit DS-1.
In his brief, Mr. Sheldon argues that the non-transmitting AMI meter still poses a
health threat. He argues that the Commission’s decision in Case No. U-17000 did not
involve an evidentiary proceeding; he also takes issue with Staff’s report in that case
because the individuals conducting the literature review did not have medical or public
health credentials, citing cross-examination of Mr. Hudson and Mr. Matthews. Mr.
Sheldon contends that there has been no representation by DTEE that the nontransmitting meters to be installed will address customers’ health or privacy concerns.
Mr. Melzer argues that the Commission should refuse to provide additional
ratepayer funding for AMI meters if DTEE continues to refuse to allow customers to
retain their analog meters. He argues that consumers should be allowed to opt-out of
the AMI program by retaining their analog meter, with no additional opt-out charges,
although he indicates some charge might be acceptable if “DTE can adopt a customercentric orientation.” He argues that the precautionary principle and biomedical research
justify customer choices to reject any form of AMI meter. He argues that DTEE should
not be allowed to shut off service to customers for refusing to accept a smart-meter, and
further that customers should be allowed to self-report their own meter readings.
537
See 10 Tr 2504.
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Mr. Meltzer argues that the Commission should consider special opt-out
provisions for apartment residents. He also recommends that the Commission require
DTEE to work with electrical industry organizations and equipment manufacturers to
eliminate power loss attributable to the “instant on” feature of the smart meters, and
should also require DTEE to perform a risk analysis regarding the long term liability
associated with continuous exposure to RF emissions from smart meters. In his reply
brief, Mr. Melzer argues that opt-out provision is not a true opt-out and “does not meet
the opt-out provision” required by the Commission in Case No. U-17000, contending
that the non-transmitting meter still has electronic characteristics that are disruptive to
individuals who are electro-magnetic sensitive. He also cites Dr. Carpenter’s testimony
at 10 Tr 2521 to show that the FCC standards are “grossly inadequate.” And he argues
that DTEE’s claims of data security are wishful thinking in view of significant data
breaches regularly reported in the news.
The Attorney General argues that the Commission should require DTEE to allow
customers to retain their analog meters, arguing that since Consumers Energy allows
this, it should be feasible for DTEE.
Mr. Sitkauskas provided rebuttal testimony for DTEE. He testified regarding Mr.
Crandall’s opt-in recommendation:
The manner in which the Company provides these services (as well as
others) is at its discretion utilizing the most cost efficient use of resources.
The Company is not required to request approval from its customers in
order to perform these functions. Customers of DTE Electric have agreed
to specific conditions of service when they agree to become a customer,
therefore, an opt in is not necessary or appropriate.538
538
See 5 Tr 742.
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He acknowledged Mr. Crandall’s testimony identifying utilities that do not charge for
opting out of a smart meter, and responded that many utilities do charge opt-out fees.
Regarding DTEE’s policy of shutting service off to customers who refuse to allow the
company to install even a non-transmitting smart meter, he testified:
DTE Energy fully complies with its tariff and the Billing Practice Rules
approved by the Michigan Public Service Commission. Specifically, tariff
Section C5.4 - Access to Premises states, “As a condition of taking
service, authorized employees and agents of the Company shall have
access to the customer’s premise at all reasonable hours to install, turnon, disconnect, inspect, read, repair or remove its meter... “In addition,
“Pursuant to Michigan Public Service Commission (MPSC) Rule 460.136,
a utility may shut off service temporarily for reasons of health or
safety...”539
Regarding privacy issues, Mr. Sitkauskas testified that DTEE fully complies with its
privacy tariff and takes customer data security very seriously, further stating that all
employees take security awareness training and DTEE has a compliance office to
ensure that the specific rules are being followed.540 Regarding health issues, Mr.
Sitkauskas testified that health issues were considered in Case No. U-17000 when the
Commission determined that an opt-out should be provided. Mr. Sitkauskas addressed
Dr. Carpenter’s testimony, explaining that the Court in the Oregon school case
acknowledged the role of the Federal Communications Commission in regulating the
radiation levels emitted by Wi-Fi. He believes a similar conclusion is appropriate in this
case. He testified that he agreed with Dr. Carpenter that many common household
products use radio frequency, including cell phones, baby monitors, and Wi-Fi. He also
539
540
See 5 Tr 743.
See 5 Tr 744.
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explained further the “switched mode power supply” component of smart meters as
common since the 1970s.541
In its brief, DTEE chronicles the history of rate cases in which the Commission
has approved funding for AMI infrastructure, including the Court of Appeals remand in
Case No. U-15768 followed by additional contested case proceedings.542 DTEE’s brief
also reviews the major benefits of the AMI program in reduced meter reading expenses,
increased bill accuracy, theft deterrence, increased customer and employee safety,
remote turn-on and turn-off capabilities, and enhanced outage and power quality
monitoring. DTEE also reviews its cost-benefit analysis, showing the present value of
expected revenue requirements exceeding costs by $87.2 million.
Responding to the RCG’s arguments, DTEE argues that its opt-out program has
been approved by the Commission in an order affirmed by the Court of Appeals,
emphasizing that DTEE is not proposing to change that program in this case.543
DTEE’s brief also reviews the calculation of the opt-out charges in that case. DTEE
argues that what other states have decided is irrelevant. DTEE also argues that there
are no outstanding privacy issues, since privacy concerns were appropriately addressed
by the Commission’s October 17, 2013 order in Case No. U-17102.
DTEE also
addresses Dr. Carpenter’s testimony, citing Staff’s report in Case No. U-17000, and Mr.
Sitkauskas’s rebuttal testimony at 5 Tr 744-46.544 In addition, DTEE cites the July 14,
2015 decision of the Michigan Court of Appeals in Detroit Edison Co v Stenman, __
541
See 5 Tr 746.
See DTEE brief, page 74.
543
See DTEE brief, page 79.
544
See DTEE brief, pages 80-81.
542
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Mich App ___ (Docket No. 321203 )(2015), arguing that the Court in that case also
rejected the defendants’ health, privacy, and Fourth Amendment arguments.545
Mr. Hudson testified regarding the history of the Commission’s orders addressing
the AMI program, including a review of the Commission’s decisions in Case Nos.
U-15768, U-16472, U-17000, and U-17002.546 In his rebuttal testimony, Mr. Hudson
addressed Mr. Crandall’s recommendation that the Commission adopt an opt-in tariff.
He testified that the meters are owned by the company, not the customers, and the
company has the ability to choose the meters that will be used to measure usage:
Customers receive electrical service from a utility company. The utility
company provides the meters that measure electricity consumption
associated with that service. Customers do not own the electrical meter
that interfaces on their home, therefore customers do not choose the
meter make, model or specific technology of the meter. This is similar to a
utility sub-station, distribution line, recloser, or other equipment that the
utility owns. Customers do not choose the make, model or type of
technology of utility equipment. In short, it is not reasonable to suggest
that customers opt-in to the meter provided by the Company. The opt-out
provision, however, simply represents a directive from the Commission to
the Company to accommodate customers who were not comfortable with
a transmitting AMI meter. The Commission further specified that the
additional costs associated with an opt-out option would be the
responsibility of the cost causers – the customers choosing to opt-out of
the default meter.547
Staff argues that the Michigan courts have upheld the utility’s reliance on the
management prerogative doctrine. In its reply brief, Staff addressed RCG’s argument
that DTEE should have considered the potential benefits of alternate investments.
Staff disputes that other investments, such as renewable energy, are a substitute for
AMI technology.
545
See DTEE reply brief, page 78.
See 8 Tr 2138-2142.
547
See 8 Tr 2145-2146.
546
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Addressing Mr. Sheldon’s and Mr. Meltzer’s arguments, Staff argues that Dr.
Carpenter is not qualified as an expert with respect to the health and safety of smart
meters, citing MRE Rule 702.548 Staff argues it does not recommend that the entire
testimony be stricken, but that the weight given the testimony be limited appropriately.
Staff also does not consider Exhibits DS-1 and DS-2 to be evidence of the type
commonly relied upon, within the meaning of R 460.17325(1). Staff argues that Dr.
Carpenter’s testimony is biased and unpersuasive. Staff also argues that Dr. Carpenter
is not an engineer, a PhD, or an accredited physician.549 Staff also argues that Dr.
Carpenter did not refute the conclusions in the report Staff submitted in Case No.
U-17000.550 Staff also responds to Mr. Sheldon’s and Mr. Meltzer’s reliance on Judge
O’Connell’s opinion in Case No. U-17087, arguing that the remand in that Consumers
Energy case was not expanded by Judge O’Connell’s opinion, and that the Court of
Appeals remand in that case does not apply to Detroit Edison.551 Staff also cites DTE
Electric Co v Ralph Stenman, -- Mich App --- (Docket No. 321203) (2015); slip op at 1-3
and 11-12.
Given that the Commission has already decided to implement an opt-out
program for AMI meters, rather than an opt-in program, and the utility has almost
completed installation of the meters under that paradigm, it is both practically and
legally difficult at this point to contemplate revising that paradigm. As DTEE argues, the
Commission’s decision has been reviewed and affirmed by the Court of Appeals. While
the Commission may reconsider its prior decisions, some degree of consistency is
548
Staff also cites portions of the Texas Report that the ALJ declined to take official notice of in section III
above, and so that report will not be considered here.
549
See Staff’s reply brief, pages 19-26.
550
See Staff reply brief, pages 25-26.
551
See Staff reply brief, pages 26-27.
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expected. In order to avoid arbitrary and capricious decision-making, the Commission
traditionally requires that parties show some changed circumstances or new evidence.
In addition, as DTEE argues, the specific holdings of the Court of Appeals in affirming
the Commission’s prior decisions must be considered. These holdings, discussed
above, are not merely dicta, and unless and until they are reversed by a higher court,
they bind the Commission and other parties to the case. Nonetheless, the arguments of
the parties are reviewed in the following sections.
a. Commission authority
The RCG argues that the Commission lacks the authority to approve an opt-out
tariff for DTEE.
As DTEE and Staff argue, and as can be seen from the discussion
above, the Court of Appeals has already ruled that the Commission has the authority to
approve DTEE’s opt-out tariff, and indeed affirmed the Commission’s decision
approving the tariff in Case No. U-17053.
The RCG also quotes at length in its reply brief the dissenting opinion of Court of
Appeals Judge O’Connell, regarding the Commission’s motion for reconsideration of the
Court’s April 30, 2015 remand of the Commission’s decision in Consumers Energy’s
rate case, Case No. U-17087.552 As Staff and DTEE argue, the Court of Appeals
remand in Case No. U-17087 is not at issue in this case. Even so, in its April 30, 2015
order remanding Case No. U-17087 to the Commission for a contested case hearing to
determine the opt-out charges for Consumers Energy, the Court rejected the argument
that the Commission lacked authority to approve an opt-out program for that utility, and
552
See In re Application of Consumers Energy to Increase Electric Rates, unpublished opinion per curiam
of the Court of Appeals, issued April 30, 2015(Docket Nos. 317434, 317456), rehrg den, July 22, 2015
(separate opinion, O’Connell, P.J.)
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cited Union Carbide in concluding that the Commission does not make managerial
decisions for the utility. In subsequent proceedings before the Commission in that
docket, if any, the Commission would be expected to follow the Court’s holding
regarding management prerogative as the “law of the case.”553
b. Notice and due process issues
Repeatedly in its brief, the RCG asserts that DTEE is not providing notice of the
meter replacements and opt-out tariff options. The RCG also cites Palmer v Columbia
Gas of Ohio, 479 F2d 153 (CA 6 1973), and Memphis Light, Gas and Water Division v
Craft, 436 US 1, 98 S Ct 1554; 56 L Ed 2d 30 (1978) in support of its arguments that the
termination of utility service requires due process protections.
While the RCG argues that DTEE is not providing notice, there is no evidence to
support that claim on this record. In Case No. U-17053, as discussed above, the
Commission approved the opt-out tariff for DTEE. Addressing a petition for rehearing in
that case objecting that DTEE was not providing notice in accordance with the
Commission’s requirements—and in particular was providing notice giving customers 30
days to decide whether to opt out--the Commission’s order provided:
Exhibits 1 and 2 to the petition show the language imposing the 30-day
decision deadline. DTE Electric does not dispute the validity of these
exhibits but instead argues that the deadline is reasonable, and that the
customer is not limited by the deadline. While the latter is true, that is not
apparent to the customer from reading the letter. The Commission agrees
with the Staff that the 30-day deadline is contrary to the tariff, which
imposes no deadline. While the Commission understands that the utility
may want to hear from the customer prior to installing the new meter, the
communication to the customer must be consistent with the tariff and must
not create the impression that the ability to opt for a non-transmitting
meter arises from a one-time choice. The Commission directs DTE
553
See, e.g., Lenawee County v Wagley, 301 Mich App 134, 149-150 (2013).
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Electric to conform its communications to customers to the dictates of the
May 15 order and the tariff adopted therein.554
In addition, Mr. Sitkauskas testified that DTEE provides notice to customers:
Our letter that goes to the customers has the opt-out costs and how to do
it inside of that letter, when we sent out the first letter to the customer. Our
website has been updated for that with Frequently Asked Questions as
well, and our actual installers carry a little four-by-six card, three-by-five
card, that has information about opt-out as well. And we do mention it in
every one of our media releases.555
Regarding RCG’s argument that DTEE is shutting off service to customers
without notice and an opportunity to file a complaint with the Commission, Mr.
Sitkauskas testified that DTEE does not believe a customer’s failure to permit DTEE to
install a smart meter justifies immediate shut-off of service without notice on health and
safety grounds:
Q: If a customer selects an opt-out option, that's not grounds for
disconnecting or shutting off his service on the basis of health or safety,
correct?
A: If a customer selects the opt-out option, we're going to change the
meter, and that is correct, we will not shut him off.
Q: Well, if a customer insists on having his existing meter, analog or other
existing meter, and doesn't want a Smart Meter, is the Company shutting
off service to such a customer on the basis of health or safety?
A: On the basis of health and safety, no.
Q: On any other basis?
A: Again, we're there to change the meter on every customer's home to an
AMI transmitting or non-transmitting meter. We will work our best efforts to
try to make sure that we have the customer comply with either one of
those two options. 556
554
See July 29, 2013 order, pages 4-5.
See 5 Tr 762.
556
See 5 Tr 825.
555
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Thus, it does not appear that there are any due process issues raised by DTEE’s
implementation of the opt-out program, since customers receive notice and have an
opportunity to file a complaint with the MPSC. The RCG, however, should not infer from
this discussion that complaints to the Commission will be fruitful, since the courts have
upheld DTEE’s rights to install the new meters as a condition of receiving service. Note
that R792.10442, Rule 442 of the Commission’s rules of practice and procedure,
provides:
If the commission finds that a complaint does not state a prima facie case
or does not conform to these rules, it shall notify the complainant or the
complainant's attorney that the complaint is rejected, give the reasons for
the rejection, and return the complaint. Nothing in this rule prohibits a
complainant whose complaint has been rejected from amending and
refiling the complaint. Upon the filing of a formal complaint that conforms
to the provisions of R 792.10441 and states a prima facie case, the
commission, acting through its staff, will commence an investigation of the
matters raised in the complaint.
It should also be noted that in its order in Case No. U-17000, the Commission made
clear the opt-out charges are to be cost-of-service based.
c. Privacy Concerns
The RCG argues that the AMI program constitutes “state action”, violates
customers’ “reasonable expectation of privacy” in their home, and violates the 4th
Amendment of the U.S. Constitution and Article 1, section 11 of the Michigan
Constitution of 1963. Mr. Meltzer and Mr. Sheldon also express privacy concerns as
discussed above. First, it should be noted that the Court of Appeals has expressly
rejected the argument that the AMI program violates customers’ rights under the Fourth
Amendment of the U.S. Constitution:
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Finally, appellants Cusumano argue that an AMI meter, either transmitting
or non-transmitting, is in fact a surveillance device that measures not only
total consumption of electricity but also when that electricity is used, and
what types of electrical devices are being used at any given time.
Appellants assert that it is virtually certain that law enforcement agencies
will access this data, and that such access would constitute an
unreasonable warrantless search under the Fourth Amendment to the
United States Constitution. We disagree.
We review for plain error an unpreserved constitutional issue. In re
Application of Int’l Transmission Co, 304 Mich App 561, 567; 847 NW2d
684 (2014).
The Fourth Amendment to the United States Constitution reads:
The right of the people to be secure in their persons, houses,
papers, and effects, against unreasonable searches and seizures,
shall not be violated, and no Warrants shall issue, but upon
probable cause, supported by Oath or affirmation, and particularly
describing the place to be searched, and the persons or things to
be seized.
The Fourth Amendment applies only to government actions, and is not
applicable to a search performed by a private actor not acting as an agent
of the government. See People v McKendrick, 188 Mich App 128, 141;
468 NW2d 903 (1991). Appellants have not established that the
installation of either a transmitting or a non-transmitting AMI meter
constitutes a search, or that even if it did, that DTE acts as an agent of the
government.557
Second, as DTEE argues, the Commission and the company have put significant
privacy protections in place. DTEE’s tariff now precludes any use of the data collected
from a customer for non-utility purposes without that customer’s express consent. See
Rule C14, Sheet Nos. 74.00-74.03. There are limits on DTEE’s ability to disclose the
information to others, including the requirement for a warrant or court order before
information is provided to law enforcement agencies. Mr. Sheldon’s review of the
Commission’s decision in Case No. U-17102 led him to conclude that the privacy policy
557
In re Application of Detroit Edison Company To Implement Opt Out Program, unpublished opinion per
curiam of the Court of Appeals, issued February 19, 2015 (Docket Nos. 316728, 316781), pages 8-9.
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is vague and unenforceable, arguing that the definition of “primary purpose” gives too
much discretion to the utilities.558 But he has not specified why he believes it gives too
much discretion to the utilities.
Mr. Shelton also argues that the non-transmitting meters do not address privacy
concerns because the information can be downloaded to the utility by other means.
While the utility intends to collect the hourly load data from these meters, the privacy
protections in place limit the use of that information as discussed above.
Mr. Melzer argues that data breaches are commonplace. While it is undeniably
true that the AMI meters collect more detailed energy usage information than their
predecessor meters, and while it is legitimately of great importance to keep this data
confidential, there is no showing on this record that the security concerns surrounding
this information rise to the level of concern required for financial information, which is a
well-known target of identity thieves. Note that Mr. Sitkauskas testified that DTEE is not
collecting the full range of detailed consumption data the meters are capable of
recording, but is only collecting hourly meter reading, unless the customer requests the
more detailed information or is on a rate that requires it.559 Mr. Sitkauskas testified:
The data that we receive from a customer’s meter is encrypted whenever
it comes across the network. When it is stored, there are people in the
Company that only by need have access to that data.
I take myself for example. I do not have access to customer service data
nor the meter management data. I have to go to somebody who is
qualified and skilled to get into that data to understand it.560
He also explained that DTEE has a cyber-security group that works to keep the data
secure.
558
See Sheldon brief, page 5.
See, e.g., Exhibit RCG-6, page 19.
560
See 5 Tr 771.
559
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d. Health
The primary concern raised by Mr. Sheldon and Mr. Meltzer, and Mr. Sheldon’s
witness Dr. Carpenter, is with the radiofrequency (RF) electromagnetic radiation emitted
by smart meters.
DTEE and Staff argue that the Commission has considered the
potential health effects of the AMI meters, and determined that any health risk is
minimal. The Court of Appeals held in its February 19, 2015 opinion that the
Commission could rely on the Staff report adopted in Case No. U-17000:
Ratemaking is a legislative rather than a judicial function. For that reason,
the doctrines of res judicata and collateral estoppel do not apply in a strict
sense. Nevertheless, “issues fully decided in earlier PSC proceedings
need not be ‘completely relitigated’ in later proceedings unless the party
wishing to do so establishes by new evidence or a showing of changed
circumstances that the earlier result is unreasonable.” In re Application of
Consumers Energy Co for Rate Increase, 291 Mich App 106, 122; 804
NW2d 574 (2010), quoting Pennwalt Corp v Public Serv Comm, 166 Mich
App 1, 9; 420 NW2d 156 (1988).
The PSC adopted the Staff report in Case No. U-17000; that report
examined literature that addressed health concerns surrounding AMI
meters and concluded that any such concerns were insignificant. In the
instant case appellants sought to introduce testimony regarding their own
concerns with AMI meters. However, that testimony was excluded
because the ALJ determined that it was beyond the scope of this
proceeding. The PSC affirmed that finding. Appellants have not shown
that new evidence or any changed circumstances render that decision
unreasonable. In re Application of Consumers Energy Company, 291 Mich
App at 122. The PSC’s order is thus not unlawful or unreasonable.561
In relying on the Staff Report, the Commission recognized that the Federal
Communications Commission (FCC) has determined that this technology is safe.562
561
In re Application of Detroit Edison Company To Implement Opt Out Program, unpublished opinion per
curiam of the Court of Appeals, issued February 19, 2015 (Docket Nos. 316728, 316781), page 8.
562
Mr. Sheldon and the RCG object to the Staff Report because Case No. U-17000 was not a contested
case. Mr. Sheldon argues that the Commission can only make findings of fact through a contested case
or rulemaking. But this is incorrect. The Commission has broad investigatory powers, including authority
under MCL 460.56, and can make findings of fact to inform its discretion and guide its choice among
competing policies. The Staff Report is also admissible evidence.
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This is critical. It is not the Commission that has the front-line responsibility to make
these determinations or to apply a precautionary principle. The Staff Report adopted in
Case No. U-17000 states that the Federal Communications Commission (FCC) is
charged with regulating communications by radio, television, satellite, and cable within
the United States and its territories:
The FCC is responsible for providing licenses for RF emissions. The FCC
regulations cover matters relating to public health and safety and have
been designed to ensure that the levels of RF emissions that consumers
are exposed to are not harmful.563
The FCC acknowledges its jurisdiction. In its March 27, 2013 First Report and Order,
Further Notice of Proposed Rule Making, and Notice of Inquiry, the FCC recognizes that
it has jurisdiction under the National Environmental Policy Act of 1969 and has been
monitoring and issuing rules regarding RF exposure for decades.564 In has also
explained its further jurisdiction as follows:
The Commission's authority to adopt and enforce RF exposure limits
beyond the prospective limitations of NEPA is well established. See, e.g.,
Section 704(b) of the Telecommunications Act of 1996, Pub. L. No. 104104 (directing Commission to “prescribe and make effective rules
regarding the environmental effects of radio frequency emissions” upon
completing action in then-pending rulemaking proceeding that included
proposals for, inter alia, maximum exposure limits); 47 U.S.C. §
332(c)(7)(B)(iv) (recognizing legitimacy of FCC's existing regulations on
environmental effects of RF emissions of personal wireless service
facilities, by proscribing state and local regulation of such facilities on the
basis of such effects, to the extent such facilities comply with Commission
regulations concerning such RF emissions); 47 U.S.C. § 151 (creating the
FCC “[f]or the purpose of regulating interstate and foreign commerce in
communication by wire and radio so as to make available, so far as
possible, to all the people of the United States, ... a rapid, efficient, Nationwide, and world-wide wire and radio communication service, ... for the
purpose of [inter alia] promoting safety of life and property through the use
563
See Staff Report, page 8.
See, In the Matter of Reassessment of Federal Communications Commission Radiofrequency
Exposure Limits and Policies, 28 FCC Rcd 3498, 28 FCCR 3498, ET Docket Nos. 13-84, 03-137, ¶205
(“Notice of Inquiry”).
564
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of wire and radio communications”). See also H.R. Rep. No. 204(I), 104th
Cong., 1st Sess. 94 (1995), reprinted in 1996 U.S.C. C.A.N. 10, 61 (1996)
(in legislative history of Section 704 of 1996 Telecommunications Act,
identifying “adequate safeguards of the public health and safety” as part of
a framework of uniform, nationwide RF regulations); Farina v. Nokia, Inc.,
625 F.3d 97 (3d Cir. 2010) (affirming that FCC regulation of cell phone RF
emissions — including those rules addressing health effects — preempted
state lawsuit dependent on claims of adverse health effects from FCCcompliant cell phone RF emissions), cert. denied,132 S.Ct. 365 (2011). In
Farina, 625 F.3d at 130, the U.S. Court of Appeals for the Third Circuit
stated that “[p]rotecting public safety [with RF emissions regulation] is
clearly within the mandate of the FCC,” observing that “although the FCC's
RF regulations were triggered by the Commission's NEPA obligations,
health and safety considerations were already within the FCC's mandate,
47 U.S.C. §§ 151, 332(a), and all RF regulations were promulgated under
the rulemaking authority granted by the [Communications Act of 1934, as
amended].” Id. at 128. The court also recognized that in promulgating RF
exposure standards, the Commission was not only acting in accordance
with its public safety mandate, but also in accordance with its mandate to
ensure the rapid development of an efficient and uniform nationwide
communications system: “In order to satisfy both its mandates to regulate
the safety concerns of RF emissions and to ensure the creation of an
efficient and uniform nationwide network, the FCC was required to weigh
those considerations and establish a set of standards that limit RF
emissions enough to protect the public and workers while, at the same
time, leave RF levels high enough to enable cell phone companies to
provide quality nationwide service in a cost-effective manner.” Id. at
125.565
The FCC explained that it continues to monitor information regarding safe exposure
limits, and opened yet another inquiry to review exposure limits:
The first Commission Notice of Inquiry (1979 Inquiry) on the subject of
biological effects of radiofrequency radiation occurred in 1979 in response
to the need for the Commission to implement the National Environmental
Policy Act (NEPA) of 1969. The most recent proceeding inviting comment
on exposure limits was initiated in 1993 and culminated in a Report and
Order in 1996, which resulted in our present limits. The instant rulemaking
that is underway, initiated with the 2003 Notice, specifically excludes
consideration of the exposure limits themselves. We continue to have
confidence in the current exposure limits, and note that more recent
international standards have a similar basis. At the same time, given the
fact that much time has passed since the Commission last sought
comment on exposure limits, as a matter of good government, we wish to
565
See, Notice of Inquiry, ¶ 103, n176.
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develop a current record by opening a new docket with this Notice of
Inquiry.566
Dr. Carpenter acknowledged that the smart meters meet FCC requirements,
although he disputed the adequacy of those requirements.567 Even given the FCC’s
assurances, the Commission has provided an opt-out option, so that DTEE is required
to provide customers with non-transmitting meters. As it was explained on the record,
the non-transmitting meters DTEE installs have the “radio transmitting” feature of the
smart meter turned off.
The intervenors also express a concern regarding the non-transmitting meter,
asserting that because it has a “switch mode” feature, it has the capability of causing
“power quality” issues that also may raise health concerns. First, there is no evidence
that the non-transmitting meters DTEE is installing have caused any such problem.
Staff characterizes the testimony in this regard as based on anecdotal reports. Second,
the “switch mode” feature appears to be a common feature of electric appliances since
the 1970s. Mr. Sitkauskas testified:
It is true that smart meters include a device called a switched mode power
supply (SMPS) but it must be pointed out that many common home
appliances and devices include and utilize SMPS. Examples include TVs,
radios, alarm clocks, digital displays on microwaves, refrigerators and
laptops and many other basic electrical appliances. In fact, switched mode
power supplies have been in use regularly since the early 1970s and are
readily found in homes and businesses. The utilization of SMPS is not
unique to smart meters and Mr. Carpenters concerns are not supportable
and do not warrant any action by the Commission. The Commission in its
prior orders has approved the utilization of AMI meters throughout DTE
Electric’s service territory and has approved an opt-out program for those
individuals who do not want a transmitting AMI meter at their residence.568
566
See, Notice of Inquiry, ¶ 205.
See 10 Tr 2521
568
See 5 Tr 746; also see Hudson, 8 Tr 2199.
567
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Essentially, the nature of the problem alleged to be harmful appears to be associated
with the existence of electrical wiring in a home. Dr. Carpenter testified:
It is my understanding that all smart meters have something called a
“switched mode power supply” in them to convert 120 volts ac to a lower
dc voltage to operate the electronics. There have been many reports from
multiple parts of the United States that these power supplies are causing
low frequencies in the kilohertz range to travel through the wiring of a
home or business. This phenomenon is called a power quality problem by
engineers but is also frequently called the “dirty electricity” problem by non
engineers. There have been many reports that this phenomenon
produces adverse health effects similar to those produced by the radio
frequency transmitters.569
While this is an example of what Staff characterized as anecdotal information, Dr.
Carpenter’s chief concern with “dirty electricity” seemed to be attributable to the
transmitting meters causing “high frequency” and “pulse” interference:
So the reason that pulse radio frequency is of such concern is that while
there aren’t that many studies specifically looking at health effects of
Smart Meters, there’s enormous number of rather anecdotal reports of
people becoming ill after a Smart Meter was installed in their house, and
that conclusion that there’s something particularly harmful about the high
frequency pulses is consistent with the Milham published reports on dirty
electricity.570
As discussed above, there is no evidence on this record that the smart meters used by
DTEE cause power quality problems. Nonetheless, even Dr. Carpenter’s testimony
indicates that such problems would be categorically different with the non-transmitting
meters, which he associated only with low frequency power quality problems.
Additionally, as Mr. Sitkauskas testified, DTEE believes a benefit of the smart meters is
that they can detect power quality issues in people’s homes.571
569
See 10 Tr 2502.
See 10 Tr 2566-2567.
571
See 5 Tr 718-720.
570
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Given the overriding responsibility of the FCC and its substantial undertakings in
discharge of this responsibility, there is no basis on this record to conclude that the
Commission should reconsider its prior decision to approve the utility’s opt-out tariff.
e. Commercial customers
Mr. Sheldon also argues that commercial customers should be given an opt-out option:
Many of the 400 plus complaints that were logged in the U-17000 docket
were from professional practices such as doctor’s offices, dental practices,
and other health professionals who are concerned not only for their own
health but for the symptoms experienced by their electro-sensitive
patients. Interveners here raise the issue that leaving out businesses and
professional practices means that electro-sensitive persons entitled to
protection under the Americans with Disabilities Act will be severely limited
where they can be employed and may experience problems visiting health
care professionals or accessing stores, libraries and community
resources. Sheldon brief, page 8.
The Commission determined in Case No. U-10753 that there was insufficient evidence
that commercial customers wanted an opt-out program. Since this is a rate case, and no
commercial customers sought an opt-out option in this case, this PFD again finds no
basis for recommending that the Commission revise its earlier decision.
3. Opt-out fees
Based on the conclusions above that there is no basis on this record for the
Commission to revise the opt-out element of the AMI program, the next question is
whether the Commission should modify or eliminate the opt-out fees. Mr. Crandall
testified that to be consistent with the Commission’s decision in Case No. U-17053,
DTEE should have filed an update to its opt-out charges:
Customers who are coerced into paying the opt-out fees are not
comfortable with the validity accuracy and need for the “opt-out” charges.
Yet, DTEE has not substantiated the basis or justification for the “opt-out”
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fees in this filing, and its “opt-out” charges are unsupported. Providing
support and review of these costs was an expectation of the Commission,
as expressed in U-17053. 572
He testified that the mass premature removal of fully functioning meters leads to
additional costs being recovered from all customers, and characterized the opt-out
charges as “punitive”. In his view, customers who do not want to use advanced meters
are not the causers of new costs, and are saving the distribution system capital costs by
avoiding the capital costs of the new meters. He acknowledged Mr. Sitkauskas’s
testimony that DTEE intends to replace all customer meters with the AMI meters, with
the transmit switch off for customers choosing to opt out.573
In its reply brief, the RCG reiterates its argument that no cost of service study
was presented in this case to support the opt-out fees, asserting that opt-out customers
save the installation costs of the meters, and can mitigate manual meter reading costs
by allowing customers to self-report usage with only annual readings by the utility.574
The RCG further argues that because the revenue collected from opt-out customers is
small in comparison to DTEE’s revenue requirement, DTEE’s primary purpose in
collecting the fees must be to discourage customers from selecting this option.575
Staff witness Mr. Isakson addressed the opt-out charge in his testimony. He
testified that Staff recommends that the Commission wait until deployment is complete
to revise the charge. He testified that the biggest uncertainty is the number of customers
opting out of the program: he explained that many of the costs are fixed costs, so the
more customers opt out, the lower the charges. He also explained that the level of
572
See 8 Tr 2258.
See 8 Tr 2264-2265.
574
See RCG reply brief, pages 6-7.
575
See RCG reply brief, pages 7-8.
573
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charges can influence the number of customers choosing to opt out, making it difficult to
project the number of customers to spread the fixed costs among. He proposed that
DTEE be required to file to update the charge the sooner of its next rate case or six
months after the completion of the AMI installation.576
Staff witness Mr. Revere also addressed the opt-out charge in his rebuttal
testimony, explaining the cost of service principles underlying the opt-out fee in
response to Mr. Crandall’s assertions regarding cost causation:
Costs are considered to be caused by a customer if they are incurred to
serve that customer in a way that differs from other customers. In a cost of
service study, customers are grouped into classes of similarly situated
customers (e.g., customers served at secondary voltage levels). The
customers within these classes are considered to cause costs in a similar
way.
Sometimes, customers that would otherwise be considered similarly
situated, but cause the company to incur specific costs differently from the
other seemingly similarly situated customers, are not separated out into a
different class (e.g., lighting customers with more expensive ornamental
poles). In such a case, those costs which are incurred to serve a customer
or group of customers differently are specifically assigned to those
customers. The costs included in the monthly opt out charges are the
costs that will remain only to serve those customers who have chosen not
to receive the Company’s AMI meters once AMI rollout is completed.
Once rollout is complete, most customers will not require meter reading
expenses to be incurred by the Company. Only opt-out customers will
require meter readers and associated equipment and expenses, though
they are otherwise similarly situated to other customers. These costs are
then caused only by opt-out customers, and should rightfully be collected
from them. Other customers should not have to pay for costs caused
solely by opt-out customers, whether they are “new” or not, any more than
a lighting customer who does not choose a more expensive pole should
have to pay for the costs of those who do. The costs are offset by the
costs currently included in rates for AMI infrastructure and meter reading,
as discussed by Staff witness David W. Isakson. Therefore, the costs
“caused” by AMI should be of no direct concern to opt-out customers, as
they are not paying them.577
576
577
See 8 Tr 1983.
See 8 Tr 2076-2077.
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Mr. Sheldon acknowledges that the opt-out rates were set on the basis of Staff’s
higher estimated customer count and thus were lower than the rates proposed by DTEE
in Case No. U-17053. He also acknowledged that current customer counts are below
the levels used to set the opt-out rates in Case No. U-17053. He expresses a concern
that the current program is not a meaningful option for customers and therefore,
participation will remain low and fees will rise.
In rebuttal, Mr. Sitkauskas testified that DTEE is not seeking to revise the opt-out
charge and thus concluded that it was not required to support the charge in this case.
He cited his testimony in Case No. U-17053, indicating that DTEE “may” seek to modify
the charge in its next rate case.578 He testified that DTEE agrees with Staff’s
recommendation that the opt-out charge be reviewed when the program is fully
implemented. In its briefs, DTEE argues that the opt-out tariff is “settled law” and it is
not obligated to relitigate it in this case.579 DTEE also reviews the calculation of the optout charges, and cites Mr. Sitkauskas’s testimony and testimony from Case No.
U-10753 to show that the charges include credits reflecting the avoided costs of the AMI
program. DTEE also cites Staff’s testimony at 8 Tr 1988.580
The RCG objects to DTEE’s characterization of the opt-out charges as “settled
law,” citing the Commission’s decision in Case No. U-17087 involving Consumers
Energy that AMI issues are to be reviewed in each rate case: “On the same basis,
DTE’s opt-out charges are subject to redetermination in rate cases, and do not involve
‘matters of law.’”581
578
See 5 Tr 739.
See DTEE reply brief, page 76.
580
See DTEE reply brief, page 75.
581
See RCG reply brief, page 10.
579
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Staff argues that it reasonably recommends that the opt-out charges be
reconsidered at the completion of the AMI installation. Staff also argues that the record
does not support RCG’s argument that opt-out customers are subsidizing other
customers:
In support of its claim, RCG relies solely on a Company discovery
response, Exhibit RCG-6, page 10, that Staff believes to be in error, given
the AMI offset approved in U-17053. (8 TR 1988) RCG’s claim that optout customers subsidize the AMI program should, therefore, be
rejected.582
Responding to the RCG’s lengthy quotation from Judge O’Connell’s opinion, cited
above, Staff argues that the Court of Appeals remand in Case No. U-17087 is not
applicable to this case, noting that the Court of Appeals remand in that case addressed
Consumers Energy’s opt-out tariff, while in another case, the Court of Appeals affirmed
the Commission’s order establishing the opt-out tariff for DTEE.
As discussed above, the Commission established these fees based on the
contested case record in Case No. U-17053, after determining in Case No. U-17000
that there should be a cost-based opt-out fee. Because the fee was set on the basis of
15,500 customers opting out, reducing the per-customer assignment of fixed costs,
revising those costs when the current number of opt-out customers is below that level
would result in an increased opt-out rate. Since DTEE has not sought an increase, and
since no party has provided the complete basis on which a revised charge can be
calculated, this PFD declines to recommend a revised charge. Instead, this PFD
recommends that the Commission adopt Staff’s proposal, requiring DTEE to file an
application for review of the charge at the earlier of its next rate case or six-months after
the installation of the AMI meters.
582
See Staff reply brief, page 16.
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4. Access tariff
The RCG also asks the Commission to revise the tariff provision that grants
DTEE employees reasonable access to customer premises. The current access tariff
provision C5.4 (Access to Premises) is quoted above. This language has been in place
at least since the Commission’s February 3, 1975 order in Case No. U-4570. The
revised language the RCG requests in Exhibit RCG-4, also restated in the RCG’s brief,
would eliminate the introductory phrase: “As a condition of taking service.” While the
RCG argues that the access tariff is inappropriate, and does not protect customers who
refuse to allow AMI meters to be installed on their property from “an unwarranted cutoff
of service,” as discussed above, there is no evidence that DTEE is failing to provide
notice. Moreover, R 460.137 permits a utility to shut off service if “[t]he customer has
refused to arrange access at reasonable times for the purpose of inspection, meter
reading, maintenance, or replacement of equipment that is installed upon the premises,
or for the removal of a meter.” The revision proposed by the RCG would not alter
DTEE’s rights under Commission rules.
IX.
REVENUE DEFICIENCY SUMMARY
Based on the rate base, cost of capital, and adjusted net operating income as
presented above, DTEE’s revenue deficiency for the projected test year is estimated to
be $159 million, as shown in Appendix C, attached.
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X.
COST OF SERVICE
DTEE presented a cost of service study sponsored by Mr. Heiser.
Staff
presented a cost of service study presented by Mr. Putnam. Several other witnesses
testified regarding cost of service allocations, including Messrs. Selecky, Zakem and
Townsend.
A.
Production Cost Allocation
Following the Commission’s June 15, 2015 order in Case No. U-17689, it
appears that many of the cost allocation issues presented in the parties’ testimony in
this case have been resolved.
DTEE continues to advocate for a 4CP-100 method of
production cost allocation. Although Mr. Selecky filed testimony addressing this topic,
ABATE does not argue for this allocation method in its briefs, nor does it argue for the
fuel adjustment Mr. Selecky recommended to offset any production cost allocation
method with an energy component.
DTEE relies on Mr. Heiser’s testimony, filed prior to and adopted a week after the
Commission issued its order in Case No. U-17689. In its reply brief,583 DTEE
acknowledges that the Commission approved a 4CP 75-25 method for allocation
production costs in Case No. U-17689, but argues: “DTE maintains that its method is
better still than the method the Commission adopted.”584 DTEE acknowledges that the
reasons it presents in this case are the same reasons it presented in Case No.
U-17689. Kroger also argues that the Commission should adopt the findings made its
583
584
See DTEE reply brief, pages 113, 114-117.
See DTEE reply brief, page 115.
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Order in Case No. U-17689, indicating its belief that the Commission’s findings “fairly
resolve several cost-of-service issues that Kroger addressed in its Direct Testimony.”585
This PFD finds that the Commission has recently addressed the appropriate
production cost allocation method and determined to use 4CP 75-25:
While the Commission recognizes that allocating production costs on the basis of
4CP 100 would minimize costs allocated to industrial customers, this proposal
fails to acknowledge the realities of why production costs for DTE Electric’s
system were incurred in the first place. Nor does 4CP recognize the significant
benefit to energy-intensive industrial customers of access to lower cost energy
provided by these base load generating units with high fixed costs.586
DTEE has presented nothing new in the case that should cause the Commission to
reconsider the decision it issued just 3 months ago, after a hearing held explicitly for the
purpose of considering cost allocation and rate design methods.
B.
Uncollectible Expense Allocation
Staff argues that the Commission should allocate uncollectible expenses on the
basis of distribution costs, rather than based on class write-offs. Energy Michigan’s
witness Mr. Zakem also testified on this topic. Staff’s brief very well sums up the issue:
The Company is proposing to allocate UAE based on net write-offs by
class. (4 TR 157.) The Commission approved a similar method in its Case
No. U-17689 June 15, 2015 Order. Staff proposes to allocate UAE on a
cost of service percentage basis. The NARUC manual accepts both the
Company’s proposed method and Staff’s preferred method:
Uncollectible Accounts . . . may be directly assigned to customer
classes. Some analysts prefer to regard uncollectible accounts as a
general cost of performing business by the utility, and would
classify and allocate these costs based upon an overall allocation
scheme, such as class revenue responsibility. (NARUC Electric
Cost Allocation Manual, page 103) [8 TR 1971.]
585
586
See Kroger brief, page 1.
See June 15, 2015 order, page 22.
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The Company believes that each major class causes uncollectible
expenses. (6 TR 897–898). On the contrary, UAEs are a general cost of
performing business as a utility, so they should be allocated based upon
an overall allocation scheme. Therefore, Staff chose an allocator that is
based on the cost to serve the distribution classes, which is consistent
with UAE allocators it supported in the past. (8 TR 1971.)
Staff agrees with Energy Michigan that customers create uncollectibles —
not customer classes. (8 TR 1901.) That is, the level of uncollectibles for a
class is not determined by the electric use characteristics of the class. Mr.
Zakem drives this point home when he said:
DTE wants to bill uncollectibles to the group of customers who use
energy in the same way as the group of customers who do not pay
their bills, simply because they use energy in the same way, e.g.,
for residential or commercial purposes. A residential customer is no
more responsible for – or the “cause” of – a residential customer
down the block who did not pay the DTE bill than is the grocery
store on the corner or the hospital a mile away. And vice versa. [8
TR 1902.]
Staff also agrees with Mr. Zakem that uncollectibles are overhead and
should be allocated accordingly:
The utility must recover uncollectible expenses. Uncollectibles are a
company-wide overhead, independent of the electric use of rate
classes. Thus the uncollectibles should be allocated in a general
and equitable way to all rate classes to be paid by all customers.
The current method of allocating uncollectibles to rate classes does
this. DTE has not provided any reason to change. [8 TR 1903.]
Granted, both Staff’s and the Company’s proposed methods are
legitimate. We simply view UAEs, and the way they cause costs,
differently. In Staff’s opinion, there is no direct relationship between a
given UAE and any customer class. Because Staff’s method reflects this
reality, Staff recommends that the ALJ and the Commission adopt Staff’s
recommendation and allocate UAEs based on the collective costs of
serving all customers.587
DTEE relies on Mr. Stanczak’s and Mr. Heiser’s testimony on this topic, as well as the
Commission’s June 15, 2015 order in Case No. U-17689.588 Although a review of the
record in Case No. U-17689 shows that this ALJ finds Staff’s arguments persuasive, the
587
588
See Staff brief, pages 65-66.
See DTEE brief, pages 129-131, citing Stanczak, 4 Tr 157-158, Heiser, 6 Tr 897-898.
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Commission ruled on this issue in that case, and no party has presented a new analysis
to call for reconsideration of that decision. On this basis, this PFD recommends that
DTEE’s proposed allocation be accepted as consistent with the Commission’s recent
decision in Case No. U-17689.
Energy Michigan also renews its recommendation made in Case No. U-17689
that uncollectible expenses be allocated to and collected from both distribution and
power supply charges. Mr. Zakem presented testimony on this. After the briefs in this
case had been filed, on September 23, 2015, the Commission issued an order
addressing Energy Michigan’s petition for rehearing in Case No. U-17689, and
reaffirming its earlier decision that uncollectible expense should not be allocated
separately to distribution and power supply charges. Since Energy Michigan did not
present new arguments on this topic in this case that the Commission did not have a
chance to consider in Case No. U-17689, this PFD concludes that the Commission has
definitively resolved this matter, and consistent with that resolution, its argument should
be rejected.
XI.
RATE DESIGN AND TARIFF ISSUES
Consistent with DTEE’s proposals in Case No. U-17689, and the Commission’s
order adopting voltage-based allocations for distribution costs, DTEE proposes to set
distribution rates by voltage class. No party opposes this proposal. Disputed issues
include a general dispute regarding appropriate monthly customer charges, and rate
design issues for various primary, commercial, and residential rate schedules.
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A.
General Issues
1. Customer charges
The parties dispute what the monthly customer charges should be. Mr. Heiser
presented an analysis in support of significant increases in the monthly customer
charges. He presented this analysis in his Exhibit A-13, Schedule F1.5. He testified that
he used a combination of direct assignment and allocations to determine customerrelated costs. He testified:
Customer-related costs include 100% of meter costs, overhead and
underground services, customer accounting costs, uncollectibles, and
customer service expenses. The customer-related portion of poles &
fixtures, overhead conductor, underground cable and conduit, and line
transformers was determined using the minimum-size distribution system
method. Finally, a share of distribution-related general plant, employee
pensions & benefits, A&G expense and taxes collected under the Federal
Insurance Contributions Act (FICA) is allocated to customer-related
distribution costs.589
Mr. Heiser also explained the “minimum-size distribution system method” he relied on
as follows:
The NARUC manual describes the minimum-size method as follows:
“Classifying distribution plant with the minimum-size method
assumes that a minimum size distribution system can be built to
serve the minimum loading requirements of the customer. The
minimum-size method involves determining the minimum size pole,
conductor, cable, transformer, and service that is currently installed
by the utility” (page 90)
***
I used figures from a DTE Electric internal report titled ‘A Look At The
Allocation Of Distribution Investment To Demand and Customer
Components’ to calculate costs associated with the minimum-size for
distribution accounts. This resulted in my allocating the following
percentages of costs to the customer charge for the following: 364 ‘Poles,
Towers, and Fixtures’ (82.3%), 365 ‘Overhead Conductors’ (81.2%), 366
589
See 6 Tr 899-901.
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‘Underground Conduit’ and 367 ‘Underground Conductors and Devices’
(62.8%), and 368 ‘Line Transformers’ (35%).590
He testified that the results of his analysis showed that monthly customer charges for
the residential class should be $25.74, customer charges for the commercial secondary
class should be $86.90, and customer charges for the primary class should be
$1,221.98 for customers taking service at primary voltage level, $1175.71 for customers
taking service at the subtransmission level, and $2,293.19 for customers taking service
at the transmission level. In his rate design, Mr. Bloch testified that he used a monthly
customer service charge of $375 for the primary class,591 Ms. Holmes testified that she
used a service charge of $16 for the commercial class,592 and Mr. Williams testified that
he used a service charge of $10 for the residential class,593 each citing principles of
gradualism for not adopting the full amount identified in Mr. Heiser’s study.
Several witnesses objected to Mr. Heiser’s analysis of the appropriate customer
charges. Mr. Revere testified that Staff based its monthly customer charges on an
analysis consistent with the Commission’s prior orders:
Staff calculated the customer-related costs appropriate to include in the
customer charge based on the guidance of the Commission orders in
MPSC Case Nos. U- 4771 and U-4331:
“Specific distribution plant such as meters and service drops used
exclusively for a given customer shall be treated as customer
related. All other distribution plant shall be treated as demand
related.” (MPSC Case No. U-4771, Order, Attachment A, Part One,
Page Two, May 10, 1976). “The maximum allowable service charge
would be limited to those costs associated directly with supplying
service to a customer. Only costs associated with metering, the
service lateral, and customer billing are includable since these are
costs that are directly incurred as the result of a customer’s
590
See 6 Tr 900.
See 4 Tr 557.
592
See 6 Tr 962.
593
See 6 Tr 1111.
591
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connection to the gas system.” (MPSC Case No. U-4331, Order, p.
30, January 18, 1974).
While U-4331 was a gas case, the same principles apply to electric
distribution utilities. Though costs other than those listed in the orders are
fixed, they do not vary with the number of customers, and are not incurred
directly as a result of any given customer’s connection to the system.
Therefore, their inclusion in the customer charge is inappropriate. In
addition, Staff’s calculation is more reflective of the marginal cost of
attachment, and therefore more economically sound.594
Mr. Revere presented Exhibit S-12 to show the results of his analysis, and testified that
Mr. Isakson and Ms. Rivera used these calculations to design rates for the industrial,
commercial and residential tariffs.
Mr. Isakson testified that he adopted DTEE’s rate
design for the primary class, which includes the $375 monthly customer charge. He
recommended no change to the monthly customer charge for commercial secondary
customers, comparing the current rate of $8.78 per month to the $8.70 in Mr. Revere’s
analysis.595 Ms. Rivera similarly testified that Staff is recommending no change in the
$6 per month residential customer charge.596
Mr. Rábago testified extensively regarding the use of monthly customer charges,
focusing particularly on the commercial and residential customer classes. He rejected
Mr. Heiser’s brief explanation for his cost analysis, testifying that DTEE is proposing to
collect $93 million of its proposed increase for residential customers through the
customer charge:
The decisions about how to allocate class costs to rates through rate
design involve important concerns relating to affordability, price signals,
and congruence with state energy policy. The Company’s foundation for
its proposal is inadequate, and in light of the significant repercussions for
customers and the State generally, and given the novelty of the
Company’s proposal, it is therefore neither just nor reasonable. In my
594
See 8 Tr 2068.
See 8 Tr 1978.
596
See 8 Tr 1995.
595
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opinion, the Company has failed on both its burden of production and its
burden of proof. 597
Mr. Rábago testified that customer charges are regressive, disproportionately affecting
low usage customers, who are often low-income customers, customers on fixed
incomes, students, and customers who have aggressively pursued green building and
energy efficiency.598 He also testified to the importance of volumetric charges in sending
accurate price signals:
It is appropriate because of the price signal function of properly designed
rates. Properly designed rates reflect properly allocated costs and send
signals for efficient consumption in the future. Sunk fixed costs, the focus
of the Company’s concern in its customer charge proposal, can be
reflected in either the fixed charge or a volumetric charge. An efficient
price signal relating to future fixed costs can only be communicated with a
volumetric charge. That is why a volumetric charge is the optimal rate
design in this case. 599
Mr. Rábago testified that fixed customer charges create a powerful incentive against
investment in energy efficiency. He testified that fixed charges affect commercial
customers in the same way. He recommended that the costs DTEE proposes to
allocate to fixed customer charges should be allocated to volumetric rate elements
unless and until DTEE demonstrates the reasonableness of its proposed rate design in
light of the potential adverse impacts, and after considering the impacts of alternatives.
Mr. Jester characterized fixed charges as “more like a tax on income than a price
for services,” and urged the Commission to be wary of increases in such charges.
600
He presented an economic analysis in Exhibit MEC-2. He rejected Mr. Heiser’s view of
the costs that should be reflected in the customer charge:
597
See 7 Tr 1781.
See 7 Tr 1782-1784.
599
See 7 Tr 1784, emphasis in original.
600
See 7 Tr 1621.
598
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The economically sound principle for establishing a fixed monthly charge
per customer is to include only those costs caused by the customer having
access to the system. To see that this does not include the distribution
system costs allocated by the minimum-size distribution method one only
needs to consider the effects of adding or decommissioning a customer
along an existing distribution line. Adding a building and service on a
vacant lot in a developed area already served by distribution does not add
to the poles, and fixtures, overhead conductor, underground cable and
conduit, and line transformers in the distribution system. It only adds a
service drop, meter, customer account, servicing thereof, and perhaps a
distribution transformer. Similarly, if a building is abandoned and
demolished and service is terminated, there is not a reduction in the
minimum-size distribution assets that are required.
Properly considered, the minimum-size distribution system is a joint and
shared cost attributable to all customers in an area and cannot be paid for
through marginal costs. As I argued in U-17689, economic theory then
tells us that the way to allocate such costs with minimum harm to the
welfare of the utility’s customers is by Ramsey-Boiteux pricing, which
would dictate that these costs should be assigned to customers within
each voltage level as a percentage markup over energy costs.
I therefore recommend that the Commission adhere to past practice and
limit customer access charges to the cost of service drop, metering,
account maintenance, and distribution transformers.601
Mr. Townsend testified regarding the monthly customer charge for primary
customers served at the primary voltage level. He objected to Mr. Heiser’s reliance on
a study from 1979 as the basis for his minimum size analysis, presenting the study in
Exhibit KC-3. He testified that he recommended a monthly customer charge for primary
voltage-level customers of not more than $100; in the alternative he testified that the
charge should not be increased from its current level of $275.
In his rebuttal testimony, Mr. Heiser took issue with Staff’s analysis, referring to
the NARUC Manual to support his argument Mr. Revere did not include in his analysis
all costs classified as customer-related or customer-and-demand related. Mr. Heiser
also presented alternate calculations, shown in Exhibit A-24. First, he testified that a
601
See 7 Tr 1622.
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technical correction should be made to Staff’s analysis in Exhibit S-12 because Staff
picked up an error in Mr. Heiser’s original numbers that Mr. Heiser subsequently
corrected:
Subsequent to filing this case, I became aware that account 369B
underground services investment was inadvertently included in the
calculation of the meter-related costs instead of AMI meter investment.
The Company filed revised exhibits in this docket on May 20, 2015 to
amend its calculation. However, the basis that Staff used in calculating
customer-related costs did not include this correction. I have revised
Staff’s calculation to remedy this situation. Exhibit A-24, Schedule N-1
“Technical Correction to Staff’s Exhibit S-12” shows the results of
replacing account 369B investment in the calculation of meter-related
costs with the correct AMI investment. 602
In addition to making this revision in his Schedule N1, he presented Schedule N2
to reflect the cost of substations required to service primary customers served at the
subtransmission or transmission level, which Mr. Heiser testified should have been
included in Staff’s analysis to fully reflect marginal costs.603 He also testified to the
following cost items:
Using Staff’s definition of customer-related, there are additional direct
costs associated with employees that perform the work that is accounted
for in USofA accounts 586 Meter Expenses, 597 Maintenance of Meters,
902 Meter Reading, and 903 Customer Records Expense that should
have been included. Staff did not include the associated social security
taxes, and pension and benefits for these employees. These are marginal
costs that the Company would not incur if the customer-related services
ceased to be provided. In addition, the employees require office space
and equipment (included in General Plant) with which to perform their jobs
and there are costs associated with support staff to provide services such
as payroll and information technology support (included in A&G). These
costs would be marginal in the longer term as they would not immediately
be reduced if the customer-related services ceased to be performed.
Nonetheless, the office space and equipment as well as support staff are
necessary for the continued ability to provide customer-related services
and should be included in the customer-related cost basis. Failure to
602
603
See 6 Tr 504-505.
See 6 Tr 908.
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classify these costs as customer-related results in the overstatement of
demand related distribution costs.604
Mr. Heiser presented Schedule N2 to show the effect on Staff’s customer cost analysis
of incorporating these items, including the substation costs. Schedule N2 shows
customer costs of $8.23 for residential customers, $12.28 for commercial secondary
customers, $112.82 for primary customers served at the primary voltage, $279.37 for
customers served at the subtransmission voltage, and $339.81 for customers served at
transmission voltage. He also reports a $463.94 cost for “total primary” and $23.27 for
lighting customers. Mr. Heiser also addressed Mr. Townsend’s analysis briefly,
essentially arguing that Mr. Townsend’s point regarding the appropriate order for
determining customer costs has exceptions, and discussing the allocation of meter
costs as an example.605
Ms. Holmes addressed Mr. Rábago’s testimony in the context of the commercial
customer charge she recommended, arguing that DTEE’s proposal increases the
portion of the total bill due to the fixed serve charge from 4.7% to 8.2%, presenting a
chart in her testimony to show the calculations.606 Mr. Williams presented the same
comparison in his rebuttal testimony, testifying that DTEE’s proposal increases the
portion of the bill due to the fixed serve charge from 7% to 10%, also presenting a
chart.607
In its brief, DTEE argues that its recommended customer charges should be
adopted. It addresses Mr. Rábago’s testimony in footnotes, citing Ms. Holmes and Mr.
Williams’s rebuttal. DTEE’s brief also mentions Mr. Heiser’s testimony, including his
604
See 6 Tr 909.
See 6 Tr 911.
606
See 6 Tr 981-982.
607
See 6 Tr 1135.
605
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revisions to Exhibit S-12, but asserts that DTEE supports the customer charges
developed in Exhibit A-13.608 In addition, DTEE states:
For purposes of completing this technical correction discussion, however,
if the Commission does not accept the customer cost study supported by
Exhibit A-13 Revised, Schedule F1.5, and instead adopts Exhibit A-24,
Schedule N-1 (Technical Correction to Staff Exhibit S-12), then the
Company proposes a primary service charge of $430.31, a commercial
service charge of $10.15, and a residential service charge of $7.00. If the
Commission adopts Exhibit A-24, Schedule N-2 (Restatement of Staff
Exhibit S-12 including Customer Service Employee Benefits and
Resources), then the Company proposes a primary service charge of
$463.94, a commercial service charge of $12.25, and a residential service
charge of $8.00 (6 T 910, 979-80, 1131).609
In its brief, Staff acknowledges the error giving rise to Mr. Heiser’s correction in
Schedule N1 of Exhibit A-24, but argues:
DTE Electric and Staff both mistakenly included some costs in their
customer-related cost calculations — for example, both inadvertently
included an underground services investment rather than the smart meter
investment. (6 TR 904.) The Company filed revised exhibits in this docket
on May 20, 2015 to amend its calculation. (Id.) A correction was obviously
required; however, Staff was unable to verify that the Company performed
the correction properly. Therefore, Staff is maintaining its original position
regarding customer charges for the secondary classes.610
Staff also does not accept Mr. Heiser’s addition of other costs in his Schedule N2 of
Exhibit A-24:
The Company also claims that Staff improperly excluded the following
costs:
586 Meter Expenses, 597 Maintenance of Meters, 902 Meter
Reading, and 903 Customer Records Expense... and the
associated social security taxes, and pension and benefits for these
employees. [6 TR 909.]
While Staff does not necessarily disagree with the addition of these costs,
the Company’s Exhibit A-24, Schedule N-2 did not include enough detail
608
See DTEE brief, page 125.
See DTEE brief, pages 124-125; also see DTEE reply brief, pages 113-114.
610
See Staff brief, page 82.
609
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to justify including them. Beyond that, Staff is unable to verify that the
costs claimed by the Company were associated with the customer
attachments identified on the exhibit.611
Staff also addresses Mr. Heiser’s rebuttal testimony, including his reliance on a cost
allocation discussion in the NARUC Manual, which Staff argues is erroneous and
ignores the specific guidance in the NARUC Manual regarding customer charges.612
Staff explains:
[T]he Company misunderstands Staff’s position, arguing that under Staff’s
definition of customer-related costs, additional customer-related costs
should be included in the customer charge. (6 TR 908–909.)
Unfortunately, the Company confuses Staff’s argument for what costs
should be included in the customer charge and what Staff believes should
be classified as customer-related. (Id.) These are distinct issues, and here
Staff is only discussing former issue, not the latter.613
In its brief, ELPC argues that monthly commercial and residential charges should
not be raised, arguing that DTEE failed to justify the need to increase the monthly
customer charge, and did not show that its proposed increases will not be more harmful
by reducing incentives for energy efficiency and precluding especially low income
customers from taking steps to control their consumption. ELPC further argues that
DTEE’s cost study confuses “fixed costs” with “sunk costs”, quoting Mr. Rábago’s
testimony at 7 Tr 1785.
ELPC also cites cross-examination of Mr. Williams regarding elements of DTEE’s
calculation, arguing that Mr. Williams could not say whether costs DTEE seeks to
include in its customer charge are sized to meet peak demand. In its reply brief, ELPC
argues:
611
See Staff brief, page 83.
See Staff brief, pages 82-83.
613
See Staff brief, page 83.
612
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DTE requests an increase in its monthly service charges for most
commercial customers from $8.78 per month to $16.00, and for all
residential customers from $6.00 to $10.00. These increases constitute
an 82% increase in the fixed service charge for commercial customers
and a 60% increase for residential customers. Hence, while this issue is
just one of many in a big rate case, the Commission should not underplay
its importance as DTEE attempts to do.
For both the commercial and residential increases the Company uses one
sentence of its Initial Brief to defend its charge, “The proposed increase in
the charge better reflects cost causation, but is limited in the interest of
gradualism.” DTE Brief at 135, 141. Additionally, in similar footnotes
(#114 and #118) DTE disputes Mr. Rabago’s testimony that the increase
will deter commercial and residential customers from investing in energy
efficiency. Id. By giving such short shrift to the customer charge issue,
DTE ignores the fact that it has the burden of proof in rate cases.
Consumers Power Co., U-4717, WL 448999 (Jan 23, 1978).614
In response to DTEE’s argument that customers will still pay a significant portion of their
total bill in variable charges, ELPC cites Mr. Rábago’s testimony explaining that DTEE’s
proposed customer charge for residential customers is equivalent to 337 kWh of energy
purchases the customer cannot avoid.615 ELPC also argues that impact of the fixed
charge is economically regressive, citing Mr. Rábago’s testimony that low-use
customers are often low and moderate income customers, and summarizing data from
Exhibit A-14, Schedule F4 to show that the impact of DTEE’s proposal on a percentage
basis is much greater on low-use customers than on high-use customers.
In their brief, M/N/S similarly argue that DTEE’s proposed increases to the fixed
customer charge are regressive, provide disincentives for energy efficiency, and send
inaccurate price signals.616
614
See ELPC reply brief, page 1.
See ELPC reply brief, page 2.
616
See M/N/S brief, pages 68-81.
615
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Kroger argues based on Mr. Townsend’s testimony that Mr. Heiser’s analysis
included many inappropriate elements. Relying on Mr. Townsend’s Exhibit KC-4, Kroger
argues that the primary voltage customer charge should not exceed $100 month.
Kroger further argues that setting the service charge significantly above customerrelated costs causes smaller customers to be overcharged and subsidize larger
customers on the rate schedule.
DTEE argues in its reply brief that it designed rates to benefit high load factor
customers:
DTE Electric disagrees because it designed rate D11 to benefit customers
that perform at higher load factors by using a rate structure with lower
energy charges and higher demand charges. The delivery charges are
based on the DTE Electric’s proposed voltage level distribution charges,
as discussed in DTE Electric’s Initial Brief and above.97 The power supply
energy charges are set close to the Company’s base fuel and purchased
power rate. The on-peak and off-peak energy rate differential is the same
as the current D6 rate. With the D11 rate class and the Company’s
proposed rate design, all primary customers will have the same
opportunity to reduce their energy rate by improving their load factor (4 T
554-55).617
Citing Mr. Bloch’s testimony identifying DTEE’s choice of customer charge for all
primary customers, DTEE accuses Kroger of “attempting to selectively manipulate”
DTEE’s overall rate design.618
This PFD finds that DTEE has not established a sound basis for increasing the
monthly customer charges for the residential and commercial customers. Mr. Heiser’s
analysis in Exhibit A-13 was thoroughly discredited by several witnesses, including Mr.
Revere, Mr. Rábago, Mr. Jester, and Mr. Townsend. His revisions to Staff’s Exhibit
S-12, in his Schedules N1 and N2 were not presented in sufficient time to be well-vetted
617
618
See DTEE reply brief, pages 121-122.
See DTEE reply brief, page 123.
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by Staff, but they do not produce a significantly different result for residential or
commercial customers. The larger results in Schedule N2 show only $8.23 and $12.28
for residential and commercial customers respectively, which is much closer to Staff’s
recommendation to freeze the customer charges for these customers than to DTEE’s
initial claim that the charges should be $25.74 for residential customers and $86.90 for
commercial customers, but for principles of gradualism. DTEE also did not provide any
meaningful response to Mr. Rábago’s analysis of the regressive and deterrent effects of
higher customer charges.
Turning to Kroger’s request regarding the primary voltage rate within the primary
class, a review of Mr. Hieser’s Exhibit N2 again shows that with all the revisions
included in that exhibit, a customer charge for the primary voltage customer should not
be on the order of $112.82. Even making some allowance for the need to consider the
resulting energy and demand charges, DTEE has not justified an increase in the
customer charge for the primary voltage customer. This PFD recommends that the
monthly customer charge for the primary voltage customer be revised to $275, with no
change to DTEE and Staff’s recommended customer charge of $375 per month for the
subtransmission and transmission-level customers.
2. Peak pricing and time-of use rates
Mr. Revere presented Staff’s recommendation that calls for DTEE to improve its
rate design for both capacity and energy charges to reflect appropriate price signals be
addressed when DTEE has completed its AMI roll-out or in its next rate case:
Staff recommends that the Commission require the Company to file a
proposal, either in their next rate case or a separate proceeding
commenced at the completion of its Advanced Metering Infrastructure
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(AMI) rollout, to incorporate on-peak/off-peak and seasonal differences in
power supply costs, both energy and capacity, into their rate design. As
the arguments regarding rate design and production cost allocation in the
instant case and the Company’s 2014 PA 169 case (MPSC Case No. U17689) point out, price signals are extremely important in order for
customers to make informed decisions based on the price of power as it
varies temporally, and for customers to bear the costs the Company incurs
as a result of those decisions.
In its June 15, 2015 order in Case No. U-17689, the Commission directed DTEE as
follows:
DTE Electric shall by January 1, 2016 revise its tariffs so that TOU[time-ofuse] rates and dynamic peak pricing are available to all customers who
have had AMI for at least one year and who wish to opt in. TOU rates
could potentially mitigate the effects on residential customers resulting
from the changes in cost allocation as a result of this proceeding and
could help residential customers better manage their electric costs. See
order, page 35.
MEC/NRDC presented Mr. Jester’s testimony in this case reviewing and
referencing the recommendations he made in Case No. U-17689. In their brief, M/N/S
argue:
MEC and NRDC submitted testimony in this case from Douglas Jester
recommending the revision and broader adoption of dynamic peak pricing
and time of use rates. The Commission also granted partial relief on those
recommendations in its June 15th Order in Case No. U-17689. Again for
purposes of this initial brief, MEC and NRDC do not intend to reargue the
dynamic peak pricing and time of use issues decided in that case.
However, we reserve the right to reply to other parties, and to take other
positions as appropriate.619
No party argued that the Commission should revise its June 15, 2015 order in Case No.
U-17689 on this issue, so this PFD considers it resolved.
619
See M/N/S brief, page 85.
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B.
Rate D11 rate design
DTEE proposed to continue the Rate D11 it proposed in Case No. U-17689. Mr.
Bloch presented DTEE’s rate design, indicating that DTEE used the same on peak and
off peak rate differential as the current D6 rate.
ABATE argues that it is not appropriate to use the same on-peak and off-peak
energy charges for all voltage levels within Rate D11.620 Mr. Selecky testified that the
energy charges should be lower for transmission and subtransmission customers
because DTEE incurs less cost to serve those customers due to system demand and
energy loss differentials between voltage levels.621 Mr. Selecky cited Consumers
Energy’s Rate GDP to show that the Commission has approved this differentiated rate
design. He also presented supporting calculations in Exhibits AB-3 and AB-4, using the
same revenue targets DTEE used, and the 2013 on-peak and off-peak energy usage by
voltage level data.
DTEE argues that its rate design proposal for Rate D11 is the same proposal it
made in Case No. U-17689.622 DTEE cites Mr. Bloch’s rebuttal testimony asserting that
there is insufficient support for separate charges:
I agree with Witness Selecky that loss differentials between voltage levels
affect costs to serve customers and should be incorporated in rate design.
However, I have concerns with the underlying assumptions used by
Witness Selecky to determine his proposed voltage level adjustment
amounts. Witness Selecky’s approach applies the demand and energy
loss factors based on the demand/energy revenue split in the rate design
as opposed to the actual allocation basis for the underlying costs as
applied in the cost of service. For example, individual A&G cost elements
are allocated based on a combination of demand and energy. The
demand and energy loss factors should be applied to the relative
proportion of demand and energy related A&G costs. In addition, I do not
620
See ABATE brief, pages 17-22.
See 9 Tr 2386-2393.
622
See DTEE brief, pages 131-132.
621
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agree with Witness Selecky’s proposal for a rate design with the added
complication of separate voltage level billing demands and separate on
and off peak energy charges, as opposed to the existing voltage level
energy discounts. Until there is sufficient support for separate voltage level
demand and energy charges, any additional voltage level cost reductions
approved by the Commission in this case should be accomplished by
increasing the existing voltage level discounts. 623
Walmart supports DTEE’s rate design proposal, specifically citing Mr. Bloch’s rebuttal
testimony.624 In its brief, Staff supports DTEE’s rate design, characterizing ABATE’s
proposal as “unnecessarily arduous.”625 Staff argues:
Staff agrees with ABATE to the extent that primary class power supply
charges should reflect the reduction in losses at transmission and
subtransmission voltage levels (as compared to the primary voltage level).
But Staff agrees with the Company that ABATE’s proposed rate design is
unnecessarily arduous and relies on assumptions from the rate-design
stage of this case, not the cost-of-service stage.
In currently applied rates, the Company’s proposed rate design and Staff’s
rate design include a discount based on voltage level. Neither the
Company nor Staff proposed a change to these discounts in their design
for Rate D11, but now both recommend changing the rate’s power supply
charges to reflect lower losses at transmission and subtransmission
voltage levels, and both recommend increasing existing voltage level
discounts to do so. One option is to recalculate the existing discounts
based on the appropriate loss factors, while still designing rates to collect
the approved revenue requirement in total.626
DTEE’s reply brief notes Staff’s agreement, but also asserts that Staff “slightly”
incorrectly characterized DTEE’s position when it indicated that DTEE wants to change
the power supply charges to reflect updated voltage level discounts. DTEE argues it
does not recommend any changes.627 ABATE generally rejects Staff’s proposal in its
reply brief:
623
See 4 Tr 571-572.
See Walmart brief, page 8.
625
See Staff brief, page 75.
626
See Staff brief, page 75.
627
See DTEE reply brief, page 122.
624
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Staff agreed with ABATE’s theory on D11 voltage level discounts,49 but
ABATE rejects Staff’s conclusions about the ultimate validity of ABATE’s
analysis as “unnecessarily arduous,” which Staff has failed to establish.
ABATE takes issue with the Staff’s position on Mr. Selecky’s rate design
because Mr. Selecky’s rate design is exactly the same as that which the
Staff supported and the Commission approved in a Consumers case for
rate GPD. However, if the Commission does not want to take the step of
creating different demand and energy charges by voltage level in DTE’s
cases, it should increase the Staff’s proposed voltage level discounts for
subtransmission and transmission customers to the level proposed by Mr.
Selecky, as shown in his Exhibit AB-4, page 2 of 2.
Finally, Staff is further concerned with the “rate-design stage” of Mr.
Selecky’s assumption and proposal, but fails to recognize that this
methodology is driven by DTE’s lack of voltage level projections in its cost
of service study. Mr. Selecky merely undertook the work that DTE did not
perform, and unbundled DTE’s single rate class for D11 by voltage level.628
This PFD recommends that the Commission adopt Staff’s recommendation to use the
different loss factors for subtransmission and transmission level customers to increase
to adjust the discounts, with additional refinements to be considered in future cases.
C.
Rider 10
Mr. Selecky raised two concerns with DTEE’s Rider 10 rate design. First, he
testified that a 23% increase in the administrative charge proposed by DTEE is not
justifiable. He presented as Exhibit AB-5 a discovery response from DTEE to show how
the charge was developed. He testified that the administrative charge contains both
administrative costs and production operating and maintenance costs. He identified
$6.615 million in production maintenance costs and $4.762 million in production
operating expenses allocated to this rate. He testified that as interruptible customers,
production O&M costs should be allocated to Rider 10. He presented Exhibit AB-6 to
show the alternative revenue target and administrative charge resulting from removing
628
See ABATE reply brief, page 14.
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these costs.629 Mr. Selecky also testified in rebuttal that Staff did not adjust the
administrative charge to remove the production O&M.630 He characterized Staff’s
recommendation as a 73% increase. He presented Exhibits AB-8 and AB-9 to show
Staff’s cost of service allocation and his revised calculation of the administrative charge
for Rider 10 using Staff’s revenue target.631
In its reply brief, DTEE disputed Mr. Selecky’s claim that Rider 10 customers do
not use electric generation and therefore should not have to pay production O&M
costs.632 DTEE argues that Rider 10 customers benefit from DTEE’s generation
resources through lower and less volatile MISO energy prices, citing Mr. Bloch’s
testimony at 5 Tr 572-73. DTEE argues that the Commission agreed with this cost
principle in its October 20, 2011 order in Case No. U-16472, page 100. ABATE does not
address DTEE’s arguments, including its reliance on the Commission’s order in Case
No. U-16472. Since DTEE has correctly cited the Commission’s prior decision, and
ABATE has not established a basis for revisiting the conclusion in that order, this PFD
recommends that the Commission reject ABATE’s recommendation.
Mr. Selecky’s second concern with DTEE’s Rider 10 rate design is DTEE’s
proposal to eliminate the “stack pricing” option for this rate.633 Mr. Bloch testified:
Currently there are two power supply billing options available under Rider
10. Both utilize hourly pricing applied to each R10 customer’s
corresponding hourly load. One determines hourly energy prices based on
a resource stacking method (stack pricing), and the other is based on the
MISO market pricing for the DTE load node. The stack pricing method
determines the R10 hourly prices by stacking DTE’s hourly generation
resources and purchases, including purchases from MISO, from lowest
629
See 9 Tr 2393.
See 9 Tr 2413-1415.
631
Also see ABATE brief, pages 12-16.
632
See DTEE reply brief, page 124.
633
See 9 Tr 2396.
630
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variable cost at the bottom to highest cost at the top. This resource stack
is then compared to the Company’s hourly load stack which has firm
service loads at the bottom and interruptible loads at the top. The hourly
R10 stack price is calculated based on the variable costs of the generation
resources that are aligned with the R10 load. The MISO market price
billing option uses the marginal energy price in the MISO market at the
DTE load node, which is the same price point for the Company’s
purchases from MISO. Due to MISO’s economic dispatch of all generation
resources, including DTE’s generation resources, the stack price is
comparable to the MISO market price.
Since both methods produce similar hourly energy prices, the Company is
proposing to eliminate the stack based power supply billing option and
have all R10 customers priced under the MISO market pricing method.
This change provides more timely and predictable price signals for
customers to adjust their loads, has more price transparency as the prices
are available every five minutes through MISO’s website, and eliminates
the uncertainty and financial risks associated with the stack price
reconciliation process in which customers are billed pricing adjustments a
month or more after the service is rendered. With this proposed change,
all Rider 10 power supply costs will now be recovered through the MISO
billing option.634
Staff agrees with DTEE’s proposal, as Mr. Isakson testified:
Staff concurs that the resources stacking method of pricing is unduly
complicated when the alternative, pricing based on MISO locational hourly
marginal energy price for the DTE Electric-appropriate load node, provides
a more accessible price that measures the same marginal power supply
costs.635
Mr. Selecky recommends that the stack pricing option be retained until DTEE
provides more information:
Although DTE Electric indicates that the stack pricing method provides
comparable prices to the MISO market prices, the Commission should
retain this option for the Rate R10 customers until DTE Electric provides
more information as to why this pricing option should be eliminated. Based
on my review of DTE Electric’s filing, there does not appear to be
adequate support to terminate this pricing option.636
634
See 4 Tr 558-559.
See 8 Tr 1984.
636
See 9 Tr 2396.
635
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Relying on Mr. Bloch’s testimony, DTEE argues both methods produce similar hourly
energy prices, but the MISO method that would remain in the tariff would provide better
transparency and eliminate the financial risk and uncertainty associated with the stack
pricing reconciliation process. This PFD finds that DTEE’s and Staff’s recommendations
to eliminate the stacking price option should be adopted. This PFD also finds that
ABATE has not supported any errors in the rate design for Rider 10, given the
Commission’s prior decision in Case No. U-16472.
D.
Rider 3
DTEE proposed to eliminate the “power supply” pricing option for standby service
under Rider 3, based on Mr. Bloch’s testimony that it does not have cost-of-service
support and is inconsistent with the design principles DTEE supports.637 Mr. Selecky
testified that the power supply option was approved as part of a settlement agreement
in Case No. U-14838. He acknowledged DTEE’s claim that it does not have price
support for this option, and quoted a discovery response from DTEE indicating that the
power supply option does not recover capacity costs. He recommended that the option
be retained because it allows customers to get power at realtime MISO LMP prices. He
testified that customers should also be required to pay MISO the auction clearing price
for Zone 7 on a daily basis for the actual standby power that was taken, to compensate
DTEE for the capacity costs.638
In its brief, DTEE characterizes ABATE’s position as “fundamentally flawed”,
arguing that allowing the Rider 3 customers to pay the MISO capacity charge results in
637
638
See 4 Tr 552, 561; see DTEE brief, page 134.
See 9 Tr 2396-2398.
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intra-class subsidies within the D11/other cost of service class. In its reply brief, DTEE
notes that ABATE also argues that the Commission should not eliminate the option
because Staff proposes a standby rate workgroup.639 DTEE argues that Staff’s
workgroup does not justify perpetuating intra-class subsidies.
DTEE also takes issue with Staff’s rate design for Rider 3, arguing that Staff
should not set distribution energy charges at zero.640 In his rebuttal testimony, Mr. Bloch
testified that the distribution energy charge for Rider 3 should be equal to the Rate D3
energy charge, in accordance with the Commission’s order in Case No. U-10102.
In its initial brief, Staff addressed Mr. Bloch’s rebuttal testimony:
Staff does not agree that its proposed secondary voltage distribution
charge for Rider 3 is wrong, as Mr. Bloch alleges. (4 TR 580.) Mr. Bloch
said that Staff’s secondary voltage distribution charges are not consistent
with the Company’s rate design method and require correction. (Id.) But
the inconsistency was no mistake. Although Staff generally followed the
Company’s approach to designing primary class distribution rates, Staff’s
secondary voltage distribution charges were different because Staff
gradually phased in its rate design.
In its rate design, Staff limited the increase to any one commercial
secondary rate schedule to 20%. (6 TR 979.) Due to this limit, Staff
increased some rate schedules more than what it would have otherwise to
make up for the missing revenue created by the 20% cap. Rider 3
secondary voltage distribution charges were increased for this reason (to
make up for missing revenue), which is presumably why the charges were
not what Mr. Bloch expected they would be. (See 4 TR 580.) Staff’s
proposed commercial secondary voltage distribution charges do not
require correction and should be adopted.641
DTEE acknowledges Staff’s initial brief explained that secondary voltage distribution
charges included an element for gradual phase-in of rate design for secondary voltage
customers, but DTEE does not accept this is a valid justification for breaking from
639
See ABATE brief at page 24, Staff brief at 112-113.
See DTEE reply brief, pages 125-126.
641
See Staff brief, page 68.
640
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fundamental cost of service principles, that require the standby customers to be billed
for the greater of distribution energy or distribution demand.
This PFD finds that Staff’s explanation is a reasonable accommodation of the
need to balance rate design goals with reasonable limits on customer impacts, and
recommends that the Commission accept Staff’s approach.
E.
Experimental Load Aggregation Provision (ELAP)
DTEE is proposing to terminate the Experimental Load Aggregation Provision
(ELAP), which allows customers with multiple locations to aggregate billing demands.
DTEE argues that in Case No. U-16472, the Commission directed DTEE to determine
whether the ELAP provision is cost based, and in response to this directive, DTEE
determined that it is not cost based, but results in intra-class subsidies. 642
Mr. Townsend testified:
DTE offers no study or empirical analysis to address this question. What
little information the Company does offer, though, supports my own
contention that the provision is cost-based. DTE’s response to the
Commission’s directive in the last case is merely to offer a
recommendation to terminate the provision, accompanied by an
explanation by Mr. Bloch defending the Company’s rationale.643
He testified that the provision is being used, citing a discovery response from DTEE
showing 93 MW taking service under this tariff provision, relative to the 125 MW cap.644
Mr. Bloch provided rebuttal testimony asserting that the ELAP was not cost
justified, testifying: “The fact that the ELAP does nothing to alter the Company’s costs
or the allocation of costs to cost of service classes and yet reduces rates paid by ELAP
642
See Bloch, 4 Tr 559-561, 5 Tr 568-571.
See 9 Tr 2472.
644
See 9 Tr 2477.
643
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customers is proof that the ELAP is not cost based.”645 In its brief, DTEE acknowledges
Kroger’s objection, but argues that Kroger’s proposals to make the ELAP permanent are
based on the flawed proposition that the ELAP is cost based because it does not alter
the cost or cost allocation. DTEE characterizes Kroger’s position as “baseless and
backwards” from a cost-of-service perspective.646 DTEE further characterizes the ELAP
as an “arbitrary pricing mechanism” that allows a select group of customers to reduce
billing demand costs based on ownership at the expense of other customers.
Kroger responds in its reply brief that DTEE has not made a demonstration that
the rate is not cost based. Kroger argues that obviously multiple locations lead to higher
distribution and customer costs, but the ELAP does not apply to those costs.647 Kroger
argues that DTEE merely reiterates as a “mantra” that the ELAP is not cost based. 648
This PFD finds that DTEE has not provided a study or analysis to aid in the
review of the ELAP provision. In its October 20, 2011 order in Case No. U-16472, the
Commission’s order discussed the ELAP as follows:
Detroit Edison’s experimental load aggregation provision (ELAP) allows
large customers with multiple locations to aggregate their power supply
billing demands. As in past rate cases, the ELAP is set to automatically
expire with the issuance of this order. Kroger recommended that the
Commission do away with the automatic expiration, and allow the ELAP to
continue until terminated by the Commission. Detroit Edison argued in
favor of continuing use of the automatic expiration language, because the
provision is experimental. The Staff also favored the current language, but
suggests that the utility be directed to demonstrate in its next rate case
whether the ELAP is cost-based, and if so, it may no longer be
experimental. The Attorney General agreed with the Staff, as did the ALJ.
The ALJ found that once actual data regarding the rate has been
collected, the Commission can decide whether to turn it into a long-term
645
See 4 Tr 568-569.
See DTEE brief, pages 133-134.
647
See Kroger reply brief, page 2.
648
See Kroger reply brief, page 3.
646
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service option. The ALJ recommended that the ELAP be continued until
the next rate case order, with direction that the filing in that case
demonstrate whether the provision is cost based.
No exceptions were filed, and the Commission adopts the ALJ’s
recommendation.649
A review of this order makes clear that the Commission was looking for an actual
analysis, with data. On this basis, this PFD recommends that the Commission permit
the ELAP to continue until DTEE’s next rate case, when DTEE should present an
analysis of the use of this provision.
F.
Rate D8
DTEE also proposed to increase the interruptible capacity limit under Rate D8
from 150 MW to 250 MW.650 Mr. Isakson testified to Staff’s recommendation to increase
the cap to 300 MW, to increase the opportunity for customers to take advantage of
demand response programs, also citing Mr. Matthews’s testimony regarding demand
response.651 In its reply brief, DTEE notes that Staff recommends increasing the limit to
300 MW, and indicates it does not object.
Energy Michigan argues that the discount should be changed “to reflect the value
of interruptible capacity.” Mr. Zakem testified:
The discount for interruptible service should reflect the value of MISO
capacity. The value of capacity is what the D8 rate provides compared to
the standard firm service D11 rate.
MISO resource adequacy rules allow interruptible service to qualify as a
“load modifying resource” and to be used to satisfy capacity requirements.
The market value of an interruptible kW is the clearing price from MISO’s
649
See October 20, 2011 order, page 104.
See Bloch, 4 Tr 552, 561; Dimitry, 5 Tr 614-15; DTEE brief, page 134.
651
See 8 Tr 1980-1981.
650
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annual Planning Reserve Auction. Therefore, the discount of the monthly
demand change for D8 should reflect the MISO PRA clearing price.652
DTEE argues that Mr. Zakem’s recommendation would reduce participation
under Rate D8. Mr. Bloch also testified that the resulting discount would be good only
for one year because the MISO PRA is held annually.
Staff agrees.
Mr. Isakson
presented rebuttal testimony, explaining:
Rate D8 is treated as a separate class in the cost of service study
sponsored by Staff witness Charles E. Putnam. The power supply demand
charge is set to collect costs allocated to Rate D8 customers not collected
through other charges. Compared to Rate D11, the discount in the power
supply demand charge for Rate D8 is not directly attributable to the value
of Midcontinent Independent System Operator (MISO) capacity, as Energy
Michigan witness Zakem suggests. Rather than design Rate D8 based on
MISO market prices, Staff designed the rate to recover the Staff proposed
power supply revenue requirement for Rate D8. Other than the
interruptible nature of D8, the service provided to customers on D8 is alike
enough to D11 that both Staff and the Company set power supply energy
rates for D8 to equal those of D11. The power supply demand charges for
D8 and D11 are different only because each rate has a different proposed
revenue requirement. The difference is not related to prices from a MISO
auction.653
Staff’s brief emphasizes that Staff’s Rate D8 is based on the revenue requirement
explicitly assigned to those customers, while the MISO-based proposal would be a
departure from cost-of-service ratemaking principles.654
This PFD finds that DTEE and Staff have reasonably explained the basis for the
D8 rate design and recommends that Energy Michigan’s proposal be rejected.
G.
Line Extension Allowances
Mr. Zakem also recommended a revision to the line extension policy:
652
See 8 Tr 1931.
See 8 Tr 1987.
654
See Staff’s brief, pages 70-71.
653
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The standard allowance table applies to costs and credits for distribution
service. However, specific allowances depend on whether a customer has
or does not have a full service contract as well as on the length of the full
service contract. “Full service” means power supply service in addition to
distribution service. As a result, two customers may receive the same type
of distribution service and same benefit from extension of distribution
facilities, but end up paying different amounts.
Revenue from power supply service should not be used as a rationale for
charging less for new distribution facilities. Power supply and distribution
are separate services, and they should be priced by cost of service and
charged for separately, without subsidy from one to the other and without
discrimination among customers.655
DTEE objects to changing the line extension allowance. DTEE argues that its line
extension policy is based on the incremental revenue from a full service customer, and
by making it available to a choice customer, the incremental revenue would be much
smaller. This PFD recommends that DTEE’s proposed revisions be adopted.
H.
Municipal Lighting
One of the principal rate design disputes involves DTEE’s proposed revision to
its municipal lighting tariff and rate design.
As background to the dispute, DTEE’s
current lighting tariff includes an “Experimental Efficient Lighting Technologies” or EELT
provision.
Also, two lighting technologies are of limited usefulness. When mercury
vapor lights fail, they cannot be replaced with new mercury vapor lights, but must be
replaced with new technology. 40% of the street lights DTE owns under its E1 tariff are
mercury vapor. DTEE also has 2,300 metal halide street lights, and continues to replace
them on failure and in five-year cycles. The Energy Independence and Security Act of
655
See 8 Tr 1933-1934.
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2007 prohibited the manufacture or import of metal halide lights with ballasts that do not
meet energy efficiency requirements beginning in 2009.656
Ms. Holmes presented direct testimony for DTEE outlining the company’s
proposal.
Ms. Holmes testified that the current method of billing Municipal Street
Lighting and Outdoor Protective Lighting customers is through a monthly lamp charge
(equal to 1/12 the approved annual charge), which includes customer-related costs,
capital, and energy costs. She testified that DTEE is proposing to unbundle these
charges into a customer charge, a fixture charge, and an energy component. She
testified that the energy charge will be “determined by applying a rate which includes
the base PSCR rate to the calculated kilowatt hours of all products.”657 She testified that
the fixture charge “will be a set amount applied to each fixture dependent on the
technology utilized and whether it is served from underground or overhead.”658 She
testified that the changes will allow customers to better understand the costs that
contribute to each charge, and be able to make more informed decisions regarding
which technology and program may best serve their community.
Ms. Holmes testified that for the different technologies and wattages, the initial
capital investment and the maintenance costs vary. She explained how she calculated
the proposed fixture charges at 6 Tr 964-966. The E1 tariff schedules are shown in
Exhibit A-14. She testified that the current EELT customers would “transition” to the
new tariff, meaning that once the new tariff becomes effective, it would establish the
rates that the EELT customers would now pay.
656
See section 42 USC 6295.
See 6Tr 963.
658
Id.
657
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The MSLC took issue with DTEE’s proposal for multiple reasons. Its first
objection is that the new tariff does not make provision for customers who paid
substantial contributions in aid of construction (CAIC) to install energy-efficient LED
technology. Mr. Jester testified:
Because of the specific interest of various municipalities in LED street
lighting, DTE previously established an Experimental Emerging Lighting
provision in the E-1 tariff. In that provision, a municipality wanting to use
LED lighting must make a significant financial payment to DTE. This
payment is called a Contribution in Aid of Construction (“CIAC”).
Thus, due to the replacement of obsolete mercury vapor and metal halide
lights and municipality interest in LED lights, the mix of lighting
technologies in DTE’s ownership is and will continue to change rapidly
over the next few years.
In this case, DTE proposes to incorporate LED technology into the
standard formulation of the street lighting tariff. In doing so, the Company
proposes to continue its practice of requiring CIAC for converting existing
street lights to LED technology and also proposes changes in the rate
design within the street lighting rate schedule that will diminish the
financial advantages for municipalities to convert from mercury vapor and
metal halide lights to LED rather than high pressure sodium lights. These
changes in rate design also undermine financial returns on the
investments in LED lights that municipalities they have already made
through CIAC.659
Mr. Johnston provided rebuttal on this issue. He explained DTEE’s contribution
in aid of construction policies under its current tariffs:
DTEE’s calculation method for CIAC varies depending on whether the
DTEE project cost is for new business or conversion of existing business
(i.e. convert mercury vapor to LED). The determination of CIAC for new
business is simply the total estimated project cost less three years of
expected incremental revenues from the project. The determination of
CIAC for conversion of existing business is total estimated project cost
less three years of expected incremental revenues from the project plus a
labor credit. The credit for three years of incremental revenue is zero in
most cases because the rates for the lighting technology to which
659
See 8 Tr 1842.
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customers are converting are typically lower than the rates for their
existing lighting technology.660
He acknowledged that under DTEE’s new lighting tariff, customers who paid
contributions in aid of construction in the expectation of receiving benefits from that
payment would not receive the same benefits or “pay back period”, but he testified that
some of those municipalities had received grants to cover some of the costs, and also
should have known that DTEE could change the tariff:
Witness Jester suggests that each of the municipalities that entered into
lighting agreements did so only based upon an expected payback and
states that the proposed increases undermine financial returns on the
investments in LED lights that municipalities have already made through
CIAC. However the payback for the early adopters (2010 – 2012),
ignoring external funding, was in the range of 12-15 years. More recently,
the payback for mercury vapor to LED conversions has typically been in
the neighborhood of 2-4 years and some of those municipalities have
already fully recovered or are well on their way to recovering, their entire
investment (CIAC). Further, some municipalities used grants from the
State of Michigan to fund their CIAC and, therefore, incurred no up-front
investment and simply continue to realize lower annual street light costs
for LED lighting than they previously paid for other lighting technologies.
For street lighting customers that funded their own CIAC, the proposed
lighting tariff does, in some instances, increase the payback modestly to a
range of 3-5 years, yet many of those customers have already realized a
significant return of their investment and a request to freeze the tariff for
an additional 10 years is unfounded and unnecessary to make them
whole.661
Mr. Jester also testified that DTEE’s proposal to continue to require a CIAC
based on the cost of the new technology discourages the use of the more efficient LED
technology:
When CIAC is charged to a customer to recover a portion of the costs of
an unusually expensive line extension, this is economically justified
because such customers are allocated and charged for power delivery at
the same rate as other customers. CIAC is warranted so that DTE
recovers its costs for distribution without undue cross-subsidization by
660
661
See 4Tr 503-504.
See 4 Tr 507-508.
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other customers who did not require unusually expensive line extension.
However, since DTE distinguishes lighting types in its rate structure, CIAC
for more expensive lighting types is not warranted to avoid crosssubsidization. Any difference in the life-cycle cost of service for LED
lighting as compared to high pressure sodium lighting should be
adequately reflected in the technology-specific charges in the Municipal
Street Lighting Rate Schedule and therefore does not warrant CIAC. Thus,
in my opinion, it would be just and reasonable for DTE to receive CIAC
from a customer that requests the proactive planned replacement of
mercury vapor or metal halide lights with LED lights for only the remaining
book value, minus salvage value, of the equipment that is prematurely
replaced.
Even though the economic logic is that CIAC for replacing still-functioning
lights with a different lighting technology should be limited to the remaining
book value, minus salvage value, of the still-functioning equipment that is
prematurely replaced, DTE’s current practice is to charge CIAC for the
entire cost of the conversion but for an allowance for labor efficiency, as is
explained in Exhibits MSLC-8, MSLC-9, and MSLC-10.662
In this regard, MSLC raises a concern with how DTEE actually has calculated the CIAC
under the existing experimental tariff provision. Mr. Jester noted that the EELT tariff
requires DTEE to consider “three years revenue”, while DTEE has implemented the
tariff as a “conversion”, using a labor offset for mercury vapor light replacement because
it acknowledges it would replace the lights eventually, anyway. Mr. Johnston’s testimony
also indicates that DTEE considers the remaining book value of the obsolete
technology, which is also provided for under the “conversion” option of the E1 tariff, but
not expressly provided for in the EELT tariff.
MSLC argues that DTEE’s entire “Community Lighting Model” that is the basis for
its rate design is flawed. MSLC presents this rate design model in Exhibits MSLC-15
and MSLC-16. MSLC argues that DTEE uses as the starting point for its revenue
requirement its 2013 revenues adjusted for inflation. It argues that DTEE then allocates
662
See 8 Tr 1851-1852.
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the revenues to the new elements of its tariff, the customer charge, the fixture charge,
the energy charge, based on a variety of factors. Mr. Jester testified:
According to the calculation methods displayed in the Conversion Project
Model spreadsheet, the entirety of cost of a project to convert mercury
vapor and/or high pressure sodium lights to LED lights will be recovered
by DTE through CIAC, calculated as the table-based project cost estimate
less the DTE labor contribution. Even if the DTE labor contribution was for
all project labor, all of the cost of luminaires and photocells were included
in CIAC payments. The EO rebate is subsequently paid by DTE’s Energy
Optimization Program to the customer. Since Contributions in Aid of
Construction should be excluded from rate base and are usually
recognized by DTE as offsets to capital expenditures, none of the costs of
projects to convert municipal street lighting to LED should be in rate base.
Further, these costs should not be recorded without offsets to asset
accounts that are then used to determine capital costs in a cost of service
study. Nonetheless, as I will show below, DTE proposes in this case to
establish fixture charges for various streetlight types that include capital
cost recovery for LED lights. Indeed, because LED lights have higher
initial cost than other streetlight types, DTE proposes to assign greater
capital costs per LED fixture than for other fixture types. It therefore
appears that the accounting principles for Contributions in Aid of
Construction are not being consistently applied in DTE’s Community
Lighting Program or that DTE is inappropriately considering the capital
costs of LED luminaires in its rate design.663
Mr. Johnston responded that by protesting the CIAC, MSLC is asking for a
subsidy from other customers.664
Mr. Jester also took issue with the O&M cost allocations. Mr. Johnston’s rebuttal
testimony essentially acknowledged Mr. Jester’s concern that historical costs are not a
solid basis for projecting future O&M costs:
Mr. Jester believes that the proposed O&M expense in 2016 and beyond
should be reduced significantly based upon DTEE no longer performing
group relamping of mercury vapor fixtures, DTEE moving to a relamping
schedule of 8 years for high pressure sodium fixtures and DTEE’s
movement to a greater LED lighting technology mix (which is projected to
require no O&M expense) and, therefore, the projected maintenance costs
don’t accurately reflect changes to the Company-owned street light asset
663
664
8 Tr 1856-1857.
See 4 Tr 504, 510-511.
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mix. I disagree with Mr. Jester’s conclusions for the proposed O&M
expense for the 2016 test year. DTEE has not yet completed its
movement to a group relamping schedule of 8 years for high pressure
sodium fixtures. DTEE continues to relamp mercury vapor fixtures, it
simply does it on a reactive basis rather than on a planned basis, and
DTEE continues to relamp metal halide fixtures on a 5-year periodicity. A
review of O&M expense recorded in Account 596 (Maintenance of Street
Lighting and Signal Systems) for the period from 2010 through 2013
reveals that the average O&M expense was $3.306 million. Applying of an
inflation adjustment to the O&M amount of $3.276 million from the
historical test year is consistent with the historical expense and therefore
appropriate. It is important to point out that the direct allocation of O&M
expense from Account 596 does not reflect all of the O&M costs that are
allocated to DTEE’s proposed Street Lighting rates. Various O&M costs
from Distribution Operation and Distribution Maintenance are also allocate
to and reflected in DTEE’s proposed street lighting rates.665
MSLC asks the Commission to decline to approve DTEE’s proposed lighting
tariff, and to require DTEE to file a revised tariff after consultation with municipalities. In
the alternative, MSLC proposes a tariff in Exhibit MSL-19 that it recommends, along
with other relief including limiting CIAC on lighting conversion to the remaining book
value of the lighting being replaced, less salvage value and any labor savings;
grandfathering the EELT tariff to preserve the benefits of the CIAC made under that
program, or alternatively providing for refunds; having Staff audit the company’s costs to
provide a basis for future charges; and requiring DTEE to submit a business plan for its
lighting program.
Staff argues in its initial brief:
While Staff initially agreed with the Company’s proposed rate design for
the lighting class, Municipal Street Lighting Coalition witness Douglas
Jester raised many interesting points regarding street lighting rates. Staff
does not necessarily agree with all of the Coalition’s criticisms of the
Company’s proposed street lighting rates, but Staff does agree that the
best way to explore the appropriate design for street lighting rates is
through a collaborative. (8 TR 1844.) If nothing else, a collaborative will
help educate all parties about the model and the resulting rate design. For
665
See Tr 514-515.
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the purposes of this case, however, Staff recommends that the ALJ and
the Commission approve a final order revenue requirement for the lighting
class as an equal percentage increase to all lighting rates. This should
minimize any potential errors facing the collaborative.666
Staff also addresses DTEE’s argument that the Commission cannot require it to
participate in a collaborative. Staff believes the Commission has this authority, but also
argues:
Alternatively, the Commission could, under its broad ratemaking authority,
find the Company’s lighting rate design deficient and open a contested
case requiring the Company to submit its lighting model and associated
documentation. The Commission did something similar when it set up the
current experimental LED rates. In re Detroit Edison’s 2009–2010 Rate
Case, MPSC Case No. U-15768, 1/11/2010 Order, pp 78–79. This would
allow other parties to explore the model, and would have many of the
same benefits as a collaborative, albeit through a more contentious
method. Staff recommends a collaborative, but should the Commission
find that this is outside of its authority, Staff recommends that the
Commission open a contested case with the same goal.667
The Attorney General also agrees with MSLC and Staff that a collaborative is
appropriate.
In its reply brief, DTEE softens what appeared to be a refusal to participate in a
collaborative:
Much of the discussion by Staff and MSLC concerns a “straw man”
argument mischaracterizing DTE Electric as suggesting that the
Commission lacks authority to order a collaborative. The Commission has
plainly ordered collaboratives in the past, and can do so again in
appropriate circumstances and in accordance with the law. MSLC instead
proposes a “management-oriented collaborative” (MSLC Initial Brief, p
60), and asserts for example that the Commission should “order a
collaborative to oversee DTE’s transition to new street lighting
technologies” (MSLC Initial Brief, p 51. Emphasis added) and “work out
the business plan” for DTE Electric’s Community Lighting Program (MSLC
Initial Brief, p 62).
666
667
See Staff brief, pages 92-93.
See Staff brief, pages 93.
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DTE Electric took issue with the Commission ordering “such a”
collaborative (4 T 501- 502), and maintains its position in accordance with
well-established law. In the context of DTE Electric’s transition to AMI
meters, for example, Court of Appeals observed that “the decision
regarding what type of equipment to deploy can only be described as a
management prerogative.” In re Application of Detroit Edison Co to
implement opt-out program, unpublished opinion per curiam of the Court
of Appeals, issued February 19, 2015 (Docket Nos. 316728 and 316781)
(Slip opinion, p 5, following Union Carbide v Public Service Comm, 431
Mich 135; 428 NW2d 322 (1988) and Consumers Power Co v Public
Service Comm, 460 Mich 148; 596 NW2d 126 (1999)).668
DTEE also argues that it did not have a chance to cross-examine Staff on its change of
position, and that a collaborative would be pointless because it has established the
reasonableness of its proposals.
This PFD finds that DTEE has failed to establish that its proposed revisions to
the municipal lighting tariff are just and reasonable. The Experimental Emerging
Lighting Technology tariff approved by the Commission provides:
Available on an optional basis to customers desiring Municipal Street
Lighting Service using emerging lighting technologies not otherwise
offered through the standard tariff. The Company will own, operate, and
maintain the emerging lighting technology equipment and the Customer
will provide a contribution in aid of construction equal to the amount by
which the investment exceeds three times the estimated annual revenue.
Emerging lighting technologies and Customer participation must be
approved by the Company and the energy and maintenance benefits for
each project will be calculated based on predicted energy and luminaire
life. The Company and the Customer will mutually agree on all prices,
terms, and conditions for the service under this provision, evidenced by
signed agreement.
Although DTEE is planning to immediately “transition” all customers currently taking
service under this provision, it makes no provision for or in consideration of the CIAC
required under this tariff or the related prices, terms and conditions of service under this
tariff. While MSLC argues that DTEE is proposing to charge rates for all LED lighting
668
See DTEE reply brief, pages 134-135.
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customers that recoup the capital cost of the LED lights, without regard to agreements
reached under the current tariff, DTEE does not directly respond to or refute the claim
that its proposed tariff does this. Instead, DTEE relies on Mr. Johnston’s recognition and
dismissal of the municipal customers’ expectations based on those agreements, as
quoted above.
Mr. Johnson’s explanation that the CIAC payments and agreements reached
under the EELT should be ignored is not persuasive. First, the source of the funds is
irrelevant, as MSLC argues. Second, that the contributions may not have fully funded
the conversion does not mean those contributions should be ignored. Third, the
municipal lighting customers who entered into agreements to pay CIAC to DTEE have
the same expectation of relative consistency that DTEE expects from the Commission—
see, e.g., the discussion of AMI above. DTEE has not shown that it has appropriately
considered the past CIAC payments in formulating its new rate design.
In addition, DTEE has not shown that its lighting proposal is cost based. MSLC
argues:
DTE’s Lighting Model spreadsheet represents DTE’s effort to allocate
costs attributable to municipal street lighting to the different types of lights
used by the Company. In constructing its Lighting Model, the Company
does not first ask basic questions (such as, for example, “What does it
cost for a certain type of luminaire?’ “How often do you have to replace
it?”), and then build a plan from the bottom up. Instead, the Company
starts with what they hope to earn (the revenue requirement). In this case,
DTE uses its 2013 total revenue, increased by an inflation factor, to
generate the 2016 revenue requirement. This methodology takes the
place of an analysis of what actual costs will be in 2016 and beyond.669
DTEE does not address this argument directly.
669
See MSLC brief, page 16.
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DTEE has also not adequately addressed MSLC’s concern regarding the use of
CIAC in its proposed tariff. Note that the tariff as revised eliminates the EELT provision,
but in Sheet 50.00, it retains a CIAC requirement for “conversions” and for “new
installations” as follows. Under the heading “Contract Term:”
Municipal Street Lighting and Outdoor Protective Lighting: Minimum 5 year
term. Upon expiration of the initial term shall continue on a month-tomonth basis until terminated by mutual written consent of the parties or by
either party with thirty (30) days prior written notice to other party. Any
conversion, relocation and/or removal of existing street lighting facilities at
the customer's request, including those removals necessitated by
termination of service, must be paid for by the customer. The detailed
provisions and schedule of charges, which may include the remaining
value of the existing facilities, will be quoted upon request.
Municipal Street Lighting: The Company shall not withdraw service, and
the municipality shall not substitute another source of service in whole or
in part, without twelve months' written notice to the other party.670
And under the heading “Option I: Company Owned Street Lighting System”:
Where new installations require an investment in excess of an investment
allowance, Option I is available only to customers who make a contribution
in aid of construction equal to the amount by which the investment
exceeds three times the annual revenue at the prevailing rate at the time
of installation. (Effective January 1, 1991, the investment amount will be
limited to direct cost. Effective January 1, 1992, the investment amount
will include full cost.)
MSLC also asks the basis for including the capital cost of the lighting if it is paid for
through a CIAC. While MSLC has reiterated that it does not believe the capital costs of
LED lighting should be paid by customers who use other lighting technologies, DTEE
continues to assert that MSLC is seeking a subsidy.
MSLC also identifies other concerns, including the use of historical O&M costs
when changes in customer lighting mix would suggest that those costs O&M costs
670
See Exhibit A-15, Sheet 50.00, stricken material omitted.
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should be falling,671 a concern with the rate differential between overhead and
underground-fed lighting,672 and the combining of the municipal street lighting and
outdoor protecting lighting tariffs and rates.673 While DTEE disputes these concerns,
given the complexity of DTEE’s lighting model as shown in Exhibit MSL-15 and MSL-16,
they are best addressed initially in a collaborative, where the details of DTEE’s lighting
model can be more fully explored.
These are important issues, and DTEE’s revised tariff should not be approved
until these issues are addressed. Note that the new tariff language provides for a fiveyear contract, which might limit the Commission’s opportunities to revise the tariff
structure readily, once it takes effect. Assuming DTEE is indeed willing to participate in
a collaborative, this PFD recommends that the Commission provide for one. In addition,
in case DTEE is unwilling to participate or to ensure a relatively prompt resolution, the
Commission should direct DTEE to file a revised tariff addressing municipal and outdoor
protective lighting. A revised tariff should have demonstrated cost support for the rates
for the different lighting technologies, reflecting DTEE’s maintenance and replacement
obligations in an orderly way, and a clear policy as to any CIAC requirement and how it
is to be calculated. There should also be some review and consideration given to the
appropriate charges for customers who took service under the EELT, given the
contributions they have already made. DTEE should also explain why continued
investment in the group replacement of metal halide lights is reasonable and prudent.
Mr. Jester’s testimony also raises concerns of MSLC members that it
acknowledges are outside the scope of a general rate case, including billing and cost of
671
See 8 Tr 1864-1867.
See 8Tr 1868.
673
See 8 Tr 1869-1871.
672
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service concerns.674 While MSLC ask the Commission to require an audit of the
company’s lighting program, this PFD recommends that MSLC work with Staff to see if
Staff can facilitate resolution of these disputes, either in or outside of a collaborative
process. If Staff is unable to resolve any significant concern(s), MSLC may bring the
matter(s) to the Commission’s attention through a formal complaint.
In the meantime, this PFD recommends that the Commission adopt MSLC’s and
Staff’s recommendation that the existing rates simply be adjusted by an equal
percentage until the Commission approves a reasonable alternative is appropriate.
I.
Residential and Commercial Distribution charges
This is the first rate case following Case No. U-17689, in which the parties
generally agreed with and the Commission accepted DTEE’s proposal to set distribution
rates by voltage level. Mr. Isakson testified that Staff supports moving the secondary
distribution rates for commercial and residential customers toward parity. Following up
on Staff’s recommendations in Case No. U-17689 on this issue, Mr. Isakson testified to
the cap Staff recommends for commercial secondary distribution rates:
Commercial secondary rates were designed at the direction of Staff
witness Revere to remain consistent with Staff’s position in MPSC Case
No. U-17689, which was a proceeding to implement the provisions of
Public Act 169 of 2014 regarding the Company’s cost allocation method.
In light of the non-zero revenue deficiency found by Staff in the instant
case, rate increases to commercial secondary distribution rates were
capped at 30%, rather than the ten percent cap Staff proposed in MPSC
Case No. U-17689 (which assumed no change in revenue requirement).
Staff witness Revere described the ten percent upper limit in his direct
testimony in that case as follows, and Staff supports the same
recommendation in the instant case:
“For certain rates within the secondary class, moving to a singleclass [distribution] rate would have resulted in an unreasonable
674
See Jester, 8 Tr 1875 .
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increase. For this reason, Staff capped the increase in any
distribution rate to 10%, though the intent is for the Company’s
distribution rates to continue moving toward in-class parity in future
proceedings.” (MPSC Case No. U-17689, 3 TR 433, lines 17-21).675
In its brief, Staff clarifies that Mr. Isakson used a 20% cap, rather than a 30% cap.676
Ms. Rivera explained Staff’s recommended 20% cap on residential secondary
distribution rates:
Residential rates were designed at the direction of Staff witness Revere to
remain consistent with Staff’s position in MPSC Case No. U-17689, which
was a proceeding to implement the provisions of Public Act 169 of 2014
regarding the Company. In light of the revenue deficiency found by Staff in
the instant case, increases to residential distribution rates were capped at
20%, which is higher than the 10% cap that Staff witness Revere
proposed in MPSC Case No. U-17689 by the average distribution
increase Staff recommends for the residential class. Staff’s proposed cap
also reflects Staff’s allowance for an additional 5 percentage points to be
added to the cap due to rate schedule elimination proposals.677
In recommending movement toward distribution rate parity, Staff clarifies that it does not
recommend that the commercial and residential classes be combined into a single
class.678
In its order in Case No. U-17689, the Commission endorsed Staff’s proposal to
cap the distribution rate increases at 10%.
The Commission also stated:
“The
Commission agrees that the goal of intra-class parity for distribution rates is important
and further agrees with the company that this issue should be addressed in the
company’s pending rate case and in future cases.”679 This PFD finds that Staff’s
recommended 20% cap is reasonable in light of the circumstances presented in this
675
See 8 Tr 1979.
See Staff brief, page 67.
677
See 8 Tr 1996-1997.
678
See Staff reply brief, page 30.
679
See June 15, 2015 order, page 31.
676
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case, to reflect both an increase in DTEE’s revenue requirement and the revised
voltage-based allocation methods adopted in Case No. U-17689.
J.
Low Income residential tariffs
DTEE proposes to modify the Residential Income Assistance provision by
increasing the monthly credit, and adding a Pilot Low Income tariff, Rate D1.6. Mr.
Williams explained DTEE’s proposal to increase the RIA credit to offset DTEE’s
proposed increase in the customer charge. Ms. Tomina testified regarding the pilot:
This tariff will offer qualifying Low Income electric customers a $40.00 per
month credit on their bill. Electric customers who select this rate must
qualify for the Residential Service rate D1 and must have been billed by
DTE Electric $1,700 or less over the last 12 months for electric service. To
qualify for this rate, an electric customer must also provide annual
evidence of receiving a Home Heating Credit (HHC) energy draft or
warrant, or must provide confirmation by an authorized State or Federal
agency verifying that the electric customer's total household income does
not exceed 150% of the poverty level as published by the United States
Department of Health and Human Services or if the electric customer
receives any of the following: i) assistance from a state emergency relief
program; ii) food stamps; or iii) Medicaid.680
She explained the basis for the $1700 limit:
The average bill amount for electric customers in the city of Detroit is
$1,700 per year. This amount was selected to ensure that the credit would
be effective in helping electric customers successfully manage their
electric bills. As electric customers’ bills increase above a certain amount,
the credit becomes less effective because the total amount owing may still
be too high for them to manage.681
She testified that participation in the pilot would be capped at 32,000 customers, with a
total cap on participation in both programs limited to 55,000, which is the number of
customers participating in DTEE’s current RIA program. She further testified that DTEE
680
681
See 7 Tr 1415-1416.
See 7 Tr 1416-1417.
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views the pilot as an opportunity for DTEE to gain knowledge and identify best practices
for serving low income customers. Mr. Williams testified:
The D1.6 Pilot is designed such that customers who qualify for the rate will
pay the same rates as D1 customers do, with the only difference being
that D1.6 customers will receive a $40 monthly bill discount. The cost of
the discount provided to D1.6 customers is proposed to be recovered from
all rate classes in the same manner the current senior discount and RIA
discounts are recovered.
Ms. Rivera explained that Staff supports the modification to the Residential
Income Assistance Provision, with one exception, and supports the pilot tariff, including
DTEE’s proposal to limit the pilot to 32,000 customers. Staff’s sole objection to DTEE’s
Residential Income Assistance Provision is that Staff does not believe there should be a
limit on the number of eligible customers able to receive the credit.
Mr. Rábago also testified that participation should not be capped, presenting the
following information:
The US Census reports that the average household poverty rate in
Michigan is 16.8%. This suggests that of the 1,925,000 DTE customers,
the Company serves nearly 120,000 households, or about 300,000 people
living at or below the federal poverty line. The low income pilot Rate D1.6
extends eligibility to 1.5 times the federal poverty rate, and combined with
the RIA provides assistance to only 55,000 customers in total, leaving tens
of thousands of customers living in poverty unable to use the low income
benefits that the Company offers.682
In his rebuttal testimony, Mr. Stanczak explained that DTEE needs to limit its
financial exposure, testifying that if rates are set on the basis of 55,000 participants in
the total programs, any excess participation will subject the company to undue financial
harm until new base rates are established. He recommended that if the Commission
682
See 7 TR 1791-1792.
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decides to increase the cap, that the participation levels be assumed to be higher than
DTEE’s calculations assume.683 DTEE’s brief relies on Mr. Stanczak’s analysis.
In its brief, Staff acknowledges both Mr. Rábago’s testimony and Mr. Stanczak’s
testimony and responds:
Staff believes that the majority of interested, eligible customers should
already be on D1.6. Therefore, it does not seem plausible that there would
be such a large influx of new customers that it would cause undue
financial harm to the Company. That said, there are surely some lowincome customers who would like to take advantage of RIA and are
currently unable to do so. For the reasons given herein, Staff recommends
that the ALJ and the Commission lift the cap related to D1.6.
In its reply brief, Staff revises this to clarify that its position is there should no cap on the
RIA credit, not that there should be no cap on the pilot Rate D1.6.
This PFD finds that Staff’s recommendation to reject a cap on the RIA credit for
eligible customers is reasonable. DTEE currently does not have a cap on participation
in the RIA, and such a cap raises questions regarding how new customers will be
chosen, once the cap is reached and an opening becomes available.
K.
Senior Citizen provisions
DTEE proposes to eliminate the Senior Citizen Residential Service Rate D1.3.
Mr. Williams testified:
There are approximately 134,000 customers taking electric service
pursuant to rate D1.3, or approximately 6.9% of residential customers.
This rate is available to customers who are at least 62 years old and head
of the household. The Company is proposing to eliminate this rate and
instead offer the Residential Service Senior Citizen Provision, which I
describe later in my testimony. As noted by Witness Stanczak, Rate D1.3
only benefits seniors who consume a certain level of electricity. If
consumption exceeds approximately 700 kWh per month, rate D1.3
results in a higher bill than the standard D1 residential service rate would.
Some senior citizens do not realize this when evaluating their options. As I
683
See 4 Tr 168-169.
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will describe later in my testimony, the Residential Service Senior Citizen
Provision being proposed in this case is easier to understand and would
provide a benefit to all senior citizens who choose to participate, not just
the customers consuming less than 700 kWh per month. Elimination of
rate D1.3 will also simplify the residential rate offerings for both customers
and the Company. The assumption in this case is that D1.3 customers will
migrate to the standard residential rate D1 and take advantage of the
proposed Residential Service Senior Citizen Provision.684
Instead, DTEE proposes a Senior Citizen bill credit of $4 per month, for all heads of
household 65 or older, with the discount amount to be recovered from other customers
the same way as the low income discount.
Staff agrees with DTEE’s proposal, recommending a $3 per month credit to
match Staff’s recommended customer charge of $6.685
Mr. Rábago reviewed DTEE’s rationale for the change. He testified that he
disagrees with DTEE’s argument that the current rate only benefits customers who use
a certain amount of electricity (less than 700 kWh per month) because the rate enrolls
customers in appliance control opportunities that could help control usage: “Given the
inclining block rate structure of Rate D1.3, the value of reductions is substantially higher
for high-use customers than for low-use customers, sending a positive and powerful
price signal.”686 He testified that he disagrees with DTEE’s argument that some
customers don’t understand the consequences of using more than 700 kWh:
The Company produced no actual evidence regarding customer
understanding of the current rate. The failure of customers to understand
a rate points more to a failure to educate and advise customers than to
any flaw in the rate design.687
684
See 6 Tr 1115-1116.
See Rivera, 8 Tr 1997.
686
See 7 Tr 1795.
687
See 7 Tr 1795.
685
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M/N/S object to eliminating Rate D1.3. They argue the elimination of this
provision is regressive, would discourage conservation and eliminate a positive price
signal, and would forfeit an existing opportunity for demand reduction.
This PFD finds that DTEE’s proposal is reasonable. Consistent with Mr.
Rábago’s testimony, reducing the monthly customer charge also reduces the regressive
nature of the rate structure, and customers still have an incentive to conserve. DTEE
has been directed to revise its tariffs so that time-of-use rates and dynamic pricing are
available to all customers who have had AMI for at least a year who wish to opt in.
Hopefully, in the course of this endeavor, there will be additional opportunities for senior
citizens to have incentives for conservation.
L.
Residential Time of Day
DTEE proposed to increase the current cap on participation in this rate from
10,000 to 20,000 customers, and remove average monthly usage requirements.
Williams related this proposal to its proposal to eliminate Rate D1.4:
It is assumed D1.4 customers will switch to D1.2 service since it is the
most similarly structured residential time of day tariff offered by the
Company. The Company is proposing to decrease the D1.2 service
charge from its current level of $19 per month to $10 per month in this
case in order to make it consistent with the D1 service charge, which
should help accommodate customers that switch from D1.4 to D1.2. It is
also relevant to note that the D1.2 rate proposal, shown on Exhibit A-14,
Schedule F3, page 4, takes into consideration on lines 12 and 27 tariff
change adjustments. These adjustments (which I explained previously in
my testimony on pages 4-5) have a downward effect on the proposed
D1.2 rates, and are attributable to the assumption that if D1.4 is
eliminated, customers will migrate to D1.2.688
688
See Williams, 6 Tr 1117.
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Mr.
Ms. Rivera and Mr. Matthews explained the basis for Staff’s recommendation
that the cap be removed completely to maintain consistency with Staff’s goals for Timeof-Day rates, and demand response in general.689
Mr. Williams provided rebuttal:
Given these changes and the effect that they have on D1.2’s current
construct, the Company does not feel that it would be appropriate at this
time to remove the D1.2 customer cap. The Company recommends the
D1.2 customer cap be doubled from 10,000 to 20,000 in this case as it
originally proposed. The Company may evaluate the D1.2 customer cap in
a subsequent rate case, once it has customer data relative to the D1.2
construct that results from this case. Should the Company’s proposed
20,000 customer cap be reached, the Company notes that it offers other
residential rate schedules with time of day pricing to interested customers,
such as Rate Schedule D1.8 (Dynamic Peak Pricing Rate, available to any
customer with an AMI meter), D1.7 (Geothermal Time of Day Rate), and
D1.9 (Electric Vehicle Rate). 690
In its brief, Staff explains:
While Staff understands that there is some potential for revenue effects
due to potential customer switching, two factors mitigate this risk. First,
there is no evidence to suggest there will be a flood of customers pouring
in to D1.2, and there is no reason to believe that there will be. Second, the
structure of the rates should reflect the costs generated in the periods
covered. Any change in usage that affects revenue should have an
offsetting effect on costs. Even if the inclusion of fixed costs in the energy
charge means that the cost reductions may not completely offset the
revenue reductions, the risk of revenue impacts is still relatively low.
Accordingly, Staff recommends that the Commission deny the Company’s
request to increase the cap, and instead order the cap removed.691
In its reply brief, DTEE argues that if it is unlikely the cap will be reached, there is no
reason to remove the cap. This PFD finds that DTEE’s proposal for a cap for this rate
appears reasonable under the circumstances, but DTEE should be required to notify
689
See Rivera, 8 Tr 1995, Matthews, 8 Tr 2215-2216.
See 6 Tr 1129-1130.
691
See Staff brief, page 85.
690
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Staff when enrollment reaches 15,000, so that Staff can evaluate whether to seek a
modification of the cap at that time.
M.
Rate D1.8
DTEE proposes to remove the word “experimental” from its Rate D1.8
Experimental Dynamic Peak Pricing Rate, and to eliminate the current customer cap.
Mr. Williams testified that to make the rate more marketable to customers, DTEE is also
proposing to reduce the critical peak pricing rate from $1.00 per kWh to $0.95 per kWh,
and to require customers electing this rate to remain on it for at least 12 months.692 Ms.
Rivera testified that Staff supports the company’s proposal as consistent with its
demand response goals.693 No party objected, and these proposals should be adopted.
N
Standard Contract Rider 16 (Net Metering)
Ms. Baldwin testified that Staff is recommending a change to the treatment of
time-of-use net metering credits, so that net excess generation credits carried over from
one time-of-use period to another are only used in a time period that has a lower per
kWh rate than the time period where the credit was created.694 She explained that under
the current tariff, customers may build up a balance of credits in the summer on-peak
time period that they will never use because they will continue to generate more solar
energy than they use during those time periods. She testified that Staff’s
recommendation is consistent with the Commission’s Electric Interconnection & Net
Metering Standards. Mr. Williams provided rebuttal testimony disputing Staff’s proposed
change, asserting that the current Rider 16 tariff language is clear, and expressing a
692
See 6 Tr 1123-1124.
See 8 Tr 1996.
694
See 8 Tr 2117.
693
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concern that Staff’s proposal could cause some confusion and complications for
customers, and could make some customers worse off.695
Addressing Mr. Williams’s rebuttal testimony in its brief, Staff argues that Mr.
Williams did not establish that his concern customers could be worse off was likely to
happen.696 This PFD recommends that Staff’s tariff modification be adopted.
O.
Rates D2, D1, D1.3, D1.4, D1.5
DTEE proposed to eliminate several residential rate schedules, D1, D1.3, D1.4,
D1.5, and D2, as well as options II and III for Rate D5, and Standard Contract Rider No.
14. Staff agrees to all of these requests except regarding Rate D2. Ms. Rivera
explained:
The customers on D2 are differently situated than customers on D1 from a
power supply perspective, which makes the power supply costs allocated
to the D1 rate not reflective of the costs to serve D2 customers. Therefore,
Staff recommends keeping D2. Power supply rates for D2 were designed
to collect a provisional revenue requirement, as described by Staff witness
Revere. 697
DTEE agrees to maintain the rate if it can be closed to new customers. Staff accepts
DTEE’s recommendation, with the proviso that the grandfathering applies to service
addresses, so if a property changes hands, the rate is still available to the new owner or
occupant. In its reply brief, DTEE accepts Staff’s recommendation.698 On this basis,
this PFD recommends that the modification to Rate D2 supported by Staff and DTEE be
adopted.
695
See 6 Tr 1131-1133.
See Staff brief, pages 109-112.
697
See 8 Tr 1996.
698
See DTEE reply brief, page 146.
696
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P.
Undisputed Items
In addition to the items addressed above, there appears to be no dispute
regarding the following items.
1. Rate D3.1
MCTA’s brief focused on ensuring that stale data is not used in determining this
unmetered rate. MCTA argued that DTEE used stale data to determine the percentages
of power supply and distribution revenue. MCTA cited DTEE’s acknowledgement that
the calculation should be changed before rates are set to use the updated final revenue
split.699 Staff witness Mr. Isakson testified that Staff used the updated power supply and
distribution revenue split.700 There appears no further dispute.
2. Rates E15.1, E15.3, E1.5 and E17
DTEE also proposes minor changes to the E15.1, E15.3, E1.5 and E17 Retail
Access Service Rider.701 There appears to be no dispute that these proposed changes
should be adopted.
3. D5 Water Heating Service
DTEE also proposes to eliminate Options II and III of the D5 water heating
service rate. There appears to be no objection to this proposal.702
699
See Exhibit MCTA-1.
See Isakson, 8 Tr 1980.
701
See DTEE brief, page 135; DTE reply brief, page 128; 4 Tr 522, 562-563.
702
See Holmes, 6 Tr 968; Isakson, 8 Tr 1981-1982.
700
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4. Rate D1.7
DTEE also proposed to change the name of Rate D1.7 from “Space
Conditioning, Water Heating Time of Day Rate” to “Geothermal Time of Day Rate” and
to adjust its on peak period. Staff concurs in DTEE’s request. 703
5. VHWF credit
DTEE also proposed to eliminate the VHWF credit in conformance with the
Commission’s order in Case No. U-17027. Staff concurs in DTEE’s request.704
6. Rates E15.1, E15.3, E1.5, D17
DTEE also argues it is making minor revisions to its Retail Access Service
Rider,705 and believes there is no opposition to its proposals.706 No party has addressed
these rates, so this PFD concurs.
XII.
MISCELLANEOUS ISSUES
A.
Accounting Issues
Among the miscellaneous issues, DTEE requests certain accounting approvals
and authorities.
Some of these have already been addressed.
DTEE requests
approval of full normalization ratemaking for the change in the City of Detroit corporate
tax rate, which this PFD recommended the Commission grant as discussed above.
DTEE requests approval to defer negative OPEB expenses, which this PFD
703
See Isakson, 8 Tr 1985.
See Isakson, 8 Tr 1982-1983.
705
See Bloch, 4 Tr 552, 562-63
706
See DTEE reply brief, page 128.
704
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recommended be granted as discussed above.
DTEE also requests accounting
approval for the amortization of deferred expenses associated with its plug-in vehicle
program.
This PFD also recommended the Commission grant this approval, as
discussed above in connection with amortization.
DTEE also seeks accounting approval for its SRP and ESRP plan expenses,
which this PFD recommended be denied, as explained above.
And DTEE seeks
approval to amortize deferred COLA costs, which this PFD recommended be denied, as
explained above.
Additionally, as explained by Ms. Uzenski at 6 Tr 1056-57, DTEE requests a
temporary plant account for lower cost computer equipment to be depreciated over five
years until reviewed in a subsequent depreciation case. No party opposed this request,
and this PFD recommends it be granted.
B.
Reporting Issues
As discussed above, Staff’s recommendation regarding DTEE’s EVMP program
includes a recommendation that DTEE collect data and provide reporting.707 Mr. Brian
Sheldon also explained Staff’s request that DTEE provide periodic reports on its cybersecurity measures.708 This PFD finds these requests uncontroversial and recommends
they be adopted.
707
708
See 8 Tr 2098.
See 8 Tr 1940-1942.
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C.
Workgroup
Staff also requests that the Commission create a standby rate working group, as
explained by Ms. Baldwin.709
This recommendation is reasonable and should be
adopted.
As discussed above, this PFD also recommended that the Commission
encourage DTEE to resolve outstanding issues regarding its municipal lighting tariff
through a collaborative, as requested by the MSLC, Staff and the Attorney General. The
arguments of the parties are set forth in section X.H and will not be repeated here.
D.
AMI cost-benefit analysis
DTEE also asks to be relieved of its continuing obligation to present a cost-
benefit analysis of its AMI program in each rate case.710 The Attorney General opposes
DTEE’s request.711 Staff also opposes the request, as explained in its brief.712 Mr.
Hudson’s testimony makes clear that Staff has found the information useful. This PFD
finds that continued cost-benefit analyses are a reasonable part of the customer
protections the Commission has put in place regarding the AMI program, and the costbenefit analyses will assist the Commission, Staff, and parties to evaluate the
company’s continued implementation of the program.
On this basis, this PFD
recommends that the Commission decline to grant DTEE’s request.
709
See 8 Tr 2119-2120.
See Sitkauskas, 5 Tr 731.
711
See Coppola, 9 Tr 2333.
712
See Staff brief, page 102.
710
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XII.
CONCLUSION
This PFD recommends that the Commission adopt the findings, conclusions and
recommendations set forth above. This PFD recommends that the Commission adjust
the company’s projected test year revenue deficiency in accordance with the rate base
recommendations set forth in section V, the capital structure and cost elements as set
forth in section VI, including an authorized return on equity of 10% and an overall cost of
capital of 5.58%, and Adjusted Net Operating Income as set forth in section VII,
resulting in an estimated revenue deficiency of approximately $159 million. This PFD
also recommends that the Commission adopt cost of service allocations consistent with
the Commission’s recent order in Case No. U-17689, design rates as discussed in
section XI above, to be applied to the final revenue requirement, and modify the tariffs,
grant and deny accounting approvals, and provide for reporting requirements and work
groups in accordance with the discussion above.
MICHIGAN
ADMINISTRATIVE
HEARING
SYSTEM
For the Michigan Public Service Commission
Sharon L.
Feldman
Digitally signed by Sharon L.
Feldman
DN: cn=Sharon L. Feldman, o, ou,
[email protected],
c=US
_____________________________________
Date: 2015.10.08 14:13:31 -04'00'
Sharon L. Feldman
Administrative Law Judge
Issued and Served: 10/08/15
drr
U-17767
Page 330
DTE Electric Company
MPSC Electric Rate Case No. U‐17767
PFD
Appendix A
Page 1
Weighted Average Cost of Capital - 10% Return on Equity
Line
No.
Description
Capital Structure
Percent
Permanent
Capital
Amounts
($000)
Weighted Costs
Percent
of Total
Capital
Cost
Rate %
Permanent
Capital
Total
Cost %
Conversion
Factor
Pre-Tax
Return
1
Long‐Term Debt
5,165,318
50.00%
38.03%
4.56%
2.28%
1.73%
100.000%
1.7343%
2
Preferred Stock
0
0.00%
0.00%
0.00%
0.00%
0.00%
163.932%
0.0000%
3
Common Shareholders' Equity
5,164,758
50.00%
38.03%
10.00%
5.00%
3.80%
163.932%
6.2340%
4
Total
10,330,076
100.00%
5
Short‐Term Debt
6
7
8
Job Development ‐ ITC ‐ Debt
Job Development ‐ ITC Equity
Total Job Development ‐ ITC 9
Deferred Income Taxes (Net)
10
11
7.28%
299,475
2.21%
1.43%
0.03%
100.000%
0.0316%
12,885
0.09%
0.09%
4.56%
10.00%
0.00%
0.01%
100.000%
163.932%
0.0043%
0.0156%
2,926,181
21.55%
0.000%
0.00%
0.0000%
Total
13,581,502
100.00%
5.5825%
8.0198%
Rate Base
13,581,502
12,885
25,770
DTE Electric Company
MPSC Electric Rate Case No. U‐17767
Projected Net Operating Income Test Year Ending June 30, 2016
$(000)
PFD
Appendix B
Page 1 of 1
Revenues
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Description
(a)
Staff Filed
Operating Income
Sales
(b)
$
4,358,714
Wholesale
(c)
$
Misc.
(d)
-
$
70,683
Fuel
P&I
(f)
Total
(e)
$
4,429,397
$
1,444,186
ALJ Adjustments
COLA Amortization
Limestone Expense
Forestry
SERP
Uncollectibles
Corporate Support Group
Injuries and Damages
CARS
Inflation
East China
Property Tax
Depreciation Expense
O&M
(g)
$ 1,175,987
Depr.
(h)
$
651,360
$
(10,186)
$
641,174
Expenses
Property &
State and
Other Tax Municipal Tax
(i)
(l)
$ 287,929
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2,600
(7,100)
(5,000)
(300)
15,000
(1,100)
Proforma Interest
Interest Synchronization
Net Operating Income
$
4,358,714
$
-
$
70,683
$
4,429,397
$
1,444,186
$ 1,180,087
$
$ 287,929
$
55,228
627
(160)
437
308
18
(923)
68
110
55,712
FIT
(m)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
201,092
Other Income
Adjustments
$
3,346
(854)
2,332
1,642
99
(4,927)
361
1
593
203,685
NOI
(n)
(3,956) $
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(3,956) $
609,659
AFUDC
(o)
$
35,730
6,214
(1,586)
4,331
3,050
183
(9,150)
671
(1)
(703)
612,668
Adjusted NOI
(p)
$
$
$
35,730
$
645,389
6,214
(1,586)
4,331
3,050
183
(9,150)
671
(1)
(703)
648,398
DTE Energy Company
MPSC Electric Rate Case No.17767
Revenue Deficiency (Sufficency)
Test Year Ending June 30, 2016 $(000)
Line
Description
(a)
PFD
Appendix C
Page 1 of Staff Projection ALJ Adjustments
(d)
ALJ Projection (e)
1
Rate Base
13,456,612
(105,375)
13,351,237
2
Adjusted Net Operating Income
645,335
3,063
648,398
3
Overall Rate of Return
4
Rate of Return
5
Income Requirements
751,449
(6,116)
745,333
6
Income Deficiency (Sufficiency)
106,114
(9,179)
96,935
7
Revenue Conversion Factor
‐
1.6393
8
Revenue Deficiency (Sufficiency)
(15,047)
158,906
.
4.80%
0.06%
4.86%
5.5842%
‐0.0017%
5.5825%
1.6393
173,953