notice of proposal for decision - michigan · environmental council (mec), the sierra club (sc),...

S T A T E O F M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * * In the matter of the application of ) Consumers Energy Company for ) Case No. U-18322 authority to increase its rates for ) the generation and distribution of ) electricity and for other relief. )

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 January 8, 2018.

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 January 29, 2018, or within such further period as may be authorized for filing

exceptions. If exceptions are filed, replies thereto may be filed on or before February 12,

2018. 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 Administrative Law Judge

January 8, 2018 Lansing, Michigan

S T A T E O F M I C H I G A N

MICHIGAN ADMINISTRATIVE HEARING SYSTEM

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

* * * * * In the matter of the application of ) Consumers Energy Company for ) Case No. U-18322 authority to increase its rates for ) the generation and distribution of ) electricity and for other relief. )

PROPOSAL FOR DECISION

Issued and Served: January 8, 2018

TABLE OF CONTENTS Page

I. HISTORY OF PROCEEDINGS ....................................................................... 1

II. OVERVIEW OF THE RECORD AND POSITIONS OF THE PARTIES ........... 6

A. Consumers Energy ......................................................................................... 6

B. Staff ............................................................................................................... 29

C. Attorney General ........................................................................................... 39

D. ABATE .......................................................................................................... 41

E. MEC/NRDC/SC ............................................................................................. 42

F. MEC/NRDC/SC, ELPC, and MCA ................................................................. 43

G. MCA .............................................................................................................. 46

H. Kroger ........................................................................................................... 47

I. Walmart ......................................................................................................... 48

J. HSC .............................................................................................................. 48

K. RCG .............................................................................................................. 49

L. Rebuttal ......................................................................................................... 50

III. TEST YEAR .................................................................................................. 71

IV. RATE CASE STANDARDS ........................................................................... 74

V. RATE BASE .................................................................................................. 81

A. Net Plant ....................................................................................................... 85

1. Contingency ....................................................................................... 86

Electric Distribution ............................................................................ 94

a. New Business .............................................................................. 99 b. Reliability .................................................................................... 101 c. Grid Modernization ..................................................................... 108 d. Demand Failures Program ......................................................... 115 e. Electric Operations - Other ......................................................... 120 f. Distribution System Contingency ............................................... 122 g. Ratemaking Mechanism ............................................................. 123

3. 2016 Meter-Estimation-Related Capital Expenses .......................... 127

4. Energy Resources (Generation) Capital Expense Projections ........ 129

a. RCRA ......................................................................................... 131 b. The Attorney General’s Additional Recommendations ............... 132 c. Medium 4 ................................................................................... 134

i. Staff ................................................................................. 135 ii. MEC/NRDC/SC ............................................................... 137 iii. Consumers Energy .......................................................... 142 iv. Discussion ....................................................................... 147 v. Contingency .................................................................... 156

5. Residential Demand Response ....................................................... 158

6. Information Technology (IT) ............................................................ 165

a. Staff Recommendations ............................................................. 165 b. Attorney General Recommendations ......................................... 169 c. Contingency ............................................................................... 171

7. Land Donation ................................................................................. 171

8. METC Easement ............................................................................. 171

9. Property Model Error ....................................................................... 172

B. Accumulated Provision for Depreciation .................................................... 173

C. Working Capital .......................................................................................... 173

1. Cash Balances ................................................................................ 174

2. Accrued Interest .............................................................................. 175

Page

VI. COST OF CAPITAL ................................................................................... 176

A. Capital Structure ........................................................................................ 176

B. Cost of Equity ............................................................................................. 186

1. Selection of a Proxy Group .............................................................. 188

2. Flotation Costs ................................................................................ 191

3. DCF Model ...................................................................................... 194 a. Consumers Energy .................................................................... 194 b. Staff ............................................................................................ 195 c. Attorney General ......................................................................... 195 d. ABATE ....................................................................................... 196 e. DCF Disputes ............................................................................. 197

4. CAPM/ECAPM ................................................................................ 198

a. Consumers Energy .................................................................... 199 b. Staff CAPM ................................................................................ 201 c. Attorney General ........................................................................ 201 d. ABATE ........................................................................................ 202 e. Disputes ..................................................................................... 202

5. Risk Premium .................................................................................. 205 a. Consumers Energy .................................................................... 205 b. Staff ............................................................................................ 205 c. Attorney General ......................................................................... 206 d. Disputes ..................................................................................... 206

6. Comparable Earnings Analysis ....................................................... 207

7. Other Authorized Returns ................................................................. 208

8. Discussion of Risk and other Factors .............................................. 210 a. Consumers Energy .................................................................... 210 b. Staff ............................................................................................ 212 c. Attorney General ........................................................................ 213 d. ABATE ....................................................................................... 215 e. Walmart ...................................................................................... 217

9. Evaluation ........................................................................................ 217

Page

C. Overall Cost of Capital ............................................................................... 230

VII. Adjusted Net Operating Income ................................................................. 230

A. Sales Forecast and Revenue ..................................................................... 230

1. Residential Sales ............................................................................. 230

2. RIA and RSC Customers ................................................................. 235

B. Fuel & Purchased Power Expense ............................................................. 236

C. Other O&M Expenses ................................................................................ 236

1. Projected Expense Savings ............................................................. 237

2. Electric Distribution O&M ................................................................. 240 a. Vegetation Management ............................................................ 240 b. Smart Energy - MTC .................................................................. 244

3. Energy Resources (Generation) O&M ............................................. 245 a. Environmental Operating Expense ............................................. 245 b. Avoidable Major Maintenance Expense ..................................... 250 c. Residential Demand Response Program ................................... 250

4. Information Technology ................................................................... 252

5. Employee Benefit Expense ............................................................. 253 a. PBGC Premiums ........................................................................ 254 b. Discount Rate ............................................................................. 255

6. Supplemental Retirement Plans ...................................................... 257

7. Uncollectible Accounts Expense ..................................................... 257

8. Injuries and Damages ...................................................................... 259

9. Payment Programs .......................................................................... 260

10. Customer Experience ...................................................................... 262

11. Incentive Compensation .................................................................. 265

METC Easement Revenue .............................................................. 268

D. Other Expenses ......................................................................................... 268

E. Adjusted Net Operating Income Summary ................................................. 269

VIII. OTHER REVENUE-RELATED ITEMS ....................................................... 269

A. Regulatory Asset for Demand Response Costs ......................................... 269

B. Other Demand Response Program Issues ................................................. 277

1. Residential Demand Response Program Parameters ..................... 277

2. Accounting ....................................................................................... 281

3. Commercial and Industrial Customer Program ................................ 282

C. Smart Meter/AMI ......................................................................................... 283

D. Smart Meter Consumption ......................................................................... 284

E. Smart Grid Reporting Metrics ..................................................................... 286

F. On-line Interconnection Queue .................................................................. 287

IX. REVENUE DEFICIENCY SUMMARY ......................................................... 288

X. COST OF SERVICE, RATE DESIGN, AND TARIFF ISSUES ................... 289

A. Capacity Costs ........................................................................................... 289

B. Allocation of Residential Discounts ............................................................ 290

C. Demand Line Loss ..................................................................................... 291

D. Interruptible Credits .................................................................................... 294

E. Intersystem Sales Allocator ........................................................................ 294

F. Distribution System Cost Allocations .......................................................... 296

Page

G. Residential Rate Design ............................................................................. 300

H. RATE GPD ................................................................................................. 304

I. Rate GPD Transmission Costs .................................................................. 305

J. Rate GPD Voltage Levels .......................................................................... 305

K. Rate GPD/GP Crossing-point Adjustment .................................................. 306

L. Rate EIP ..................................................................................................... 307

M. Rate GSG-2 ............................................................................................... 307

N. Rate GSG-2 Power Supply Revenues ....................................................... 320

O. Customer-specific Delivery Charge ............................................................ 321

P. Commercial and Industrial Customer Rate Design .................................... 327

Q. AMI Opt-Out Tariff ...................................................................................... 330

1. RCG Request to Eliminate Opt-out Charges ................................... 330

2. Consumers Energy Request to Revise Tariff Language .................. 331

XI. OTHER MISCELLANEOUS ITEMS ............................................................ 333

XII. CONCLUSION ........................................................................................... 333

Attachment ……………………………………………………………….. Appendix A

Attachment ……………………………………………….………………. Appendix B

Attachment ……………………………………………………………….. Appendix C

Attachment ……………………………………………………………….. Appendix D

S T A T E O F M I C H I G A N

MICHIGAN ADMINISTRATIVE HEARING SYSTEM FOR THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * * In the matter of the application of ) Consumers Energy Company for ) Case No. U-18322 authority to increase its rates for ) the generation and distribution of ) electricity and for other relief. )

PROPOSAL FOR DECISION

I.

HISTORY OF PROCEEDINGS

On March 31, 2017, Consumers Energy Company (Consumers Energy) filed a

rate application requesting a $173 million revenue increase, and other relief. The

application relies on an October 1, 2017 through September 30, 2018 projected test

year. The Commission issued its order in the company’s most recent prior rate case,

Case No. U-17990, on February 28, 2017.

At the May 9, 2017 prehearing conference, Staff, Consumers Energy, and

potential intervenors appeared.1 Intervention was granted to the Michigan Department

of the Attorney General (Attorney General), the Kroger Company (Kroger), Michigan

Environmental Council (MEC), the Sierra Club (SC), Natural Resources Defense 1 No one appeared to present comments under Rule 207 of the Commission’s rules of practice and procedure. Also, counsel for Wal-Mart Stores East, LP and Sam’s East, Inc. did not attend the prehearing conference.

U-18322 Page 2

Council (NRDC), Association Of Businesses Advocating Tariff Equity (ABATE), Gerdau

Macsteel, Inc. (Gerdau), Hemlock Semiconductor Operations LLC (HSC), Constellation

NewEnergy, Inc., Environmental Law & Policy Center (ELPC), Energy Michigan, Inc.,

Michigan State Utility Workers Council, Utility Workers Union Of America, AFL-CIO, the

Residential Customer Group (RCG), Midland Cogeneration Ventures, LP (MCV), and

the Michigan Cable Telecommunications Association. At the prehearing conference,

the parties agreed to a 12-month schedule meeting the applicable time limits of

MCL 460.6a. Following the prehearing, a ruling on the timely petition to intervene of

Wal-Mart Stores East, LP and Sam’s East, Inc. (Walmart) was deferred and granted on

May 16, 2017; a protective order was entered on May 16, 2017; and a May 22, 2017

ruling granted the Petition to Intervene Out-of-Time of Midwest Cogeneration

Association (MCA).

On May 11, 2017, the Commission issued an order jointly in this docket and

several other dockets addressing the requirements of MCL 460.6w of 2016 PA 341.

Following this order, ABATE and the RCG filed motions addressing the portion of

Consumers Energy’s filing related to these requirements. ABATE’s June 9, 2017

Motion for Summary Disposition sought dismissal of the rate application in its entirety

due to the alleged lack of billing determinants for the proposed generation capacity

charge, and in the alternative, that Consumers Energy be directed to amend its filing,

with the amendment considered significant under MCL 460.6a to extend the case-

processing deadline. The motion was accompanied by the affidavit of Jeffrey Pollack.

The RCG’s May 25, 2017 Motion to Requirement Amendment of Rate Filing or In the

Alternative, Motion to Dismiss contended that allowing the capacity-charge-related

U-18322 Page 3

component of the company’s case to remain created the possibility of confusion and

duplicative recovery. Consumers Energy and Staff each filed a written response to the

motions on June 23, 2017. While the Administrative Law Judge set a hearing date of

June 27, 2017 for oral argument on both these motions, the RCG did not file a notice of

hearing for its motion, and did not attend the motion hearing. On July 12, 2017, before

the ALJ ruled on ABATE’s motion, the Commission issued an order granting rehearing

and clarifying its May 12, 2017 order. On July 18, 2017, the ALJ issued a ruling denying

ABATE’s motion for the reasons stated in the ruling, and providing that the RCG’s

similar motion would only be heard if the RCG filed a brief distinguishing its motion from

the motion addressed in the ruling.

On July 6, 2017, MEC and the Sierra Club (MEC/Sierra Club) filed two motions, a

Motion to Compel Discovery, and a Motion to Unseal Certain Exhibits. MEC/Sierra club

subsequently withdrew the discovery motion. The Motion to Unseal Certain Exhibits

sought to exclude six exhibits relating to Consumers Energy’s analysis of retirement

scenarios for four of its coal-fired generating units referred to as “the Medium 4”. After

Consumers Energy’s July 12, 2017 written response, which included the affidavit of

Timothy J. Sparks, and after the July 14, 2017 oral argument, the ALJ issued a ruling on

July 24, 2017, granting the motion to unseal and delaying the effective date to the start

of cross-examination.

In accordance with the schedule set at the prehearing conference, Staff, ELPC,

MEC, SC, NRDC, MCA, HSC, Walmart, ABATE, Kroger, the Attorney General, and the

RCG filed testimony on August 10, 2017. Some testimony was jointly filed on behalf of

multiple parties. On August 15, 2017, the RCG filed a Motion for the Filing of the

U-18322 Page 4

Testimony of William S. Bathgate Out of Time, along with the proposed testimony and

exhibits. Following written responses by Staff and Consumers Energy on August 24,

2017, and an August 28, 2017 reply by RCG, oral argument was held on the motion on

August 28, 2017. At the hearing, the ALJ permitted the filing of a portion but not all of

the proposed testimony and exhibits for the reasons explained on the record.

On August 10, 2017, Consumers Energy also filed the testimony and exhibits of

Michael A. Torrey addressing its proposed self-implementation. With no other self-

implementation-related filings, the testimony was bound into the record on August 18,

2017, with Exhibits SI-1 and SI-2 admitted into evidence.2 Consumers Energy’s

August 24, 2017 brief was the only brief filed to address self-implementation, and this

record was transmitted to the Commission on the same date that brief was filed.

Consumers Energy, Staff, ABATE, HSC, and Kroger filed rebuttal testimony on

September 7, 2017. Three motions to strike testimony were filed: Consumers Energy

moved to strike the testimony of RCG witness William A. Peloquin; Staff moved to strike

a portion of the rebuttal testimony of Consumers Energy’s cost of capital witness,

Srikanth Maddipati; and ABATE filed a motion to strike portions of the rebuttal testimony

of Consumers Energy’s witness Josnelly C. Aponte regarding capacity costs and

charges. Consumers Energy filed written responses to each motion and they were

argued during the evidentiary hearings in advance of each witness’s testimony.3 Also,

MEC and NRDC (MEC/NRDC) filed a motion to permit the surrebuttal testimony of their

2 The self-implementation testimony is included in transcript volume 5. 3 The motions to strike Mr. Peloquin’s testimony and Ms. Aponte’s testimony were denied; the motion to strike limited portions of Mr. Maddipati’s rebuttal testimony was granted.

U-18322 Page 5

witness Douglas B. Jester. Consumers Energy also filed a written response to this

motion, and it was also addressed during the evidentiary hearings.4

Evidentiary hearings were held on September 26-29 and October 2-4, 2017.

Twenty-four witnesses appeared and were cross-examined on their testimony, while the

testimony of the remaining 27 witnesses was bound into the record without the need for

them to appear. On October 13, 2017, Consumers Energy filed a motion to correct the

transcript, which is addressed in this Proposal for Decision. The following parties filed

briefs on November 1, 2017: Consumers Energy; Staff; the Attorney General; HSC;

CNE; Walmart; Kroger; ELPC; and MEC, NRDC, and SC collectively (MEC/NRDC/SC).

ABATE and Gerdau (ABATE/Gerdau) filed a brief and a corrected brief on November 2,

2017, but served all parties the uncorrected version on November 1. Two additional

parties filed briefs the following day, MCA and RCG, and filed motions to admit the late-

filed briefs, with explanations for the delay. By agreement of the parties, to resolve a

potential dispute over the late filings, the deadline for reply briefs was extended from

Friday, November 17, 2017 to Monday, November 20, 2017. The following parties filed

reply briefs: Consumers Energy, Staff, the Attorney General, HSC, ELPC,

MEC/NRDC/SC, ABATE/Gerdau, MCA, RCG, and Energy Michigan.

The evidentiary record in this proceeding is contained in 2797 pages of transcript

and 448 exhibits admitted into evidence. This PFD follows the standard organization:

after an overview of the record in section II and a review of rate case standards in

section III, rate base elements are discussed in section IV; the cost of capital is

4 The ALJ’s ruling permitted only a portion of Mr. Jester’s proposed surrebuttal testimony. See 6 Tr 257-258. Subsequently, Consumers Energy and MEC/NRDC/SC agreed that the entire proposed surrebuttal testimony would be admitted, and that Consumers Energy’s sur-surrebuttal testimony of Ms. Collins would also be admitted. See 7 Tr 845-848. None of the parties objected to this agreement.

U-18322 Page 6

discussed in section V, adjusted net operating income is discussed in section VI, the

revenue deficiency calculation is reviewed in section VII, other revenue-related issues

are discussed in section VIII, the cost of service allocation issues are discussed in

section IX, and rate design and tariff issues are discussed in section X.

II.

OVERVIEW OF THE RECORD

The discussion that follows reviews the direct testimony presented by each party,

and then reviews the rebuttal testimony. This section is intended to provide a general

overview; the record is discussed in further detail as necessary in the subsequent

sections.

A. Consumers Energy Consumers Energy reduced its requested revenue increase from the $173 million

initially filed to $148 million in its initial brief, based in large part on positions the

company took in rebuttal testimony.5 The utility’s revised rate request is based on a

jurisdictional rate base of approximately $10.3 billion,6 a return on equity of 10.5% with

an overall cost of capital of 6.09%, and total projected operating expenses of

$3.7 billion, or $1.6 billion excluding $2.1 billion in fuel costs. Consumers Energy

presented the testimony of 24 witnesses and 137 exhibits in support of its rate request.

The direct testimony is reviewed briefly below, while the rebuttal testimony is reviewed

in section L. Cross-examination testimony is discussed throughout as necessary to

describe and resolve disputed issues. 5 See Consumers Energy brief, Appendix A ($147,666,000 on a jurisdictional basis). 6 See Consumers Energy brief, Appendix B ($10,258,460,000).

U-18322 Page 7

Mr. Torrey is Vice President of Rates and Regulation for Consumers Energy.7 He

provided an overview of the company’s request in his direct testimony. After discussing

the company’s commitment to “customer value,” including safety, reliability, value

reflected in both price and service, and sustainability, he testified that Consumers

Energy has a goal to achieve first-quartile rankings in all four J.D. Power Utility

Customer Satisfaction Studies by the end of 2017, and described its progress toward

that goal.8 Mr. Torrey also identified the driving factors behind the company’s request.

He indicated that $47 million is attributable to infrastructure investments in generation

supply reliability, new business, grid modernization, a distribution-system capacity

program and a demand failures program, environmental compliance projects, and

enhanced technology programs.9 He also reviewed elements of the company’s

projected $56 million increase in O&M expenses from current rate levels, including

increases for line clearing, customer payment options, and a “lean operating system”

program called CE Way. Mr. Torrey also identified the company’s incentive

compensation program as designed to retain employees as well as enhance

performance on a variety of metrics. He described the company’s ongoing efforts to

minimize O&M cost increases through capital expenditures that will increase reliability,

minimize fuel costs, improve safety, reduce customer outages, support economic

growth and enhance the customer experience. Providing an overview of the testimony

of the other company witnesses, Mr. Torrey also reviewed the company’s recent capital

expenditures, presenting a chart to show that Consumers Energy’s average net plant

7 His testimony, including his rebuttal testimony and cross-examination, is transcribed at 7 Tr 610-667. As noted above, he also provided testimony on the company’s self-implementation plans as transcribed in volume 5. His qualifications are set forth at 7 Tr 614-616. 8 See 7 Tr 617-623. 9 See 7 Tr 624-629.

U-18322 Page 8

balances for 2014 and 2015 have exceeded approved amounts.10 Turning to the cost of

capital, Mr. Torrey testified that $37 million of the company’s request reflects the higher

requested return on equity and increases related to the capital structure, partially offset

by reduced long-term debt costs. And he testified that $42 million of the projected

increase is due to forecast sales reductions, partially offset by reductions in working

capital requirements.11 Mr. Torrey also noted the following items in the company’s filing

presented in part as a result of the Commission’s order in Case No. U-17990: the

analysis of the potential retirement of the Medium 4 units; the AMI business case

analysis; a review of the company’s capital structure plans; actuarial review of the

Pension and Other Postretirement Employee Benefits (OPEB); and consideration of

various rate design issues.12 He testified that the company has not completed its AMI

installation and is not recommending tariff changes at this point. He also testified that

the company witnesses have increased the information presented in support of capital

and O&M expenditures, while acknowledging that the company has not yet completed

its five-year distribution system plan.

Mr. Torrey testified regarding the customer impacts of the company’s proposal,

presenting benchmarks for comparison purposes. He also described the company’s

demand response proposals, and noted the company’s testimony regarding

capacity charges under MCL 460.6w.

Heidi Myers, Principal Rate Analyst in the Rates and Regulation Department of

Consumers Energy, presented the revenue requirements calculations supporting

10 See 7 Tr 635; the average net plant balances approved reflect the Commission’s May 15, 2013 decision in Case No. U-17087. 11 See 7 Tr 636. 12 See 7 Tr 636-641.

U-18322 Page 9

Consumers Energy’s filed revenue deficiency, as shown in Exhibit A-6, including the

development of its projected rate base of $10.3 billion, as shown in Exhibit A-7, and the

development of the adjusted net operating income of $529 million, as shown in Exhibit

A-8.13 Her exhibits include comparisons to the historical test year results. Ms. Myers

also presented one of Consumers Energy’s alternate proposal to recover the revenue

requirement associated with the company’s demand response programs through the

creation of a regulatory asset.14 She identified benefits from this approach, and

explained the mechanics of the company’s proposal, including reporting and

reconciliation.

Jason R. Coker, Senior Rate Analyst II in the Rates and Regulation Department

of Consumers Energy, presented the 2015 historical test year revenue requirement

calculation and the associated historical test year schedules in his Exhibits A-1 through

A-4.15 He reviewed adjustments to the historical adjusted net operating income

schedules to comply with prior Commission orders and to make traditional ratemaking

normalization adjustments for weather, unusual, one-time, out-of-period items, and

regulatory disallowances.

Eugene M.J.A. Breuring, Senior Rate Analyst II in the Rates and Regulation

Department of Consumers Energy, presented the company’s sales, demand, and

system output forecasts for the projected test year, supported by schedules in Exhibit

A-10.16 He identified the key variables he considered as affecting the electric deliveries

13 Ms. Myers adopted the testimony originally filed by James R. Fraga. Her testimony, including rebuttal and cross-examination, is transcribed at 7 Tr 752-845. Her qualifications are set forth at 7 Tr 784-785. 14 See 7 tr 774-782. 15 Mr. Coker’s testimony is transcribed at 7 Tr 912-921; his qualifications are set forth at 7 Tr 913-914. 16 Mr. Breuring’s testimony, including rebuttal and cross-examination, is transcribed at 8 Tr 1196-1231. His qualifications are set forth at 8 Tr 1201-1202.

U-18322 Page 10

and demand forecasts, explaining the importance of weather data and economic

indicators, and testifying that the company’s forecast are a combination of econometric

and end-use techniques. He testified that electric deliveries are expected to increase

0.4% per year from 2015 through the projected test year, and peak demand is expected

to decrease 1% per year from 2016 through 2021. His Schedules E2 and E3 of Exhibit

A-10 show projected deliveries and output for individual classes and for sales and

choice customers. He testified that the projections consider the energy efficiency

provisions of 2008 PA 295 and 2016 PA 341 and 342. He also testified that the

company’s total forecast electric deliveries are increased by a line loss factor of 7.45%

based on the 2015 system loss study to project total generation requirements as shown

in Schedule E3. His Schedule E4 shows projected peak load, while Schedule E5 has

the test year PSCR cost calculation.

Several witnesses presented testimony to support the company’s projected

capital and operating and maintenance (O&M) expense projections through the 2017-

2018 test year. Scott D. Thomas, Executive Director for Project Development at

Consumers Energy, testified to support the company’s inclusion of “contingency

expense” in its capital expense projections, particularly in the context of the capital

expense projections for the company’s generation resources, characterizing the

inclusion of contingency expense as legitimate and forecastable.17

Andrew J. Bordine is Executive Director for Grid Infrastructure for Consumers

Energy. He presented testimony reviewing the company’s electric distribution system

performance and programs, and in support of the company’s projected capital and O&M

expense projections for its distribution system. Mr. Bordine emphasized the importance 17 Mr. Thomas’s testimony, including his cross-examination, is transcribed at 7 Tr 894-909.

U-18322 Page 11

of distribution system maintenance in providing safe and reliable service, testifying there

is a direct and measurable relationship between the level of distribution system

investment and the service reliability and quality experienced by customers. He

reviewed Consumers Energy’s performance on a variety of metrics, including SAIDI,

SAIFI, and CAIDI, over the last 10 years.

He presented several exhibits to support the reasonableness and prudence of

the capital expense projections.18 His Exhibit A-19 shows the programmatic breakdown

of projected capital expenditures, with a comparison to historical spending in Exhibit

A-34, and program timelines and cash flow by month in Exhibit A-35. Additional detail

for each major program/line item is shown in Exhibits A-20, A-22, A-24, A-26, A-28,

A-30, and A-32, with specific projects identified for each program in Exhibits A-21, A-23,

A-25, A-27, A-29, A-31 and A-33. He also reviewed the reclassification of certain

HDV assets to transmission in early 2016, with related capital adjustments shown in

Exhibit A-37. In his discussion of capital expenditures related to demand failures, which

includes expenditures for street lighting replacement and upgrade, he addressed the

company’s proposed street lighting tariff, also discussed by Mr. Hurd, that would reduce

customer contributions for the conversion of certain lighting technologies and the

installation of new streetlights.

Mr. Bordine also addressed the projected distribution system O&M expense

categories as shown in Exhibit A-14, along with savings projections. Exhibit A-15

provides a breakdown of expenses by major department; Exhibit A-16 provides a

breakdown of expense by major program. He testified that the main adjustments from

the historical 2015 test year to the projected test year include increased line-clearing 18 See 6 Tr 396-424.

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expense and incorporation of the Smart Energy/AMI functions and budget. Finally,

Mr. Bordine presented the company’s 2015 line losses study, Exhibit A-36. Mr. Bordine

also presented rebuttal testimony and was cross-examined.

Danielle M. Hill is employed by Consumers Energy as the Director of Portfolio

and Performance Management for Generation Engineering Services – Energy

Resources, Portfolio and Performance Management.19 She presented testimony in

support of the company’s projected capital and O&M expense projections for its

generating fleet. Ms. Hill described the company’s 5,496 MW of demonstrated summer

operating capacity by unit, including fossil-fuel and hydroelectric generating facilities as

well as wind and solar facilities. Periodic outage plans and projected random outage

rates are presented in her Exhibits A-58 and A-59.

She presented the company’s projected capital expenditures on page 1 of Exhibit

A-61, along with 2015 and 2016 actual capital expenditures, for each unit, with

environmental costs by type separately stated, and a line for residential demand

response. She testified that the major drivers of the $408.3 million projected capital

expenditures for 2017 and the first 9 months of 2018 are plant reliability and EPA

regulations, and that the projected capital expense have been approved by the

company management. She also acknowledged that 2016 capital expenditures were

$50 million below the level projected in Case No. U-17990, and provided an explanation

for the overprojection.20 Ms. Hill also presented the company’s requested test year

O&M expenses for energy resources in her Exhibit A-60, with “base O&M” as shown

projected based on historical experience, and other categories including environmental 19 Ms. Hill’s testimony, including rebuttal and cross-examination, is transcribed at 8 Tr 1040-1190; her qualifications are set forth at 8 Tr 1044-1045. 20 See 8 Tr 1065-1067.

U-18322 Page 13

operations, residential demand response program, Jackson gas plant, and major

maintenance costs separately stated. Ms. Hill’s Exhibits A-60 and A-61 also contain

information on avoidable costs under early retirement scenarios for Karn units 1 and 2

and Campbell units 1 and 2, also referred to as the Medium 4 units.

Ms. Hill described cost control and safety efforts undertaken at the company,

characterizing it as one of the safest utilities in the country, and stating that safety

efforts help reduce O&M expense. She also described “sustainability efforts”

undertaken at the company, citing a recent PPA with Geronimo Huron Energy and other

renewable generation sources owned by the company. Ms. Hill also presented rebuttal

testimony and was cross-examined.

Heather A. Breining, Senior Engineering Technical Analyst II for Consumers

Energy, testified to support the reasonableness and prudence of the company’s

projected environmental compliance capital and O&M costs included in Exhibits A-60

and A-61.21 She reviewed applicable environmental regulations governing air quality,

water quality, and waste disposal, and described the company’s strategy to comply with

these requirements. Her Exhibit A-38 shows the status and costs for air quality control

projects underway. Her Exhibit A-39 contains the projected cost of complying with the

Resource Conservation and Recovery Act (RCRA) requirements for coal ash (coal

combustion residuals or CCR) management by the end of 2019, with additional

information in confidential Exhibit A-41. Ms. Breining’s Exhibit A-40 shows the projected

expenditures for compliance with Clean Water Act (CWA) regulations for cooling water

intake structures (CWIS) to protect fish and aquatic organisms, referred to as CWA

21 Ms. Breining’s testimony, including her rebuttal and cross-examination testimony, is transcribed at 9 Tr 1420-1489; her qualifications are set forth at 9 Tr 1424-1425.

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section 316(b) requirements, and regulations governing steam electric point source

discharges (Steam Electric Effluent Guidelines or SEEG), with additional information in

confidential Exhibit A-42. Ms. Breining also presented rebuttal testimony and was

cross-examined.

Thomas P. Clark, Manager of the Resource Planning Organization for

Consumers Energy, presented the company’s analysis of retirement scenarios for the

Medium 4 units.22 He testified that the analyses consider the expenditures required to

continue to operate the units until 2021, 2023, and 2031, in comparison to the benefits

expected form the units under the same retirement scenarios. He presented net

present values of the costs and benefits of operating under the three scenarios in

Exhibits A-89, A-90 and A-91, with underlying capacity and O&M expense assumptions

in Exhibit A-86, A-87, and A-88. He concluded based on this analysis that it is

premature for the company to decide to accelerate retirement of any of the units.

Mr. Clark also presented rebuttal testimony and was cross-examined.

Julio H. Morales, Executive Director of Customer Services for Consumers

Energy, testified regarding projected capital and O&M expense projections for

Consumers Energy’s Customer Experience Organization, including the commercial and

industrial customer demand response programs, “digital customer experience” program,

and customer payment programs.23 He described the “digital customer experience”

program, identifying four functions: a tool for completing transactions; a source of

energy-use education and resources; a branding mechanism; and “an asset that drives

22 Mr. Clark’s testimony, including rebuttal and cross-examination, is transcribed at 8 Tr 1232-1317; his qualifications are set forth at 8 Tr 1237-1239. 23 Mr. Morales’s testimony, including rebuttal and cross-examination, is transcribed at 9 Tr 1517-1564; his qualifications are set forth at 9 Tr 1520-1521.

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operational efficiencies.” He testified that the costs for this program are included in his

Exhibit A-67 as part of the customer experience line, and discussed the benefits of the

program for customers.

Turning to the company’s commercial and industrial demand response program,

Mr. Morales testified that the program is designed to give Consumers Energy a flexible

energy resource that can be used to meet peak demand, and explained how business

customers are enrolled in the program and aggregated to create a portfolio. He testified

that the projected capital costs are included in Exhibit A-66 and the projected O&M

costs are included in Exhibit A-67. A sample customer contract is Exhibit A-68.

Turning to the $7.3 million test year O&M expense request shown in Exhibit A-67

for customer payment programs, Mr. Morales explained that this amount reflects the

company’s September 1, 2016 elimination of the $6.25 convenience fee for credit card

payments. He identified benefits to customers from this program, including increased

customer satisfaction, and testified that the company has seen an 85% increase in

credit card payments since the elimination of the fee. Mr. Morales also provided

rebuttal testimony and was cross-examined.

Jeffrey J. Shingler, Executive Manager of Business Services for Consumers

Energy, testified regarding the electric business portion of the Business Services

group’s capital projects for asset preservation, transportation and equipment,

computers, and other equipment, and O&M expenses for facilities-related work such as

building repairs and snow removal.24 Projected capital costs are in his Exhibit A-70 and

projected O&M costs are in his Exhibit A-69. He explained the cost and project

24 Mr. Shingler’s testimony is transcribed at 7 Tr 993-1001; his qualifications are set forth at 7 Tr 994-996.

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categories, and provided examples of work performed by the group. He referred to

Exhibit A-37 for spending variances from prior cases.

Christopher J. Varvatos, Executive Director of Information Technology, formerly

the Business Technology Services department, testified in support of projected

Information Technology (IT) capital and O&M expenditures.25 He described the IT

department as a mix of employees and contractors, and described the functions the

department performs, including both software and hardware to facilitate the company’s

work process including the customer call center, field operations, supply chain

functions, and financial operations. His Exhibit A-74 contains recent actual and

projected test-year O&M expenses, and his Exhibit A-75 contains the recent and

projected capital expenses for the IT department. He testified that the 21% increase in

O&M expense projections compared to 2016 levels is primarily to maintain and support

investments made in 2016 and 2017, with some new software programs planned for

2018. He described the programs included in the capital expense projections, also

presented Exhibits A-76 and A-77 with additional descriptions of the costs and benefits

of these programs.

Lincoln D. Warriner is a Financial Benchmarking Analyst in the Economic

Portfolio Management Section of Consumers Energy’s Distribution Operation,

Engineering and Transportation Department.26 Mr. Warriner testified that the Smart

Grid/AMI installation will be essentially complete prior to the start of the test year in this

case, with 1.8 million meters installed by the end of the third quarter of 2017. He

25 Mr. Varvatos’s testimony, including rebuttal and cross-examination, is transcribed at 9 Tr 1635-1688; his qualifications are set forth at 9 Tr 1640. 26 Mr. Warriner’s testimony, including his rebuttal and cross-examination, is transcribed at 6 Tr 284-352; his qualifications are set forth at 288-291.

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presented the “business case” benefit/cost analysis in his Exhibit A-82. Reviewing the

level of capital expenditures approved in Case No. U-17990, he testified that the capital

expenditures approved in Case No. U-17990 are being reduced in this case by

$6.534 million, with updated capital expenditures shown in his Exhibit A-80. He testified

that including projected 2017 expenditures, capital expenditures for the program total

$327.5 million.27 He similarly reviewed O&M expenses through 2016 in Exhibit A-81.

He explained that changes in the organizational responsibility for capital and O&M

expenditures have been transferred to the Energy Resources, IT, and Electric and Gas

Distribution Operations departments of the company. He provided updated information

regarding the installation progress and other metrics including air conditioning load

control switch installations. He explained how load control was implemented on ten

days in 2016, and he explained how the remote connection and disconnection features

of the AMI installations have led to cost savings in collection activity.28 He also

reviewed successful system implementations in the program to date, and planned

development and testing for 2017. He reviewed the benefits of the AMI system,

including reduced meter reading staff, improved meter reading accuracy, increased theft

detection, help in outage restoration, and customer access to usage data and the ability

to implement dynamic pricing and load control programs.29 Mr. Warriner requested on

behalf of the company to be relieved of the obligation to continue to file a business case

review of the AMI program in future rate cases. Additionally, he testified that the

company is requesting to retain the current charges for opt-out customers, and asks to

have the charges reconsidered in the company’s next general rate case, rather than 27 See 6 Tr 294. 28 See 6 Tr 300-303. 29 See 6 Tr 306-311.

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6 months after installation is completed as required by the Commission’s order in Case

No. U-17990.30 Mr. Warriner also provided rebuttal testimony and was cross-examined.

Daniel L. Harry, Director of Accounting Process and Control for Consumers

Energy, testified in support of the company’s O&M expense projection for Corporate

Services, including uncollectible expense and injuries and damages expense.31 Total

corporate services test year O&M expense projections are shown in Exhibit A-52, along

with historical expenses, with adjustments reflecting normalizations and disallowances

in Exhibit A-53. He explained that a five-year average is used for certain insurance

refunds and credits, and that the company has added ongoing costs of $1 million per

year to implement its “lean operating system” referred to as “the CE Way.”32 He

explained the projected uncollectible accounts expense as a product of the thee-year

average bad-debt loss ratio and test-year revenue, with an adjustment for the estimated

impact of the Smart Grid/AMI benefits as shown in Exhibit A-55. He also explained that

the projected injuries and damages expense is based on a five-year average, shown in

Exhibit A-56. He also explained how total-company salary and wage costs for the test

year were projected, including base salary increases averaging 3.2% annually, not

including promotional increases. Mr. Harry also presented the company’s request for

accounting approvals, including a request related to the transfer of certain transmission

assets to FERC jurisdiction, and the accounting required to implement the company’s

requested regulatory asset treatment for demand response costs. He presented the

30 See 6 Tr 317-318. 31 Mr. Harry’s testimony, including direct and rebuttal, is transcribed at 6 Tr 555-591; his qualifications are set forth at 6 Tr 556-557. 32 See 6 Tr 563.

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historical and projected amounts in Exhibit A-57. Mr. Harry also presented rebuttal


Herbert B. Kops, Executive Director of Employee Benefits and Compensation for

Consumers Energy, testified in support of the company’s projected expenses for

pensions and other post-retirement benefits (OPEBs), and the health insurance and

other benefits provided to active employees.33 His Exhibit A-65 presented the actual

and projected O&M expenses broken down by benefit category for 2015, 2016, 2017

and the projected test year. He reviewed the process for determining the company’s

pension expense, recent contributions to the pension plan made by the company, and a

new FASB standard the company has not yet adopted. He similarly reviewed the

projected expenses for the company’s other post-retirement benefit obligations (OPEB),

which are subject to the same accounting standard. He also addressed cost projections

for two plans for executives, the Defined Benefit Supplemental Executive Retirement

Plan (DB SERP) for executives hired before April 1, 2006, and the Defined Contribution

Supplemental Executive Retirement Plan (DC SERP) for employees hired after that

date, which are included in lines 2 and 4 of his Exhibit A-65. Mr. Kops reviewed the

cost projections for the company’s Employee Savings Plan (ESP), a 401k plan, as well

as health, life insurance and long-term disability plans for active employees. Mr. Kops


Amy M. Conrad, Director of Compensation for Consumers Energy, testified in

support of the inclusion in revenue requirements of the costs of the company’s annual

Employee Incentive Compensation Plan (EICP) and its long-term incentive plan also

33 Mr. Kops’s testimony, including rebuttal and cross, was transcribed at 10 Tr 1922-1989; his qualifications are set forth at 10 Tr 1926-1929.

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known as the restricted stock plan.34 She testified regarding the company’s

compensation philosophy, which considers these incentive plans part of an employee’s

market-based compensation. She discussed the design of the EICP, including a review

of the operational and financial metrics, the long-term incentive plan, and the customer-

related benefits she ascribes to the plans. The EIPC performance measures are in her

Exhibit A-44, with the requested expense projections in Exhibit A-45, and a “target pay

level market analysis” in Exhibit A-46. Ms. Conrad also provided rebuttal testimony.

R. Michael Stuart, Utility Metrics Director at Consumers Energy, also testified to

support the company’s requested recovery of expenses associated with its EICP.35 He

discussed the operational performance goals and thresholds, and testified to the

customer benefits from meeting these goals. His Exhibit A-71 contains the performance

measures. He testified that quantification of the customer benefits is difficult for some

metrics, but presented the company’s quantitative analysis of five key metrics,

concluding that substantial benefit accrues to the customer. He described revisions to

the operational metrics in the 2017 EICP, and testified that the quantification of

operational benefits obtained prior to 2017 is illustrative, and the same conclusion from

that quantification applies to 2017. Mr. Stuart also provided rebuttal testimony.

Brian J. VanBlarcum, Property Tax Manager for Consumers Energy, testified to

support the projected property tax costs for the test year, and to explain the derivation.36

His Exhibit A-72 shows 2017 property tax expenses of $167.9 million, allocated to the

34 Ms. Conrad’s testimony, including her rebuttal testimony is transcribed at 7 Tr 923-979; her qualifications are set forth at 7 Tr 924-925. 35 Mr. Stuart’s testimony, including his rebuttal testimony, is transcribed at 7 Tr 1004-1027; his qualifications are set forth at 7 Tr 1005. 36 Mr. VanBlarcum’s testimony, including his rebuttal and cross-examination, is transcribed at 7 Tr 851-893; his qualifications are set forth at 7 Tr 855-856.

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electric portion of the company’s business, and a projected increase of $12.4 million in

2018. Mr. VanBlarcum explained how net additions are calculated, explained the

exemption for certain pollution control equipment and software, and explained the

derivation of the test year amount. Mr. VanBlarcum also provided rebuttal testimony

and was cross-examined

Mr. Denato is Assistant Corporate Controller for Consumers Energy and its

parent company, CMS Energy.37 He recommended a capital structure for ratemaking

based on the company’s actual capital structure as of December 31, 2016, adjusted for

projected changes in debt, equity, deferred income taxes, and Investment Tax Credit

(ITC) through the end of the test year. He presented this projected capital structure in

Schedule D1 of Exhibit A-9, which shows equity as 52.91% of permanent capital.

Mr. Denato explained that he increased the 13-month common equity balance by

$742 million from the 2016 level to reflect retained earnings of $154 million projected

through September 2018, and equity infusions of $588 million. He explained how he

estimated retained earnings, and he explained that the equity infusion includes the

January 2017 actual equity infusion of $250 million, and expected additional equity

infusions of $200 million each in June 2017 and January 2018. Mr. Denato also

explained that he increased the average debt balance by $581 million, reflecting several

planned retirements and debt issuances through September 2018.38 He testified that

the planned debt issuances “have been determined based on the Company’s financing

plans after evaluating cash and liquidity requirements for the Company.”39 He testified

37 His testimony, including his rebuttal testimony and cross-examination, is transcribed at 9 Tr 1229-1419; his qualifications are set forth at 9 Tr 1333-1334. 38 See 9 Tr 1343. 39 Id.

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that the resulting equity percentage of 52.91% “is in line with the Company’s goal to

maintain a permanent equity ratio consistent with the Company’s recent actual equity

ratios and also with recently approved rate cases in the low 50% range.”40

Acknowledging the Commission’s order in Case No. U-17990, Mr. Denato testified that

it is “reasonable and prudent” for Consumers Energy to maintain an equity ratio slightly

higher than 50%.41

For short-term debt balances, Mr. Denato testified that he based the projected

balances on monthly cash flow requirements, long-term financing plans, and the amount

of short-term financing available.42 Mr. Denato also explained other amounts included

in the ratemaking capital structure, including the renewable surcharge liability balance,

the deferred income tax adjustment, and the ITC balance. He estimated a long-term

debt cost of 4.82% as shown in his Schedule D2 of Exhibit A-9, using projected costs of

5%, 6%, and 6.5% for debt issuances to be made in August 2017, March 2018, and

August 2018, respectively.43 He estimated short-term debt costs at 3.55%. He

discussed other cost elements, including the letter of credit fees for the company’s

Pollution Control Revenue Bonds, and letter of credit fees for a letter of credit related to

the company’s proposed buyout of its Palisades power purchase agreement. And he

used a 4.5% cost rate for the company’s preferred stock. Using the 10.5% return on

equity recommended by Mr. Maddipati, Mr. Denato calculated an overall rate of return

of 6.16% on an after-tax basis.

40 See 9 Tr 1339. 41 See 9 Tr 1339. 42 See 9 Tr 1344. 43 See 9 Tr 1350.

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In his Exhibits A-47 and A-48, Mr. Denato presented current and historical credit

ratings with associated outlooks for the previous five years, and recent public utility

corporate bond issuances. In addition, he recommended a $24 million increase in the

cash balance included in working capital for the test year ending September 30, 2018,

testifying that the company plans to hold a cash balance of $44 million.44 Mr. Denato


Srikanth Maddipati, Treasurer and Vice President of Investor Relations for

Consumers Energy testified to support Consumers Energy’s projected cost of equity

capital.45 Mr. Maddipati recommended that the Commission set a return on equity of

10.5%, which he believes would balance the needs of customers as well as incentivize

investment in necessary infrastructure. His testimony includes a discussion of the

importance of authorized rates of return, a discussion of the standards for rates of

return, a discussion of the current economic outlook, and an assessment of current

interest rates. He testified that utility stocks are particularly sensitive to rising interest

rates. Discussing trends in authorized rates of return, he testified that there is no

accurate or complete source of information, and presented a chart showing authorized

returns for 10 companies. He testified to a relationship between authorized returns and

customer satisfaction ratings, and also between authorized returns and the quality of the

regulatory environment, and he provided his opinions regarding investor expectations.

Mr. Maddipati presented a quantitative analysis using a group of proxy companies,

shown at page 13 of his Schedule D5 in Exhibit A-9, based on his selection criteria. He

performed nine different analyses or variants of analyses, including a Capital Asset 44 See 9 Tr 1357. 45 Mr. Maddipati’s testimony, including his rebuttal and cross-examination, is transcribed at 10 Tr 1727-1921; his qualifications are set forth at 10 Tr 1732-1734.

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Pricing Model (CAPM) analysis with two sets of risk-free-rate and market-return

assumptions, along with a variant called the Empirical Capital Asset Pricing Model

(ECAPM), a risk premium analysis and a discounted cash flow (DCF) analysis, each

also using two sets of assumptions, and a comparable earnings analysis. Mr. Maddipati


Sara Walz, Senior Engineering Technical Analyst in the Electric Sourcing and

Resource Planning Section of Consumers Energy’s Energy Supply Operations

Department, presented the company’s projected power supply costs for the test year,

with alternative presentations with and without early termination of the Palisades power

purchase agreement (PPA) in exhibits A-78 and A-79.46 She also acknowledged

Ms. Aponte’s testimony proposing revisions to the allocation of revenues from energy

sales to MISO. She indicated that estimated credits to PSCR costs for the net sales of

energy to MISO are shown in lines 55 and 57 of Exhibits A-78 and A-79. She testified

that the estimates are a product of PROMOD and should be considered energy related.

She also presented rebuttal testimony and was cross-examined.

Josnelly C. Aponte is a Principal Rate Analyst in the Rates and Regulation

Department of Consumers Energy.47 Ms. Aponte presented the 2015 historical

allocation schedules which are included in Exhibit A-5, as well as the company’s

projected test-year cost-of-service studies in Exhibit A-11, with alternate versions in

Schedules F1 and an alternate version in Schedule F1.1. Ms. Aponte explained the

development of the historical allocation schedules used for the 2015 cost-of-service

46 Ms. Walz’s testimony, including her direct and cross-examination testimony, is transcribed at 6 Tr 523-549; her qualifications are set forth at 6 Tr 527-528. 47 Ms. Aponte’s testimony, including rebuttal and cross-examination, is transcribed at 7 Tr 669-748; her qualifications are set forth at 7 Tr 674-676.

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study, using the allocation methods approved in Case No. U-17990 including the 4 CP

75/25 allocation method for production costs and the 12 CP allocation method for

transmission expense. For the projected test year, she testified that she developed the

cost-of-service study in Schedule F1 using the same schedules, methods, and

principles, with information from Mr. Breuring and Ms. Collins. She testified that she

adjusted the sales for the General Service—Unmetered Lighting Rate (Rate GUL) to

reflect the company’s proposal to upgrade company-owned lights/lamps with LEDs.48

She testified that she also adjusted the demands associated with the Energy Intensive

Pilot customers consistent with the treatment in Case No. U-17990. She testified that

she also reclassified production costs into capacity and non-capacity costs to reflect a

provision of 2016 PA 341, MCL 460.6w(3). Ms. Aponte explained that she presented a

second version of the cost-of-service study in Schedule F1.1 of Exhibit A-11. In the

second version, she changed the intersystem sales allocation factor to an energy

allocation, and she updated the loss factors to reflect the updated loss study presented

by Mr. Bordine. She testified that the first change moves $4.4 million in credits from the

residential class and $1.4 million in credits from the secondary class to the primary

class.49 She testified that the updated loss study report indicates higher system losses

attributable to the secondary distribution system used to serve residential and general

service secondary customers. Ms. Aponte also reviewed the determination of a credit

for substation owners, the allocation by rate class of the revenue requirement for the

demand response regulatory asset requested by the company, the reason for the

revenue sufficiency shown for the General Service Self-Generation Rate GSG-2, and a 48 See 7 Tr 684. 49 Her testimony states the primary class revenue credits are increased by $4.5 million, but this appears to be a typographical error. See 7 Tr 687.

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study in her Exhibit A-84 to show the elimination of the interclass crossing point

adjustment proposed by Ms. Collins for the General Service Primary Demand Rate

GPD and the General Service Primary Rate GP. Ms. Aponte also presented rebuttal


Laura M. Collins, Principal Rate Analyst in Consumers Energy’s Rates and

Regulation Department, was the principal witness addressing rate design, including an

explanation of the allocation of revenues to the various rate schedules.50 She

summarized the company’s rate change proposals, including proposed changes to the

self-generation rate, Rate GSG-2, and the addition of a State Reliability Mechanism

(SRM) charge based on the separation of capacity costs to comply with 2016 PA 341,

MCL 460.6w. Her Schedule F2 of Exhibit A-11 contains a summary of proposed

changes in revenue by rate and service type, based on projected test year billing

determinants. Her Schedule F2.1 shows the calculation of the revenue targets she

used in designing rates, including a reflection of subsidies and discounts. Her Schedule

F3 shows the test year proposed rates to collect the jurisdictional revenue requirement

for each rate schedule based on billing determinants from Mr. Breuring, which are used

in Mr. Hurd’s tariff revisions, and her Schedule F4 shows the impact on typical bills.

Ms. Collins explained how capacity costs otherwise allocated to interruptible

customers are spread to other customers for whom capacity is planned and purchased.

She also explained the Energy Intensive Primary (EIP) rate pricing adjustments, and the

interclass crossing point adjustment between rates RPD and GP based on the rate

design approved in Case No. U-17990. Referencing Ms. Aponte’s study of the potential

50 Ms. Collins’s testimony, including her rebuttal, sur-surrebuttal, and cross-examination, is transcribed at 10 Tr 1990-2073; her qualifications are set forth at 10 Tr 1995-1996.

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elimination of the crossing-point adjustment for Rates GP and GPD, she testified that

her rate design maintains the crossing point at a 45% load factor, which the company

believes to be more efficient than eliminating the adjustment, avoiding the need to

contact the affected customers and offer to move them to a new rate schedule.

Ms. Collins also presented the company’s proposed Rate GSG-2 rate design to collect

capacity costs based on the equivalent charge paid by comparable primary customers.

She presented study results in Exhibit A-85 showing that Rate GSG-2 customers are

paying more than their allocated embedded cost of service, but also paing half of what

other comparable customers pay on a dollars-per-megawatt basis.

Turning to the SRM, she identified and reviewed the dockets the Commission set

up to consider the capacity charge under MCL 460.6w, and testified that the costs in

this rate case will provide the basis for the capacity charges that are ultimately

established.

For the residential rates, she also reviewed the development of rates for electric

vehicle charging, and calculation of credits for the residential demand response

program. For the primary rate, Rate GPD, she explained that due to the SRM, the rate

design has been changed to collect 100% of capacity costs through the on-peak

demand change rather than the 75% used previously. She also presented the

company’s proposal for customer-specific delivery charge for very large customer that

reflect the company’s investment in facilities but cap the demand charges. She

described the development of time-of-use rate for primary customers, Rate GPTU, and

discussed changes to the Unmetered Experimental Lighting Rate, Rate GU-XL.

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Ms. Collins also presented rebuttal and sur-surrebuttal testimony and was cross-

examined.

Shawn C. Hurd, Business Support Advisor I in Consumers Energy’s Rates and

Regulation Department, provided testimony addressing proposed changes to tariffs and

rate schedules.51 He presented a summary of the tariff changes in his Exhibit A-64,

with a redlined version of the tariffs in Schedule F5 of Exhibit A-11. He explained the

proposed change in the name of the General Service Primary Demand (GPD) to the

Large General Service Primary Demand, to eliminate confusion. He explained

language changes to address tree trimming of distribution lines, and to clarify that

customers with both residential and nonresidential usage at their premises can obtain

residential service for their residential usage if it is separately metered. He also

explained a proposed language change to the AMI opt-out tariff, to apply the charge to

each meter at a customer’s location. He explained several changes related to the line

extension policies: to clarify the “free” 600’ extension for residential customers; to

modify the time for general service customers to reach full load potential for purposes of

determining a refund of connection charges; to increase the potential refund to a

residential customer funding a line extension when a General Service customer

subsequently connects to that line; and to match the tariff language to the approved

refund for General Service customers from Case No. U-17990, and the waiver authority

approved in Case No. U-18039. Mr. Hurd revised the tariff to provide for the capacity

charges that are the subject of Case No. U-18239. He revised the tariff to include the

residential demand response programs under the name Peak Power Savers Program,

51 Mr. Hurd’s testimony, including his rebuttal and cross-examination, is transcribed at 9 Tr 1490-1515; his qualifications are set forth at 9 Tr 1494-1495.

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and to require customers to be enrolled for a full 12 months. He also explained

provisions for a customer-specific distribution rate for customers with more than 100

MW of load, and to increase the amount of contracted interruptible load available to a

single customer, with other modifications to the interruptible service tariffs.

Mr. Hurd identified proposed changes to the General Service Primary Time Of

Use rate (Rate GPTU), to reserve it for full-service customers, directing generators

above 550 kW who take standby service to Rate GSG-2. He also identified clarifying

language addressing the availability of Energy Intensive Primary rate (Rate EIP),

changes to reflect the Rate GSG-2 rate design sponsored by Ms. Collins, and the

revised lighting replacement policy sponsored by Mr. Bordine.

B. Staff Staff’s filing recommended a revenue deficiency of $16.5 million on a

jurisdictional basis, based on a return on equity of 9.8%. In its reply brief, Staff revised

its revenue deficiency to $64.5 million. Staff presented the direct testimony of 11

witnesses, including rebuttal testimony as discussed below in section L.

Robert F. Nichols II, Manager of the Revenue Requirements Section of the

Commission’s Financial Audit and Analysis Division, presented the calculation of Staff’s

recommended revenue deficiency, including Staff’s projected rate base, working capital,

and adjusted net operating income, incorporating the recommendations of other Staff

witnesses.52 The revenue requirements calculation is shown in Exhibit S-1, with rate

base and working capital calculations in Exhibit S-2, and projected net operating income

in Exhibit S-3. Mr. Nichols presented a chart showing Staff’s recommended adjustments

52 Mr. Nichols’s testimony is transcribed at 11 Tr 2392-2401; his qualifications are set forth at 11 Tr 2393-2395.

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to utility plant with a reference to the sponsoring witness for each.53 He testified that

Staff’s audit identified errors in the company’s property model affecting rate base,

depreciation expense, and property tax, as shown in Exhibit S-10.2, and Staff’s figures

correct for this error. Mr. Nichols also explained Staff’s that Staff’s property tax

adjustment reflects Staff’s projected plant balances. Mr. Nichols addressed the

company’s JR Whiting plant land donation, presenting as Exhibit S-10.1 the company’s

acknowledgment that it should be removed from rate base. And he addressed

Mr. Harry’s testimony regarding a dispute pending before FERC between the company

and METC, recognizing that adjustments to the revenue requirement may be

appropriate.

Several Staff witnesses recommended adjustments to the company’s capital and

O&M expense projections. Ryan Laruwe is Public Utilities Engineering Specialist in the

Operations and Wholesale Markets division of the MPSC.54 In his testimony,

Mr. Laruwe addressed the reasonableness and prudence of Consumers Energy’s

proposed electric distribution system capital and O&M expenditures. He testified that

Staff is concerned with the lack of evidentiary support for the reasonableness of

projected capital expenditures in four areas: grid modernization, reliability, demand

failure, and electric operations-other. Reviewing historical spending levels in

comparison to amounts approved in Case Nos. U-17990 and U-17735, as well as the

company’s testimony, exhibits and workpapers, he testified that Staff recommends

limiting projected annual expenditures to the 2016 level, adjusted for inflation, through

53 See 11 Tr 2398. 54 His qualifications are set forth at 11 Tr 2372-2374; his testimony is transcribed at 11 Tr 2371-2389.

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the test year, for the grid modernization, reliability, demand failure, and electric

operations-other categories.

He also took issue with the company’s request for a ratemaking mechanism that

will provide a reconciliation process for the return of any distribution system capital

funding not spent. He recommended that any reconciliation be done at the project level

for each program.55

Regarding projected O&M expense levels, Mr. Laruwe testified that Staff does

not support the company’s proposed $15 million increase in annual line-clearing/tree-

trimming expenditures, based in part on a concern with the company’s ability to mobilize

the additional resources required, and in part on a concern with its commitment to doing

so, noting prior periods when Consumers Energy did not spend the full amount

authorized in rates. He recommended a tree-trimming allowance of $51.8 million, which

is the most recently-approved spending level, adjusted for inflation, plus an additional

$1 million allowance for trimming outside the right-of-way to address known risks such

as the Emerald Ash Borer. He presented Exhibit S-16 in support of his testimony.

Nicholas M. Evans, Public Utility Engineer in the Electric Reliability Division of the

MPSC, testified regarding certain projected environmental capital expenditures.56 He

also addressed the company’s projected O&M expense for environmental compliance,

and presented Staff’s review of the company’s Medium 4 retirement analysis.

Regarding Consumers Energy’s projected capital expenses, he recommended

adjustments to the expense projections for RCRA compliance due to changed plans

and delayed expenditures. He testified the recommended adjustments to the RCRA 55 See 11 Tr 2386. 56 Mr. Evans’s testimony, including cross-examination, is transcribed at 11 Tr 2273-2307; his qualifications are set forth at 11 Tr 2276-2280.

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environmental capital expense projections reduce projected expenses for the first 9

months of 2017 by $23.7 million, and by $16.6 million for the test year. He testified that

Staff has also removed contingency amounts from the projected environmental

expenditures, citing Exhibit S-14.2, S-14.5 and S-14.8.57

Mr. Evans also addressed the company’s Medium 4 retirement analysis. After

reviewing the Commission’s order in Case No. U-17990, he testified that Staff believes

the analysis “meets the minimum requirements” to comply with the ordering paragraph

of that order. Agreeing that the analysis is preliminary, he recommended that the

Commission require Consumers Energy to conduct the further additional analysis the

company had stated that it planned to undertake. He also recommended that the

Commission exclude projected capital costs identified as avoidable for Karn units 1 and

2 under the 2021 or 2023 retirement scenarios, concluding there is a strong possibility

the company will decide to retire the Karn units.

Regarding projected O&M expenses, Mr. Evans cited a history of Consumers

Energy overprojecting expenditures this category, and recommended that the projected

test year expenses be reduced by 30%. Mr. Evans was cross-examined on his

testimony.

Naomi J. Simpson, Public Utilities Engineer in the Generation and Certificate of

Need Section of the MPSC’s Electric Reliability Division, testified regarding the

company’s proposed demand response program for its commercial and industrial

customers, proposed expenditures for its residential demand response program, and its

57 See 11 Tr 2285-2290.

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proposed ratemaking mechanism for demand response costs.58 Regarding the

commercial and industrial demand response program, Ms. Simpson reviewed the

projected capital and operating expense projections, and explained that Staff is not

recommending any adjustment to these projections or to the program. Regarding the

residential demand response program, Ms. Simpson testified to Staff’s programmatic

and expense level concerns. She testified that Staff is concerned that the company’s

website tool does not adequately communicate the impact on the customer’s monthly

bill from enrolling in the time-of-use programs, and recommended a monthly shadow

billing, or in the alternative, a trial period before the one-year commitment provided for

in MCL 460.1095 applies. Ms. Simpson also recommended an $8.1 million reduction in

the projected capital expenditures for the AC load control program, based on the

conclusion that the company had not achieved the program level funded in Case No.

U-17990, and did not anticipate it would achieve this level before the end of the test

year. She also recommended that the capital expenditures for the switches be

depreciated or amortized over a five-year period, and not accounted for in the same

account as the 25-year AMI switches. She also recommended that the company

increase its marketing and educational efforts for these programs to make them more

accessible to customers, and to consider piloting other programs. Finally, Ms. Simpson

recommended that the Commission reject the company’s alternative proposal to recover

its demand response costs through the creation of a regulatory asset, recommending

that it first be considered through the workgroup forum.

58 Ms. Simpson’s testimony is transcribed at 11 Tr 2432-2448; her qualifications are set forth at 11 Tr 2433-2436.

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Lauren Fromm is a Public Utilities Engineer in the Smart Grid Section of the

Operations and Wholesale Markets division of the MPSC.59 In her testimony,

Ms. Fromm addressed the use of contingency allowances in the company’s capital

expense projections generally, recommending that the Commission exclude

contingencies as shown in Exhibit S-13.2. Ms. Fromm recommended a $900,000

reduction in projected capital expense projections for information technology, finding the

projected expenditures unsupported. She also recommended a disallowance of

approximately $300,000 for 2016 expenditures related to estimate meter readings

related to the Commission’s order in Case No. U-18002.

Ms. Fromm also testified regarding the company’s smart grid program,

recommending that the company provide the same smart grid reporting metrics as DTE

Electric Company, on the same annual schedule. Regarding the AMI program

specifically, she recommended that the company continue to provide a business-case

benefit/cost analysis. She also recommended revisions to the company’s proposed

changes to the AMI opt-out tariff. Related to the company’s increased deployment of

AMI meters, Ms. Fromm also addressed the “bad debt loss ratio” underlying the

company’s calculation of uncollectible account expense, concluding that use of the

three-year average masks a trend in declining loss ratios attributable to the new meters

and the company’s use of related systems to decrease instances of uncollectible

expense. She noted that Mr. Welke presented Staff’s uncollectible expense

recommendations.

59 Ms. Fromm’s testimony is transcribed at 11 Tr 2345-2361; her qualifications are set forth at 11 Tr 2346-2347.

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Brian Welke is the Manager of Income Analysis Unit of the MPSC’s Regulated

Energy Division.60 He presented testimony in support of Staff’s recommended

adjustments to O&M expense as shown in Schedule C5 of Exhibit S-3. Mr. Welke

recommended a $1.8 million adjustment to the company’s projected pension expense to

remove projected Pension Benefit Guarantee Corporation (PBGC) premiums

significantly above recent levels. Also in the category of employee benefit expense,

Mr. Welke recommended eliminating the company’s projected incentive compensation

expenses associated with the attainment of financial performance metrics, a total

reduction of $13.6 million, and he recommended eliminating $2.3 million in projected

expenses for the company’s supplemental executive retirement plans to be consistent

with prior Commission decisions. Mr. Welke also recommended a $2 million

adjustment to the company’s uncollectible expense projection. Looking at the

company’s overall O&M expense projection for the test year, Mr. Welke recommended

a 2% reduction to reflect the company’s expected cost savings.

Kavita Bankapur, Auditor in the MPSC’s Regulated Energy Division, testified

regarding the ratemaking capital structure and cost of capital.61 She utilized Consumers

Energy’s projected capital structure Consumers Energy, but recommended a revised

cost rate for the company’s planned new debt issuances of 4.36%, rather than the rates

of 5%-6.5% Consumers Energy used, resulting in a weighted-average cost of long-term

debt of 4.68% rather than 4.82%. Ms. Bankapur testified that based on her analysis,

the cost of equity for Consumers Energy is in the range of 9% to 10%, and

60 Mr. Welke’s testimony is transcribed at 11 Tr 2451-2467; his qualifications are set forth at 11 Tr 2452-2453 61 Ms. Bankapur’s testimony is transcribed at 11 Tr 2322-2343; her qualifications are set forth at 11 Tr 2323-2326.

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recommended an authorized return of 9.80% for the company. After reviewing the

applicable standards, she explained the analysis she conducted, including the selection

of a proxy group, parameters and choice of inputs for the financial models she used,

and the model results for her DCF, Capital Asset Pricing Model (CAPM), and risk-

premium analyses. The results of her analyses are summarized on page 8 of Schedule

D5 of Exhibit S-4.

Staff’s cost-of-service study was presented by Charles E. Putnam, Departmental

Specialist in the Rates and Tariffs section of the Regulated Energy Division.62 He

sponsored Schedule F1, summarizing Staff’s cost-of-service study results, and

explained the adjustments Staff made to the company’s cost-of-service study. He

testified that Staff has used its recommended revenue inputs so that the cost-of-service

study supports Staff’s revenue requirement. He testified that Staff changed the

allocator for intersystem sales from the energy-based allocator Consumers Energy used

back to an allocator based on the 4CP 75-25 method used to allocate production costs,

also referring to Mr. Revere’s testimony. And he testified that Staff changed the method

Consumers Energy used to classify production costs into capacity and non-capacity

portions.

Nicholas M. Revere, Manager of the Rates and Tariffs Section of the

Commission’s Regulated Energy Division, presented Staff’s position regarding the costs

to be included in the capacity charge under MCL 460.6w, and how the charge should be

levied. He testified that Staff takes the same position in this case as it presented in

Case No. U-18239. Mr. Revere reviewed the applicable statutory provisions, and

62 Mr. Putnam’s testimony is transcribed at 11 Trb2403 -2411; his qualifications are set forth at 11 Tr 2404-2406.

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explained the Cost of New Entry (CONE) as the determinant of capacity cost. He

explained that Staff has directly examined the costs in the cost-of-service study to

determine which are capacity related, generally allocating 75% of the production costs

using the 4CP allocation method. He explained that an alternative approach would be

to determine the percentage of production costs equivalent to CONE, which could be

estimated using the levelized cost from the company’s recent PURPA case, Case No.

U-18090. He also addressed the inclusion of intersystem sales revenue in the capacity

cost calculation, and recommended distributing capacity costs to the rate classes using

the cost-of-service study if the statute permits this result. He also recommended that

costs be recovered through summer peak demand charges for rate schedules with

demand charges and through summer on-peak kWh charges for rate schedules without

demand charges. He also identified alternative approaches in the event the Commission

determines that a single capacity charge must be uniform across all classes,

recommending the use of on-peak summer kWh as the best alternative.

Mr. Revere also presented Staff’s recommended rate design for residential

service, reflecting Staff’s capacity charge proposal. He recommended that the inverted

block structure currently used for Rate RS be eliminated and replaced with an on-peak

and off-peak summer rate, arguing that current rate for consumption above 600 kWh is

a good proxy for the on-peak rate.

David W. Isakson, Departmental Analyst in MPSC’s Regulated Energy Division,

presented Staff’s rate design recommendations, proposed customer counts for RIA and

RSC rates, and proposed tariff changes.63 He testified that Staff’s residential rate

63 Mr. Isakson’s testimony, including rebuttal and cross-examination, is transcribed at 11 Tr 2223-2272; his qualifications are set forth at 11 Tr 2226-2227.

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design eliminates the inverted block rate structure as Mr. Revere explained, and

implements Staff’s proposal to collect capacity costs through summer on-peak charges.

He identified the rates for which Staff has adopted the company’s rate design, but with

Staff’s cost-of-service study results, including Staff’s allocation of low-income and senior

credits to all customers based on total cost of service. As did Ms. Aponte and

Ms. Collins, he recommended maintaining a crossing-point adjustment for Rate GPD

and Rate GP, noting that the Commission’s capacity cost determination in Case No.

U-18239 will affect the magnitude of the adjustment.

Mr. Isakson objected that Consumers Energy had not properly addressed the

Commission’s call for an analysis related to a joint substation credit for Rate GPD, and

objected to the company’s proposal to establish customer-specific delivery charges for

very large Rate GPD customers. Mr. Isakson also recommended decreasing the Rate

RSC and Rate RIA customer counts, citing a steady decrease in customers taking this

provision over the last five years, and recommended using the 2016 customer counts in

lieu of the company’s projections. Mr. Isakson also presented rebuttal testimony and

was cross-examined.

Julie K. Baldwin is Manager of the Renewable Energy Section of the MPSC’s

Electric Reliability Division.64 She presented testimony recommending that Consumers

Energy develop an on-line public list of interconnection requests. She identified

information that she wanted to see as soon as possible, while the company pursues its

plan to work with DTE Electric on a format. In support of this recommendation, she

presented the company’s response to a Staff audit request as Exhibit S-15. She also

64 Ms. Baldwin’s testimony is transcribed at 11 Tr 2310-2320; her qualifications are set forth at 11 Tr 2311-2314.

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objected to the company’s proposed recommendation to limit the time-of-use rate

available to general service primary customers, recommending that the rate be

available to customers with solar projects of any size, rather than only full-service

customers. She presented the Standby Rate Working Group Report and Supplemental

Report as Exhibits S-15.1 and S-15.2.

C. Attorney General

Sebastian Coppola, independent business consultant and president of Corporate

Analytics, Inc., testified on behalf of the Attorney General.65 Mr. Coppola concluded

that Consumers Energy has a revenue sufficiency of $12.2 million for the projected test

year, based on his recommended reductions to the company’s capital and O&M

expense projections, and modifications to the company’s sales projections. Regarding

the capital expense projections, he recommended reductions in total capital

expenditures for 2017 and the first 9 months of 2018 totaling $122.8 million, including: a

$23.5 million reduction to exclude contingency projections. He also recommended a

$56.6 million reduction in electric distribution capital expenditures for new business,

reliability programs, demand failures, and for other operations; a $27.7 million reduction

in projections for capital spending on generating plants; and an $11.4 million reduction

in IT capital spending projections, concluding that the company’s projections were not

supported by specific projects or were otherwise inconsistent with historical spending

levels. In recommending a rate base for the projected test year, Mr. Coppola also

recommended two adjustments to working capital, testifying that the Commission

should reject the proposed increase in cash balances recommended by Mr. Denato,

65 Mr. Coppola’s testimony is transcribed at 12 Tr 2498-2624; his qualifications are set forth at 12 Tr 2499-2502 and 2612-2624.

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and further adjust the accrued interest component to reflect higher debt costs in the

projected test year.

Regarding O&M expense projections, Mr. Coppola recommended a total

reduction of $76.8 million in projected test year spending, including: a reduction in

projected spending on vegetation management to reflect historical levels; a reduction in

smart energy metering costs; reductions to projected environmental operating expenses

and residential demand response projections; reductions to the “customer experience”

cost category for digital customer experience tools and for credit card payment costs,

reductions to IT projected spending for increased staffing and contractors; the

elimination of projected expenses for the company’s incentive compensation plans; and

a reduction in pension and other-post-retirement benefits (OPEB) based on a revised

discount rate. To calculate adjusted net operating income, Mr. Coppola also

recommended that the Commission use a higher forecast for residential sales than

recommended by the company, concluding that the company’s projected 1.1%-2.1%

reduction in per-customer consumption is overstated relative to historical experience,

and recommending a projected annual decrease of only 0.3%.

He further recommended use of an alternative capital structure based on 50%

debt and 50% equity, and an authorized return on equity of 9.75%. He presented

quantitative analyses including DCF, CAPM, and risk premium analyses, and took issue

with elements of Consumers Energy’s analysis. Mr. Coppola also recommended

against adopting a ratemaking mechanism for electric distribution capital expenses, and

against discontinuing the AMI business case reporting.

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D. ABATE ABATE presented the testimony of Jeffry Pollock and Billie S. LaConte.

Mr. Pollock is an energy advisor and President of the consulting firm J. Pollock, Inc.66

He addressed three issues relating to the revenue requirement: he took issue with the

use of a projected test year, recommending that the Commission reduce the authorized

return on equity to reflect a reduction in business risk from this ratemaking approach; he

also objected to the company’s proposed recovery of costs associated with its incentive

compensation plan; and he objected to the creation of a regulatory asset for demand

response costs. Regarding the class cost-of-service study, Mr. Pollock recommended

four modifications to Consumers Energy’s allocations: he recommended the use of

demand-based loss factors rather than average annual loss factors; he objected to the

allocation of the credits provided to interruptible customers, arguing that credits should

be allocated only to firm customers; he recommended increasing the test-year power

supply revenues due to the increases proposed for the Rate GSG-2 power supply

demand charge; and he objected to the allocation of the senior citizen and low-income

customer discounts based on class revenue requirements rather than distribution-only

customer costs. He also recommended several rate design changes for the Rate GPD

and the Rate GSG-2 rates.

Ms. LaConte is an energy advisor and Associate Consultant for Mr. Pollock’s

firm. In her testimony, Ms. LaConte recommends a rate of return on equity of 8.6%,

based on a range of 7.4% to 9.7%.67 She presented two discounted cash flow

66 Mr. Pollock’s testimony, including his rebuttal testimony, is transcribed at 12 Tr 2628-2793; his qualifications are set forth at 12 Tr 2632 and 2692-2710. 67 Ms. LaConte’s testimony, including her rebuttal testimony, is transcribed at 12 Tr 2737-2793. Her qualifications are set forth at 12 Tr 2741, 2778-2781.

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analyses, a constant growth and a multi-state model, as well as a CAPM analysis. She

explained her selection of a proxy group, and compared her selection to Mr. Maddipati’s

proxy group. She also explained her choice of inputs to the DCF and CAPM models

she used. Ms. LaConte also discussed Consumers Energy’s business risk, and

identified other factors that in her opinion support her recommended return on equity.

Ms. LaConte critiqued Mr. Maddipati’s analysis, including his methods and choice of

inputs. Finally, Ms. LaConte reviewed Mr. Denato’s testimony regarding the capital

structure Consumers Energy proposes for use in ratemaking, and recommended that

the Commission reject the increased equity ratio in the company’s proposal and instead

use the average equity ratio of her proxy group, 52.1%. Her analyses are presented in

Exhibits AB-7 through AB-14.

E. MEC/NRDC/SC

MEC/NRDC/SC presented the testimony of two witnesses, Dan F. Koehler and

Douglas B. Jester. Mr. Koehler is a Senior Consultant at Daymark Energy Advisors

Inc.68 Mr. Koehler reviewed Consumers Energy’s analysis of early retirement scenarios

for the Medium 4 units. He concluded that the company has not shown that it is

reasonable and prudent to continue to invest in the operation of the Medium 4 units

beyond 2021. He characterized the analysis as preliminary in nature, lacking the detail

called for by the Commission in its order in Case No. U-17990. He also testified that the

results of the preliminary analysis show economic benefits from retiring one or more of

these units in 2021 or 2023 under a range of market assumptions, with additional

benefits from early retirement likely if certain biases in the company’s analysis were

68 Mr. Koehler’s testimony is transcribed at 11 Tr 2119-2150; his qualifications are set forth at 11 Tr 2120-2121 and his resume, Exhibit MEC-1.

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corrected. He recommended that the Commission reject all projected spending that it’s

avoidable under an early retirement scenario, pending a more complete analysis. He

presented Exhibits MEC-2 through MEC-7 in support of his conclusions. Mr. Jester’s

testimony is discussed below.

F. MEC/NRDC/SC, ELPC, and MCA

Five parties jointly sponsored the testimony of Douglas B. Jester. Mr. Jester is a

Partner of 5 Lakes Energy LLC.69 He presented recommendations regarding line

losses and demand response programs on behalf of MEC/NRDC/SC; he presented

recommendations regarding rate design on behalf of MEC and NRDC; and he

presented recommendations regarding self-generation rates on behalf of

MEC/NRDC/SC, ELPC, and MCA.

Regarding line losses, Mr. Jester testified that after his review of the line loss

study in Exhibit A-36 identified certain anomalies, Consumers Energy provided a

revised study, which is Exhibit MEC-9. He testified that the company’s cost allocation

does not properly use the demand loss results of the study. He presented a revised

cost-of-service study in Exhibit MEC-11, and a comparison of the resulting revenue

requirements for each class at 9 Tr 1579. He recommended that future line loss studies

determine line losses separately for summer and winter, peak and off-peak times, and

include additional information. He also recommended that the demand loss factors be

expressly adopted in this case for purposes of determining avoided costs under

PURPA.

69 Mr. Jester’s testimony, including his surrebuttal testimony and cross-examination, is transcribed at 9 Tr 1569-1634; his qualifications are set forth at 9 Tr 1573-1575 and in Exhibit MEC-8.

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Regarding rate design, he testified that the demand allocators 12 CP and 4CP as

well as class peak are not appropriate for billing determinants because they occur at

random times, but recommended reliance on billing determinants that provide

customers with control over the costs they incur, based on those allocators. He testified

that he recast the cost-of-service study results to costs each allocated based on a single

allocator, to illustrate his point. He took issue with the allocation of class distribution

costs to rate schedules on the basis of the rate schedule’s share of the class peak,

recommending that the Commission review the rate-schedule allocations in the context

of its distribution plan review. From a sample of 120 residential customers with smart

meters taking service under the Residential Service Secondary rate (Rate RS), he

computed the cost of serving each customer using the billing determinants underlying

the company’s cost allocations, and compared the results to the actual billed charges

for those customers. He testified that for a given cost of service, there is a wide range

of billed charges paid by customers, which he views as an indictment of the rate design,

also performing a regression analysis for a more formal comparison. He testified that

his regression results show that if the allocation methods are sound, production plant

allocated using the 4CP allocator should be recovered through summer rates per kWh,

transmission costs allocated using the 12CP allocator should be recovered throughout

the year but weighted more heavily toward summer, and that distribution costs allocated

on a class-peak basis should be recovered in the summer. He further explained that

regressions show the current billing determinants for Rate RS are not warranted by a

relationship to the basis on which costs are allocated. He recommended time-of-use

rates as an alternative, concluding that the regression results to support this approach.

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Citing the Commission’s order in Case No. U-17688, he recommended a transition to

time-of-use rates beginning with this rate case, since the AMI meter installation will be

complete.

Mr. Jester also testified that he strongly supports the use of demand response,

but raised two concerns with the company’s commercial and industrial demand

response proposals. He objected that the program is only available to primary

commercial and industrial customers, and he objected that the costs of the program are

to be allocated to all customers as a capacity resource. He recommended that the

costs of the program be recovered from the participating customers.

Turning to Rate GSG-2, Mr. Jester referenced the study of standby demand

charges required by the Commission’s order in Case No. U-17790, and the

comparisons in Exhibits A-83 and A-85, and recommended that the company’s

proposed power supply capacity charges be revised to better reflect the cost of serving

the standby customers. He reviewed the company’s reasons for rejecting the revenue

sufficiency shown by the cost allocations, and found them insufficient. He

recommended that the Commission adopt a rate design that limits generation capacity

charges to recovery based on the expected forced outage rate of that customer and the

average cost of capacity that would be assigned if the customer were not a full-service

customer. He also recommended that the Commission allow customers with solar self-

generation to take service under the Rate GSG-2 tariff or the tariff to which they would

otherwise be assigned, until the Commission approves distributed generation tariffs

under MCL 460.6a(14).

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G. MCA

In addition to sponsoring Mr. Jester’s testimony as discussed above, MCA also

presented the testimony of two additional witnesses. Jamie Scripps is a Partner with

the firm 5 Lakes Energy LLC.70 Ms. Scripps testified that interest in cogeneration has

increased around the country. She also described her analysis of Consumers Energy’s

standby tariff, Rate GSG-2, as proposed in this case, in what she labeled an “apples-to-

apples” comparison to other utilities. She presented the analytic framework in her

Exhibit MCA-2, with her understanding of Consumers Energy’s tariff in Exhibit MCA-4.

Exhibit MCA-3 contains her comparison of the company’s proposal in this case to the

standby tariffs of the other utilities she evaluated, under 8 hypothetical scenarios. She

testified that customers pay relatively high standby charges under Consumers Energy’s

proposal, the second-highest charges in a no-outage month. She also testified that for

a scheduled on-peak maintenance outage of 16 hours, charges would double under the

company’s proposal. Ms. Scripps cited the MPSC Staff Standby Rate Working Group

Supplemental Report, and endorsed specific conclusions, taking issue with Consumers

Energy’s proposals in this case as inconsistent with the Supplemental Report. She also

reviewed discovery responses from the company, and provided examples of best

practices based on her experience.

Ron Dueweke is Principal Strategist with Sustainable Partners LLC (“Spart”), an

alternative and renewable energy project development and consulting firm.71 He

explained how projected standby rates are included in the analysis of the operating

costs of a potential cogeneration project. He testified that for Consumers Energy and

70 Ms. Scripp’s testimony is transcribed at 6 Tr 201-222; her qualifications are set forth at 202-205. 71 Mr. Dueweke’s testimony is transcribed at 6 Tr 186-199; his qualifications are set forth at 6 Tr 187-189.

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DTE Electric Company, standby charges typically increase the payback period for

projects by 6 to 18 months, which may be critical to the decisions whether to implement

each project. He testified that uncertainty in cost projections can also adversely affect a

decision to implement a project. He characterized Consumers Energy’s Rate GSG-2

tariff as using a “complicated calculation” that is not straightforward. He recommended

that the Commission require the company to eliminate complicated formulas and state

the same energy charges for standby power as full service customers, with differential

on-peak and off-peak pricing. He also objected the monthly charges as excessive and

recommended that delivery demand charges be prorated based on a customer’s use of

the delivery system. He objected to Consumers Energy’s proposed increase in standby

users’ capacity demand charge, discussing typical forced outage rates and schedule

maintenance outage durations. He recommended a limit on the allocation of non-

dedicated utility resources to standby customers to 5%, which he testified is the typical

limit of cogeneration outages. He further identified benefits from cogeneration

programs.

H. Kroger

Kroger presented the testimony of Neil Townsend, Principal at the consulting firm

Energy Strategies, LLC. He described Kroger as one of the largest retail grocers in the

United States, purchasing 500 million kWh from Consumers Energy annually, primarily

under Rate GPD. He addressed the Rate GPD rate design and revenue allocation

among voltage levels. Reviewing Ms. Collins’s testimony, he generally endorsed the

company’s cost-of-service study and rate design for the Rate GPD class as a whole.

He recommended that the system access charges for Rate GPD voltage levels 1 and 3

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be adjusted to that the system access charges better match the customer costs for each

subclass, and he recommended that the differential between the capacity demand

charges for these subclasses be decreased to bring each subclass closer to its rate

design target. He presented Exhibit KRO-1 in support of his testimony, and he also

presented rebuttal testimony as discussed below.

I. Walmart

Walmart presented the testimony of Gregory W. Tillman, Senior Manager for

Energy Regulatory Analysis for Wal-Mart Stores, Inc. He testified that Walmart has 118

retail units in Michigan, with over 30,000 employees, and purchased $3 billion worth of

goods and services from Michigan suppliers in 2017. He recommended that the

Commission carefully consider the impact on customers in examining the revenue

requirement for Consumers Energy and setting an authorized return on equity. He

provided his opinion that the return on equity requested by Consumers Energy is

excessive, discussing Michigan’s regulatory framework, the inclusion of construction

work in progress (CWIP) in rate base, and the authorized returns on equity granted by

other regulatory commissions. He further testified that Walmart does not oppose the

company’s cost of service study or rate design, but reserved the right to address

alternatives presented.

J. HSC

HSC presented the testimony of Michael P. Gorman, a consultant and managing

principal of Brubaker & Associates, Inc. Mr. Gorman explained that HSC is a

manufacturer of semiconductor and solar grade polycrystalline silicon and related

chemicals, headquartered in Hemlock, Michigan, and is Consumers Energy’s largest

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single-site customer. He addressed Consumers Energy’s proposed modifications to

Rate GPD, testifying that he supports the company’s proposal to include a customer-

specific delivery charge as a result of the Commission’s order in Case No. U-17990. He

also recommended that the power supply charge for Rate GPD be modified by the

addition of a separately-stated transmission charge. He views the separate charges for

production and transmission as more transparent and more conducive to load and cost

management for customers. He presented charts showing the separation of the

transmission capacity charge by voltage level, and a revised energy charge. He

presented four exhibits in support of his testimony, Exhibits HSC-1 through HSC-4, the

first two of which are confidential.

K. RCG

The RCG presented the testimony of two witnesses. Mr. Bathgate, an engineer,

testified that he has experience with the technology used in AMI meters.72 He testified

that the AMI meters use a significant amount of electric energy, 2.37 kWh per day or

865 kWh per year on average. He calculated the cost of this amount of energy as

$120.67 per year per customer, and asserted that these costs were never disclosed to

customers. He recommended that the Commission require the company to provide

analog meters to customers who want them, and eliminate initial and monthly

surcharges for opt-out customers. In the alternative, he recommended that if the

Commission retains opt-out charges, that the costs of energy consumption associated

with the smart meters be credited against the opt-out costs assigned to the opt-out

charges. He also recommended that Consumers Energy be required to advise 72 Mr. Bathgate’s testimony is transcribed at 11 Tr 2191-2204; his qualifications are set forth at 11 Tr 2192-2193, and in his resume, Exhibit RCG-2. A portion of Mr. Bathgate’s prefiled direct testimony was stricken by ruling of the ALJ.

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customers of the new costs associated with operating the smart meters. He presented

Exhibits RCG-3 and RCG-5 in support of his testimony.

Mr. Peloquin, a retired C.P.A. who has worked for the MPSC and for the

Michigan Department of Attorney General as well as working as a consultant on utility

matters, testified regarding his personal experience with an AMI meter at a home he

owns.73 Based on his understanding of the appliances in the home and his review of

the bills, he concluded that after the AMI meter was installed, metered consumption

increased due to the meter itself. Mr. Peloquin also testified regarding the

Commission’s approval in Case No. U-17990 of the use of deferred tax accounting for

City of Detroit income tax increases. After reviewing the accounting, he testified that the

Commission should not allow the company to include the regulatory asset in rate base.

L. Rebuttal

Five parties presented rebuttal testimony, with MEC/NRDC/SC and Consumers

Energy presenting additional testimony in the nature of surrebuttal. Consumers Energy

witnesses provided rebuttal testimony addressing the rate base, rate of return, adjusted

net operating income, cost allocations, and rate design. Mr. Torrey’s rebuttal testimony

addressed concerns raised by Mr. Coppola and Mr. Laruwe regarding the company’s

proposal to refund unspent distribution capital expenditures funded through rates, and

Mr. Pollock’s concerns regarding the use of a projected test year.

Ms. Myers’ rebuttal testimony addressed Mr. Coppola’s recommended

adjustments to the revenue requirements calculations, principally referring to other

rebuttal witnesses, but specifically taking issue with Mr. Coppola’s reduction in working

73 Mr. Peloquin’s testimony is transcribed at 11 Tr 2212-2221; his qualifications are set forth at 11 Tr 2213 -2218. Mr. Peloquin’s testimony was also the subject of a motion to strike, which the ALJ denied.

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capital by using an assumed higher balance of accrued interest. She presented Exhibit

A-134 in support of this testimony. She also took issue with other details of

Mr. Coppola’s revenue requirements calculation, including the interest on preferred

stock used to calculate the overall cost of capital, a perceived error in use of total versus

jurisdictional figures, and his calculation of the tax-effect of pro forma interest. She also

took issue with Staff and ABATE testimony recommending rejection of regulatory asset

treatment for demand response program expenses. Finally, Ms. Myers presented the

calculations of a revised jurisdictional revenue deficiency of $148 million for the

projected test year, based on the positions taken in the company’s rebuttal case.

In his rebuttal testimony, Mr. Bordine took issue with proposed reductions in

capital expenditures recommended by Staff witnesses Mr. Laruwe and Ms. Fromm, and

by the Attorney General witness Mr. Coppola. In responding to Mr. Coppola regarding

the electric operations –other category, he acknowledged that Consumers Energy had

provided incorrect information regarding 2017 actual expenditures to the Attorney

General in discovery and presented the corrected discovery response in Exhibit

A-103.74 He also reiterated his view that contingency projections should be included in

capital expense projections. He also took issue with Mr. Laruwe’s and Mr. Coppola’s

proposed reductions in the company’s projected line-clearing expense. Addressing

Mr. Jester’s testimony on line losses, Mr. Bordine objected that the hourly data required

for Mr. Jester’s recommended analysis is not available for the entire system.

Ms. Hill’s rebuttal testimony addressed recommendations by Staff witnesses

Mr. Evans and Ms. Fromm, Attorney General witness Mr. Coppola, and MEC/NRDC/SC

74 See 6 Tr 451.

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witness Mr. Koehler regarding recommended reductions to O&M and capital expense

projections.

Regarding the Medium 4 retirement analysis, she objected to Mr. Evans’s

recommendation that avoidable capital expenditures for Karn 1 and 2 be avoided, and

she objected to Mr. Koehler’s recommendation that the Commission not approve any

capital or major maintenance O&M spending on the Medium 4 units that is avoidable

under a 2021 or 2023 retirement scenario. She emphasized that the company has not

made a decision to retire any of these units, and asserted that the test year

expenditures provide value to customers. She also reviewed some of the company’s

assumptions underlying its retirement analysis. Ms. Hill also took issue with

Ms. Fromm’s recommended exclusion of contingency expense from the capital expense

projections, citing Mr. Thomas’s testimony, and presenting revised figures in her Exhibit

A-114. And she objected to Mr. Coppola’s recommended $13 million reduction in

projected capital spending, disputing a connection between capital spending projections

and cash flow projections. She also objected to three other adjustments recommended

by Mr. Coppola, disputing that the company’s estimates are preliminary.

Regarding Mr. Evans’s recommended reductions in O&M environmental

spending, she provided additional testimony addressing reasons for past

underspending, and asserted that Staff’s recommendation does not take into account

that 2017 is the first year of operation of the Air Quality Control System (AQCS) at the

Campbell plant. She similarly objected to Mr. Coppola’s recommended reductions in

environmental O&M expense, and she objected to his recommended reductions in the

projected O&M expense for the residential demand program, disputing that the

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company will not meet target enrollment increases for the program. She presented

Exhibits A-109 through A-119 in support of her rebuttal testimony.

Mr. Clark’s rebuttal testimony responded to the testimony of MEC/NRDC/SC

witnesses Mr. Koehler regarding the Medium 4 retirement analysis, and to Mr. Jester’s

testimony regarding line losses. He testified that the company’s Medium 4 analysis

complied with the Commission order and included reasonable assumptions, but

committed to a more decisive analysis in the company’s Integrated Resource Plan filing

in 2018. He presented Exhibit A-104 as an additional summary of the results of the

analysis in explaining why no reductions should be made in the company’s projected

costs to maintain these units. He also objected that Mr. Jester’s recommendation to

establish line loss factors to use in determining PURPA avoided cost rates is

inappropriate for this case, and he took issue with certain assumptions in his

recommendations.

Ms. Breining’s rebuttal testimony responded to Staff witness Mr. Evans’s

recommendation that certain environmental capital expenditures for Karn labeled

avoidable under an early retirement scenario should not be included in the rate case

projections pending a determination on early retirement. She testified that the

company’s consideration of a double-lined bottom-ash surface impoundment at Karn

does not mean the company has decided to retire Karn, but perceives an opportunity for

the cost savings because the MDEQ expects to have a permit program for coal

combustion residuals by 2019, providing an opportunity for an alternate compliance

plan.75 Citing Mr. Clark’s testimony, she stated that Consumers Energy has not decided

to retire Karn 1 or 2, or Campbell 1 or 2, and further, that MISO approval would be 75 See 9 Tr 1451.

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required before the units could be retired. She recommended that the projected

expenditures be approved.

Mr. Morales’s rebuttal testimony addressed Mr. Jester’s testimony regarding the

company’s demand response program for commercial and industrial customers. He

testified that the demand response program is reasonably limited to commercial and

industrial customers because there is a residential demand response program called

the “Peak Power Savers Program,” addressed by Mr. Hurd. He also disputed that the

program costs should be recovered from participating customers. Mr. Morales also

addressed Mr. Coppola’s testimony regarding the digital customer platform. He

contended that in recommending holding projected expenses to 2016 levels,

Mr. Coppola did not understand the scope of the platform, its importance to customers

and its evolutionary nature. He reviewed the development of the program from 2015

forward.

Mr. Varvatos presented rebuttal testimony to address Staff’s and Attorney

General’s recommendations regarding IT spending adjustments. He objected to

Ms. Fromm’s recommendation to remove the cost for “fleet handhelds” from the

projected expenditures, testifying that subsequent to the company’s response to

discovery indicating no device had been selected, the company selected a specific

handheld device. He objected to Ms. Fromm’s recommendation to remove the cost

estimates for “mobile security” from the projected expenditures, testifying that although

the company had not yet determined the solution needed to protect mobile assets from

cyber security attacks, it has progressed substantially through the planning phase.

Turning to Mr. Coppola’s recommended reduction in IT O&M spending, he contended

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that Mr. Coppola wrongly relied on the employee and contractor count information in

Exhibit A-73 as well as a company discovery response in questioning the projected cost

increases, and contended that the projections were supported in his direct testimony.

He also took issue with Mr. Coppola’s recommended reduction in the capital expense

projections for the test year, testifying that the company has reduced the projected cost

of its digital customer experience and related projects, but testifying that the projects are

necessary, and disputing Mr. Coppola’s criticisms. Mr. Varvatos also objected to

removing contingency cost projections as recommended by Ms. Fromm and

Mr. Coppola.

Mr. Warriner’s rebuttal testimony addressed testimony provided by the RCG

witnesses Mr. Peloquin and Mr. Bathgate, by Mr. Jester, by Ms. Fromm and

Ms. Simpson, and by Mr. Coppola. Addressing the RCG witnesses’ concern that the

AMI meters are registering consumption for the energy billed to customers, he testified

that the smart meters do not measure the power requirements of the meter as part of a

customer’s billed electric consumption, citing Mr. Arcienega’s testimony. He also

testified that he has verified that smart meters for customers whose service has been

remotely disconnected do not register consumption, and he took issue with the

estimates of meter consumption presented by Mr. Peloquin and Mr. Bathgate,

presenting usage statistics for comparison. He also reviewed some of the components

of the AMI opt-out charge and testified that the company is not willing to rely on self-

reporting of meter readings by customers, citing the Commission’s decisions in Case

No. U-17735 and U-17990.

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Also related to the AMI program, Mr. Warriner responded to Ms. Fromm’s

recommendations on the application of the opt-out tariff to premises with multiple

meters, explaining that the company has been applying the monthly charges per meter,

and wants the tariff changed to avoid additional system enhancement costs. And he

objected to Staff’s and the Attorney General’s recommendation to continue the

business-case presentation, citing the Commission’s order in Case No. U-17735 and

disputing that additional updates will be useful.

In response to Mr. Jester’s testimony recommending time-of-use rates,

Mr. Warriner reviewed the company’s current time-of-use offerings and enrollment

levels. Regarding Staff’s recommendations on smart-grid reporting, he stated that the

company agrees with Staff’s recommendation to separate the report from the five-year

distribution plan, but recommends an annual reporting date of March 31 rather than

February 15. He also objected to Ms. Simpson’s recommended accounting and

depreciation provisions for the load control switches, and to Staff’s recommended

adjustment to the capital expense projections for residential load control switches,

contending that the participant counts should be increased as the company proposed,

and that the Commission did not intend to limit the program to 42 MW. He also took

issue with the calculations presented in Exhibit S-12.7. Regarding Staff’s

recommendation to increase demand response marketing and education efforts, he

testified that the company is open to increasing its efforts but has not requested

additional funding in this case, and believes the company should first consider the

recommendations in the recent demand response stakeholder workgroup report.

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Mr. Kops’s rebuttal testimony addressed Staff’s recommended adjustment to

pension expense and the Attorney General’s recommended adjustment to pension and

OPEB expenses. He presented as his Exhibits A-120 and A-121 the Aon Hewitt

actuarial projections for pension and OPEB expenses for 2017 and 2018, which he

stated had been included in his workpapers.76 Responding to Staff’s recommended

reduction in PBGC premiums and actuarial fees, he identified recent increases in the

fees and explained that Consumers Energy expects to incur variable as well as fixed

fees because it has not made a contribution to its pension fund for 2017 to bring the

market value of the fund to the level of projected benefits. Responding to Mr. Coppola’s

recommended revision to the discount rate, he testified that Consumers Energy is

relying on the discount rate it determined as of December 31, 2016. He acknowledged

that Consumers Energy refused to provide the Aon Hewitt corporate bond yield curve

he testified that the company relied on, but asserted that Aon Hewitt adheres to strict

standards and can therefore be relied upon.

Mr. Harry’s rebuttal testimony responded to Staff’s recommended adjustment to

the company’s uncollectible expense projection, and the Attorney General’s objection to

the credit card payment program. He objected to Staff’s $2 million adjustment to

uncollectible expense, contending the Commission had rejected reliance on

presentations to the company’s board of directors in Case No. U-17735, and contending

that the budget number is unsupported by any calculation methodology, assumptions,

or basis.77 He also objected to Staff’s alternative projection, indicating the company had

relied on a three rather than a five-year average consistently in its recent rate filings.

76 A typographical error in his testimony refers to 2018 and 2019 projections. See 10 Tr 1980. 77 See 6 Tr 576.

U-18322 Page 58

Mr. Harry also objected to the Attorney General’s recommended reduction of

$5.2 million in the company’s projected cost of credit card processing fees. He cited

Mr. Morales’s testimony that fee-free credit card payments are convenient for

customers, but testified that because customers could always use credit cards, subject

to a $6.25 fee, the elimination of the fee should not reduce uncollectible expenses.

Finally, Mr. Harry explained that the FERC case involving the company’s transmission

assets has been resolved, and he presented a calculation in Exhibit A-108 of the

appropriate adjustments to be made in this case, also recommending a transitional

adjustment to PSCR rates.

Ms. Conrad’s rebuttal testimony addressed objections to the inclusion of

incentive compensation program costs from witnesses for Staff, the Attorney General,

and ABATE. She testified that for purposes of this case, the company is withdrawing its

request for recovery of the long-term restricted stock plan. She objected to Staff

witness Mr. Welke’s recommendation to exclude from rates the portion of the projected

cost of the EICP tied to financial measures, disputing his conclusion that financial

measures do not benefit customers, contending that they allow the company to maintain

an attractive cost of capital and that customers benefit from a financially healthy utility,

and citing Mr. Maddipati’s rebuttal testimony. She also reiterated that overall

compensation levels are market-based and therefore reasonable. She disputed

Mr. Coppola’s characterization of the EICP payments as a bonus, and disputed that the

measures are too heavily weighted to financial performance. Further, she disputed that

mixing gas and electric measures causes a concern, and she disputed that measures

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are duplicative. Responding to Mr. Pollock’s testimony, she reiterated that a financially

strong utility allows it to better meet customer needs at the best price.

Mr. Stuart’s rebuttal responded to Mr. Coppola’s recommendation to exclude the

EICP costs from rates. He took issue with Mr. Coppola’s assertion that the plan does

not provide real customer benefits, referencing his direct testimony. He also testified

that even if the Commission agrees with Mr. Coppola’s criticisms of a number of

measures and benefit quantifications, the Commission should still include the full

$3.4 million requested because it is part of a reasonable level of compensation. He also

reviewed some of the disputed measures, testifying that they were carefully constructed

to balance customer value, reliability, and safety.

Mr. VanBlarcum’s rebuttal testimony responded to Mr. Peloquin’s objection to

recovery of the regulatory asset approved for changes to the City of Detroit Income Tax,

citing prior Commission orders, noting that the Commission approved the regulatory

asset treatment in the last rate case.

In his rebuttal testimony, Mr. Denato revised his recommended capital structure,

recommending a common equity balance approximately $69 million lower than in his

direct testimony. He presented the revised capital structure in Exhibit A-106, modeled

on Staff’s Exhibit S-4, Schedule D1, with the company’s recommended cost of equity,

resulting in an overall rate of return of 6.09%.78 Mr. Denato responded to testimony

regarding the capital structure recommendations made by Mr. Coppola and

Ms. LaConte, opposing their recommendations that would result in a lower equity

percentage. He objected to the Attorney General’s recommendation to reduce the

78 See 9 Tr 1362.

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working capital cash balance, and provided a correction to the cost rate Mr. Coppola

used for preferred stock.79

Mr. Denato also addressed Staff’s 2% reduction in O&M expenses, contending

that Mr. Welke wrongly relies on general goals, and further arguing that this type of

adjustment has previously been rejected by the Commission, and that Staff’s

calculations contain discrepancies. And Mr. Denato addressed Mr. Laruwe’s testimony

regarding distribution capital expenditure projections, taking issue with his statement

that prior underspending may have contributed to the company’s actual rates of return.

Mr. Maddipati’s rebuttal testimony took issue with the recommendations of the

other return on equity witnesses, including Ms. Bankapur, Ms. LaConte, and

Mr. Coppola. He contended they had ignored the legal standards for setting rates of

return, objected that they had not consulted with the investment community, and

objected that they had not used the same models and assumptions he used in

formulating their recommendations.

In his rebuttal testimony, Mr. Breuring addressed Mr. Coppola’s testimony

regarding electric residential sales, testifying that Mr. Coppola’s use of a five-year trend

does not reflect economic indicators or increased efficiency. He also testified that

Mr. Coppola did not extrapolate the trend to cover the entire projected test year.

Mr. Bruering also objected to Staff’s recommendation to reduce the projected RIA

customer count, arguing that Staff’s recommendation does not reflect historical

enrollments, and he objected to Mr. Pollock’s testimony that a billing demand forecast

should be required for the Rate GSG-2 class power supply revenues, arguing that the

79 See 9 Tr 1382-1383.

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company’s delivery forecasts do not reflect rate design changes, and cannot predict

when these customers’ generators will be down.

Ms. Walz presented rebuttal testimony regarding capacity-related expenses.

Addressing Mr. Revere’s testimony, she rejected his contention that capacity costs

under MCL 460.6w should be capped at CONE. She testified that the Commission

should provide incentives to ensure needed capacity is developed in Michigan. She

also testified that only net market sales should be deducted in determining capacity

costs. Her Exhibit A-135 is a discovery response provided by Staff.

Theresa K. Martinez, Director of Distribution Agreements and Attachments,

testified in rebuttal to Ms. Baldwin’s testimony regarding generator interconnection

requests.80 She testified that Consumers Energy is not opposed to the request, but

seeks certain clarifications and refinements regarding the information to post and how

and when changes should be reflected. She recommended that the Commission initiate

a separate docket for a work group to a consistent approach for all utilities.

Josh R. Hall, Director of Information Technology, presented rebuttal testimony in

response to Staff witness Ms. Simpson’s recommendations regarding the company’s

time-of-use residential demand response programs.81 He objected that implementing

this approach would require complex changes to the company’s existing IT

infrastructure, without significant benefits. He also expressed a concern with

Mr. Revere’s recommended elimination of the Rate RS block rate design in favor of an

on-peak and off-peak summer rate, again indicating it would require complex changes

in the company’s billing system, and recommended a phased approach. 80 Ms. Martinez’s rebuttal testimony is transcribed at 7 Tr 986-991; her qualifications are set forth at 7 Tr 987-989. 81 Mr. Hall’s rebuttal testimony is transcribed at 7 Tr 981-984; his qualifications are set forth at 7 Tr 982.

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Luis E. Arcienega, Senior Lead Engineer in Metering Technology, provided

rebuttal testimony addressing the energy consumption of the AMI meters in response to

Mr. Peloquin’s and Mr. Bathgate’s contention that operation of the AMI meters along

causes the meters to register customer consumption.82 He testified that the meters do

not cause consumption on the customer side of the meter. He reviewed applicable

standards and the company’s own tests supporting his testimony. He was also cross-

examined on his testimony.

Ms. Aponte presented rebuttal testimony addressing Mr. Putnam’s and

Mr. Revere” recommendations on behalf of Staff, Mr. Pollock’s recommendations on

behalf of ABATE, Mr. Jester’s recommendations on behalf of MEC/NRDC/SC, ELPC,

and MCA, Mr. Dueweke’s and Ms. Scripps’s recommendations on behalf of MCA, and

Mr. Gorman’s recommendations on behalf of HSC. She objected to Staff’s proposal

regarding production costs, citing the NARUC manual and arguing that Staff’s approach

to capacity costs ignore other capacity-related costs such as intangible plant allocated

on a demand basis, and other joint-and-common costs allocated based on labor ratios

or plant-in-service. She also objected to the exclusion of plant held for future use from

capacity costs. (She also contended that Staff’s proposal is inconsistent with a position

in took in Case No. U-17032.) Ms. Aponte also disputed Mr. Revere’s objection to her

proposed reallocation of system sales.

Regarding ABATE’s recommendations, Ms. Aponte testified to two

inconsistencies in Mr. Pollock’s methodology and results, and testified that his proposed

use of demand line loss factors would shift $2.2 million in costs to the primary class,

82 Mr. Arcienega’s testimony, including cross-examination, is transcribed at 6 Tr 259-283; his qualifications are set forth at 6 Tr 263-264.

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including $0.6 million in distribution costs that he did not intend to address. She also

objected to his proposal to change the allocation of interruptible credits, also stating that

it would not materially change the allocation between major classes. Reviewing

Mr. Jester’s testimony regarding the use of demand line loss factors, she testified that

his modifications were not fully explained, and referred to Mr. Bordine’s rebuttal

testimony regarding limits on future line loss studies.

Responding to Mr. Gorman’s testimony regarding the calculation of the

customer-specific delivery charge for HSC, Ms. Aponte testified that Consumers Energy

agrees to reduce the total distribution O&M expense allocated to the Rate GPD-voltage

1 by 77% to account for the overhead portion related to the load served by HSC

substations, and presenting the revised calculation.83

Responding to Mr. Dueweke’s reliance on the cogeneration outage rate of 5% to

as a limit on the allocation of costs, she testified that this recommendation is

inconsistent with the Commission’s currently-approved methods, and explaining that

load profiles could change significantly as new customers subscribe to the rate. She

also reviewed Ms. Scripps’s apples-to-apples comparison, stating that utilities in other

states may be able to use incentives in their rate structures, which is not permitted

under Michigan law. She also contended that Ms. Scripps was confusing reservation

fees and delivery charges, contending that the company’s Rate GSG-2 delivery charges

are based on the fixed distribution costs ready to serve standby customers at all times.

Ms. Collins presented rebuttal testimony addressing recommendations made by

Staff, ABATE, HSC, MCA, and MEC/NRDC/SC/ELPC/MCA. She objected to Staff’s

use of the same capacity cost adjustment for the EIP rate as used in the company’s 83 See 7 Tr 707-708.

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filing, contending that the purpose of the adjustment was to keep the EIP increases in

line with the GPD increases. She also objected that Staff’s implementation of a cross-

point adjustment results in a crossing point of 55% rather than the 45% Staff stated it

was using, and recommended the 45% be used. She also defended the company’s

proposals for customer-specific distribution rates, specifically discussing HSC.

Turning to capacity costs, she objected to Mr. Revere’s proposal to collect

capacity charges through summer on-peak kWh charges for rate schedules without

demand charges, and through summer on-peak billing demand charges for rate

schedules with demand charges. She characterized this as a dramatic rate change,

contending that he confuses cost responsibility with rate design, asserting that capacity

is not free the rest of the year, and also expressing a concern that this rate design could

cause hardship or disruptions for customers in the summer months. She also objected

to his proposal for on-peak and off-peak summer rates for residential customers,

characterizing this as a “fundamental change” that is unnecessary because the

company already offers voluntary time-of-use rates. Further, she recommended that

any such proposals be phased in, if adopted by the Commission, and cited Mr. Hall’s

rebuttal testimony.

Addressing Mr. Pollock’s testimony, she agreed with him that senior citizen and

low-income discounts should be allocated based on distribution customer-related costs

rather than total cost of service, and agreed that transmission costs allocated to the

Rate GPD class should be recovered in the demand charge, further recommending that

they be separately stated as a line item. She objected to his proposal to increase the

summer and winter differential, contending that the current differential is based on the

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value of capacity in the summer relative to other months, and also characterizing his

proposal as a dramatic change, and she objected to his proposal to retain the current

rate design for Rate GSG-2, referring to the planned termination of the Palisades PPA,

and the need to avoid a subsidy. She also disputed that backup power should be

distinguished from power for scheduled maintenances in designing standby rates, and

objected to his other proposals regarding Rate GSG-2.

Responding to Mr. Gorman, she agreed with the proposed revision to the

calculation of the customer-specific delivery charge for HSC, and presented Exhibit

A-105 to reflect the revision. Responding to MCA’s witnesses, she objected to

Mr. Dueweke’s statements and proposals regarding Rate GSG-2, arguing that the 4CP

capacity allocation “may not be reflective when an intermittent standby customer is

actually using capacity,” that 15 customers is an insufficient basis for a cost-of-service

study, and further that the company is required to propose rates that are cost-based. 84

She disputed that standby rates are a barrier to cogeneration project development, and

responded to Ms. Scripps’s applies-to-apples comparison by reiterating that rates must

be cost based.

Responding to Mr. Jester’s testimony regarding the Rate GSG-2 rates, she

testified that a reservation charge would reflect the expected forced-outage rate for

standby customers, but testified that the company has not proposed a reservation

charge, and objected to his proposal to let standby customers choose the standby rate

or the rate they would otherwise be eligible for, noting that the company has agreed to

allow solar customers to use the time-of-use rate, Rate GPTU, and can evaluate the

results of that expansion in the future. Responding to Mr. Jester’s testimony regarding 84 See 10 Tr 2030.

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the mismatch of residential billing determinants and cost allocators, she stated her belief

that the two are not related, emphasized that capacity is used all year long, and

contended that Mr. Jester ignored the impact on low-income and fixed-income

customers.

Mr. Hurd presented rebuttal testimony addressing tariff and rate schedule

changes proposed by Staff, MEC/NRDC/SC, ELPC, and MCA. Responding to

Ms. Fromm’s testimony on modifications to the AMI opt-out tariff, Mr. Hurd asserted that

the current language is “open to interpretation” and requires clarification. Regarding

Ms. Simpson’s concerns with his proposal to require residential demand response

customers to remain in the program for 12 months, he cited MCL 460.1095 as the basis

for the choice of 12 months, and further indicated that any trial period should be at least

6 months. Regarding Ms. Baldwin’s testimony that the Rate GPTU should be open to

solar customers of any size, he testified that the company would agree to this on a trial

basis, proposing a minimum period of 5 years.

Responding to Mr. Dueweke’s testimony, Mr. Hurd agreed that transmission

losses should be itemized within Rate GSG-2. Responding to Mr. Jester’s testimony

regarding Rate GSG-2, he disputed that the company is violating the Public Utility

Regulatory Policy Act of 1976 (PURPA), he reviewed the tariff language dating to the

creation of Rate GSG-2 indicating it is available to all QFs and is available to all full-

service customers with generation above 550 kW.

Staff presented the rebuttal testimony of three witnesses. In his rebuttal

testimony, Mr. Revere addressed Mr. Jester’s recommendation regarding future

analysis for Consumers Energy to undertake. He objected to requiring the company to

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evaluate using critical summer peaks in rate design, because such a rate design risks

moving those peaks. He also testified that while parties should be free to make

recommendations regarding rate design, the Commission should not require the utility

to undertake an analysis similar to that presented in Mr. Jester’s testimony. Mr. Revere

agreed with Mr. Jester’s recommendations to reexamine the allocation of distribution

costs in the next rate case.

Kevin Krause is an Auditor in the Rates and Tariff section of the MPSC’s

Regulated Energy Division.85 He presented rebuttal testimony addressing

recommendations of witnesses for MCA and ABATE regarding Rate GSG-2. He

explained how use of the distribution system is measured for rate design purposes,

based on the peak demand of the customer, non-coincident with the system peak. He

referred to the recent Standby Rate Working Group Supplement Report, Exhibit S-15.1,

and further recommended that the Commission direct Consumers Energy to provide

additional information regarding Rate GSG-2 customers.

Mr. Isakson’s rebuttal testimony addressed HSC witness Mr. Gorman’s testimony

and ABATE witness Mr. Pollock’s testimony regarding a customer-specific delivery rate

for very large customers, recommending that facilities agreements are a better

approach to addressing the cost of shared facilities rather than an ongoing change in

rates. He also addressed Mr. Pollock’s testimony regarding the allocation of RIA and

RSC discounts, contending that the application of the discounts to the distribution

charge does not mean the discounts are related to distribution customer costs, and

citing the Commission’s June 7, 2012 order in Case No. U-16794. He also responded

85 Mr Krause’s rebuttal testimony is transcribed at 11 Tr 2363-2370; his qualifications are set forth at 11 Tr 2364-2366.

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to Mr. Jester’s recommendations regarding demand response, arguing that the demand

response benefits are realized by all customers, characterizing the customers as acting

in a dual role for the company, as customers and as providers, and endorsing the

company’s proposal.

Both ABATE witnesses presented rebuttal testimony. Mr. Pollock’s rebuttal

testimony addressed Staff’s cost-of-service study and rate design. He objected to

Staff’s proposal to change the allocation of intersystem sales revenues from an energy-

based allocation to an allocation based on the 4CP 75/0/25 method, disputing that Staff

has a basis for the change. He objected to Staff’s proposal to classify 25% of

production fixed costs as non-capacity related, taking issue with the rationale provided

by Mr. Revere as unsupported and overly simplistic, and arguing that the full-service

rate designs should not be modified to facilitate the development of a capacity charge

under section 6w. He also objected to the revenue requirement Staff recommended for

the “Energy Intensive Primarily Rate” (EIP) class, contrasting the percentage increase

under Staff’s proposal to Staff’s overall recommended increase in the revenue

requirement, and arguing Staff has not provided any cost support for its proposed

increase in the EIP rate. He recommended that the Commission adopt the company’s

proposal to keep the EIP rate in parity with the GPD rate. And Mr. Pollock objected to

Staff’s proposed rate design for retail customers that would collect production capacity

costs through summer on-peak charges, contending it would create rate shock and

have other adverse consequences.

Mr. Pollock’s rebuttal testimony generally supported MCA witness Mr. Dueweke’s

proposed revision to the Rate GSG-2 delivery charge, recommending that the

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Commission designate the proposal for further review and analysis. His rebuttal

testimony also generally supported HSC witness Mr. Gorman’s recommendation

regarding customer investments in delivery facilities, citing his recommendation for

further analysis as presented in his direct testimony.

In her rebuttal testimony, Ms. LaConte took issue with Staff’s recommended

return on equity as presented by Ms. Bankapur and with the Attorney General’s

recommended return on equity as presented by Mr. Coppola. Ms. LaConte testified that

these witnesses recommended excessive returns on equity that ignore Consumers

Energy’s low risk and reduced regulatory lag.

Mr. Gorman’s rebuttal testimony addressed Staff’s rate design recommendations

as presented by Mr. Isakson. Mr. Gorman took issue with his explanation of Staff’s

opposition to the customer-specific delivery charge for certain Rate GPD customers,

contending that the charges would be cost-based and an appropriate way to address

substation ownership, and consistent with the Commission’s order in Case

No. U-17990.

Mr. Townsend’s rebuttal testimony addressed Staff’s cost-of-service study and

rate design proposals, ABATE’s and HSC’s recommendations regarding the recovery of

transmission expense, and ABATE’s and MEC/NRDC/SC’s recommendations regarding

the use of line loss factors. He objected to Staff’s proposal to recover certain non-

capacity-related costs through energy charges, arguing that the costs at issue should

instead be recovered through a demand charge, and he objected to Staff’s proposal to

recovery capacity-related costs through a summer on-peak demand charge for demand-

billed customers, characterizing it as a radical and unnecessary change. Mr. Gorman

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recommended that the Commission adopt ABATE’s and HSC’s proposal to collect

transmission costs through a separate demand charge to more accurately reflect cost

causation. And he recommended that if the Commission approved changes to the cost-

of-service study to incorporate the use of demand loss factors, the Commission also

consider the intra-class revenue misalignment he identified in his direct testimony

between the Rate GPD voltage levels 1 and 3.

As noted above, the parties agreed that Mr. Jester could present surrebuttal

testimony in response to Ms. Collins’s rebuttal testimony. Mr. Jester’s surrebuttal

addressed Ms. Collins testimony that he had ignored the impact of his proposed rate

design on low-income and fixed-income customers. He responded that he attempted to

get the necessary data from Consumers Energy to address this topic, but did not get the

data until August 29, 2017, when it was too late to include in his direct testimony. He

testified that he used the data he received to compute the average contribution of the

RIA customers to the allocators used in the company’s cost-of-service study. He

testified that while the average RIA customer uses 93% as many kWh on an annual

basis as the average RS customer, the average RIA customer uses only 73% as much

on-peak summer energy.86 He testified that he computed average bills for RS and RIA

customers and concluded that the average RS customer would pay about one-half-

percent more than the cost-of-service study indicates, while the average RIA customer

would pay 15.6% more than the cost-of-service study indicates without the bill credit,

and 9.1% more with the bill credit. Based on his conclusion that the average RIA

customer is subsidizing the average RS customer by approximately $101 per year, and

$185 per year if they do not take advantage of the discount program, he concluded that 86 See 9 Tr 1626.

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the rate design is unjust. He testified that he had not yet had the opportunity to analyze

comparable data for the RSC customers.87

In her sur-surrebuttal, Ms. Collins objected that the random samples Mr. Jester

relied on were not sufficient to justify relying on, and presented aggregate data for the

RS and RIA customers in her Exhibit A-136, contending that RIA customers used more

energy than Rate RS customers in each of the last 12 months.

III.

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.

Consumers filed its rate application using the projected test year October 1, 2017

to September 30, 2018. Mr. Pollock objected to the use of a projected test year:

A future test year invites unnecessary uncertainty over the many assumptions essential to setting just and reasonable rates (i.e., sales, revenues, investments and expenses). Such projections depend on a wide range of assumptions, such as customer additions, the timing of new investments and retirements, inflation, generation capacity additions/ retirements and dispatch, and economic indicators. Further, the utility has complete control over the information required to support future projections. As any forecast is inherently inaccurate, future test years are more difficult to verify than actual historical amounts. Even if the projections are thoroughly vetted, variations between projected and actual test-year costs are inevitable due to changing spending priorities, unanticipated efficiencies and/or unforeseen circumstances. Thus, future

87 See 9 Tr 1628.

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test years create uncertainties and further complicate the rate-setting process.88

Mr. Pollock referenced the Commission’s order in Case No. U-17990 finding that

Consumers Energy had underspent the prior projected reliability expenses by

$46 million,89 and testified that for 2016, Consumers Energy’s generation capital

expenditures were $50 million below what was projected in that case, and its actual

O&M expenses were $48 million below its 2016 projection.90 He also presented a chart

comparing Consumers Energy’s earned return on equity to its authorized return on

equity for calendar years 2011 through 2016, and for the 12-months ended May 2017.

He testified that Consumers Energy’s actual returns were above authorized in every

year except for 2012.91 He views the use of a projected test year as giving the utility

more than a reasonable opportunity to earn a reasonable return on its investment,

testifying: “Following a rate case order, a utility will ultimately determine how capital is

invested and the level of discretionary spending.”92 Nonetheless, Mr. Pollock did not

recommend the use of an alternate test year, and ABATE/Gerdau do not make this

recommendation in its brief. Instead, Mr. Pollock recommended and ABATE/Gerdau

argue that the use of a projected test year in setting rates should be taken into account

when setting the authorized rate of return.93

In should also be noted that Mr. Torrey presented rebuttal testimony identifying

benefits from using a projected test year:

88 See 12 Tr 2641. 89 See 12 Tr 2641, citing the February 28, 2017 order in Case No. U-17990, page 17. 90 See 12 Tr 2642. 91 See 12 Tr 2643. 92 See 12 Tr 2642. 93 See 12 Tr 2639; see ABATE/Gerdau brief, pages 3-6.

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The Legislature has made a policy decision recognizing the appropriateness and value of future test years. Test years are premised on the goal of determining a reasonable level of expenses for a future period. All parties are provided an opportunity to challenge and propose changes to test year assumptions. To the extent there is any uncertainty in the projections adopted by the Commission in setting rates, it is a worthwhile and important tradeoff to provide timely recovery of needed infrastructure investments; this is especially critical during periods of relatively flat sales.94

In its brief and reply brief, Consumers Energy correspondingly argues that the

legislature mandated the use of a projected test year if requested by the utility.95 Staff

disputes that the Commission is bound to use the test year chosen by the company,

although Staff has no objection to the company’s choice of test year.96

While several other parties disputed elements of the company’s test year

projections, only the RCG proposed using an historical test year to set rates, and that

proposal was only made in the RCG’s reply brief, leaving no party the opportunity to

respond.97 The basis for the RCG’s proposal appears to be that Consumers Energy

has filed rate case so frequently that the results of the immediately prior case cannot yet

be evaluated in the next case that is filed. The RCG argues that the record contains

sufficient information for the Commission to adopt a different test year than the one

used by Consumers Energy, but the RCG does not cite any testimony in support of this

argument, and does not even identify a specific historical period to be used. Given that

the RCG’s argument was raised for the first time in its reply brief and does not contain

record support, and given that no other party proposed the use of a different test year,

94 See 7 Tr 650-651. 95 See Consumers Energy brief, pages 6-9; Consumers Energy reply brief, pages 1-2. 96 See Staff reply brief, pages 3-7. 97 See RCG reply brief, pages 1-2.

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this PFD recommends that the Commission adopt the October 1, 2017 through

September 30, 2018 test year.

IV.

RATE CASE STANDARDS

Before addressing the disputes among the parties regarding revenue

requirements, cost allocation, rate design, and other matters, it is appropriate to review

certain legal issues. It is axiomatic that the Commission is required to set rates that are

just and reasonable. Ratemaking is essentially a legislative function, and the

Commission is not bound by any particular method or formula in exercising this

legislative function. The Commission is required to balance the interests of the public

utility and the consuming public. The Commission has also made clear that Consumers

Energy has the burden of proof to establish that its proposals are just and reasonable.

While these standards are indisputable, the arguments presented by the parties

reveal two disputes that undergird many of the disputed issues in this case. The first

dispute involves the company’s recurring argument that it has a statutory right under

MCL 460.6a to rely on projected values in setting rates for a projected test year, and the

second involves the used and useful doctrine. In addressing the choice of a test year

and responding to Mr. Pollock’s testimony on the value of using an historical test year,

Consumers Energy cites exclusively the Commission’s November 2, 2009 order in Case

No. U-15645, including the following language, with the emphasis supplied by

Consumers Energy:

The Commission is aware that the exceptions and replies are replete with arguments by the parties regarding test year issues. The Commission is persuaded that in this case and in future rate cases it should direct its

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focus upon the strengths and weaknesses of the evidentiary presentations of the parties regarding specific expense and revenue projections. Pursuant to MCL 460.6a(1), as recently amended by Act 286, a utility has explicit authorization to rely on projections of its future costs and revenues. The new provisions thus recognize that using projected data as a basis for rates may optimally reflect the cost of service contemporaneously with the effective period of the rates. A projected test year may reduce rate lag by providing more accurate adjustments when capital expenditures are escalating or revenues and costs are in flux. Given all of the circumstances, the Commission finds that the starting point for its analysis of the record shall be Consumers’ 2009 test year projections. The reliance by the Staff and the ALJ on historical data as the determinant of just and reasonable renders the statutory mandate in Act 286 meaningless. While the Commission retains its authority and duty to determine and set rates that are just and reasonable, it must make that determination by giving due consideration to the projected costs of the utility on a forward looking basis. The debate regarding the proper test year was decided by the legislature and the Commission finds the use of a future test year to be the proper measure of projected costs and revenues. For future guidance, the Commission's expectation is that the parties will fully document the basis for their test year projections by offering into evidence detailed supporting explanations and underlying assumptions rooted in expected business, financial, and economic circumstances. Rate applications may not rely on undocumented estimates of future ratemaking expenses and revenue criteria. When necessary, parties should provide competing projections, with a similar basis of support. The record thus created should lend itself to a comparative review of the reasonableness and prudence of the projections. Historical data may play a role, but ordinarily will not be the controlling factor except in circumstances that clearly demonstrate that it is a more fair and reasonable reflection of the utility's cost of service, relative to projected data.98

Consumers Energy then argues:

The Commission’s interpretation of the requirements of Act 286 in Case No. U-15645 is instructive for the Commission’s consideration of the issues disputed in this case. The relevant provision of MCL 460.6a(1) relating to the utility’s right to have its rates based on a fully projected test year has not changed. The Commission’s Case No. U-15645 recognition of MCL 460.6a(1)’s mandatory shift in the regulatory ratemaking

98 See Consumers Energy brief, pages 8-9, quoting the Commission’s November 2, 2009 order in Case No. U-15645, pages 6-9.

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paradigm-changing from the use of historical, known, and measurable costs, with known and measurable adjustments, to forward-looking, projected costs, should be repeated in this case in order to achieve a lawful result.99 As discussed above, no party seriously advocates for the use of a purely

historical test year in this case. To the extent, however, that Consumers Energy relies

on this argument to claim that the Commission cannot reject the company’s projections

in favor of alternatives that rely on historical data, such reliance ignores important

language from Case No. U-15645 that Consumers Energy has not highlighted, as well

as significant additional directives from the Commission regarding the utility’s

obligations to support its projections. In its January 25, 2010 order in Case No.

U-15645, addressing requests for rehearing and clarification, the Commission quoted its

January 11, 2010 order in a Detroit Edison rate case, Case No. U-15768 et al., as

follows:

[T]he Staff and intervenors should direct their focus “upon the strengths and weaknesses of the evidentiary presentations of the parties regarding specific expense and revenue projections.” . . . In a case where a utility decides to base its filing on a fully projected test year, the utility bears the burden to substantiate its projections. Given the time constraints under Act 286, all evidence (or sources of evidence) in support of the company’s projections should be included in the company’s initial filing. If the Staff or intervenors find insufficient support for some of the utility’s projections they may endeavor to validate the company’s projection through discovery and audit requests. If the utility cannot or will not provide sufficient support for a particular revenue or expense item (particularly for an item that substantially deviates from the historical data) the Staff, intervenors, or the Commission may choose an alternative method for the projection.100

In its November 4, 2010 order in Case No. U-16191, the Commission provided this

direction to the company:

99 See Consumers Energy brief, page 9 (emphasis added). 100 See January 25, 2010 order, Case No. U-15645, page 10.

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Consumers shall file in subsequent rate cases stronger evidence that will demonstrate its commitment to major capital projects and O&M expenses. For example, Consumers could file proposals and plans that have been provided to upper management or the Board of Directors for approval, actual and projected spending levels and completion status for the three years before and after the test year respectively, and any other evidence that will demonstrate Consumers’ commitment to its projected major capital projects and O&M expense.101

In Case No. U-16794, the Commission expressly rejected Consumers Energy’s

argument that it is statutorily entitled to rely on projected capital expenditures:

The Commission rejects Consumers’ assertion that simply because an amount is projected, it must therefore be granted lest the Commission violate the utility’s statutory right to rely on projections. In the statute providing for the use of a projected test year, nothing eliminated the requirement that all rate increases must be shown to be just and reasonable. MCL 460.6a(1); see, also, MCL 460.6, 460.54, and 460.551 et seq. The same statutory section that allows for use of projected costs also requires that the “utility shall place in evidence facts relied upon to support the utility’s petition or application to increase its rates.” MCL 460.6a(1). The ALJ observed that her recommendations do not preclude the company from seeking environmental capital expenditures in its next rate case that were also sought in this rate case. That is not a holding, or a suggestion. Whether Consumers chooses to do so is entirely in the utility’s discretion. Whenever it chooses to do so, however, if the utility realistically expects inclusion of the total projected costs, it must supply the Commission with enough evidence to support a finding that the costs are just and reasonable – in the absence of thorough, detailed, and meaningful evidence, the Commission’s hands are tied.102

The Commission also quoted this language in its rate case order in Case No. U-18014,

and added:

Moreover, in the case where the company seeks approval for a projected cost, the company must not only provide sufficient evidence to demonstrate to the Commission that both the specific project and its cost are reasonable and prudent, but it must also show by a preponderance of the evidence that the cost will in fact be incurred before the end of the test period.103

101 November 4 order, Case No. U-16191, page 8 (emphasis added). 102 See June 7, 2012 order, Case No. U-16794, page 13. 103 See January 31, 2017 order, Case No. U-18014, page 9 (emphasis added).

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Thus, while the Commission has adopted projected test years in each of the rate

case orders issued since the enactment of 2008 PA 286, the company’s contention that

this statute has resulted in a paradigm shift from the use of historical data “adjusted for

known and measurable changes” to create a projected test year expense to the use of

“forward-looking projected costs”104 is not supported by these orders. Indeed, DTE

Electric rate requests have been presented to the Commission expressly in reliance on

the “known and measurable change” approach to a projected test year.105 A cursory

review of the Commission’s orders in Case Nos. U-17335 and U-17990 is sufficient to

establish that Commission rejected several of the company’s expense projections in

favor of recommendations grounded in historical experience. Even in its own evidentiary

presentation in this case, Consumers Energy has relied on this approach. Mr. Denato

testified that the company’s capital structure should be based on the known and

expected changes, and then opined in his rebuttal testimony that “[f]uture cost

reductions should not be incorporated into ratemaking before they can be supported,

known or measurable.”106 And in discussing its projected demand failures expense,

Consumers Energy argues: “Due to the nature of this program, the Company

reasonably based its projections on historical experience. . . [and] included incremental

expenditures that were known to occur as part of this program during the test year.”107

104 See Consumers Energy brief, page 9. 105 See, e.g., the Commission’s January 31, 2017 order in Case No. U-18014, page 2 (DTE Electric explained that the starting point for determining its revenue deficiency was the data from the year ended December 31, 2014. According to the company, this historical data was then normalized and adjusted for known and measurable changes to arrive at the company’s August 1, 2016, to July 31, 2017, projected test year.) Also see December 11, 2015 order in Case No. U-17767, page 2. 106 See 9 Tr 1364; also see 9 Tr 1369, 1373. 107 See Consumers Energy brief, page 19.

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In a second but related dispute, in its reply brief, Consumers Energy strongly

objected to Staff’s reference to “used and useful” plant, arguing at length that the

projected capital expenditures included in the projected rate base need not be “used

and useful” in the test year, and that such a requirement would interfere with the

company’s right to rely on projected rate base amounts. After reviewing several cases

explaining the broad authority granted to the Commission to determine what is properly

included in a utility’s rate base, the company argues:

The contention that expenditures are required to be “used and useful” is in direct opposition to how the Commission reviews costs – as well as Consumers Energy’s statutory rights. It should be undisputed that the Commission regularly examines costs in advance of when they are incurred. The Company’s rate cases, and the expenses requested therein, are developed around the use of a projected test year, which often is by definition a future period in time. See MCL 460.6a(1). The very nature of the use of a future test year is contrary to the assertion that investments must be “used and useful.” And while the Company fully plans on expending the costs requested, as a general matter, there is no guarantee that the requested costs will be incurred or that the Company will spend the exact amount projected. This is because the Company’s request for these future costs is based on projected costs and revenues. The use of a future projected test year based on projected costs is provided for by statute. Regarding establishing reasonable rates, MCL 460.6a(1) expressly provides that “[a] utility may use projected costs and revenues for a future consecutive 12-month period in developing its requested rates and charges.” (Emphasis added.) The rationale offered by Staff that Consumers Energy should not be permitted to include investment in rate base until they are “used and useful” amounts to contending that expenditures may only be included in rates on a historical basis, i.e., after the costs have actually been incurred and are known for certain. This theory is contrary to the language and legislative intent of MCL 460.6a(1). In bringing forth this argument, Consumers Energy recognizes that the Commission is not bound by the Company’s projections. But in the same vein, the Company is afforded the right to use future projections as opposed to being required to base its rate recovery on historic events and the application of the “used and useful” test.108

108 See Consumers Energy reply brief, pages 9-10.

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While Consumers Energy is correct that the Commission is not limited by law to

allowing recovery only of used and useful expenditures, it is clear the Commission has

not abandoned the used-and-useful principle. Indeed, the Commission has only rarely

deviated from general adherence to principle that investments must be used and useful

before they may be recovered. In rate case after rate case, the Commission has

explained rate base as “the capital invested in used and useful plant . . .”109 Moreover,

the Commission has articulated an expectation that projected expenditures used to

project test-year rate base are for investments that will be used and useful in the test

year. Thus, the Commission still reflects construction work in progress (CWIP) with an

offsetting allowance for funds used during construction (AFUDC) for non-environmental

projects, as it has discussed in recent rate cases.110 In Case No. U-17767, the

Commission explained its decision to disallow recovery of additional licensing costs for

a potential Fermi 3 “until the plant could be considered used and useful.”111 As an

additional example of the Commission’s general reliance on the principle that rate base

investments should be used and useful, in Case No. U-18014, the Commission declined

to include projected expenditures associated with an IT application for landlords that

would likely not be completed by the end of the test year. The Commission explained:

“[N]ot only must the company demonstrate the reasonableness and prudence of the

proposed project and its proposed cost, it must also demonstrate that it is more likely

109 See, e.g., February 28, 2017 order in Case No. U-17990, September 8, 2016 order in Case No. U-17895, June 7, 2012 order in Case No. U-16794, November 4, 2010 order in Case No. U-16191, July 1, 2010 order in Case No. U-15981. 110 For example, the Commission reaffirmed this in two recent rate cases for DTE Electric. See December 11, 2015 order in Case No. U-17767, page 36; January 31, 2017 order in Case No. U-18014, pages 46-47. 111 See December 11, 2015 order in Case No. U-17767, page 39.

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than not that the item is appropriately included in rate base during the test year.”112 In

addition, the Commission has notably recognized an exception for environmental

pollution-control capital expenditures, so that Construction Work in Progress (CWIP) for

these investments may be included in rate base with no offsetting Allowance for Funds

Used During Construction (AFUDC).

While individual capital expense projections can be evaluated on rate case

records, the Commission should expect that Consumers Energy will expressly identify in

its filing any projected investment it is including in its test year projected rate base that

will not be used and useful during the test year. It should also be noted that the rate

case projections of future rate base are not the determinant of actual rate base. If a

utility does not make a capital investment it projected, it may not include the projection

in its rate base as if the expenditure had been made. Similarly, if the Commission

subsequently determines an investment was unreasonable or imprudent, or is not used

and useful or subject to a specific exemption from that standard, that investment will not

be considered part of rate base.

V.

RATE BASE

Rate base consists of the capital invested in used and useful plant, less

accumulated depreciation, plus the utility’s working capital requirements. In its

application, Consumers Energy projected a total jurisdictional electric rate base of

$10,289,206,000, adjusted to $10,258,460,000 in its initial brief. Staff calculated a rate

base of $10,206,705,000, adjusted to $10,131,927,000 in its brief. Disputes involving

112 See January 31, 2017 order in Case No. U-18014, page 29.

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the company’s capital expense projections are discussed in section A below. Section B

discusses disputes regarding working capital.

In the discussion that follows, there are many examples where Consumers

Energy has spent substantially less than it projected it would spend in prior rate cases.

Overall, it appears that for the projected test year used in Case No. U-17990, the

company spent approximately 2% below the level of capital expenditures used in setting

rates in that case. The company’s discovery response in Exhibit S-18 states: “The

jurisdictional net plant included in rate base and approved by the Commission in

U-17990 was $9,336,495,000. The 13-month average net plant achieved as of

August 31, 2017 was 98% of that approved or $9,159,937,000.” The dollar magnitude

of this difference is approximately $177 million, or more than three times the difference

in projected net plant in dispute between Consumers Energy and Staff.

The arguments presented in this case show that notwithstanding individual

company witness testimony that certain expenditures are “necessary” or “required,”

Consumers Energy’s overarching view is that the capital expense projections provide an

allowance for capital spending that the company is free to reprioritize to address

“emergent” issues or for other reasons. Indeed, the company’s view seems to be that it

will not make capital expenditures in excess of the total projected amounts included in

current rates. Thus, if capital expenditures are required to address atypical storm

damage, capital expenditures in other areas are reduced. This view is reflected in the

testimony of the company’s Treasurer, Mr. Maddipati, who testified that it is a common

practice in managing a dynamic business to balance over-spending in some programs

and under-spending in others based on emergent priorities as circumstances change

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throughout the year.113 Staff asked a series of questions about this in discovery, and

the responses are as follows:

163. Does the Company believe these unforeseen and emergent costs are considered when setting the Company’s ROE? Response: No. If such unforeseen and emergent costs are expected to borne by shareholders, I would expect the volatility of the Company’s earnings to increase and the authorized ROE would be set at a meaningfully higher level, commensurate with investments of similar risks.114 164. Does the Company believe it is reasonable that these unforeseen/emergent costs be borne by the shareholders until they have been reviewed for prudency? Response: No. If such unforeseen and emergent costs are expected to borne by shareholders, I would expect the volatility of the Company’s earnings to increase and the authorized ROE would be set at a meaningfully higher level, commensurate with investments of similar risks.115 177e. Does the Company agree that inclement weather is an inherent risk of utility operation that is considered when approving ROE? Response: No. Inclement weather, among a number of other variables, is a risk in achieving the Company’s authorized ROE. However, the Company’s authorized ROE does not make a specific adjustment for unusual weather.116

And it is reflected in the arguments presented in the company’s briefs:

While rate case projections are necessary for the development of rates, these projections cannot control the overall actions of the utility. Consumers Energy needs to be able to spend money to run its business, to provide service, and to invest in its plants. In fulfilling its responsibility, the Company must have the ability to make management decisions. Union Carbide v Pub Serv Comm, 431 Mich 135, 151; 428 NW2d 322 (1988). In turn, the Commission reviews the Company’s expenditures to determine a level of costs necessary for the utility to provide service and have an opportunity to earn a reasonable return on its investment. Id. at 149.

113 See 10 Tr 1824. 114 See Exhibit S-22. 115 See Exhibit S-23. 116 See Exhibit S-24.

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Under the Court’s decision in Union Carbide, Consumers Energy’s management has the discretion to decide whether or not to expend monies on a particular investment. Likewise, the Commission’s role is responsive in nature – if the utility decides to invest in a particular area, then the Commission must determine if cost recovery is reasonable. While the Commission may support or encourage certain choices, the decision to invest in a particular area is uniquely that of the utility. As recognized by Union Carbide, in the course of providing electric service to its customers, Consumers Energy needs to make decisions on a daily basis that are not, and should not be, subject to advance regulatory approval. The Company manages the business as a whole, which requires balancing spending more than projected in some programs and spending less than projected in others based on emergent priorities as circumstances change throughout the year. 9 TR 1376. Some of these changes in spending are outside of the Company’s control. A clear example of this is restoration after a storm. When emergent and unforeseen circumstances arise, Consumers Energy should respond in the interest of public and employee safety and to ensure customer reliability. This is in line with the Company’s overall goal of providing safe, excellent operations while providing exceptional value and service to customers. 9 TR 1376. In managing its business, the Company balances safety, reliability, and customer service with the funds available through sales and customer rates that are established by the MPSC. Typically, when the Company encounters expenses which are higher or lower than expected for the point in time during the year for some programs, adjustments are considered and sometimes made in other expense programs. 6 TR 447. By reviewing the Company’s electric distribution expenditures in a vacuum, without any acknowledgement of the Company’s spending in total, Staff fails to recognize Consumers Energy’s reasonable actions to manage its business.117

In making these general claims, Consumers Energy thus acknowledges that it does not

necessarily consider the projected investments in system maintenance and upgrades at

issue in this case “necessary” and does not recognize its requests for funding for these

projects as commitments. This is at odds with the Commission’s stated expectation in

Case No. U-16191, as quoted in section IV above, that the company “file in subsequent


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rate cases stronger evidence that will demonstrate its commitment to major capital

projects and O&M expenses.” The evidence in this record shows that when the

company does not make investments as projected in rates, it can cause significant

additional future costs. For example, the failure to invest in distribution system

maintenance can increase future restoration and maintenance costs,118 while the failure

to invest in generation plant maintenance can increase future forced outage rates.119

Nothing in the Union Carbide decision relied on by Consumers Energy requires the

Commission to include in rates the projected costs of future capital expenditures that

are not substantially certain to be made. While the specific expense projections in

dispute are discussed individually below, the Commission may consider the company’s

past spending and commitment philosophy in evaluating the individual projections.

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

(CWIP)--less the depreciation reserve, which includes accumulated depreciation,

amortization and depletion. The principal disputes among the parties involve the

projected capital expenditures used to project test-year net plant balances.

Consumers Energy presented testimony on its projected capital expenditures

broken down into categories including electric distribution, energy resources (generation

plant) requirements, customer experience, electric business services, information

technology (IT), and smart energy. Following a discussion of the company’s disputed

118 See, e.g., Laruwe, 11 Tr 2381-2382. 119 See, e.g., Hill, 8 Tr 1086.

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use of contingency amounts in capital expense projections, the projected expenditures

are discussed in that order.

1. Contingency

As in prior rate cases, there is a dispute regarding Consumers Energy’s inclusion

of “contingency” amounts in projected capital expenditures for the test year rate base.

In recent rate cases, the Commission has rejected the use of contingency amounts in

projecting future test-year capital expenditures to include in the projected rate base. In

Case No. U-17990, the Commission held:

The Commission agrees with the Staff, the Attorney General, MEC/NRDC/SC, and the RCG that Consumers’ projected contingency costs should be disallowed. Although Consumers argues that contingency costs are no different than other projected costs, the Commission disagrees. As the Commission has previously determined, “[b]ecause Michigan utilities are permitted to rely on fully projected test year costs and revenues, which already introduces a measure of uncertainty in the rate setting process, the Commission finds that it is far too speculative to add contingency amounts on top of that.” January 31 order [in Case No. U-18014], p. 12. In addition, what distinguishes projected contingency costs from other projected costs is not only that these costs are speculative, but also, that the cost depends upon the occurrence of some future event outside of the utility’s control. The question of whether projected contingency costs should be included in rate base thus requires a determination about who, the utility’s investors or its ratepayers, should bear the risk that the contingent event may never occur. In four previous orders, the Commission has consistently answered that question by denying recovery of projected contingency costs.120

The Commission explicitly rejected Consumers Energy’s argument that an explanation

of the method used to estimate contingency and identification of the amount of

contingency is sufficient to include contingency in projected test year rate base:

120 See February 28, 2017 order, pages 11-12, also citing the Commission’s November 19, 2015 order in Case No. U-17735, its December 11, 2015 order in Case No. U-17767, its December 9, 2016 order in Case No. U-17999, and its January 31, 2017 order in Case No. U-18014.

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Although the ALJ is correct that Consumers provided an explanation as to how it derived contingency costs, those findings are not dispositive. The ALJ appeared to rely on language in the November 19 order [in Case No. U-17735] determining that the company in that case had failed to convincingly explain how the contingency amounts were arrived at, or to specify which projects included contingency amounts. However, the Commission agrees with the Staff, the Attorney General, and MEC/NRDC/SC that the Commission excluded contingency costs because including such costs is not sound ratemaking practice.

As the Commission has discussed previously, the inclusion of contingency costs allows the utility to receive a return of and on those costs to the detriment of ratepayers who may never benefit at all. In addition, if ratepayers were required to bear this risk, there would be no incentive for the utility to minimize projected contingency costs, but every incentive to inflate them. For these reasons, as well as those the Commission articulated in its previous orders, the Commission reaffirms its determination and disallows projected contingency costs totaling $32.943 million.121

In its filing in this case, Consumers Energy included $23.5 million in contingency

amounts in its capital expense projections, and presented testimony and rebuttal

testimony defending the practice. Mr. Thomas testified expressly to address the

company’s use of contingency costs, contending that contingency is “a legitimate and

forecastable cost of a projected, recognized and accepted practice, and real expense

which is incurred.”122 He cited the Association for the Advancement of Cost

Engineering International (AACE):

The [AACE] defines contingency as ‘An amount added to an estimate to allow for items, conditions, or events for which the state, occurrence, or effect is uncertain and that experience shows will likely result, in aggregate, in additional cost.’ (Emphasis added.) Contingency is generally included in most estimates, and is expected to be expended.”123

121 See February 28, 2017 order, page 12. 122 See 7 Tr 898. 123 See 7 Tr 898 (emphasis in original).

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He described two methods Consumers Energy uses to estimate contingency as part of

the energy resources capital expense projections sponsored by Ms. Hill: a statistical

method of estimating uncertainty used for larger projects, and Project Management

Institute (PMI) and AACE guidelines for smaller projects.124 In his opinion, Consumers

Energy “takes an active and thoughtful role in establishing contingency in these projects

which encourages active project management, prompting ongoing focus on identifying

and acting on cost avoidance opportunities during the entirety of the project life

cycle.”125

Mr. Bordine testified in support of the company’s inclusion of contingency costs in

capital expense projections in both his direct and rebuttal testimony.126 He also cited

the AACE:

It is a common practice to include project contingency costs and is recognized as an accepted Project Management practice. According to the Association for the Advancement of Cost Engineering International, contingency is “An amount added to an estimate to allow for items, conditions, or events for which the state, occurrence, or effect is uncertain and that experience shows will likely result in aggregate, in additional costs.” Contingency is included in some major project estimates, and is expected to be expended. It is a real item in a project estimate like any other cost, and should be included in estimates of major projects. For these reasons, contingency costs are appropriate and should be included in the capital expenditures and rate base in this filing.127

Mr. Bordine’s rebuttal testimony is substantially the same.128 Ms. Hill cited

Mr. Thomas’s testimony in her rebuttal, also stating:

Consumers Energy’s risk-based methodology for projecting contingency costs reflects established and accepted industry practices that are supported by the AACE. Furthermore, the AACE recognizes that

124 See 7 Tr 898-899. 125 See 7 Tr 900. 126 See 6 Tr 397-398, 445. 127 See 6 Tr 397-398. 128 See 6 Tr 445.

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contingency is a reasonable and prudent component of the total costs and is expected to be expended.129

And similarly, Mr. Varvatos testified in support of including contingency expense in the

IT projections in his rebuttal testimony:

It is common practice when forecasting a project’s costs to estimate the project’s contingency costs. This is recognized as an accepted Project Management practice. According to the Association for the Advancement of Cost Engineering International, contingency is “[a]n amount added to an estimate to allow for items, conditions, or events for which the state, occurrence, or effect is uncertain and that experience shows will likely result, in aggregate, in additional costs.” Contingency costs are expected to be expended. It is a real item in a project estimate like any other cost. Consistent with the above definition of “contingency,” the Company does not add contingency to a project because it has under-estimated the base cost of the project. Instead, contingency is part of the base cost of the project. Without contingency, the estimate of the project cost is incomplete. Removing contingency results in the base cost of the project being under-estimated. For these reasons, contingency costs are appropriate and should be included in the capital expenditures and rate base in this filing.130

He further testified:

Program and Project Managers, who are the individuals responsible for and most knowledgeable about their program’s respective costs, establish the figures for contingency to quantify amounts that are not assignable to a particular line item in the project budget precisely when an estimate is developed. Because technology being implemented is often new, with complex integration, cost estimations for system implementations are not exact. Contingency addresses the commonly followed process of progressive elaboration, wherein more is made known through the course of the project when complete foresight isn’t reasonable to expect. These figures are always discussed, scrutinized, and approved by IT management before being finalized, but are always expected to be fully expended.131 Witnesses for Staff and the Attorney General recommended excluding

contingency allowances from Consumers Energy’s capital expense projections for the

129 See 8 Tr 1090. 130 See 9 Tr 1660. 131 See 9 Tr 1661.

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purpose of determining the projected test year rate base. Citing the Commission’s prior

decisions on this topic, Ms. Fromm explained the basis for Staff’s exclusion of

contingency costs from capital expense projections:

Staff is recommending contingency expenditures be disallowed from recovery through rates because of the inherent uncertainty associated with the expense. Contingency expenditures are just that, contingent upon the unexpected. While Staff recognizes these expenditures may be important to the Company for the use of budgeting internally, it is inappropriate to include them in rates at this time. If the Company does incur these costs they may earn a return on them once they have been reviewed for reasonableness and prudence. However, at this time, given the uncertainty, and the fact that they have yet to even be incurred, Staff does not find these expenditures to be reasonable and prudent.132

Mr. Evans also cited the Commission’s prior orders133 and further explained Staff’s

removal of contingency costs:

Staff believes it is inappropriate for the Company to earn depreciation and return on projected contingency expenditures for two main reasons: 1) There is a much greater degree of uncertainty regarding how much contingency will ultimately be expended than the amount of uncertainty found with projected expenditures in other cost categories. Contingency expenditures may not be incurred at all, and if some expenditures are ultimately incurred, the final amount could be far less than what the Company projected. In either of these situations, ratepayers end up overpaying for investments. Allowing contingency projections in rates causes ratepayers to pay for a return of and on the contingency portion of the investment, a portion that might not be expended during the test year, or might be only partially expended. 2) The specific equipment or items that may cause the Company to expend contingency funds during the test year are unknown at the time of this filing. Without knowing what these contingency expenditures would be incurred for or the circumstances that would prompt their incurrence, it is impossible for Staff to determine whether such expenditures are reasonable and prudent at this time.134

132 See 11 Tr 2359. 133 See 11 Tr 2289 134 See 11 Tr 2288.

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Mr. Coppola also cited the Commission’s prior orders, stating that nothing had changed

since those orders were issued, and testified:

The $23,480,000 should be excluded from the calculation of rate base for the projected test year. Contingency expenditures are typically amounts above the base forecast of capital expenditures for non-routine projects. The contingency amounts are usually established early in the life cycle of the project in case cost increases are experienced due to unforeseen circumstances. The fact that these added costs are contingent means that they may not be spent in whole or in part. Despite the Company’s claim that the amounts may actually be spent on the project or may be spent on other new work, does not mean that these costs belong in rate base. It is neither fair nor reasonable for the Company to recover the depreciation expense and the return on the investment on potential costs that may not be actually incurred but have been added to rate base.135

In their briefs, Staff and the Attorney General continue to urge the Commission to

exclude these costs.136 Citing a series of Commission orders including the

Commission’s order in Case No. U-17990 as quoted above, Staff takes issue with the

company’s failure to acknowledge the Commission’s recent orders on this issue,

arguing that the company has offered nothing new and the Commission may simply

refuse to reconsider this issue.137 In their reply briefs, MEC/NRDC/SC and the RCG

also argue that contingency costs should be excluded.

In its brief, Consumers Energy argues that the Commission should adopt its

capital expense projections including the contingency amounts, citing the testimony of

witnesses Mr. Bordine, Mr. Thomas, Mr. Varvatos and Ms. Hill. Consumers Energy

does not address the Commission’s order in Case No. U-17990, or acknowledge its

conclusion that including contingency costs in projected rate base is not sound

135 See 12 Tr 2556. 136 See Staff brief, pages 7-13; see Attorney General brief, pages 35-36. 137 See Staff brief, page 11.

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ratemaking practice. Instead, the company alludes to the Commission’s prior decisions

in its reply brief as follows, arguing that each case must be judged on its own record:

To further support its position, Staff points to prior rate case orders and alleges that the Commission indicated that it is not sound ratemaking to include costs in rate base that may or may not occur. Staff’s Initial Brief, page 10. However, the Commission orders cited by Staff were based on the specific records in the referenced proceedings. The Commission’s final order in this case should be based on the record in this proceeding which contained a bolstered evidentiary presentation on contingency costs by the Company. This detailed evidentiary presentation satisfies the Commission’s stated desire for a more specific evidentiary presentation related to this request.138

This PFD concludes that contingency expense projections should be excluded

from the capital expense projections used in setting rates. The Commission has

addressed this issue repeatedly. In Case No. U-17990, the Commission explicitly

determined that contingency expense projections are not appropriate for inclusion in

rates. It is inexplicable why Consumers Energy does not expressly acknowledge this

holding, instead claiming as quoted above that “Staff . . . alleges that the Commission

indicated that it is not sound ratemaking” to include contingency costs.

Consumers Energy argues that it is responding to the Commission’s invitation in

Case No. U-17735 to provide additional information regarding contingency expense

projections,139 without acknowledging that it made this same argument in Case No.

U-17990. The Commission summarized Consumers Energy’s arguments in Case No.

U-17990 in part as follows:

In rebuttal, Consumers argued that including contingency in project cost projections is an industry-accepted, well-established, project management methodology. Consumers claimed that because contingency costs are a proper component of projected costs, the Staff’s and the Attorney General’s rationales for excluding these costs potentially violate

138 See Consumers Energy reply brief, pages 4-5. 139 See Consumers Energy reply brief, page 5.

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MCL 460.6a(1): “A utility may use projected costs and revenues for a future consecutive 12-month period in developing its requested rates and charges.”140

And in part as follows:

Consumers explains that “[w]hile the Company fully plans on expending the costs requested, as a general matter, there is no guarantee that the requested costs of any category of projected costs will be incurred exactly as projected. The fact of the matter is that the contingency costs at issue are projected and expected to be expended by the Company.” Consumers’ replies to exceptions, p. 2. (Emphasis in original.) Therefore, the company argues, contingency costs are a reasonable component of its projected costs, and should be approved. Consumers further asserts that, pursuant to the Commission’s directive in the November 19 order [in Case No. U-17735], it provided support for its projected contingency costs through unrefuted, expert analysis on the calculation of risk-based contingency expense in project planning. In addition, the company states, its evidence shows that including contingency in project cost projections is an industry-accepted, project management methodology.141

While Consumers Energy claims in its reply brief that it provided a “bolstered

evidentiary presentation” in this case, all it offered was redundant argument. Its reply

brief on this topic is virtually identical to the replies to exceptions it filed approximately a

year ago in Case No. U-17990, including the use of the same quotations from

Mr. Thomas’s testimony, with updated citations, and the same claim that it provided a

“bolstered evidentiary presentation.”142 Indeed, the information the company has

presented on this record confirms exactly what the Commission has concluded, that it is

reasonable for Consumers Energy to use contingencies in financial planning and project

management, but not appropriate to include in projected rates. Mr. Thomas, for

140 See February 28, 2017 order, page 8. 141 See February 28, 2017 order at page 11. 142 See Consumers Energy reply brief, pages 2-7; see Consumers Energy’s January 18, 2017 replies to exceptions in Case No. U-17990 (Docket No. 397), pages 1-10. The principal difference between the two arguments is that in this case, the company acknowledged that it does not use the “probability model” for all its generation capital expense projections, but uses a percentage for smaller projects.

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example, explains that contingencies for large projects use a probability model that

adds contingency to reduce risk to the company, explicitly calling contingency “an

estimate of uncertainty.”143 For smaller projects, he testified that the estimates range

from 6% to 40% of the project total. It is also worth noting that Mr. Shingler testified that

contingency costs are not included in the company’s electric business services capital

expense projections:

[T]he Transportation Equipment and Computer & Other Equipment categories pertains to the purchase of physical assets; vehicles/equipment. Therefore, there are no contingency costs included in the Company’s projections. With respect to Asset Preservation, the Company does not include contingency in its projects. Accurate projected costs are established based on standard designs, construction estimates, and historical spend.144 Contingency amounts included in the company’s projections total $23.5 million as

shown in Exhibits S-10.0, S-13.4 and AG-13. To avoid overlap with any recommended

adjustments, contingency amounts to be excluded are also addressed in the sections

below as appropriate.

2. Electric Distribution

As shown in Exhibit A-19, Consumers Energy is projecting capital expenditures

for its electric distribution system totaling $762.9 million for calendar year 2017 and the

first 9 months of 2018, i.e. through the projected test year. Mr. Bordine presented the

company’s projected capital expenditures for the electric distribution system based on

the following seven program categories shown in Exhibit A-19: 1) new business;

2) reliability; 3) grid modernization; 4) capacity; 5) demand failures; 6) asset relocations;

and 7) electric operations-other. Mr. Bordine also provided 2015 and 2016 capital

143 See 7 Tr 899. 144 See 7 Tr 1000.

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expenditures for certain assets that have now been reclassified from HVD distribution to

transmission. Mr. Bordine testified that the projected capital expenditures in these

areas are based on future projections of the investment levels “necessary . . . to

account for new business, address customer reliability expectations, modernize and

implement system infrastructure improvements[,] meet expected load, replace assets in

response to emergent demand failures and to relocate distribution infrastructure.”145

Staff took issue with projected expenditures totaling $59 million in four of those

categories: reliability, grid modernization, demand failures, and electric operations-

other, as explained by Staff witness Mr. Laruwe. The Attorney General took issue with

projected expenditures for new business, reliability, demand failures and electric

operations-other, recommending a total reduction of $57.7 million in projected capital

expenditures. These recommendations are discussed in sections a through e below.

By way of background underlying the disputes in this category, in Case No.

U-17990, the Commission reviewed Consumers Energy’s proposed capital spending for

its distribution system and found that Consumers Energy had not consistently spent

Commission-approved amounts from prior cases, and also found that the company had

not fully supported the reasonableness of its proposed expenditures. The Commission

also recognized the importance of expenditures in this category, and referenced its

order in DTE Electric Company’s rate case, Case No. U-18014:

Nevertheless, the Commission finds, as it did in DTE Electric Company’s (DTE Electric) most recent rate case, that Consumers is faced with significant investments in the coming years to address aging infrastructure and the need to incorporate advanced technologies into its distribution system. “[I]n order to properly evaluate these investments, and provide a greater level of regulatory certainty, the Commission finds that the rate case process would benefit from the company providing a more

145 See 6 Tr 396.

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comprehensive, forward-looking capital investment and operations plan.” January 31 order, p. 40. Thus, the Commission directs Consumers to produce and submit a five-year distribution investment and O&M plan that includes: (1) a detailed description, with supporting data, on distribution system conditions, including age of equipment, useful life, ratings, loadings, and other characteristics; (2) system goals and related reliability metrics; (3) local system load forecasts; (4) maintenance and upgrade plans for projects and project categories including drivers, timing, cost estimates, work scope, prioritization and sequencing with other upgrades, analysis of alternatives (including AMI and other emerging technologies), and an explanation of how they will address goals and metrics; and (5) benefit/cost analyses considering both capital and O&M costs and benefits. As the Commission explained in the January 31 order [in Case No. U-18014], p. 41:

A plan of this nature would increase visibility into the system needs and facilitate review by the Staff, other parties, and the Commission outside the contested rate case process. The Commission does not expect to formally “approve” the plan, but sees value in having a more thorough understanding of anticipated needs, priorities, and spending. The Commission therefore directs the Staff to work with the company to address clarifying questions on the plan framework.146

The Commission directed Consumers Energy to file a draft plan by August 1, 2017, to

consult with Staff, and then to provide a final plan not later than January 31, 2018. As

Mr. Torrey acknowledged in his testimony, because Consumers Energy filed the

present case in March 2017, it had not prepared this five-year plan. Note that in its

November 21, 2017 order in Case No. U-17990, the Commission extended the deadline

for the company to submit its final plan to March 1, 2018.

Distribution expense is again this year one of the areas in which the company

has not spent the amounts it projected to spend in prior rate cases for programs with

expected benefits to ratepayers. Mr. Bordine’s Exhibit A-37 compares the 2016

146 See February 28, 2017 order in Case No. U-17990, pages 18-19.

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spending levels projected in Case No. U-17990 with preliminary actual spending for

2016. It shows total net capital underspending of $33 million for electric distribution as a

whole,147 principally driven by $30.4 million underspending on the grid modernization

program, with increased spending in the new business, reliability, and asset relocation

programs. The exhibit also shows a partially offsetting $12.1 million expense in a

completely different category of expenses (electric business services) to reach the net

underspending for all line items shown in Exhibit A-37 of $20.8 million. The company

argues that rather than looking at the categories and programs in which the company

failed to meet its projections, the Commission should take a broader view. Thus,

Consumers Energy argues:

The Electric Distribution section of Staff’s Initial Brief portrays an overly narrow and unreasonable view of the Company’s expenses and expenditures. See, e.g., Staff’s Initial Brief, pages 25-26. Staff inappropriately reviews the Company’s projected expenditures in a vacuum without any acknowledgement of critical issues in other areas of the business which impact spending in a given period of time. This is despite the fact that the Company is investing in its Electric Distribution system. As shown in Exhibit A-34 (AJB-21), in 2016, the Company projected Electric Distribution capital expenditures totaling $415,245,000, and the Company exceeded that amount as it actually spent $424,589,000 in 2016 in Electric Distribution capital expenditures. And, as further evidence of the Company’s commitment to its Electric Distribution system, as seen in Exhibit A-103 (AJB-33), through July of 2017, the Company had already exceeded its 2017 Electric Distribution projected capital expenditures by approximately $22,000,000.148

It should be noted at the outset, however, that the company’s assertion that Exhibit A-34

shows that Consumers Energy exceeded its distribution capital expense projections for

2016 is not correct. Exhibit A-37 shows that it did not meet, let alone exceed, its

distribution capital expense projection for 2016, instead showing a shortfall of 147 This figure is not totaled on the exhibit, but is the sum of the variances in column f, not including line 9 relating to Electric Business Services. 148 See Consumers Energy brief, page 10.

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$33 million. What Exhibit A-34 does show is that at the time it filed its case, Consumers

Energy had a projection of 2016 capital spending based on actual expenditures for the

first 10 months, which is labeled as “2016 projected” in Exhibit A-34, and it also had

“preliminary actual” expenditures for the full calendar year. As also discussed below,

Mr. Bordine explained this at 6 Tr 397, and it is unclear on this record whether the “2016

projected” or “preliminary actual” are more accurate. Nonetheless, Consumers Energy

uses the generally higher “preliminary actual” amounts in its Exhibit A-37 comparison.

Exhibit A-103 compares distribution system spending by program category for

the first seven months of 2017 to the monthly projections included in this case, Exhibit

A-35.149 While Consumers Energy is correct that it shows an additional $22 million for

the demand failure spending, it also shows underspending in several of the program

categories. As noted above, Consumers Energy is of the view that capital expense

funding provides only an allowance for the company, within which it is free to operate,

and that “emergent needs” such as storm damage, justify the abandonment or deferral

of distribution system or generation maintenance activities for which funding was

provided in the most recent rate case. Regarding the demand failures spending in

Exhibit A-103, Ms. Hill explained that 2017 underspending on generation fleet

environmental activities was in part attributable to the reassignment of $20 million to the

demand failure program.

In his testimony, Mr. Torrey requested that if the Commission does not find

sufficient support for the company’s distribution capital expenditures in this case, that

149 The company’s spending during the pendency of this case as shown in Exhibit A-103, was presented in the rebuttal phase, and was a substantial correction to a discovery response Consumers Energy had previously provided to the Attorney General, Exhibit AG-15.

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the Commission include the expenditures subject to refund if not spent.150 Staff and the

Attorney General addressed this proposal in testimony, and it is discussed in more

detail in section g below, following a discussion of the new business, reliability, grid

modernization, demand failures, and electric operations-other capital expense

categories in sections a through e, and a review of contingency in section f.

a. New Business

Mr. Bordine testified the new business category includes the capital costs of

adding new commercial, industrial, and residential customers, including the costs of

poles, conductors, transformers, services, meters, and new customer-requested

streetlighting.151 Mr. Bordine also presented a chart to show actual and projected

increases in new business connections from 2011 through 2018, and presented other

related statistics.152 As shown on line 1 of Exhibit A-19, Consumers Energy projects

that it will spend $82.4 million in new business capital expenditures in 2017, and an

additional $57 million in the first 9 months of 2018. Exhibit A-20 has a breakdown of the

projections into 6 categories. Exhibit A-21 provides further detail for major projects.

Mr. Coppola recommended a reduction of $12.6 million in the expense

projections for this category. First, he objected to the use of loading rates for 2017 and

2018 that are considerably higher than for 2016. Overhead and other indirect cost

loadings are included in the cost of construction estimates as shown in lines 5, 33, 42 of

Exhibit A-21, which are labeled “loading rate” or “loading %.” On line 5, the percentage

shown for 2016 is 165%, and is 180% for 2017 and 2018. On line 33, the loading rate

shown for 2016 is 131%, moving to 148% in 2017 and 156% in 2018. On line 42, the 150 See 7 Tr 640. 151 See 6 Tr 398. 152 See 6 Tr 399, 399-401.

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loading rate shown for 2016 is 137%, moving to 153% for 2017 and 162% for 2018.

Citing discovery responses, Mr. Coppola concluded that the company’s explanation for

the difference was not logical:

In two discovery requests, the Company was asked to explain the reasons for the higher loading rates. In the responses to the discovery, the Company stated that the forecasted loading rates reflect a three-year historical average and take into account the increase in capital investments the Company is projecting in this filing. Unfortunately, the information provided does not adequately explain why the rates increased from 2016 or what underlying factors are included in the loading rate to cause the increase. In fact, the explanation provided about the loading rates for 2017 and 2018 reflecting higher capital expenditures is illogical. Assuming no significant increase in overheads and other indirect costs, the loading rate should decline as capital expenditures increase.153

Mr. Coppola recommended that the expense projections be recalculated using the 2016

loading rates, resulting in a $10.6 million reduction in forecast expenses as shown in

Exhibit AG-14.

Second, Mr. Coppola recommended excluding the $2.7 million projected

expenditure for 2018 emergent projects on line 18 of Exhibit A-21, for high voltage

strategic customers. He testified that there are no projects supporting this estimate, and

characterized it as a “simply a placeholder” akin to contingency projections that should

be disallowed.154

Regarding Mr. Coppola’s first recommendation, in rebuttal Mr. Bordine asserted

that he used a three-year-average loading rate, and that it is reasonable to do so. He

disputed that the loading percentage should decrease as capital expenditure levels

increase.155 Regarding the emergent projects, he testified that Consumers Energy

cannot now know every new customer that will request service, and that “given the 153 See 12 Tr 2557. 154 See 12 Tr 2558. 155 See 6 Tr 449.

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volume of projects historically in this program, it is a reasonable expectation that the

small amount set aside for emergent projects will occur.”156

Although the Attorney General’s brief recommends that the Commission accept

Mr. Coppola’s recommendations, it does not address Mr. Bordine’s rebuttal testimony.

In the absence of briefing on this issue from the Attorney General, this PFD accepts Mr.

Bordine’s testimony that the loading rates are based on three-year averages and are

reasonable to use in the capital expense projections. Nevertheless, the mathematics

underlying the three-year averages in Exhibit A-21 show a great deal of variability. For

example, assuming the loading rates shown in line 5 of Exhibit A-21 each reflect three-

year averages from the prior three years, then simple calculations show that the 2015,

2014, and 2013 loading rates were 195%, 180%, and 120% respectively. Given this

variability, the Commission should expect a little more attention to the estimation of this

cost element in future cases. Note that the costs included in Exhibit A-21 calculated

using the loading rates in lines 5, 33, and 42 total approximately $55 million for 2017

and 2018.

Regarding the emergent projects for 2018, while Mr. Coppola is correct that the

“placeholder” expense projections are not appropriate for ratemaking, in the absence of

further argument from the Attorney General, this PFD accepts Mr. Bordine’s testimony

that his projection is consistent with historical spending levels in an expense category

that is difficult to project.

b. Reliability

In describing the types of activities to be funded, Mr. Bordine testified that the

reliability program expenditures are designed to ensure the long-term safe and reliable 156 See 6 Tr 449-450.

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operation of the HVD and LVD systems, by upgrading deteriorated equipment, reducing

system outages during weather challenges, and generally strengthening the electric

distribution system assets.157 Exhibit A-19, line 2, shows Consumers Energy’s

projected capital spending of $107.6 million in 2016, $105.3 million in 2017,

$93.2 million for the first 9 months of 2018, and $126.6 million for the calendar year

2018. On a test year basis, it shows projected capital expenditures of $121.6 million for

the projected test year, and $101 million for the 12-months ending September 30, 2017.

Exhibit A-22 provides detail for the company’s projected reliability program capital

expenditures, by major equipment category including LVD lines, HVD lines, LVD

substations, HVD substations, HVD system protection, LVD repetitive outages, and the

Metro underground system reliability. Major projects are listed in Exhibit A-23, with

projected expenditures for 2017, and some items for 2018. As noted above, the

projected timing of expenditures is in Exhibit A-35, and Exhibit A-37, page 2, shows

2015 expenditures as well as a comparison of 2016 preliminary actual expenditures to

the 2016 projections from Case No. U-17990.

Staff recommends a $14.6 million reduction in capital expenditures for this

category for the projected test year.158 Mr. Laruwe testified that Consumers Energy’s

projections for 2017 capital spending in this category are significantly above 2015

levels, and its projections for 2018 capital spending are significantly above preliminary

2016 levels. Focusing on five categories listed in Exhibit A-22, lines 1 and 4-7,159 he

testified that the company has not provided project-level detail or support for the

157 See 6 Tr 402-403. 158 See Staff brief, pages 21-24. 159 These are the LVD lines, HVD substations, HVD system protection, LVD repetitive outages, and Metro reliability expense categories.

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approximately $47 million projected capital expenditures shown on these lines for the

first 9 months of 2018, which he likened to contingency. He testified that Consumers

Energy should be required to provide a detailed analysis to support its projections,

especially given that it spent $42 million below the program level provided for in Case

No. U-17735.160 He cited, and Staff cites in its brief, the Commission’s orders in Case

No. U-17990 and U-18014 in support of the contention that more should be required.161

Noting that the Commission has yet to receive or review the 5-year plan called for in

Case No. U-17990, he recommended that the Commission limit projected 2017 and

2018 spending to preliminary 2016 levels, adjusted for inflation.

Mr. Coppola also objected that Exhibit A-23 does not contain projects or

spending for 2018 for several of the subcategories. Concluding that $42.7 million of the

total $93.2 million in projected 2018 expenditures were not supported, he looked at

historical expenditure levels to conclude that the 2017 projected capital expenditures

were in line with 2016 actual expenditures, but that the 2018 projected capital

expenditures were not. Using 2016 actual expenditures in the reliability category, he

recommended limiting projected 2018 capital expenditures to the 2016 level. He

calculated a $12.5 million reduction to the company’s 2018 projection.162

In rebuttal, Mr. Bordine disputed that the company had failed to provide adequate

support for the expense projections, citing his testimony at 6 Tr 402-405.163 He also

presented as Exhibit A-95 a discovery response he provided to the Attorney General

“concerning the methodology utilized to select reliability projects and the timing of the

160 See 11 Tr 2382-2383. 161 See 11 Tr 2383. 162 See 12 Tr 2559-2560. 163 See 6 Tr 436-437.

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project selection for 2018.” He asserted that the company is investing more in the

reliability program to reduce outages, including improving the reliability of the 30 worst-

performing circuits in 2017, and changing its focus from improving SAIFI to improving

SAIDI. He also presented in Exhibit A-96 additional support for 2018 expenditures he

provided to the Attorney General in discovery. Mr. Bordine disputed Mr. Laruwe’s

characterization of the $47 million projected for the first 9 months of 2018 as akin to

contingency, asserting that:

The Company provided evidence that it is prudent to conduct the project selection and analysis close to construction. This should not be construed as being “contingent” funding. . . . This project determination happens closer to the time that the projects are to be constructed so that timely data is utilized to provide the most benefit to customers. Planning these types of investments too far in advance could result in using stale data and reducing overall system benefit. Further, projecting areas identified for pro-active reliability improvements so far in advance could have system improvements done under other capital or O&M programs (i.e. Service Restoration, Demand Failures, Capacity) in the interim. Thus these are not contingent costs.164 In its brief, Consumers Energy argues that the Staff and Attorney General

proposals fail to take into account how the reliability projects are determined, citing

Mr. Bordine’s testimony as quoted above. It also argues that the company is investing

more in this program than historically in order to improve reliability and customer

satisfaction, also citing Mr. Bordine’s testimony at 6 Tr 436.165 In its reply brief, the

company also argues for the first time that Staff’s adjustment does not reflect 2016

“preliminary actual” expenditures of $113.9 million for 2016, shown in Exhibit A-34, but

164 See 6 Tr 436-437. 165 See Consumers Energy brief, pages 13-15, 24.

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instead uses the “2016 projected” expenditures of $107.6 million.166 The company also

cites 2017 expenditure data through July 2017 included in Exhibit A-103, and argues:

Similarly, the for the year 2017, the Company projected a Reliability Program expenditure amount of $105.321, and, as of July 2017, the company already spent $51.131 million – almost half of its projected amount. . . . Thus, Staff’s criticism of past performance is misplaced as the Company has responded to these previous contentions and increased its level of spending for the reliability program.167 In Case No. U-18014, the Commission declined to include certain IT expense

projections of DTE Electric in projected rate base, explaining: “The Commission agrees

with the ALJ that including “placeholder” amounts in the company’s initial filing, and then

attempting to justify those amounts later is unreasonable.”168 Staff cited this order,169

and in its reply brief, Consumers Energy attempts to distinguish this order, arguing that

Staff discounts the prudent manner in which Consumers Energy develops its reliability

projects, to avoid duplication with other capital or O&M programs like service

restoration, demand failure, or capacity programs.170 The company also cites the 2018

projects it identified in Exhibit A-96.

This PFD finds that Mr. Laruwe and Mr. Coppola have correctly concluded that

Consumers Energy’s 2018 projected expenditures reflect a significant increase over

2015 and 2016 levels that is not supported on this record. As shown by a review of

Exhibit A-23, the company’s filing did not identify specific projects for its projections in

lines 1 and 4-7 of Exhibit A-22. Exhibit A-95 is merely a report used for determining

166 See Consumers Energy reply, pages 12-15. 167 See Consumers Energy’s reply brief, page 13. 168 See January 31, 2017 order, Case No. U-18014, page 30. 169 See Laruwe, 11 Tr 2383. 170 See Consumers Energy’s reply brief, page 14.

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2017 projects, which Mr. Bordine characterized as a ranking.171 It expressly states that

an analysis will be done in the third quarter of 2017 to determine 2018 projects. Exhibit

A-96 is a discovery response to the Attorney General’s request for support for the 2018

expense projections. For the HVD system protection category, the response provides a

list of projects to match the projected $1.7 million expense projection.172 For the HVD

substation reliability expenditures, the response lists approximately $1 million in projects

relative to projected expenditures of $3.4 million, but indicates that the planning process

to define the complete workplan for 2018 will not occur until the fall of 2018.173 For the

Metro reliability program expense projections, the response provides a list of projects

under consideration, “currently being reviewed for inclusion in the 2018 plan”.174

Regarding the $33 million in expenditures projected the first 9 months of 2018 for LVD

lines, the response indicates that “[t]hese projects will be determined in the fall of 2017

and thus are not currently available.”175 For the $5.6 million projected capital

expenditure for the first 9 months of 2018 for the LVD repetitive outages reliability

program, the response indicates: “Some of the 2018 projects would be identified in late

2017 but most projects will be identified during 2018.” Thus, even including the projects

in Exhibit A-96, which were not filed with the company’s case, the company’s

projections still contain expenditures of at least $38.6 million for 2018 with no identified

projects.

Consumers Energy’s reliance on Exhibit A-103 for this category of expense is

misplaced. This exhibit shows that expenditures for 2017 through July 2017 are

171 See 6 Tr 479. 172 See Exhibit A-96, part c. 173 See Exhibit A-96, part b. 174 See Exhibit A-96, part e. 175 See Exhibit A-96, part a.

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$6 million below the monthly spending projections in Exhibit A-35 for those seven

months. On an annualized basis, the company’s $51.131 million expenditure for the

first seven months of 2017 equates to an annual expenditure of $87.7 million, or

$17.6 million behind its 2017 projection of $105.3 million. The LVD lines reliability

spending and the LVD repetitive outages spending discussed by Mr. Laruwe are among

the categories lagging behind projected 2017 expenditures. Because this PFD finds

that Consumers Energy has not supported its projected expenditures for 2018, this PFD

recommends that the Commission adopt Staff’s proposed reduction of $14.6 million.176

While Consumers Energy also argues that the “preliminary actual” levels shown

in Exhibit A-34 and A-37 should be used in lieu of Staff’s adjustment, it has not

established that these “preliminary actual” values are more reliable than the projections

based on 10 months of actual 2016 data more thoroughly reviewed by the company in

the preparation of its case. Mr. Bordine explained the difference between the 2016

projected values and the 2016 preliminary actual values as follows:

Exhibit A-34 (AJB-21) shows the Electric Distribution Capital Program expenditures for 2015 through 2018 and includes the 2016 preliminary actual amounts. In preparing this filing, the Company projected the capital expenditures for 2016 based upon the actual amounts through October of 2016 and forecasted amounts for November and December. The Company utilized the data from this time frame due to the lead time necessary to compile the information for, and to conduct, a property model calculation. The 2016 preliminary actual amounts are shown for illustrative purposes only.177

176 Although Staff does not expressly discuss this, it is clear from a review of Staff’s testimony regarding capital expenditures that Staff separately adjusts capital expenditures before the start of the test year, i.e. before October 1, 2017, which Staff refers to as the bridge period, and during the test year, i.e. from October 1, 2017 through September 30, 2018. This facilitates determining the impact on projected test year plant balances, since expenditures before the test year affect the beginning balance but expenditures during the test year affect only the ending balance. It is more difficult to evaluate the Attorney General’s recommendations presented on a calendar-year basis. 177 See 6 Tr 397.

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He testified that Exhibit A-37 “provides the variances in the capital and O&M spending

in the 2016 preliminary actual from the amounts filed in the Company’s most recent

general electric rate case, Case No. U-17990.”178 As this testimony shows, the 2016

projected values and 2016 actual preliminary values were filed by Consumers Energy at

the same time, and it is unclear whether the partially-projected 2016 or preliminary

actual 2016 values are more accurate. Mr. Laruwe in his testimony referenced

“preliminary 2016” spending, and clearly referenced the $14 million difference between

the 2016 value and the 2018 projection.179 Although Consumers Energy challenged the

calculation of Staff’s adjustment in its brief, it did not do so in rebuttal. It appears that

the company is relying on the brief’s use of the phrase “preliminary actual,” although

Mr. Laruwe did not use this phrase in his testimony. Instead, it appears that both Staff

and the Attorney General used the 2016 projected values reported in Exhibit A-22 in

formulating their recommendations, which is reasonable under the circumstances.

c. Grid Modernization

Mr. Bordine described grid modernization as “the sustained advancement in

technology and integration to improve generation, transmission, and delivery of energy

to our customers, with the desired outcomes of improved reliability, lower operations

and maintenance requirements, and accomplishing this at a reasonable cost.”180 He

testified that the grid modernization components including communications, substation

and lien automation, the installation of additional distributed management system (DMS)

functionality and system conditioning will improve the overall service, power quality and

178 See 6 Tr 424. Although Mr. Bordine revised certain figures in this exhibit on the witness stand, he did not revise this testimony. 179 See 11 Tr 2382. 180 See 6 Tr 405.

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reliability to customers, and help meet future goals for reducing energy waste.181 He

presented charts to show the functions and benefits associated with these components.

As shown in Exhibit A-19, Consumers Energy projects spending $28.6 million on grid

modernization capital projects in 2017, and $31.2 million for the first 9 months of 2018,

with a 2018 total of $42.9 million. As alternately presented on page 2 of Exhibit A-19,

projected capital expenditures for the 12-months-ending September 30, 2017 are $28.5

million, and projected capital expenditures for the test year ending September 30, 2018

are $39 million. Exhibits A-24 and A-25 provide detail regarding the company’s

projected expenses in the grid modernization category. Exhibit A-37 shows substantial

underspending in this category in 2016 in comparison to approved amounts included in

rates.

Mr. Laruwe reviewed the history of the company’s spending in this category

relative to the actual approved spending plans from Case Nos. U-17735 and U-17990.

His analysis showed underspending of $16 million for the test year ending May 2016

used in Case No. U-17735 and underspending of $33 million for the 2016 calendar year

compared to the levels approved in Case No. U-17990. He testified: “Although Staff

understands that projecting future expenditures in any program is not an exact science,

the variations occurring in this program are in excess of what Staff considers

reasonable plan deviations.”182

181 See 6 Tr 406. 182 See 11 Tr 2377.

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In Exhibit A-37, revised from the originally-filed exhibit,183 Consumers Energy

explained the $30 million underspending for this category in 2016 relative to the

spending level approved in Case No. U-17990 as follows:

The 2016 amount proposed in U-17990 was based upon a conceptual proposal to install Grid Modernization on 65% of circuits over the program timeline. In filing this plan the Company was seeking support and approval from the Staff and Commission to proceed with this proposal. The Company held back the 2016 funding as it awaited review of the proposal and to further its analysis of the targeted circuits and their need for grid modernization. It became clear that there was not support for the program level proposed.

Mr. Laruwe addressed this explanation, concluding that the explanation does not justify

the reasonableness of the company’s decisions, but raises more concerns:

Staff does not believe it is reasonable for the Company to significantly vary spending plans because of a lack of support by Staff or any intervenor in the case without first acknowledging this change of spending plan in rebuttal testimony. Not only did the Company admittedly do this in U-17990, they proceeded in litigation to argue the reasonableness of a vacated spending plan throughout 2016.184

In support of this testimony, Mr. Laruwe cited arguments from Consumers Energy’s

January 9, 2017 brief in Case No. U-17990 asserting that the planned grid

modernization expenditures “are appropriate, reasonable, and prudent investments” that

should be approved.185 He also expressed Staff’s concern that Consumers Energy’s

explanation for the underspending did not identify how it reallocated the $30 million in

unspent funding for grid modernization. Citing Exhibit S-16, he testified that the

available evidence indicated the grid modernization funding may have been used to

fund the purchase of fleet and facilities in the electric business services program that

were not reviewed in U-17990 and that were not supported in this case, and additionally 183 See 6 Tr 357-358. 184 See 11 Tr 2379. 185 See 11 Tr 2379.

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to contribute to the company’s 2016 return on equity of 11.2%, 110 basis points above

its authorized return.186 Additionally, he testified that excluding major storm events,

SAIDI, SAIFI and CAIDI indices declined in 2016, indicating that the company’s failure

to execute approved spending plans negatively impacted reliability in addition to

increasing O&M expense, with lower service levels to ratepayers.187 Finally, Mr.

Laruwe characterized the support provided by the company as “aspirational” in nature,

lacking well-defined spending plans, a quantification of benefits, or details such as the

number of assets to be installed. Nonetheless, Mr. Laruwe recommended that the

Commission use 2016 spending levels, adjusted for inflation, to project 2017 and 2018

capital spending for grid modernization, resulting in a reduction of $23.6 million in

projected capital expenditures for this category.188

In rebuttal, Mr. Bordine asserted that his direct testimony included a “description

of the various investment programs that will be addressed with the funding level

projected,” including a description of the investments, how the expenditure amounts

were derived, and the associated customer benefits. He cited his testimony at

6 Tr 405-413, and Exhibits A-24 and A-25. He also stated that he had provided a

discovery response containing a program benefit analysis conducted by a third party “to

demonstrate how the company made the decision to move forward with the Grid

Modernization programs.”189

In his rebuttal testimony, Mr. Denato took issue with Mr. Laruwe’s concern that

the company’s 2016 underspending in an important category of expense contributed to

186 See 11 Tr 2380. 187 See 11 Tr 2381-2382. 188 See 11 Tr 2382. 189 See 6 Tr 434.

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earnings above its authorized rate of return. He testified that for the 12 months ending

July 2017, Consumers Energy has spent $13 million more in O&M than authorized in

rates, with $20 million more in storm-related O&M than authorized.190 He testified:

The Company needs to manage the business as a whole, balancing over-spending in some programs and under-spending in others based on emergent priorities as circumstances change throughout the year, some portions of which (storms for example) are out of the Company’s control. The Company’s overall goal is to provide safe, excellent operations while providing exceptional value and service to customers.191

Mr. Maddipati also presented rebuttal testimony on this topic, disputing that the

company would purposefully underspend to benefit shareholders, and citing abnormally

warm weather in 2016 as the basis for the excess earnings:

The authorization Staff is referring to, in Case U-17990 concerning grid modernization, authorized an increase in rate base. This increase in the Company’s rate base did in fact occur, and it is acknowledged by Mr. Laruwe. If the Company consistently raised revenue without growing rate base, such a claim could make sense; however, even Mr. Laruwe acknowledges that the Company ultimately did grow rate base though not specifically related to grid modernization. As noted by witness Denato, it is common practice in managing a dynamic business to balance over-spending in some programs and under-spending in others based on emergent priorities as circumstances change throughout the year.192 In its brief, Consumers Energy disputes that Mr. Bordine did not support the

benefits related to the grid modernization investments, citing his description of the

investment categories and the customer benefits related to each category, and citing his

testimony that the company relied on a third-party analysis in deciding to move forward

on the grid modernization program. In its reply brief, Consumers Energy also disputes


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that past underspending contributed to an increase in its return on equity,193 citing

Mr. Maddipati’s testimony at 10 Tr 1825:

The approved Grid Modernization expenditures are capital in nature. The Company does not dispute that the Commission authorized an increase in rate base in the Company’s previous electric rate case, Case No. U-17990, as indicated in Staff’s Initial Brief at page 29. And, if the Company consistently raised revenue without growing rate base, Staff’s claim could make sense; however, the Company ultimately did grow rate base – though not specifically related to Grid Modernization.194 Staff argues that since the inception of this program, Consumers Energy has

spent less than half of the amounts approved by the Commission, and also that the

company has not explained how funds earmarked for grid modernization were actually

spent. Staff characterizes the information provided by the company as “essentially a

glossary of grid-modernization terms,” citing Exhibit A-25.195 Staff objects that

Consumers Energy has not quantified the benefits from its projected expenditures,

arguing that the company has only described the benefits in vague terms.196 Staff does

not find Mr. Maddipati’s rebuttal testimony sufficient explanation of the underspending,

arguing that capital additions approved in rates should not be considered a “blank

check”:

When the Company significantly deviates from these approved plans during the execution of a projected test year and reallocates approved capital to other programs, the Company must bear the burden of proving that these expenditures are reasonable and prudent and used and useful. The Company’s failure to provide evidence that the reallocated capital was reasonably incurred and is currently used and useful does not provide the necessary information for setting reasonable future rates. It is not enough to simply say that the capital was spent elsewhere.

193 See Consumers Energy reply brief, pages 15-18. 194 See Consumers Energy reply brief, page 17. 195 See Staff brief, page 25. 196 See Staff brief, page 28.

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Staff attempted to validate Company witness Srikanth Maddipati’s claim that the Company had actually spent the authorized capital through a discovery request after the rebuttal filing. Based on the Company’s response, the Company’s actual net plant additions during the U-17990 test year were $176 million less than the Commission approved. (Exhibit S-18.)197 This PFD finds that Staff’s recommendation to limit the projected bridge period

and test year capital spending to 2016 levels adjusted for inflation is a reasonable

recommendation. The company’s projected 2018 spending level is twice the 2016 level

and three times the 2015 level. The company has not presented a benefit-cost analysis

to support its chosen level of projected expenditure. As noted above, the Commission

is preparing for a more thorough review of the company’s electric distribution system

planning, in which the Commission can consider the need for long-term investment in

the distribution system as well as the short-term demands caused by new business and

storms. The company’s chronic underspending in this category is also a substantial

reason to be cautious. The Commission’s concern with the lack of commitment to the

programs for which advance capital funding is requested in rates as articulated in Case

No. U-17990 remains applicable.198 Contrary to Consumers Energy’s assertions,

growing rate base is not the only measure of accountability for the company. Indeed,

rate base growth does not have independent benefit to ratepayers. The reasoning

provided in Exhibit A-37 parallels the reasoning expressly rejected by the Commission

in Case No. U-17990.199 Even with this rate case pending, the company’s rebuttal

197 See Staff brief, page 29. 198 See February 28, 2017 order, page 17 (“Because the evidence suggests Consumers did not spend the amount approved for the program in its last rate case, and could not accurately trace the funds, the Commission has serious doubts about the company’s willingness to spend the projected expenditures on its reliability program during the test year in this rate case.”) 199 See February 28, 2017 order, page 25 (“[T]he Commission rejects Consumers’ argument that its underspending in this particular area was necessitated by the timing of the last rate order. The Commission issued a timely order in the company’s last rate case, and it was the company’s decision to

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exhibit, Exhibit A-103, shows 2017 spending through July of 2017 approximately $4.2

million below projected levels for those 7 months.200

d. Demand Failures Program

Line 5 of Exhibit A-19 shows projected 2017 and 2018 capital expenditures for

the demand failures program of $133.1 million in 2017 and $134 million for 2018.

Exhibit A-28 provides detail for the company’s projected demand failures program

expenditures by category and Exhibit A-29 provides project costs in each category.

Mr. Bordine testified that this category of expense includes costs for customer outage

restoration, and the repair or replacement of equipment including pole-top rehabilitation

due to imminent failure. He testified that it also includes a projected enhancement of

the credit for the replacement of certain lighting technologies with LED fixtures.

Staff recommends a $13.6 million reduction in the projected demand failure

capital expenditures. Mr. Laruwe acknowledged that Consumer Energy provided a list

of projects in support of its 2017 expenditures, but testified that the company did not

provide any documentation of the necessity of the projects or the scope of work to be

done.201 He also testified that Consumers Energy did not provide evidentiary support

for its 2018 projected capital spending in key programs including LVD and HVD lines

and LVD substations, with projected expenditures of $72 million, over half of the

projected test year capital spending. Referring to his testimony regarding the reliability

capital expense projections, discussed above, he reiterated that Consumers Energy

not follow through on planned investments. Thus, it was reasonable for the Staff and the Attorney General to consider the discrepancy in approved, versus actual, spending on an historical basis.”) 200 In its brief at page 28 seems to read Exhibit A-103 as comparing spending for the first seven months of 2017 to projected annual spending, but this PFD concludes that the “2017 Projection” column of Exhibit A-103 summarizes the projected spending for the first seven months of 2017 from Exhibit A-35. 201 See 11 Tr 2384.

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cannot reserve dollars as a placeholder and months later develop a plan as to how to

spend those dollars. He testified that the company’s projected expenditures exceed the

five-year average by $27 million for this category.202

Mr. Coppola similarly testified that the company’s projection for calendar year

2018 is 15% above 2016 spending levels, and a greater percentage above prior years.

He testified that the 2017 projection is $16.5 million above 2016 spending levels. He

testified that he reviewed the additional detail in Exhibit A-29 and supporting

workpapers, and concluded that $25 million of the forecast 2017 expenditures and

$72.4 million of projected spending for the test-year portion of 2018 were for emergent

projects, lacking specific projects or work plans. Testifying that the 2016 expenditure

level was above the three-year average, he recommended that the Commission use

2016 actual expense levels for 2017 and 2018 projections, resulting in a total reduction

of $26.8 million for the demand failures program projections.203

In rebuttal, Mr. Bordine asserted that he had provided sufficient support for the

projections, given the responsive nature of the expenses to respond to customer

outages and to repair and replace equipment due to unanticipated or imminent failure.

He testified further that the scope of work could not be provided for each project

because “it is impossible to provide project-level information for a program that in 2016

alone contained 33,000 work orders.”204 He also presented as Exhibit A-97 his

discovery response to an Attorney General interrogatory that he asserted contains “the

selection process and/or projects currently identified for 2018 for certain Demand

202 See 11 Tr 2384. 203 See 12 Tr 2560-2562. 204 See 6 Tr 438.

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Failure programs.”205 Finally, Mr. Bordine asserted that Staff’s recommended

adjustment excluded the additional $2 million annual cost for the company’s revised

streetlight replacement program, and the additional $4.3 million for a resumption of the

company’s meter exchange program.206 He also testified that a recent issue has arisen

regarding certain Allis Chalmers transformers malfunctioning due to a design flaw, with

expected costs of $4.8 million in 2017.207

In its brief, Staff addresses this testimony in detail. Staff argues that Mr. Bordine

did not describe and explain the expenses underlying the capital expense projections,

but identified a list of asset failures that fall within the scope of the program, contending

that “Mr. Bordine does not offer insight into the work that will be done in the test

year.”208 Staff also disputes that its recommendation does not provide funding for

metering or streetlights, stating that Staff’s $121 million spending allowance for the test

year is well above the $106 million five-year average. Staff also contends that the

company has not fully justified the amounts of those projected expenditures.209

Consumers Energy relies on Mr. Bordine’s rebuttal testimony in its brief in

arguing that it would be virtually impossible to provide the scope of work Staff desires

for this program. The company acknowledges that it based its projections on historical

experience, and asserts that it included incremental expenditures were known to occur

as part of its program, including changes to its streetlighting program, and the

205 See 6 Tr 438. 206 See 6 Tr 438-439. 207 See 6 Tr 440. 208 See Staff brief, page 32. 209 See Staff brief, pages 30-34.

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transferred meter program. The company argues that Staff did not contest any of these

additional expenditures.210

In its reply brief, Consumers Energy expresses surprise that Staff raised

concerns with specific elements of its projections:

Staff’s criticism of the project-level detail provided by the Company as support for the expenditure projections is surprising. Staff’s Initial Brief, pages 32-33. In order to address Staff’s request for the specific projects to be undertaken during the projected test year, the Company provided actual project locations. See Exhibit A-29 (AJB-16). The Staff then uses its Initial Brief to further criticize the specifics of the Company’s evidentiary presentation by demanding that additional information should have been provided. This hindsight evaluation puts the Company in the untenable position of never being able to fully address or provide the information that Staff believes is necessary for its review. Staff has had a significant amount of time to review the Company’s case. During this time, Staff can conduct an audit and submit discovery requests. Since Staff did not utilize that review process to evaluate the reasonableness of the Company’s proposed expenditures, it is unreasonable to now suggest that the Company has not fully supported its request and criticizing aspects of the evidentiary presentation in brief.211

The company also argues that Staff’s adjustment does not reflect the company’s

increased spending in the demand failure program. Citing Exhibit A-34, it argues that in

2016, the company projected it would spend $116.6 million, but actually spent

$118.7 million. Citing Exhibit A-103, it argues that it projected 2017 spending of

$98.8 million and is on track to spend above its projected amount. The company also

argues in a footnote that Staff never mentioned the use of a five-year average in in its

testimony and does not expressly advocate for the use of the five-year average in its

brief.212

210 See Consumers Energy brief, pages 17-19. 211 See Consumers Energy reply brief, page 21. 212 See Consumers Energy reply brief, page 19 at n3.

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This PFD finds that Staff’s recommendation is reasonable. The company did not

present any projects to support the 2018 projections. While some projects are identified

in Exhibit A-97, that response also states that projected expenditures are based on

historical experience, and does not refute Staff’s analysis. Since Staff identified

$72 million of the 2018 projection that is without support, Staff’s recommended

reduction of $13.6 million reflects the difficulty of projecting expenditures in this category

while providing a measure of protection for ratepayers. The reference in Staff’s brief to

the five-year average identified by Mr. Laruwe, $106,664,000,213 which Consumers

Energy objects to, shows that Staff’s analysis provides a reasonable allowance based

on historical expenditures with room for the additional programs identified by

Mr. Bordine. The company’s expression of surprise at the argument in Staff’s brief that

its project identification lacks detail is itself surprising, given that Mr. Laruwe testified to

this:

In support of the Company’s projected spending plan the Company has provided a list of projects to be completed in 2017, but has failed to provide any documentation of the necessity of the projects, or the scope of the work to be done for each project supporting the projected costs. Absent any information regarding the necessity that these projects be completed in the test year, or that the projected project costs are reasonable approximations of the cost of the work to be done (scope), Staff is not persuaded that the request is representative of the work that will actually be performed during the test year and is not just an over-inflated capital spending plan.214

The company’s claims about what was or was not done in discovery, without record

citation, is inappropriate.

The demand failures category is clearly one in which the level of expenditure

from year to year is difficult to predict, and reflects the frequency and severity of storm 213 See 11 Tr 2384. 214 See 11 Tr 2384.

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activity. The record also shows that when the company has an atypical expense in this

category, it may take funding away from investments in system reliability or generation

maintenance that are expected to lower future costs and improve reliability. As

discussed below, in reviewing the company’s five-year distribution system plan, the

Commission can consider whether any particular ratemaking mechanisms are

warranted to address this dilemma. Of course, all reasonable and prudent actual capital

expenditures will be included in rate base in the company’s next rate case.

e. Electric Operations—Other

Line 7 of Exhibit A-19 contains the projected capital expenditures for the electric

operations—other category. Mr. Bordine testified that this category includes

expenditures for computers and equipment, capital tools, system control projects,

National Electric Reliability Council (NERC) cyber security compliance requirements

and National Electrical Safety Code (NESC) working space compliance requirements,

and substation fall protection. Exhibit A-32 provides projected expenditures for these

five categories for the company’s projections, while Exhibit A-33 has specific projects

identified for two of the categories.

Staff argues that projected capital expenditures should be reduced by

$7.5 million in this category. Mr. Laruwe testified that the company only provided

support for one of five program categories for 2018, and for that category, NERC/NESC

compliance, he testified that Staff has concerns about the reliability of the expense

projection. He cited Exhibit A-32 showing no expenditures for NERC/NESC compliance

for 2016, although the company projected expenditures of $7.2 million in Case No.

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U-17990.215 He further testified that the company has failed to identify the compliance

work to be done at each listed site in Exhibit A-33. Mr. Laruwe recommended that

projected spending be held to 2016 preliminary levels adjusted for inflation for the

bridge and test year periods.216

Mr. Coppola also testified that Consumers Energy did not spend the amounts

projected in Case No. U-17990 for 2016 or 2017.217 He quoted the company’s

discovery response addressing this discrepancy:

Based upon the guidance from Reliability First, the Company was no longer required to treat the Frame Relay telephone circuits in a manner consistent with the requirements under NERC CIP as was projected in MPSC Case No. U-17990 and so the related expenditures are no longer necessary.218

Citing Exhibit AG-15, he also testified that the company’s projections for the first

5 months of 2017 of $1.7 million were not incurred. He recommended removal of the

2017 and 2018 projected NERC/NESC expenditures totaling $5.8 million.219

In rebuttal, Mr. Bordine asserted that he did fully describe and explain the

expenditures in this category.220 He cited his Exhibits A-32 and A-33, and presented his

response to the Attorney General’s discovery request as Exhibit A-98, contending that

this exhibit provides the system control projects “currently identified” for 2018. In its

brief and reply brief, Consumers Energy argues that it provided sufficient detail to

support its projections, also citing the spending timeline in Exhibit A-35.221 The company

does not address the reliability of its projections in light of past underspending.

215 See 11 Tr 2385. 216 See 11 Tr 2386. 217 See 12 Tr 2562. 218 See 12 Tr 2562. 219 See 12 Tr 2562-2563. 220 See 6 Tr 440. 221 See Consumers Energy brief, pages 19-20; reply brief, pages 22-23.

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This PFD finds that Consumers Energy has not supported its projected expenses

for this category. Exhibit A-98 confirms Staff’s and the Attorney General’s testimony

that Consumers Energy did not spend any of the funds allocated for NERC/NESC

compliance in Case No. U-17990. Although Consumers Energy subsequently revised

the discovery response in Exhibit AG-15 the Attorney General relied on, the revised

figures in Exhibit A-103 confirm that the company made no expenditures through July

2017 toward its projected $1.7 million expenditure for NERC/NESC compliance, and

additionally, that the company is $3.2 million behind in its projected spending for the

electric-other category over that same time frame, including significant deviations from

projected spending in multiple line items. Because Staff’s adjustment reflects the

compilation of all the line items in this category, this PFD recommends that the

Commission adopt Staff’s adjustment.

f. Distribution System Contingency

Ms. Fromm testified that Staff recommends the exclusion of contingency from the

electric distribution category totaling $1.8 million if the Commission adopts Consumers

Energy’s capital expense projections for electric distribution.222 Although Exhibit S-10.0,

and S-13.2 show contingency included in the distribution system capital expense

projections, she testified that the contingency expense issue for this category was

resolved by Staff’s recommended distribution system capital expense projections.

Mr. Coppola recommended excluding the total $1.8 million. In its brief, Staff argues that

the additional $1.8 million contingency associated with this category should be excluded

consistent with Staff’s recommended adjustments to the distribution system capital

222 See 11 Tr 2359.

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expense projections.223 A review of the record shows that Mr. Bordine expressly

acknowledged that the contingency expense projections for the electric distribution

system relate to the “new business” category discussed in section a above.224

Consumers Energy does not dispute this.225 Since the contingency relates to the “new

business” expense projections that Staff did not adjust, and this PFD does not

recommend adjusting, the $1.8 million in contingency expense included in the

company’s capital expense projections should be excluded for the reasons discussed

above.

g. Ratemaking Mechanism

Consumers Energy and Staff have alternate proposals for ratemaking

mechanisms to address concerns regarding underspending on electric distribution

system infrastructure. Mr. Torrey presented the company’s proposal in his direct

testimony:

This case is being filed prior to the conclusion of the filing requirement update initiated in Case No. U-18238 and prior to the five-year distribution investment and O&M report submission. In the interim, the Company stresses the importance of receiving timely rate recovery for electric distribution capital expenditures presented in this case. These investments are necessary to provide safe and reliable service to customers. Should the Commission find that these investments have not been presented with enough detailed support, the Company would propose that the electric distribution capital expenditures be put into rates subject to refund if not spent.226

He proposed that the company file a reconciliation on January 1, 2019, and return the

costs associated with any shortfall in applicable actual average rate base compared to

the approved amount. He testified that this will allow the company to make the

223 See Staff brief, pages 8-9. 224 See 6 Tr 398. 225 See Consumers Energy brief, page 20. 226 See 7 Tr 640.

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necessary capital investments, and “provide the Commission the comfort of knowing

that the customers will only pay for the electric distribution investments serving them.”227

Staff instead recommended a mechanism that is project specific. Mr. Laruwe

testified:

Staff believes, in order to ensure that rate payers are receiving the actual investments approved in this case the reconciliation must be done at a project level for each individual distribution capital program. This will ensure that when the rate payers are paying their future bills with the belief they are funding a distribution grid automation scheme, capable of reducing customer outage frequency/duration and able to provide valuable real-time system data to grid operators for the next 20 years, they are not in fact funding the purchase of potentially unnecessary fleet or IT at the same cost. The Company’s proposal of reconciling based upon average rate base rather than execution of plans and projects provides no such assurance.228

Mr. Coppola recommended against approving the mechanism, objection to changing

the traditional ratemaking approach:

The purpose of a rate case is to determine the amount of reasonable expenses and rate base costs that should be included in rates. Despite Mr. Torrey’s wishes, the rate case proceeding should not be changed to an automatic cost recovery or program funding mechanism that includes 100% of what the Company deems reasonable, subject to future resolution of disputes of reasonableness. This is perverse approach to ratemaking that may be appealing to the Company but is fraught with negative consequences for customers who will pay higher rates.229 In rebuttal, Mr. Torrey acknowledged Mr. Coppola’s concern with the overall rate

level, and testified that the company’s proposal to refund distribution capital

expenditures could apply to whatever level the Commission determines is reasonable

227 See 7 Tr 641. 228 See 11 Tr 2386-2387. 229 See 12 Tr 2573-2574.

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and prudent in this case, but requested that any reconciliation be “two directional”.230

He objected to Staff’s proposed project-by-project approach, contending that this

approach “fails to recognize that adjustments may need to be made to timing or scope

of projections throughout a year, and amounts can be shifted from one project to

another based on changed circumstances or priorities.”231 He also referred to the

explanations for project spending variances provided by Mr. Bordine, Mr. Maddipati, and

Mr. Denato in their rebuttal testimony. He expressed a concern that under Staff’s

approach: “The Company would refund amounts on projects where underspending

occurred and not collect overspending on other projects for many months when all

spending was found to be reasonable and prudent.”232

In his brief, the Attorney General indicates that he opposes the company’s

proposal based on Mr. Coppola’s testimony. Staff argues in favor of a project-based

mechanism:

Staff’s proposed approach will ensure that the Commission-approved project expenses included in rates will be incurred and the related projects will be performed absent unforeseen circumstances. This expectation from the vantage of the regulator and rate payer is reasonable given that these same projects served as the premise for rate increase in this case (11 TR 2386.). Given the huge incentive to the Company grow rate base regardless of prudency that is inherent in rate-of-return regulation, these customer protections are necessary to avoid frivolous spending to meet aggregate spending plans to avoid customer refunds and maximize rate base. Staff’s approach mitigates this incentive through greater accountability and granularity.233 This PFD recommends that the Commission defer consideration of an electric

distribution system ratemaking mechanism such as the mechanisms recommended by

230 See 7 Tr 648-649. 231 See 7 Tr 649. 232 See 7 Tr 650. 233 See Staff brief at page 37.

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the company and Staff until it has an opportunity to review the five-year distribution plan

called for in the company’s last rate case. Adding another layer of review, the

reconciliation of the mechanism, could prove an unnecessary distraction given the

utility’s recent history of filing annual rate increases, the need to review the upcoming

report, and myriad other items on the Commission’s agenda.

If the Commission does decide to adopt a mechanism to track distribution system

capital expenses in this docket, however, this PFD recommends that the Commission

adopt Staff’s proposed mechanism. Only a project-specific mechanism would provide

an incentive to the utility to undertake needed system maintenance and upgrades when

faced with other, e.g. storm-related, uses for capital. As Mr. Maddipati’s testimony

makes clear, the company will reduce investments in long-term reliability to

accommodate short-term demands for service restoration following storms or

unexpected new business. A review of Exhibit A-103 also shows the potential

consequences of an unstructured tracking mechanism. This exhibit shows that for the

first 7 months of 2017, the company’s spending in the categories of reliability and grid

modernization are well below projected values, while spending for demand failures is

significantly above forecasted levels, and spending on new business and asset

relocation is somewhat above forecasted levels. The mechanism proposed by

Consumers Energy does not seem tailored to ensure that the utility makes the long-term

investments in reliability and grid modernization that are generally recognized to benefit

customers.

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3. 2016 Meter-Estimation-Related Capital Expenses

Ms. Fromm recommended that $156,516 in software for its meter estimation

process and $234,611 in new meter reading hardware costs be disallowed. She

reviewed the Commission’s orders in Case No. U-18002. She explained:

Staff is recommending both these expenditures be disallowed because it is inappropriate to expect ratepayers to pay for costs that were incurred due to actions described by the Commission as

the utility’s lack of effective monitoring, controls, and customer communications to avoid recurring estimated bills for such a large number of customers over an extended period of time [that] shows a disregard for the Commission’s rules. (MPSC Case No. U-18002, Order, June 9, 2016, p 21.)

The meter estimation process received the $156,516 of additional work in 2016. Meanwhile, Consumers will be fully complete with their AMI installations by September of 2017, an investment which ratepayers have been paying for since 2012. Additionally, ratepayers also pay through their rates for the meter reading staff the Company employs to provide them with actual reads. While it is understandable that the Company utilize their meter estimation process when it is not plausible nor safe to obtain an actual read, it is inappropriate to rely on the estimation process and expect the ratepayers to be responsible to pay for the additional investment made to improve its accuracy, when the process was only relevant for an additional year or so due to the timing of the AMI installations. Additionally, the meter estimation process is only necessary when actual meter reads are not being obtained. In 2015, the Company had 49,000 accounts identified that had not received an actual meter read for 3 or more months. Of these, 12,671 meters had gone 12 months or longer without receiving an actual read. (MPSC Case No. U-18002, Order, June 9, 2016, p 6.) Given that the Company was relying so heavily on its estimation procedure for these accounts, this may explain the necessity of improving an inaccurate meter estimation procedure, but it does not justify it being the responsibility of the ratepayers to pay for this remedy.234

234 See 11 Tr 2353-2354.

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She also testified that the meter reading hardware costs were attributed to the need to

hire 30 seasonal meter readers, the company had not explained why those additional

meter readers were needed given the AMI implementation.235

Mr. Bordine testified in rebuttal on this issue, contending that the Commission’s

order in Case No. U-18002 did not preclude the company from making additional

investments, and presenting as Exhibit A-99 a revised version of his response to Staff’s

audit request, Exhibit S-13.4, page 5, contending that the assets at issue are gas assets

that “should not be excluded from an electric rate case.” Consumers Energy relies on

this testimony in its brief.236 In its brief, Staff acknowledges Mr. Bordine’s revision to the

audit request, but points out that nothing in the company’s revised response or in

Mr. Bordine’s testimony establishes that the expenditures at issue have not been

included in the company’s electric rate case.237

This PFD finds that Consumers Energy did not establish the reasonableness and

prudence of these expenditures for electric distribution system operations, given the

near-completion of the company’s AMI installation and Mr. Warriner’s testimony

regarding meter reading rates. This issue thus distills to the question whether

Consumers Energy included these 2016 expenses in its electric rate calculation in this

case. A review of Staff’s audit request in Exhibit S-13.4, pages 4-5, shows that the

question expressly sought information regarding “any costs in this filing associated with

the measures taken to mitigate the meter reading issues as discussed in docket

U-18002.” Regarding costs for “any software/systems development work done to

specifically address the meter estimation process,” Mr. Bordine’s response clearly 235 See 11 Tr 2354-2356. 236 See Consumers Energy brief, page 237 See Staff brief, pages 17-20.

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states: “In 2016, the Company spent $156,516 in software/systems development to

address consecutive estimates and improve meter reading rates.” Regarding costs for

“any additional investments made to address the issue,” Mr. Bordine’s response clearly

states: “In 2016 the Company invested $234,611 in new meter reading hardware costs

to enhance the ability to obtain a 97% meter reading rate and address consecutive

estimate issues. These were necessitated by the additional meter readers added to

enable the Company to obtain the targeted read rate.” Mr. Bordine’s revised response

in Exhibit A-99 contains the new statement: “These devices were all purchased for gas

headquarters and thus were charged to gas division capital accounts.” While it is

regrettable that Mr. Bordine’s original response inaccurately identified these expenses

as included in the company’s filing, this PFD finds that it is reasonable to accept his

revised statement that the costs are only reflected in gas accounts. While Staff would

prefer a more definitive statement that the costs in the gas accounts are not included in

the electric rates, given the relatively small magnitude of the expenditures and

Mr. Bordine’s unequivocal statement that the costs are not included in electric accounts,

this PFD recommends no adjustment in this case for those costs.

4. Energy Resources (Generation) Capital Expense Projections As shown in Exhibit A-61, Consumers Energy’s projected capital expenditures for

its generating resources are developed for each unit, excluding environmental capital

spending, with separate projections for expenditures to comply with Air Quality

requirements, Resource Conservation and Recovery Act (RCRA) requirements, section

316b of the Clean Water Act, Steam Electric Effluent Guidelines (SEEG), and other

environmental requirements. Ms. Hill testified in support of the projected expenditures

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for the generating units,238 but relied on Ms. Breining’s analysis of the required

expenditures for compliance with key environmental requirements. Ms. Hill also

presented information regarding planned outages and projected generating unit

availability in Exhibits A-58 and A-59, and additional information regarding capital

projects in Exhibit A-63. Ms. Breining presented additional information regarding

planned environmental expenditures shown in Exhibit A-61. Her Exhibits A-38, A-39,

and A-40 present compliance schedules for air quality, coal combustion residuals

disposal, and water quality projects, with additional supporting documentation in

confidential Exhibits A-41 and A-42.

Referring to the Commission’s November 4, 2010 order in Case No. U-16191,

Ms. Hill testified that the company’s capital expense projections have been reviewed by

senior management.239 She also testified that Consumers Energy projected 2016

capital expenditures for energy resources to be $370.8 million, but actually spent

$320.9 million, and explained the $49.9 million underspending as follows:

The Company manages its capital spending to ensure that all investments made are in the best interest of the customer. As circumstances change, and emergent investments arise, the Company shifts its limited resources to optimize safe operations, unit reliability, and customer value. The $49.9 million can be classified into the following areas: $18.9 million of budgeted projects were reduced to fund emergent gas compression and storage capital projects; $14.9 million represented a delay of the Ludington Overhaul main transformer bank replacement and overhaul timing; $14.6 million was reduced spending or delay of the AQCS project at Campbell due to commission and startup; and the remaining $1.5 million was scope or project reductions and delays into 2017.240

In compliance with the Commission’s order in Case No. U-17990, Consumers Energy

also presented an analysis of retirement scenarios for four of its coal-fired generating 238 See 8 Tr 1063-1080. 239 See 8 Tr 1065. 240 See 8 Tr 1065.

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units, Karn units 1 and 2 and Campbell units 1 and 2, also referred to as the Medium 4.

Mr. Clark presented this analysis, incorporating information from Ms. Hill and

Ms. Breining.

a. RCRA

During the course of the rate case, Consumers Energy acknowledged changing

its planned spending for RCRA compliance for the Karn and Campbell plants. Staff

recommended adjustments totaling to the company’s projected spending for RCRA

compliance to reflect these changes. First, Mr. Evans recommended a net reduction of

$5.1 million to reflect the company’s revised plans for coal combustion residual storage

at Karn, including switching from bottom ash tanks to a less-expensive double-lined

impoundment.241 Second, he recommended changing the expense projections to

reflect a delayed expenditure for the bottom ash tanks projected to be installed at the

Campbell plant, moving half the projected expenditure for the first 9 months of 2017 into

the projected test year, with the effect of reducing the projected rate base. He testified

that monthly expenditure data from Consumers Energy presented in Exhibit S-14.4

showed that Consumers Energy had spent only 31% of the amount it projected to spend

from January to May of 2017, as shown in Exhibit S-14.3, leading Staff to believe total

spending for the first 9 months of 2017 would also fall short of projections.242 The

Attorney General also recommended revising the projected Karn RCRA spending to

reflect the revised plans, citing the information presented in Exhibit AG-18.243

Consumers Energy agreed with these recommendations, as explained in its rebuttal

testimony, and adopted Staff’s recommended adjustments. 241 See 11 Tr 2282-2284. 242 See 11 Tr 2284-2285. 243 See 12 Tr 2566-2567.

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In its initial brief, Staff argued that an additional $4.4 million reduction in the

capital expenditure should be made, citing Exhibit S-14.13 as showing spending at an

even slower rate than reflected in Mr. Evans’s adjustment. In its reply brief, Consumers

Energy argues:

The record supports a total cost for the bottom-ash tank at the Campbell facility of approximately $23 million. The Commission should continue to apply the same logic that Staff applied in its own direct testimony in this case. To the extent that the spending in the early months of the project has continued to be incurred more slowly than originally projected, the additional $4.4 million identified by Staff in Exhibit S-14.13 should be shifted from the pre-test year 2017 portion of spending into the test year. Staff’s inconsistent new proposal to disallow $4.4 million should be rejected.244

This PFD finds that Consumers Energy’s recommended revision to this expense

category, moving the additional $4.4 million from the first three-quarters of 2017 to the

test year, is a reasonable accommodation of the information presented in Exhibit

S-14.13, and consistent with the earlier adjustment recommended by Staff and adopted

by the company.

b. The Attorney General’s Additional Recommendations

The Attorney General also recommended two additional adjustments to the

energy resources capital expense projections shown in Exhibit A-61. First, Mr. Coppola

recommended a $13 million general reduction in the $213 million projected 2017 capital

expenditures for generation facilities shown in Exhibit A-61. Citing Exhibit AG-16, he

testified that the 2017 expenditures through May 2017 were $26 million below the

company’s expense forecast for those months, or approximately 30%. Giving

Consumers Energy the benefit of the doubt that it will make up some of the

244 See Consumers Energy reply brief, page 28.

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underspending, he recommended a $13 million reduction in projected 2017 capital

expenditures. 245

Ms. Hill acknowledged in her rebuttal testimony that 2017 actuals do not track

with forecast cash flows, presented Exhibit A-115 showing totals through July 2017.

She testified that part of the explanation for the $45 million reduction compared to

planned spending for those months results from the delay in expenditures to later in

2017 or into 2018. She testified that part of the delayed expenditures are related to the

changed plans for Karn, and part of the delayed expenditures ($9 million) relate to the

Ludington project. She also testified that $20 million was reallocated to the electric

distribution side of the business for customer demand related work.246 She testified that

the company anticipates spending increased amounts later in 2017, in 2018, “and in

other areas of the business.”247

Second, Mr. Coppola recommended a reduction to projected 2017 and 2018

spending in the “other environmental” category, related to projects at the Campbell plant

labeled Ash Storage Facility Cell Closure, UBAS Upgrades for Aqueous Ammonia, and

SDA and DSI Remediation. Citing Exhibit AG-17, he testified that the company

identified the projections as preliminary in nature, and recommended excluding the

$6 million 2017 cost and 9/12ths of the $7.8 million 2018 cost ($5.8 million) of these

projects.248

245 See 12 Tr 2564-1565. 246 See 8 Tr 1096. 247 See 8 Tr 1097. 248 See 12 Tr 2565-2566.

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In rebuttal, Ms. Hill acknowledged that she characterized these projects as

preliminary,249 but stated that the project costs are supported by engineering estimates

as shown in Exhibit A-63, and in some of her workpapers, which she presented as

Exhibit A-118.250

In its brief, Consumers Energy relies on Ms. Hill’s rebuttal testimony. The

Attorney General does not address this rebuttal testimony in his brief. This PFD finds

that the first of these adjustments, a general reduction of $13 million to reflect the pace

of spending, is substantially duplicative of the specific adjustments for Karn and

Campbell spending recommended in section a above. Regarding the second of these

adjustments, this PFD finds that it is reasonable to accept Ms. Hill’s testimony that the

projections are adequately supported by engineering estimates.

c. Medium 4

As discussed in section II above, Mr. Clark presented an analysis of the early

retirement of the Medium 4 plants to meet the directive of the Commission in Case No.

U-17990. He testified that the company’s analysis is preliminary and not conclusive.

Staff and MEC/NRDC/SC presented testimony addressing this analysis, and projected

costs for the Medium 4 units. The disputes between the parties involve whether the

company’s analysis complied with the Commission’s directives in Case No. U-17990,

whether costs identified as avoidable in the event of an early retirement should be

excluded from this rate case, and what additional analysis the company should perform.

249 See 8 Tr 1097. 250 See 8 Tr 1097-1098.

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i. Staff

Mr. Evans recommended that the Commission exclude the avoidable capital

costs associated with maintaining Karn units 1 and 2 until a decision is made whether

the units will retire. He identified these avoidable costs as $1,613,000, excluding the

contingency amounts addressed separately. He cited Ms. Breining’s testimony

acknowledging that Consumers Energy was exploring cost-savings at Karn in

connection with a possible early retirement scenario.251 Recognizing uncertainty in the

company’s plans based on Mr. Clark’s testimony, he explained:

[A]ccording to Mr. Clark, in order to make a decision on accelerated retirement of the units, numerous factors should be considered and analyses looking at these factors is ongoing. So, either the Company has in fact decided to retire Karn 1 and 2 in the near future, or accelerated retirement of those units is still under evaluation. Given that with the first possibility, Karn 1 and 2 will be retired early, and with the second, Karn 1 and 2 may be retired early, Staff believes it prudent to err on the side of caution and assume the units will be retired in 2021. Hence, Staff recommends removing all capital expenditures categorized as “avoidable” at D.E. Karn under a 2021 early retirement scenario.252

Mr. Evans also recommended that the company present additional analyses based on a

discovery response provided by Mr. Clark in which he described the company’s plans:

In order to make a decision on accelerated retirement of the units, at least the following five factors should be considered. The Company is performing analyses looking at these items which it expects to complete by the end of this year. 1. Integrated Resource Plan analysis including capacity replacement

costs;

2. Impact of recovery of undepreciated book value;

3. Customer rate impact analysis;

4. Consideration of non-economic variables such as portfolio balance, employment, and community impact; and

251 See Evans, 11 Tr 2295-2297. 252 See 11 Tr 2297.

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5. Effect on contractual fuel obligations.

Mr. Evans recommended that in addition, Consumers Energy be required to examine:

the internal rate of return, near-term revenue requirements, conditions of existing

equipment, execution risks, and any other factors the Commission deems important.

Based on Mr. Clark’s statement that the analysis he described should be completed by

the end of 2017, Mr. Evans recommended that the new retirement study be completed

and submitted by June 15, 2018, with all supporting documentation.253

In its brief, Staff argues that the Karn avoidable costs should not be included in

projected rate base:

While outside factors can influence when generating units retire, the Commission should still address the risk that avoidable expenditures will not be spent during the test year. Staff believes it prudent to err on the side of caution and assume those units will be retired in 2021. The Company argues that there would be incremental capital costs associated with retiring Karn Units 1 and 2 early, due to capital required to separate Karn Units 1 and 2 from Karn Units 3 and 4. The Company states that if the decision is made to retire Karn Units 1 and 2 early, the avoidable capital expenditures will simply be replaced by the incremental capital required for Karn Units 3 and 4. (8 TR 1086-1087.) Staff does not disagree that there will be capital costs associated with retiring Karn Units 1 and 2 early. However, the Commission should not replace the projected avoidable expenditures with a preliminary estimate (8 TR 1086) of a different activity. The two types of expenditure should be treated separately.254

Staff also proposes a revised schedule for the company to file a new retirement

analysis, recommended that the company file a new retirement study both in this

docket, on or before April 20, 2018, and as part of its IRP filing:

While the study would not be contested in that docket, such a filing should provide Staff and other parties with pertinent information before the

253 See 11 Tr 2292-2294. 254 See Staff brief, pages 56-57.

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Company files its next rate case. In addition, timing is critical. Company witness Danielle Hill indicated during cross examination and in a discovery response to the MEC dated September 20, 2017 that for each of the Medium 4 units, a decision to pursue a 2021 retirement would have to be approved no later than March 2018 in order for the majority of the 2019 capital costs identified as avoidable to be avoided. (8 TR 1159, Exhibit MEC-31.) To potentially save ratepayers millions of dollars in avoidable capital costs, the Company should be required to finish and submit its new retirement study as soon as practicable after the final order in the instant case. A submission date of April 20, 2018 into the U-18322 docket should give the Company adequate time to finalize its analysis and meet its own stated deadline to potentially avoid millions of dollars in avoidable capital costs (8 TR 1159.) Again, the new retirement study should provide the Company’s final decision(s) regarding when to retire each of the Medium Four units. In addition, the Company should include the new retirement study as part of its first Integrated Resource Plan under Public Act 341 of 2016, which the Company has already agreed to file no later than June 2018. (8 TR 1251.) The IRP will, of course, be reviewed in a contested case proceeding. Staff recommends the Commission require the Company to file its first IRP on or before June 15, 2018.255

ii. MEC/NRDC/SC

MEC/Sierra Club recommend that the Commission exclude all projected

avoidable expenses associated with the Medium 4 units until a determination is made

whether to retire the units early. Mr. Koehler testified on this topic. He concluded that

the company’s analysis was insufficient to show that continued investment in the

Medium 4 units is reasonable and prudent. He began his explanation by reviewing the

company’s NPV analysis and the Commission order calling for the analysis. He testified

that the analysis Consumers Energy presented in this case was similar to the analysis it

presented in Case No. U-17990, and that the company drew the same conclusions from

both, that additional analysis is required before a decision can be made.256 He objected

that a redo of the same analysis was not the detailed benefit/cost analysis the 255 See Staff brief, pages 54-53. 256 See 11 Tr 2126-2127.

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Commission called for in Case No. U-17990. He testified that the study shows that a

2021 retirement of one or more of the Medium 4 units would be a lower cost option

under a range of assumptions about future market conditions. By failing to demonstrate

continued operation of the Medium 4 units is reasonable and prudent, Mr. Koehler

testified, the company has failed to support some of the proposed capital and major

maintenance expenses for the projected test year.

Mr. Koehler acknowledged Consumers Energy’s contention that very little of its

proposed capital and O&M expenses are avoidable under an early retirement

scenario.257 He objected that there was little analysis to support these designations.

He presented a summary table of the results from Exhibits A-89 to A-91 in his

Exhibit MEC-2. He testified that the results are highly dependent on the assumed

capacity value; he testified that when capacity values are assumed to be at or below

50% of the Cost of New Entry (CONE), none of the units showed economic benefits

from operating beyond 2021, while when capacity values increase, Campbell units 1

and 2 continue to show economic benefits from retirement until the cost of capacity

reaches 100% of CONE.258 Noting that Consumers Energy used a capacity value of

75% as its base case, he testified that this value is too high relative to the price

Consumers Energy has paid in the capacity market, higher than the price of capacity in

the MISO PRA, and higher than the cost at which Consumers Energy has indicated in

other proceedings it can obtain replacement resources:

Consumers has identified significant amounts of capacity that it could obtain economically when market prices are assumed to be 50% of CONE. This same capacity market case was relied on as the base case in the Company’s analysis of the proposed Palisades Buyout and

257 See 11 Tr 2129. 258 See 11 Tr 2130.

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Replacement Plan in Case No. U-18250, filed in February 2017. In a comparable NPV analysis with similar market energy and capacity assumptions, the Company identified potential capacity replacement resources totaling over 1,200 Zonal Resource Credits (ZRCs) by 2020 in MISO Zone 7 that would save customers almost $400 million on a long-term net present value basis relative to market purchases. The termination of the Palisades PPA would only represent the loss of 780 ZRCs through April 2022. The Company demonstrated that more than enough economic replacement capacity is likely available at below 50% of CONE capacity value to replace one or more Medium 4 units in addition to the Palisades PPA. In response to discovery, the Company has also noted that it recently paid about 51% of CONE in a reverse auction for 525 ZRCs. The Company has also stated that it paid approximately 54% of CONE in a similar reverse auction held in 2016.259

He also presented Exhibit MEC-3 to show the PRA clearing prices.

Mr. Koehler also testified that Consumers Energy’s analysis overstates the

benefits of later retirement by assuming in its 2031 retirement analysis the capital

expenses will be reduced in the years approaching the retirement date, but does not

consider comparable reductions in the last few years under a 2021 or 2023 retirement

scenario. In his exhibits, he showed the impact of more aggressive cost savings for the

early retirement scenarios, or less aggressive cost savings for the later retirement

scenario, also using a 50% of CONE capacity price assumption, and found early

retirement benefits in all cases.

Mr. Koehler testified that in other cases, Consumers Energy has assumed

significantly higher capital costs for continuing to run these units, citing information in his

confidential Exhibit MEC-5 from Case Nos. U-17990 and U-18142. He also calculated

the NPVs associated with these expenditure levels as a “sensitivity” analysis.260 Mr.

Koehler also took issue with the company’s assumed O&M expense levels for the 2021

retirement case, asserting that these expense levels are inconsistent with the avoidable 259 See 11 Tr 2131-2132 260 See 11 Tr 2137-2138.

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major maintenance and environmental O&M costs identified by Ms. Hill and Ms.

Breining. He testified that revising these figures in the NPV analysis incrementally

improves the benefits of retiring Campbell unit 2 and both Karn units in 2021.261

MEC/NRDC/SC argue in their brief that Consumers Energy has the burden to

justify the reasonableness and prudence of further capital and major maintenance

spending on the Medium 4. Relying on Mr. Koehler’s testimony and citing Exhibits

A-89, A-90 and A-91, they argue that the company’s analysis strongly suggests that

retiring one or more of the Medium 4 units by the end of 2021 would likely be better for

ratepayers. In addition, they contend that the company’s analysis understated the

capital investments required to keep the units operating until 2031, as well as the

benefits of early retirement.262 MEC/NRDC/SC acknowledge Ms. Hill’s rebuttal

testimony regarding the ability to reduce capital expenditures for a retiring plant with

sufficient lead time, but argue it is unreasonable to assume the units will not experience

the same diminution in capital costs in the early retirement scenarios as in the 2031

retirement scenario.263 MEC/NRDC/SC also cite Consumers Energy’s Exhibit A-62,

intended to show the cost performance of its generating units, as demonstrating that the

Karn units are the bottom half or bottom quartile as measured by non-fuel O&M costs

per MWh.264

MEC/NRDC/SC argue that the company’s analysis did not comply with the

Commission’s order in Case No. U-17990, and that a further delay in reaching a final

determination creates unreasonable risks for the ratepayer. They recommend that the

261 See 11 Tr 2139. 262 See MEC/NRDC/SC brief, pages 12-17. 263 See MEC/NRDC/SC brief, page 17. 264 See MEC/NRDC/SC brief, page 19.

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Commission not only disallow recovery in this case of costs that are avoidable under an

early retirement scenario, but they recommend that the Commission deny Consumers

Energy a return on any incremental investment in the Medium 4 units. In making this

recommendation, MEC/NRDC/SC reference the Commission’s treatment of DTE

Electric Company’s licensing costs for a proposed Fermi 3 nuclear facility.265 They also

recommend that the Commission provide direction to the company regarding its future

analysis:

In particular, the Commission should require:

• Consumers to complete and submit to the Commission for vetting in a contested case proceeding a detailed unit disposition study supporting a specific planned retirement year for each of the Medium 4 Units.

• Consumers to make a retirement decision and submit the supporting unit disposition study for each of the Medium 4 Units before any further capital or major maintenance expenditures beyond the test year are made or committed to, and no later than the June 15, 2018 submittal of Consumers’ IRP.

• That the unit disposition analysis for each of the Medium 4 Units

that is submitted to the Commission include:

o robust consideration of commodity and market price scenarios and sensitivities, including future policy-driven carbon pricing;

o consideration of uncertainties around estimated costs to

continue operating the Medium 4 units;

o a comprehensive replacement resource analysis that ensures the Company considers the most appropriate least cost options to replace any Medium 4 unit when it retires;

o a thorough and documented analysis and determination of

the capital and major maintenance expenditures that can and cannot be avoided for each of the Medium 4 Units if

265 See MEC/NRDC/SC brief, pages 46-48.

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each unit were scheduled for retirement in 2021, 2023, 2031, or some other date;

o Consideration of non-economic factors such as

environmental and public health risks, as well as regulatory risks;

o A complete evaluation of any other factor that Consumers

deems relevant and necessary to the decision whether to retire one or more of the Medium 4 Units by 2021 or 2023.266

iii. Consumers Energy

Consumers Energy argues that because it has not decided to retire the units

early, it is reasonable to assume they will continue to operate until 2031. Ms. Hill

testified in rebuttal to address Staff’s and MEC/NRDC/SC’s recommendations regarding

the avoidable costs identified in the company’s analysis. Specifically addressing

Mr. Evans’s recommendations, she disputed that the potential retirement of the Karn

units had anything to do with the company’s decision to install a double-lined bottom-

ash surface impoundment at Karn.267 She further objected to eliminating from the rate

case projections cost elements that have been identified as avoidable under an early

retirement scenario. She testified that the decision to retire one of more of the Medium

4 units is a complex issue, explaining that until an official decision is made and reviewed

as part of the company’s IRP, the company must continue to invest in these units to

ensure their continued safe and reliable operation and regulatory compliance.268 She

testified that if the Commission does not include the avoidable costs in rates, the

random outage rate for Karn would likely increase, leading to higher power costs.269

She also testified that in the event the company decides to retire the units, there would

266 See MEC/NRDC/SC brief, pages 50-51. 267 See 8 Tr 1084. 268 See 8 Tr 1085. 269 See 8 Tr 1086, 1099, 1102.

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be incremental capital costs that were not included in the test year, but are shown in

Exhibit A-86.270 Ms. Hill also addressed Mr. Koehler’s concern that the company had

not included capital expense reductions in the early retirement scenarios comparable to

the 2031 retirement case. She testified that those reductions are appropriate only when

the company has substantial time to prepare for the retirement.271 Ms. Hill also

reviewed and defended the company’s identification of avoidable costs, citing her

Exhibit A-119.272

Ms. Breining also testified that the potential retirement of the Karn units did not

play a role in the company’s decision to adopt a less-expensive approach to coal ash

disposal.273 Like Ms. Hill, she testified that the retirement decision is complex, and that

until a decision is made in the IRP process, the company must continue to ensure the

safe and reliable operation of its units.274 She also testified that before a unit could

retire, a number of factors including MISO procedures would need to be addressed.

In his rebuttal testimony, Mr. Clark disputed that the company’s analysis failed to

comply with the Commission’s order in Case No. U-17990.275 He testified that

Consumers Energy plans to file its Integrated Resource Plan under 2016 PA 341 by

mid-year 2018, and provide a fully-comprehensive analysis on the disposition of the

Medium 4 units by that time.276 He presented Exhibit A-104 to show the range of

results from his analysis. He testified that while the analysis shows potential savings to

customers from early retirement, the magnitude of the savings at what he considers the

270 See 8 Tr 1087. 271 See 8 Tr 1101. 272 See 8 Tr 1101-1102. 273 See 9 Tr 1450-1451. 274 See 9 Tr 1451-1452. 275 See 8 Tr 1249-1251. 276 See 9 Tr 1247, 1254.

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most likely price for capacity are “decidedly marginal.”277 He testified that Consumers

Energy believes capacity values will be between 50% and 75% of CONE. He also

testified that Consumers Energy is assuming the retirement of the Palisades Nuclear

Power Plant beginning in 2018, and further reductions in capacity would likely drive up

prices above those estimated in the company’s plans to replace Palisades capacity.278

Early retirement of the Karn 1 and 2 and Campbell 1 and 2 Units, assuming capacity prices fall between 50% and 75% of CONE, range between $64 million in NPV of increased customer cost to $60 million in NPV of customer savings. The individual annual cost increases or decreases corresponding to an NPV of approximately $60 million can be found in Confidential Exhibits A-89 (TPC-4) through A-91 (TPC-6)1 as less than $20 million per year. To put $20 million in perspective, that is less than 1% of the $2.5 billion annual revenue requirements for generation production necessary to meet customer demand. The Company firmly believes it is imprudent to pursue a potential savings of less than 1% of total revenue requirements when a defined capacity replacement plan has not yet been identified.279

He also testified that the company’s analysis in this case examined only one market

scenario, and committed in the future analysis to include additional scenarios. He

further argues that the level of avoidable expenditures are small relative to the

unavoidable expenditures, and argues that any disallowance would create “the

assumption of retirement” and thus interfere with the company’s ability to continue to

operate the units.280 Mr. Clark also defended the reasonableness of the assumptions

underlying the company’s analysis, including the determination of avoidable costs, and

the operating performance and availability of the units.281

277 See 8 Tr 1251. 278 See 8 Tr 1252. 279 See 8 Tr 1252-1253. 280 See 8 Tr 1253-1254. 281 See 8 Tr 1254-1257.

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Testifying that the company believes the determination regarding continued

operation of the generating units should be decided in the IRP proceedings, Mr. Clark

specifically objected to considering public health impacts and public policy risks as

recommended by Mr. Koehler. He testified:

The Company should complete an IRP in accordance with the legislation and corresponding Commission orders. Whatever filing requirements are identified as appropriate for an IRP are also appropriate considerations for retirement analyses of existing units.282 In its briefs, Consumers Energy relies on Ms. Hill’s, Ms. Breining’s, and

Mr. Clark’s rebuttal testimony. The company argues that because it has not made a

decision to retire the units, any reduction in its capital spending plans is not appropriate.

(At one point, the company argues that because it has not reached a final decision, “it

has decided not to retire the units early.”) In its reply brief, Consumers Energy further

argues that it needs to maintain reliable capacity, citing the Commission’s September

15, 2017 order in Case No. U-18197, and citing MCL 460.6w(7), enacted as part of

2016 PA 341, urging the Commission to “err on the side of caution” and assume that the

units will continue to operate through 2030.283

Consumers Energy takes issue with Staff’s and MEC/NRDC/SC’s description of

the additional analysis that should be provided, contending that this would interfere with

and be contrary to the use of the IRP framework for analyzing this issue. Addressing

the factors Staff identified for further analysis, Consumers Energy argues that its new

analysis should be limited to whatever is required for its IRP. Consumers Energy

acknowledges that it has previously identified factors that should be considered, and

that these factors are reflected in Staff’s recommended analysis: 282 See 9 Tr 1258. 283 See Consumers Energy reply brief, pages 33-35.

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The Company has since concluded that any stand-alone analysis of the potential for the early retirement of these plants would be insufficient and that analysis in the context of a full IRP would provide the most appropriate basis for making any potential early retirement determination. 8 TR 1251, 1280, 1286. The Company never affirmatively asserted in this record that any of the four factors listed in Exhibits MEC-21 and MEC-44 would be appropriate in the context of an IRP. Mr. Clark testified that, aside from internal rate of return, some of the remaining three factors from Exhibits MEC-21 and MEC-44 might be relevant in an IRP, but he was uncertain, at least in part, because some of those analyses would need to be conducted by other personnel at the Company. 8 TR 1294-1295. He was, therefore, unwilling to commit to the appropriateness of their inclusion in an IRP. 8 TR 1294-1295. Mr. Clark likewise testified that some of the five factors identified in Exhibits S-14.11 and MEC-42 might be appropriate in the context of an IRP filing, but again, he was unwilling to commit to the appropriateness of their inclusion because some of those analyses would need to be conducted by other personnel at the Company. 8 TR 1287-1293. Mr. Clark pointed out that several of the factors identified in Exhibits S-14.11 and MEC-42 are, themselves, contingent on other results that would be derived in the course of an IRP. 8 TR 1288-1289. The Commission is already in the process of establishing, in a separate proceeding, the filing requirement that will be required as part of an IRP filing under MCL 460.6t. Mr. Clark testified that any retirement analysis pertaining to Karn units 1 and 2 and Campbell units 1 and 2 included in the IRP filing should comply with the filing requirements established by the Commission. 8 TR 1251. Furthermore, Mr. Clark testified that his modeling team simply does not have the resources to, in essence, run two separate IRP analyses within the timeframe being considered if the result of this case were to include an order to model scenarios for purposes of a retirement analysis of Karn units 1 and 2 and Campbell units 1 and 2 that are, in some respects, different from or supplemental to the analytical requirements established by the Commission for the IRP generally. 8 TR 1287-1288. In light of the Commission’s ongoing proceedings regarding IRP filing requirements, it is premature to determine in this proceeding what considerations should be included in the Company’s IRP.284 Consumers Energy argues that in its initial brief, Staff deviated from the

recommendation of Mr. Evans, agreed to by Mr. Clark, that a retirement analysis be

filed by June 2018. The company argues that the April 20, 2018 filing Staff envisions

should be rejected, characterizing it as tantamount to requiring that the entire IRP be


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filed early.285 Consumers Energy argues it cannot as a practical matter commit to

this.286 Consumers Energy nonetheless acknowledged Staff’s concerns regarding the

dates by which spending commitments must be made in order to avoid the more

significant avoidable costs identified in the company’s analysis, indicating that these

costs would become “sunk costs” in the company’s analysis once they were no longer

avoidable. Consumers Energy states:

In order to address Staff’s concerns, Consumers Energy is willing to commit that the IRP filed no later than the end of June 2018 will include at least one modeling run that models the Karn units 1 and 2 and Campbell units 1 and 2 in such a way that otherwise avoidable costs that the Company commits to or incurs in and after March 2018 will not be reflected as sunk costs in the IRP. The Company’s alternative proposal avoids the potential bias to the early retirement analysis that Staff is concerned about while also avoiding the redundancy of two filings and the unintended and potentially infeasible consequence that the full IRP would effectively be mandated by April 20, 2018. The Company’s proposal should be adopted instead of Staff’s proposed filing in this docket.287

iv. Discussion

Based on the record and arguments of the parties, this PFD concludes that

Consumers Energy’s analysis of the Medium 4 retirement scenarios must again be

characterized as “preliminary”. No party claims the company’s analysis is sufficient to

justify a choice of retirement date for any of the units.

The first question to be resolved is whether the company complied with the

Commission’s directives in Case No. U-17990. In that case, the Commission discussed

at length the disputes between MEC/NRDC/SC and Consumers Energy regarding the

Medium 4 units. After explaining MEC/NRDC/SC’s argument that the company should

285 See Consumers Energy reply brief, pages 28-29. 286 See Consumers Energy reply brief, pages 29-30. 287 See Consumers Energy reply brief, page 30.

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not recover projected capital spending for the Medium 4, the Commission explained the

parties’ request for additional analysis:

MEC/NRDC/SC recommended that the Commission should require Consumers to produce, in a timely manner, a full and adequate analysis of the potential retirement of each of the Medium 4 Units to determine, on a unit-by-unit basis, the prudent disposition of each unit before the company commits to or incurs any post-test year spending that could be avoidable. This will ensure that any future spending plans are made with an understanding of the value and cost of each unit to customers so as to avoid unnecessary expenditures. See, 8 Tr 2154, 2164-2166. 288

The Commission then explained Staff’s position:

In its initial brief, the Staff stated that, by and large, it agrees with MEC/NRDC/SC that Consumers should be required to perform a thorough analysis before seeking future recovery of expenditures on the Medium 4 Units. However, the Staff provided two modifications to MEC/NRDC/SC’s witness’ recommendation: (1) in addition to a 2021 retirement scenario, Consumers should include a 2023 retirement scenario; and (2) the analysis should be completed before Consumers files its next general rate case, and the study should be submitted as part of that filing. In addition, the Staff recommended that the Commission require the company to regularly meet with the Staff to discuss its environmental projects. Staff’s initial brief, pp. 23-24; 8 Tr 2569-2570.289

The Commission also explained Consumers Energy’s argument as follows:

Regarding the preliminary early retirement analyses performed by the company in considering the long-term NPV of the Medium 4 Units, Consumers states that “MEC places much more weight upon the NPV Analyses than is warranted given the purpose and preliminary nature of the analyses. These analyses do not provide sufficient support to conclude that a 2021 retirement of one or more of the Medium 4 units would ‘likely be beneficial to customers.’” Consumers’ replies to exceptions, pp. 47-48. Consumers contends that there are several other additional analyses that are important in considering early retirement of the Medium 4 Units. Id., p. 49. In reply to the Staff’s request that Consumers perform an analysis of the benefits/costs of continued operation of the Medium 4 Units, the company argues that the Staff’s recommendation is premature and unnecessary in light of the uncertain status of the CPP. In addition, Consumers asserts

288 See February 28, 2017 order, page 34. 289 See February 28, 2017 order, page 34.

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that the Medium 4 Units “continue to operate reliably and provide value to the Company’s customers and assist in ensuring the reliability of the entire Midcontinent Independent System Operator (“MISO”) footprint.” Consumers’ replies to exceptions, p. 28. The company states that it will continue to keep the Staff apprised of pertinent developments and changes in the regulatory compliance landscape and compliance strategies. Id.290

The Commission concluded as follows:

The Commission agrees with the ALJ that MEC/NRDC/SC failed to specify the expenditures for the Medium 4 Units that they deem avoidable or how the expenditures would affect the facilities’ operation if Consumers were to retire the Medium 4 Units in 2021. In contrast, Consumers met its burden of supporting projected costs and the benefits for the test year, rendering the costs reasonable. Thus, the Commission adopts the ALJ’s recommendation to reject MEC/NRDC/SC’s proposed disallowance. Nevertheless, the Commission agrees that the company should submit a benefit/cost analysis for the Medium 4 Units. The regulatory, market, and technical underpinnings of Consumers’ previous analyses of the Medium 4 Units have evolved significantly and the company’s prior decision to keep the units running until after 2021 may no longer be economically justified. Therefore, the Commission directs Consumers to provide a detailed benefit/cost analysis regarding the retirement of the Medium 4 Units, as set forth by MEC/NRDC/SC and modified by the Staff, in its next rate case.291

Putting the Commission’s requirement that Consumers Energy provide a detailed

benefit cost analysis “as set forth by MEC/NRDC/SC and modified by the Staff” in

context, it is appropriate to consult the record of that case to determine what analysis

the Commission called for.

In that record, MEC/NRDC/SC also relied on the testimony of Mr. Koehler.

Mr. Koehler testified to explain why the company’s analysis to date was not sufficient for

deciding the disposition of the Medium 4 units:

290 See February 28, 2017 order, pages 37-38. 291 See February 28, 2017 order, pages 38-39.

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Q. What additional information must the company consider to make a retirement decision and judge if continued investment in these facilities is prudent? A. The Company in their own words must “consider additional economic, operational, and community impacts, including but not limited to: internal rate of return, near-term revenue requirements and rate impacts, conditions of existing equipment, execution risks, and job and community impacts”.292

He further testified:

Long-term net present value is an important metric to consider when weighing the disposition of generation resources, but it is certainly not the only one. Just because the continued operation of the units beyond 2021 has been shown to be uneconomic in the Company’s NPV study, I would not necessarily recommend a retirement decision based on those results alone. However, these NPV results do strongly indicate that the investment necessary to operate the units beyond 2021 is not in customers’ best interests. The Company’s recovery of any further spending that assumes continued operation beyond 2021 should be deemed imprudent unless and until the Company has made a detailed and reasonable showing that the benefits of continued operation outweigh the unfavorable NPV results of its “preliminary analysis.” As will be outlined further, a far more extensive analysis should be required to demonstrate life-extending investments as prudent rather than simply assuming, as the Company has in developing its capital investment budgets, that the Medium 4 units will maximize customer benefits by continuing operation to the year 2030. No such showing has been made by the Company at this time.293

He elaborated further:

Q. What do you recommend with regard to unit disposition studies for the Medium 4? A. Before requesting recovery of or on any expenditures at the Medium 4 after August 31, 7 2017, the Company should demonstrate that it has conducted a thorough and timely analysis weighing the benefits to customers associated with continued operation versus retirement by 2021 or earlier of each unit individually and in appropriate groupings. The analysis should be conducted before any investment is made beyond the current test year, or, failing that, the analysis should consider those investments as going forward and not sunk costs. The Commission should

292 See Case No. U-17990, 8 Tr 2163. 293 See Case No. U-17990, 8 Tr 2154.

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make such a study a pre-requisite for any future general rate case filing by the Company.294

Consumers Energy’s position in that case also made clear that it thought a substantially

more detailed analysis was called for than the NPV analysis under discussion in that

case. For example, in its replies to exceptions on this subject in Case No. U-17990,

Consumers Energy explained why the company’s NPV analysis was “preliminary”:

Company witness David F. Ronk, Jr. testified as to the preliminary nature of the NPV Analyses, making clear that the “preliminary evaluations consider only one financial metric of the value of the Medium 4, which is the long-term net present value.” 4 TR 352. Mr. Ronk testified that the preliminary NPV Analyses were “not intended to address avoidance of expenditures in anticipation of retirement in the period prior to late 2017 and early 2018 when adequate information was expected to be known to make an informed decision regarding compliance with [certain environmental] rules.” 4 TR 353. Rather, Mr. Ronk indicated that these evaluations remain incomplete, and the Company has not yet made any decisions based on the analyses for several reasons:

“1. The Company must consider additional economic, operational, and community impacts including but not limited to internal rate of return, near-term revenue requirements and rate impacts, conditions of existing equipment, execution risks, and job and community impacts; “2. These units continue to provide positive economic value to customers in the near term and no decision on early retirement is currently required. The major avoidable investments do not begin until late 2017 and 2018; therefore, no decision regarding these investments is required until that timeframe, and it would be unreasonable to make such a decision unnecessarily prematurely; “3. There is significant uncertainty in projected gas prices. The analyses indicate a wide range of results depending on the gas price outlook assumed. The business as usual gas price used in these analyses was developed in fall 2015 and represents a relatively low gas price outlook. There are a number of risks that could lead to increased gas prices, such as reduced gas production and increased environmental regulations on the oil and gas industry and wind generation. This includes the proposed New Source Performance Standards for the oil and gas sector and the recently

294 See Case No. U-17990, 8 Tr 2165.

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proposed United States Fish & Wildlife Service’s Habitat Conservation Plan which may require feathering at wind facilities, resulting in reduced renewable energy production; “4. It is important to understand the full impact of the recent retirement of various coal generators in the Midwest as a result of the Mercury and Air Toxics Standards. The results of the recent MISO Planning Resource Auction indicate these coal retirements have created a much tighter capacity market in MISO. Auction prices cleared at just over 25% of Cost of New Entry and Zone 7 imported capacity to meet its planning reserve margin requirements; and “5. Consumers Energy must consider the value and importance of a diverse and balanced generating portfolio. Too heavy a reliance on any one generating technology creates risk of devastating effects and missed opportunities for our customers. We must maintain a reasonable capacity mix of generation technology to ensure our customers are appropriately insulated from unforeseen increases in fuel prices.” 4 TR 352-353.

Additional analyses important in considering early retirement of the Medium 4 units include: (1) Integrated Resource Plan including capacity replacement costs; (2) recovery of undepreciated asset value; (3) effect on customer rates; (4) MISO Attachment Y analysis; (5) decommissioning effect on employment; (6) decommissioning effect on communities; and (7) decommissioning effect on fuel contract obligations. Exhibit MEC-34.295

As set forth in its initial brief in that case, Staff recommended two modifications to the

analysis Mr. Koehler called for:

Staff would like to modify two aspects of this recommendation: 1) In addition to a 2021 retirement scenario, the Company should include a 2023 retirement scenario; and 2) the analysis should be finished before the Company files its next general rate case, and the completed study should be submitted as part of the filing. An analysis like this would greatly inform the Company, the Commission, and other stakeholders within the state.296 Based on this review of the Commission’s order in Case No. U-17990 and the

underlying record, this PFD finds Mr. Koehler’s testimony persuasive that Consumers 295 See Consumers Energy reply brief, pages 48-49. 296 See Case No. U-17990, Staff brief, page 23.

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Energy failed to undertake the more thorough analysis that MEC/NRDC/SC and Staff

recommended to the Commission, and that the Commission subsequently required, in

part based on the analytical shortcomings of its NPV analysis that Consumers Energy

itself identified in that case. Thus, as Mr. Koehler testified:

Similar to Mr. Clark’s testimony in this case, in Case No. U-17990, Company witness David Ronk Jr. testified that the NPV analyses were “preliminary” and identified seven further analyses for consideration (capacity replacement costs, undepreciated asset value, customer rate impacts, MISO Attachment Y analysis, employment effects, community effects, and fuel contract obligations). Submitting the same type of “preliminary” study again in this case that was submitted in the prior case fails to provide the “detailed benefit/cost analysis” ordered by the Commission in Case No. U-17990.297

Although Staff characterized the company’s study as meeting the minimum

requirements of the ordering paragraph of the Commission’s order, Staff’s brief explains

Staff’s view in more detail:

In the February 28, 2017 Order in the Company’s previous electric rate case, Case No. U-17990, the Commission required a benefit-cost analysis regarding the retirement of the Medium Four units. (11 TR 2290.) The Company filed a cost/benefit analysis that, in Staff’s opinion, met the minimum requirements of the Commission’s order, in that the analysis: 1) was a cost-benefit analysis; 2) included the Medium Four units; 3) evaluated the units individually and in appropriate groupings; 4) included 2021 and 2023 retirement scenarios; and 5) was submitted as part of the rate case. (Exhibit MEC-56.) Company witness Thomas Clark provided the conclusion that should be drawn from the analysis:

The results of the Company’s benefit/cost analysis regarding the retirement of Karn Units 1 and 2 and Campbell Units 1 and 2 indicate that, based on information currently available, it would be premature to make a decision to accelerate retirement of any of these units. These are operating base load plants that currently provide benefits to customers. Consumers Energy plans to perform additional analysis to look at various scenarios and commodity price sensitivities. We are in the process of undertaking further analysis. [8 TR 1245.]

297 See 11 Tr 2126-2127.

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Mr. Clark stated in a discovery response to the Michigan Environmental Council that the Company was performing analyses looking at five items: 1) Integrated Resource Plan analysis including capacity replacement costs; 2) impact of recovery of undepreciated book value; 3) customer rate impact analysis; 4) consideration of non-economic variables such as portfolio balance, employment and community impact; and 5) effect on contractual fuel obligations. (Exhibit S14.11.) Mr. Clark also indicated that the analyses were expected to be complete by the end of 2017 (Exhibit S-14.11), although under cross examination he stated the analyses were not going to be completed until the spring of 2018. (8 TR 1285.) Finally, under cross-examination Mr. Clark admitted that the Company’s benefit/cost analysis submitted in the instant case was incomplete. (8 TR 1279- 1280.)298 The next question to resolve is the question whether the avoidable capital costs

associated with the operation of the Medium 4 units should be included in the rate case

capital expense projections. This PFD recommends that the Commission accept Staff’s

recommendation to exclude the $1.6 million non-contingency avoidable costs

associated with the Karn units 1 and 2, which constitute the bulk of the avoidable costs

identified in Exhibit A-61, page 3. Given that the company has represented that it is

working on a more-detailed analysis in both this case and in Case No. U-17990, and

given that the timing of its analysis is within the control of the company, it is reasonable,

as Staff argues, to “err on the side of caution” and not include in rates an expense that

Consumers Energy may choose to forego or to delay. As Ms. Hill’s testimony makes

clear, Consumers Energy commonly revises its capital spending plans for its generating

units. Rather than assume, as Staff and MEC/NRDC/SC urge, that the units will retire

in 2021, this PFD merely recommends that the Commission defer including uncertain

capital expenses in rates, without prejudice to a future review, should the company

298 See Staff brief, pages 52-53.

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indeed make the capital investment. Given that the analysis is incomplete, it does not

provide a solid foundation for a conclusion.

The next issue to resolve is what additional study the Commission should again

require Consumers Energy to undertake. While Consumers Energy makes a

reasonable argument that compliance with the IRP process alone could resolve the

retirement question, given the two-rate-case history of this issue, and the company’s

prior commitments to conduct a more-detailed standalone analysis, this PFD

recommends that the Commission require Consumers Energy to include a standalone

analysis considering the factors identified by Staff as part of its IRP filing. Consumers

Energy has committed to run at least a version of its studies without consideration of

certain interim investments as sunk costs, making the June 2018 filing date a

reasonable one under the circumstances. It is difficult to foresee a mechanism for an

earlier analysis to be evaluated, and Consumers Energy will be obligated to justify its

investment decisions regarding any of the Medium 4 units as of the time it makes them.

As a further observation, however, regarding Staff’s changed view of the timing

of the updated analysis, Staff is well within its rights to make this argument in its brief.

The timing of any further study is essentially a policy recommendation committed to the

Commission’s discretion, and does not require that Staff have presented a witness

making the same recommendation. Moreover, it frequently happens in rate cases that

the parties modify their views on such matters as requirements for future cases or

additional study.

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d. Contingency

In recommending adjustments to this category of capital expense projection,

Mr. Evans and Ms. Fromm carefully delineated the elimination of contingency

projections from Staff’s other recommendations. As a result, Staff recommends

removal of $15.4 in contingency from the energy resources capital expense projections

not included in the environmental expense category, and removal of an additional

$2.4 million from the environmental capital expense projections.299 Consumers Energy

does not take issue with this delineation. It does argue, however, that modified expense

projections and contingency allowances should be adopted based on Ms. Hill’s rebuttal

testimony.

In her rebuttal testimony, Ms. Hill presented updated projections in Exhibit A-114:

To ensure the correct amount of contingency is identified in this case, the Company has updated the $18.5 million of contingency originally identified in response to Staff Audit Question #002. The updated contingency amount is reduced from $18.5 million to $14.2 million. See Exhibit A-114 (DMH-12).

* * *

The total contingency amount is less because the Company has now incurred actual costs for the period October 2016 through July 2017; contingency projections remain only for August and September in the “12 Months October 2016 – September 2017.” Energy Resources’ projected test year (October 1, 2017 through September 31, 2018) contingencies increased by approximately $1 million.300

In its initial brief, Staff addressed Ms. Hill’s testimony as follows, arguing that such

revisions should not be accepted in the rebuttal phase:

Company witness Danielle Hill attempted to update the Company’s contingency figures in her rebuttal testimony, claiming that contingency only remains for the test year (8 Tr 1091.) The Commission should not accept the updated contingency figures. Generally, if a utility updates

299 See Staff brief at pages 7-9. 300 See 8 Tr 1091.

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test-year figures during the course of a case, and if the updated figures are undisputed, it is not a problem. But if the updated figures are disputed or could potentially be disputed, it is unreasonable to expect Staff and Intervenors to continuously audit information as it is updated, particularly if the updated figures are not supported. The Commission cautioned against this very practice in In re Detroit Edison Co, MPSC Case No. U-15768. 1/11/10 Order, pp 23-28 when it rejected Detroit Edison’s attempt to revise its sales forecast based on updated inputs.

In this instance, the introduction of late evidence has not allowed Staff or other parties enough time to review and verify the costs for accuracy or audit them for reasonableness and prudence. If the Company would like Staff, Intervenors, and the Commission to rely on actual expenditures, it should consider filing its request based on a historic test year.301

In its reply brief, Consumers Energy responds:

The updated contingency expenditures were not “late,” but were provided during rebuttal and were separated into 17 distinct categories. Staff was free to submit audit or discovery requests regarding the updated amount. The updated contingency expenditures respond to and address Staff’s position that contingency costs “may not be incurred at all.” The Company provided evidence that, for the period October 2016 through July 2017, actual costs had replaced the contingency projections. Thus, if the Commission accepts Staff’s position and determines that contingency amounts should be excluded, the Commission should only exclude the remaining $14.2 million of Energy Resources contingency expenditures.302 This PFD finds that Staff has correctly analyzed the company’s request to use

updated contingency amounts in determining any contingency-related exclusions. The

company should not be able to use contingency, which the Commission has repeatedly

declined to include in rate base projections, as a placeholder to finalize its cost

projections in the rebuttal phase of the rate case. This PFD concludes that it is

appropriate to exclude the entire contingency amounts reflected in Staff’s analysis,

because the revised projections with and without contingency amounts could not be

301 See Staff brief, pages 12-13. 302 See Consumers Energy reply brief, page 36.

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audited or evaluated on this record. The company always has the ability to seek a

delay of the schedule to allow for the evaluation of new evidence.

5. Residential Demand Response

Mr. Warriner explained that as Consumers Energy nears completion of the AMI

meter installations, it has transferred responsibility for its residential demand response

program to the energy resources department.303 He explained that the Smart Grid/AMI

program retained responsibility for the Air Conditioning (AC) load control program

through 2017, while 2018 capital expense projections are included in Ms. Hill’s Exhibit

A-61. Ms. Hill explained that the company’s residential demand response program has

three components, an air conditioning load-control program and two time-of-use rate

options. Ms. Hill’s Exhibit A-61 contained projected expenditures for the test year

totaling $6.2 million, for “capital expenditures related to the purchase and installation of

load control switch devices that are installed on individual central air conditioning units

and all related costs.”304 Mr. Warriner’s Exhibit A-80 shows projected 2017

expenditures of $2 million.

This section discusses the disputes related to the residential demand response

program capital expense projections, while the accounting for the AC load control

switches and programmatic disputes relating to the company’s residential demand

response program are discussed in section VIII below, along with the company’s

request for regulatory asset treatment for its demand response costs.

Ms. Simpson recommended an $8.1 million reduction in the projected capital

expenditure for the AC cycling program. Citing the Commission’s order in Case No.

303 See 6 Tr 295-296. 304 See 8 Tr 1063.

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U-17990, she testified that the Commission linked the funding level of $4.9 million

approved in that case to 42 MW of demand response savings.305 Based on Staff’s

analysis that 1.12 kW of peak load savings can be expected from each installed switch,

she testified that based on the company’s projected enrollments, Staff does not expect

the company to reach the 42 MW of savings until May 2018, and Staff does not find the

company’s projected enrollment increases realistic. Therefore, she testified, Staff

recommends that expenditures be limited to the amount approved in Case No.

U-17990. She noted that the company has indicated that the approved amount was not

spent on AC switches, but she testified that the company has not explained by the

approved amount was not spent:

Staff believes that the Commission was very clear in its order for U-17990 that the money approved in both U-17735 and U-17990 was approved to provide the Company with a full 42 MW of demand response savings through the installation of AC switches used specifically for the AC Peak Power Savers® program.306 Mr. Warriner disputed Staff’s recommended capital expense reduction of

$8.1 million, testifying that the Commission should not cap investments in the AC

demand response program at 42 MW or 37,500 participants, citing Exhibit S-12.6 to

show that the company is targeting 61,700 participants by the end of 2018, 54,350 by

the end of the test year. He further testified that the company’s current projection is for

an additional 3,000 participants by the end of 2018. In contrast, he testified that the

$4.9 million approved in Case No. U-17990 only supports the installation of

18,476 switches through the test year, which ends August 2017, and argued that the

Commission did not intend to cap the program at 42 MW. He also took issue with

305 See 11 Tr 2444, citing the Commission’s February 28, 2017 order in Case No. U-17990, page 41. 306 See 11 Tr 2446.

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Staff’s calculated adjustment, testifying that Staff’s $8.1 million adjustment includes

September 2017 expense projections, and also ignores that the 37,500 level is

projected to be reached in May of 2018, as shown in Exhibit S-12.6.

Mr. Coppola also addressed the AC load program enrollment issue in the context

of O&M expenses, contending the company’s projected enrollment was overly

optimistic. Ms. Hill responded in her rebuttal testimony,

As of July 31, 2017, the Company has enrolled over 13 20,000 customers in the AC Peak Cycling Program based on a December 31, 2017 target of 26,700 customers. In other words, through July 31, 2017, the Company has achieved 75% of the total 2017 enrollments for the AC Peak Cycling Program.307

She also testified regarding the company’s residential demand response programs:

In 2017, the Company began to ramp-up enrollment and participation in the Company’s residential Demand Response programs and is planning to expand its programs from 48 MW by the end of 2017 to 344 MW by the end of 2021. To be successful in enrolling customers and meeting these committed goals, the Company requires the $5.9 million being requested in this case.308

In its brief, Staff acknowledges that the $4.892 million approved in Case No.

U-17990 was intended only to fund 18,476 switches, but argues that the total 42 MW

milestone included funding from Case No. U-17735 as well.309

Consumers Energy relies heavily on Mr. Warriner’s testimony and on the

following statement in Exhibit S-12.7, attempting to provide context to the details of the

company’s underspending:

The approved capital investment for AC Peak Cycling switches in Case No. U17335 was $5.186 million, which was projected to be incurred during the time period of 1/1/2015 through 5/31/2016. The actual capital expenditure from 1/1/2015 through 5/31/2016 totaled $0.554 million. As a

307 See 8 Tr 1094. 308 See 8 Tr 1095. 309 See Staff brief, page 40.

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result, the Company has reduced the gross plant balances form AMI switches from U-17735 to reflect the slower program customer enrollment ramp-up. In this case, the gross plant balance for AMI switches at the end of September 2016 is $0.839 million. The approved capital expenditure amount for AC Peak Cycling switches in U-17990 was $4.892 million, which was projected to be incurred during the time period of 1/1/2016 through 8/31/2017. In this case, the Company projects capital expenditures of $5.078 million from 1/1/2016 through 4/30/2017 of $2.499 million and projected capital expenditures from 5/1/2017 through 8/31/2017 of $2.579 million. In its order in Case No. U-17990, the Commission took note of the company’s

failure to fund the load control switches consistent with the Commission’s November 19,

2015 order in Case No. U-17735, but in view of the importance of the program, provided

additional funding, to be cumulative with the earlier funding:

The Commission approves projected capital expenditures of $4,892,000 for the DLA program. This approved amount is predicated on 20.69 megawatts (MW) of demand savings for customer installations through the test year ending August 31, 2017. This additional funding, combined with the 22 MW of demand savings from the amounts approved for Consumers’ DLA program in its last rate case, representing a fully funded commitment by the company of 42 MW of DR savings.310

In its brief, Staff emphasizes the Commission language “fully funded commitment.”

Consistent with Mr. Warriner’s rebuttal testimony, in responding to Staff’s argument,

Consumers Energy acknowledges the underspending in its reply brief, but refers to the

explanation in Exhibit S-12.7 quoted above:

Staff notes that the Commission’s February 28, 2017 Order in Case No. U-17990 stated that the funding approved in that case represented a fully funded commitment by the Company of 42 MW (or 37,500 switches) of Demand Response (“DR”) savings, and Staff’s recommended reduction in this proceeding is “because the Company did not adhere to the timing presented in U-27990 and has not yet met the 42 MW milestone.” Id. Company witness Lincoln D. Warriner pointed out that the $4.892 million approved by the Commission in Case No. U-17990 only supports the

310 See February 28, 2017 order, page 41.

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installation of 18,476 switches through August 2017. 6 TR 336. And, if Staff intended to limit the Company to the installation of 37,500 switches, then Staff should have supported expenditures through May 2018, which is when such installation amount is projected to occur. 6 TR 337. Staff responds that the 42 MW milestone is made up of the $4.892 million that the Commission approved in Case No. U-17990 plus the amount the Commission approved in Case No. U-17735, and that “[a]t such time that the Company meets the 42 MW milestone for which the Commission has granted funding, then the Company is encouraged to seek recovery of additional expenditures to expand the program beyond the already funded 42 MW.” Staff’s Initial Brief, pages 40-41. Staff’s position does not reflect the fact that, while the Commission approved capital expenditures in the amount of $5.186 million for load control switches in Case No. U-17735 for the period January 1, 2015 through May 31, 2016, total Company expenditures over that time period were only $0.554 million. Exhibit S-12.7, page 2. Thus, the Company reduced the gross plant balances for switches from that approved in Case No. U-17735 to reflect the slower program ramp-up, and in the instant proceeding has only included the gross plant balance for load control switches of $0.839 as of the end of September 2016. Exhibit S-12.7, page 2. Staff’s recommended reduction of expenditures is not reasonable considering the Company has removed from its gross plant balance most of the amount that was approved in Case No. U-17735. As shown in Exhibit S-12.6, the Company is targeting 61,700 AC Peak Cycling Program participants by the end of 2018, with 54,350 participants by the end of the test year (or September 2018). The Commission should approve the Company’s projected expenditures to support the Company’s continued efforts to implement a robust and beneficial residential DR program.311 The company’s response is troubling on multiple levels. Consumers Energy

does not dispute that the Commission approved expenditures of $5.2 million in Case

No. U-17735, of which the company spent $0.5 million, and that it approved

expenditures of an additional $4.9 million in Case No. U-17990, of which the company

had spent only approximately $2.5 million as of April 30, 2017, with only 4 months left in

the projection period, as shown in Exhibit S-12.7. The company even acknowledges

the Commission’s understanding that the company committed to 42 MW by the end of


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the 2016/2017 test year used in that case. It does not seem to be an adequate

response that the dollars not spent are not included in rate base. Indeed, in claiming

that it “removed from its gross plant balance most of the amount that was approved in

Case No. U-17735,” the company is confusing the projected rate base used to set rates

for a projected test year with its actual rate base: projected expenses should never

have been included in actual gross plant balances, so there should have been nothing

to remove. Ratepayers, of course, paid a return on the projected expenditures in those

cases and a measure of depreciation expense. Consumers Energy is clearly asking

that the ratepayers replace the initial funding when it argues, as also quoted above:

[I]f Staff intended to limit the Company to the installation of 37,500 switches, then Staff should have supported expenditures through May 2018, which is when such installation amount is projected to occur. 6 TR 337.312

In essence, Consumers Energy argues that there are no consequences for its failure to

meet programmatic commitments.

Staff is also correct that in Case No. U-17990, the Commission approved a

program that it expected to achieve a 42 MW peak-load reduction:

The Commission approves projected capital expenditures of $4,892,000 for the DLA program. This approved amount is predicated on 20.69 megawatts (MW) of demand savings for customer installations through the test year ending August 31, 2017. This additional funding, combined with the 22 MW of demand savings from the amounts approved for Consumers’ DLA program in its last rate case, represents a fully funded commitment by the company of 42 MW of DR savings. The Commission finds this goal reasonable and achievable and stresses that it is more concerned about the program’s cost effectiveness, and the demand savings actually being achieved and verified for capacity planning purposes, than about the particular technology used – whether DLA switches or smart thermostats – to reach these results. Similar to the approach for utility energy waste reduction programs, the Commission believes that the cost-effectiveness of new and existing DR efforts should


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be more transparent and guide decision making along with other variables such as the speed of deployment, short- and long-term impacts, customer receptivity, and balancing program offerings for different types of customers. 313 The Commission explained its reasons for opening a separate docket to consider

alternative regulatory approaches for demand response programs:

The testimony in this case highlighted Consumers’ challenges with technology testing and system deployment that delayed the initial schedule to implement the DLA installations. Although delays may occur during the design, testing, marketing, and customer enrollment phases, the Commission observes that traditional rate setting processes are not particularly conducive to dealing with changes in program design, spending, and timing. That is, the cost recovery approach through base rates is not sufficiently flexible to account for uncertainties that impact program spending and results. On the one hand, the Commission does not want to delay authorizing cost recovery until the programs are fully deployed; yet, the Commission is also cautious about approving investments in rate base when it is uncertain the demand reductions will materialize in the test year and beyond. Id. After reviewing the Commission’s order in Case No. U-17990, this PFD

concludes that it would be inconsistent with that order to fund an expansion of the

program provided for in that case. The Commission concluded that the 42 MW demand

reduction for the test year in that case was “reasonable and achievable,” and it was not

achieved. As noted above, Consumers Energy now projects it will achieve that level by

May 2018. The Commission also clearly expressed a concern to avoid funding levels of

demand reduction that would not materialize in the test year. Recognizing the

Consumers Energy projects expansion of its program beyond the 42 MW previously

funded, the company has not provided a solid evidentiary basis to conclude that it will

attain even the 42 MW of demand reduction in the test year it now projects will be

attained by May 2018. Based on this record, this PFD finds Staff’s recommendation the

313 See February 28, 2017 order, Case No. U-17990, pages 41-42.

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most reasonable and appropriate for ratemaking. The Commission also indicated in

Case No. U-17990 that it would consider the myriad challenges involved in expansion of

the program in connection with a separate docket.

6. Information Technology (IT)

Mr. Varvatos presented testimony in support of the company’s projected capital

expenditures in the IT category, as shown in Exhibit A-75, with project descriptions in

Exhibit A-76. Staff recommendations are discussed in section a below, while the

Attorney General’s recommendations are discussed in section b.

a. Staff recommendations (fleet handhelds and mobile security)

Staff witness Ms. Fromm recommended two reductions to the company’s

projected IT capital expenditures, in addition to removing projected contingency

allowances. First, she recommended that the Commission exclude $576,000 in

projected costs for “fleet handhelds,” devices to be provided to fleet mechanics. She

testified that when asked, the company could not specify what sort of devices would be

provided, and instead indicated that evaluations were ongoing. She presented the

response in Exhibit S-13.4.314 Second, she recommended that the Commission

exclude $327,000 in projected costs for “mobile security,” to protect mobile assets from

cyber-security threats. Citing Exhibit A-76 and Exhibit S-13.4, she testified that the

company had not yet determined the solution.315 She found both projections

314 See 11 Tr 2360; see Exhibit S-13.4 (“A handheld device recommendation will be brought forward at the end of the evaluation period.”) 315 See 11 Tr 2361; see Exhibit S-13.4 (“As with most projects, the business need is identified and the project is proposed and estimated without having the specific solution selected. Solution specification and final selection is part of the planning phase. . . An estimate at this stage is expected to be refined as the project progresses.”)

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unsupported, explaining that Staff could not assess the reasonableness of the

projections or the likelihood of the money being spent.

In his rebuttal testimony, Mr. Varvatos acknowledged that type of handheld

device being provided to Fleet Mechanics had not been selected when Staff inquired,

but he objected that Staff “did not ask the Company the basis for the project’s estimated

costs.” He testified:

Although the specific type of handheld device had not yet been determined . . . to estimate the cost of the handhelds, the Company used the cost of a Toughpad handheld computer, which is the type of handheld used by the Company’s Electric and Gas Distribution field employees. Because the Toughpad is a standard handheld device within the Company, the Company believes a project estimate based on the Toughpad unit cost to be very reasonable and accurate to support allowance of the Fleet Handhelds in the Company’s IT capital plan. In addition, the Fleet organization is again looking at the Toughpads as the favored option.316 Regarding the mobile security project, he testified:

[T]he Company uses an IT Project Delivery Process based on best practices and industry standard methodologies. As part of the IT Project Delivery Process, procurement decisions for new technology solutions are finalized at the end of the Plan phase, along with refinement of the project budget and schedule. The Plan phase is largely O&M expense, and is the second phase of a project, coming after Origination, and preceding the Define, Execute and Close phases. Importantly, at the end of the Plan phase, the project passes through a Plan Phase Gate check, which would include a comparison of the capital funding requirements to proceed with the original estimate, to determine if the project should continue. Although highly unlikely to be canceled at this Plan Phase Gate, due to the comprehensive project work done to that point in the Origination and Plan phases, the Plan Phase Gate provides a cost control step in the project process, before the capital funds are expended.317

316 See 9 Tr 1658. 317 See 9 Tr 1658-1659.

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He further testified that because Staff does not object to the purpose of the

expenditures, and the handhelds and security must cost something, the Commission

should provide funding at the requested level:

The Company should be assured it has the authorization to recovery capital fund to address projects deemed necessary, so it can invest the required time and resources in the essential Plan phase. Thus, the Company should be approved to proceed with its Mobile Security and Fleet Handheld projects and permitted to utilize its management processes to effectively manage scope and cost of those projects.318 Consumers Energy relies on this testimony in its brief.319 Staff addressed

Mr. Varvatos’s rebuttal testimony in its initial brief, arguing that the company’s projection

provides an insufficient opportunity for Staff to review the handheld device selection or

cost, and that even if the mobile security project is not likely to be canceled, the costs

are unsupported.320 Staff further argues that acknowledging the need for a project is not

an admission that the project expenditures are reasonable and prudent.321

In its reply brief, Consumers Energy inexplicably argues that Staff has changed

the basis for its objection to the capital expense projection for the mobile handheld

devices: “While Staff originally stated that its rationale for disallowance was the lack of

an identifiable ‘specific device’ in the Company’s projected expenditures, in its Initial

Brief, Staff adopted the rationale that, “[a]lthough the projected cost may be based on a

specific device, the Company has not said with certainty that this is the device it will

choose. Although this is a new argument and, thus, one to which the Company has not

had an opportunity to fully respond, the Company respectfully disagrees.” It argues that

because the Toughpad is already widely used by the company, any projection based on

318 See 9 Tr 1659-1660. 319 See Consumers Energy brief, page 55. 320 See Staff brief, pages 14-17. 321 See Staff brief, page 17.

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the Toughpad must be reasonable, without regard to whether the company will actually

purchase the Toughpad.322

Regarding the mobile security projection, Consumers Energy also inexplicably

argues that:

Staff abandoned its original position that the lack of an identified solution for cyber security threats was the basis for its proposed disallowance and instead, adopted the explanation that the Company does not explain why the Company should recover the capital expenditures for this specific project.323

Consumers Energy also label as “new” the argument in Staff’s brief that the company

has not shown that the projected costs will not change.324 The company goes on to

argue that Staff’s objection to the uncertainty in the company’s cost estimate “is

inconsistent with the statute and should not be accepted as a proper basis for

disallowance.”325

This PFD finds that the company has failed to adequately support its projected

expenditures. Because it does not have more well-defined purchase plans, its expense

projections cannot be adequately reviewed, and the likelihood of the expenditures

taking place in the test year is questionable. In response to the concerns Mr. Varvatos

expressed in his rebuttal testimony, if the company proceeds with these projections, it

should take comfort from the general level of Staff support expressed in this case.

There is, moreover, no impediment to the company utilizing its management process to

effectively manage the scope and cost of those projects, for presentation in a future

case.

322 See Consumers Energy reply brief, pages 37-38. 323 See Consumers Energy reply brief at page 39. 324 Id. 325 See Consumers Energy reply brief, pages 39-40.

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This PFD also finds that Staff has in no way changed the basis of its objections

to the projected expenditures for these projects, but merely took the opportunity in its

brief to explain why Mr. Varvatos’s rebuttal testimony did not resolve Staff’s concerns.

Moreover, it is also inconceivable given the uncertainty the company acknowledges in

its own projection, and its documented history of not making capital investments

consistent with its rate case projections, that the Staff’s rejection of these expense items

violates MCL 460.6a.

b. Attorney General Recommendations

Mr. Coppola also recommended two adjustments to projected IT capital

spending, focusing on the projected $8.9 million for web design for what Consumers

Energy labels the Digital Customer Experience (or DCE). After reviewing the

company’s expenditures for its website redesign and replacement projects, Mr. Coppola

testified that the total projected expenditure from 2012 through 2017 is $65.9 million,

with $8.9 million projected for 2017. He characterized this as a series of projects “that

seems to have gone amok with features that most customers are not likely to use.”326

Citing Exhibits A-78 and AG-19, he testified that the company’s benefit/cost analysis

shows a negative value from the projected expenditures, and recommended disallowing

the $8.9 million projected for 2017.

Mr. Varvatos testified in rebuttal that the company has revised its plans and

reduced its capital projection for the DCE to $7.2 million, including $1.7 million

transferred to the SAP platform and $4.1 million transferred into 2018, leaving

$4.1 million to be spent on the DCE website replacement in 2017.327 Consumers

326 See 12 Tr 2569. 327 See 9 Tr 1669-1670, and Consumers Energy brief, pages 61-62.

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Energy includes this adjustment in Attachment B to its brief. Neither the Attorney

General nor any other party has expressly objected to the revised spending plan, so this

PFD finds the adjustment should be reflected in rates.

Second, Mr. Coppola recommended an adjustment to the projected expenditure

for the replacement of the company’s document storage system, Lotus Notes. Citing

Exhibit AG-20, he testified that the project had projected costs in excess of benefits, and

recommended removing the $2.1 million in costs associated with the later phases of the

project that fall within the projected test year.328 Mr. Varvatos testified in rebuttal to the

company-wide value of Lotus Notes and the corresponding need for the replacement:

The use of the now unsupported Lotus Notes and newer SharePoint platforms extends beyond “document storage and retrieval system with various bells and whistles,” as inaccurately characterized by Mr. Coppola on page 73, lines 4 and 5, of his testimony. The Lotus Notes system received high utilization across the company for daily tasks across a wide variety of departments and employees. The scope of the Lotus Notes project deals with migrations of complex, custom applications built over time not only by the IT department, but also non-IT employees residing in the business areas. The number of applications and databases reviewed for the migration was approximately 1700 applications, and 1850 document repositories. 414 applications and 790 document repositories have been migrated. The varied and complex nature of these applications has meant that developers working on the project need to understand the customizations, gather requirements, determine the best solution, and develop and test the applications on the new platform. In addition, Lotus Notes had functionality that was no longer relevant and needed to be researched and addressed as part of the migration. Likewise, the functionality included increased security management, workflow management, and the implementation of additional functional requirements when applicable. Without completion of the Wave 3 and 4 projects, key business applications such as Building Access Requests, Miss Dig Alerts, and Confidential Information Authorization Requests will remain at operational risk on the unsupported Lotus Notes platform.329

328 See 12 Tr 2571-2572. 329 See 9 Tr 1670-1671.

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Neither the Attorney General nor any other party challenged Mr. Varvatos’s testimony.

This PFD concludes that it is reasonable to accept the company’s projected expenditure

for the Lotus Notes replacement project.

c. Contingency

Staff excluded contingency expenses from this category totaling approximately

$3.2 million, as Ms. Fromm explained.330 No party took issue with her identification of

the amount of contingency expense, and this PFD finds that her adjustment should be

adopted for the reasons set forth in section 1 above.

7. Land Donation

It appears that Staff and Consumers Energy agree on the proper ratemaking

treatment of a land donation Consumers Energy made as part of a consent decree

entered in the U.S. District Court for the Eastern District of Michigan. As Mr. Nichols

testified, and as shown in Exhibit S-10.1, and in Appendix E to Staff’s brief, rate base

should be reduced by $160,780 to reflect the consent decree.331 Consumers Energy

does not address this directly in its briefs.

8. METC easement

It appears that Staff and Consumers Energy agree on the proper treatment of

settlement agreement approved by the Federal Energy Regulatory Commission (FERC)

resolving a dispute between the Michigan Electric Transmission Company (METC) and

Consumers Energy over the classification of certain assets.

In its brief, Consumers Energy argues:

FERC jurisdictional rates are based on historical data, and as such the modified Attachment O inputs are not expected to be reflected in FERC

330 See 11 Tr 2359; also see Exhibit S-13.2. 331 See 11 Tr 2400; Staff brief, page 58.

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rates until June 1, 2019. 6 TR 582. In order to address any negative customer impact that may result from this regulatory lag, the Company proposes to include a reduction in its PSCR Reconciliation proceedings in the same amount by which the Company’s transmission rates are expected to be reduced once the modified Attachment O is reflected in FERC rates. 6 TR 583. For example, in 2018, if the increased distribution revenue requirement is in effect for nine months as proposed in this proceeding (effective upon final order in this proceeding, April through December), the Company will reduce the PSCR expense in the 2018 PSCR Reconciliation by 9/12 of the annual amount by which the Company’s transmission rates are expected to be reduced. The Company is proposing to calculate the reduction in PSCR expense as of the effective date of the final order in this proceeding because that is when the impact of removing the assets, expense, and rent will first be reflected in Consumers Energy’s retail rates. See 6 TR 583. Consumers Energy did not include the impact of removing the assets, expense, and rent in its originally filed revenue requirement in this proceeding, and such impact is not reflected in the Company’s self-implementation rates. See 6 TR 572. The Company will perform the same adjustment in the 2019 PSCR Reconciliation for the portion of 2019 that does not have the modified Attachment O inputs reflected in FERC rates. Once the modified Attachment O becomes reflected in FERC rates, the Company will discontinue the PSCR adjustment. 6 TR 583.332

In its initial brief, Staff presented the same resolution:

Staff agrees with the Company, and has reduced distribution plant by $70,000,000, depreciation expense by $300,000, property tax by $800,000, and offsetting revenue by $9,300,000, as Mr. Harry proposed in Exhibit A-108 (DLH-8). (Appendices C and E.) Per the FERC order, these items are to be reflected in the Attachment O going forward. Lastly, the Company’s proposal to hold ratepayers harmless by adjusting the PSCR until the FERC formula rate takes effect is reasonable and should be approved.333

No party appears to have objected, therefore this PFD recommends that the

Commission adopt the identified ratemaking treatment for the transferred assets.

9. Property Model Error

As Mr. Nichols explained in his testimony, Staff’s audit revealed errors in the

company’s property model that the company subsequently corrected as shown in 332 See Consumers Energy brief, page 189. 333 See Staff brief, page 60.

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Exhibit S-10.2 and Exhibit A-129. This error affected the determination of plant in

service, the accumulated provision for depreciation, depreciation expense, as well as

property tax.334 In its brief, Staff cites Exhibit S-10.2, and Appendix E to its brief, in

indicating that the appropriate adjustment is a reduction in rate base of $14.4 million, a

reduction of $282,000 in depreciation expense, and a reduction in property tax expense

by $76,000.335 Consumers Energy also cites Exhibit S-10.2 in showing the revisions in

Appendices B and C to its brief.

B. Accumulated Provision for Depreciation (property model error)

As discussed above, Staff and Consumers Energy agree on the appropriate

revisions to the depreciation reserve to correct an error in the company’s property

model. 336 The only remaining differences among the parties relating to the accumulated

provision for depreciation and amortization are attributable to different recommended

projected capital additions for the test year.

C. Working Capital

Ms. Myers presented the company’s projected test year working capital

allowance as shown in Exhibit A-7, incorporating the recommendations of Mr. Denato to

increase the cash balance. Mr. Coppola recommended two adjustments to Consumers

Energy’s projected test year working capital balance. First, he recommended against

the increase in cash balances, and he recommended an increase in the accrued

interest component. These two components of working capital are discussed in

sections 1 and 2 below.

334 See Myers, 7 Tr 795; Exhibit A-129 and A-131. 335 See Staff brief, page 58. 336 See Myers, 7 Tr 795, Exhibits A-129 and A-131, Consumers Energy brief, page 78, and Appendix B.

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1. Cash Balances

Mr. Denato recommended an increase of $24 million in the cash balance

component of working capital. He testified that Consumers Energy “plans to hold an

average cash balance (excluding temporary cash investments) of $44 million,” although

$20 million is included in the thirteen-month average for the 13 months ending

November 30, 2016.337 In support of the increase in cash balance, Mr. Denato testified

that Consumers Energy believes it should hold an average cash balance of 2% of

revenues. He acknowledged that in the past, the company held a significant portion of

this 2% in temporary cash investment accounts, but has reconsidered this in light of the

Commission’s order in Case No. U-17735 excluding temporary cash investments from

the company’s working capital allowance. He testified that the company now intends to

hold 1% of its revenues in ordinary cash accounts,338 and further explained:

I began with the actual cash balance (excluding temporary cash investments) as of December 31, 2016. Based on historical trends and taking into account short-term financing projections, I projected the monthly ending cash balances from January 2017 through the test year ending September 2018. This is shown on Exhibit A-9 (AJD-7), Schedule D-6. The projected average cash balance for the test year ending September 2018 is $44 million.339 Mr. Coppola objected to the increase, testifying that the company had not

presented an operational justification for the increase.340 He testified that both Staff and

the Attorney General had explained in prior cases that it is not desirable for the

company to hold large cash balances, characterizing it as costly for customers and

unnecessary given the company’s multiple lines of short-term credit. He also testified


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that DTE Electric includes only $12.9 million in its working capital or 0.3% of its

revenues.

In his rebuttal testimony, Mr. Denato listed what he characterized as legitimate

business reasons supporting the level of cash included in its working capital allowance,

including: the seasonality of cash flows; the issuance of refinancing bonds several

months in advance of the maturity of the existing bonds; and liquidity needs both day-to-

day and in the event of difficulty accessing the capital markets for long-term

financing.341 He cited, and Consumers Energy cites in its brief, recent cases in which

the Commission had rejected reductions to the company’s cash balances.342 As

Consumers Energy argues in its reply brief, the Attorney General has not addressed

Mr. Denato’s rebuttal testimony in his brief.343 This PFD recommends that the

Commission accept the projected cash balances.

2. Accrued Interest

Mr. Coppola also recommended a reduction in working capital to reflect that the

company is issuing significant amounts of long-term debt:

The increase in long term debt from the end of 2016 to the end of the projected test year is $700 million or 12%. It is logical that more long term debt leads to more interest expense and more Accrued Interest. The higher level of accrued Interest reduces working capital since this item is a liability and a source of funds.344

Ms. Myers testified in rebuttal and presented Exhibit A-134 to show there has been no

correlation historically between long-term debt and accrued interest.345 The Attorney

General does not address this rebuttal exhibit in his brief, nor does any other party. On

341 See 9 Tr 1382-1283. 342 See Consumers Energy brief, pages 80-82, citing Case Nos. U-17990 and U-18124. 343 See Consumers Energy reply brief, page 47. 344 See 12 Tr 2577-2578. 345 See 7 Tr 787-788.

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this basis, this PDF recommends that the Commission accept the accrued interest

balance in the company’s projected working capital.

D. Rate Base Summary

As shown in Attachment B, this PFD estimates that the recommendations

discussed above result in a projected jurisdictional rate base of $10,203,659,000.

VI.

COST OF CAPITAL

The principle disputes among the parties involve the appropriate capital structure

to use in determining the overall cost of capital and the authorized return on equity.

While Staff took issue with the cost of long-term debt presented in the company’s direct

case, Consumers Energy subsequently revised its long-term debt cost rates to match

Staff’s recommendation. The disputes regarding the appropriate capital structure are

discussed in section A below, while the return on equity recommendations are

discussed in section B below, with a review of the other cost rates and calculation of the

overall cost of capital in section C.

A. Capital Structure

In its order in Case No. U-17990, the Commission explained its concerns with

Consumers Energy’s capital structure:

The Commission desires to arrive at an optimized capital structure that is both supportive of planned infrastructure investments, yet is not unnecessarily burdensome on ratepayers. The Commission also anticipates that a cycle of heavier-than-usual investment will present an ideal opportunity to rebalance Consumers’ capital structure to reach its 50/50 goal. In the next rate case, the Commission expects that Consumers will have arrived at, or will present a strategy to return to, a balanced structure within the five-year infrastructure plan time period. If Consumers is unable to do so, a more complete analysis should be

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included to explain why such a result is reasonable and prudent. For example, a pro-forma debt capacity analysis using rating agency methodology ratio benchmarks could be included to bolster the company’s arguments.346

After the filing of this case, addressing the company’s capital structure in its gas rate

case, the Commission reiterated its expectation that the Company achieve a 50% equity

ratio:

The Commission adopts the findings and recommendations of the ALJ. However, the Commission notes that Consumers’ proposed capital structure comprised of 53.1% equity to 46.89% debt represents a departure from its stated objective of a roughly balanced capital structure. . . .

The Commission cannot overemphasize the company’s responsibility to rebalance its equity and debt capital. . . . Although the Commission adopts the ALJ’s recommendation of a common equity balance of $6.320 billion, or 53.10% of the company’s permanent capital structure, Consumers shall, in its next rate case, articulate its strategy to return to a balanced capital structure and the steps it intends to take to reach its stated goal, or the Commission will have to consider using its regulatory authority to rebalance Consumers’ capital structure. 347

Consumers Energy initially requested a capital structure with an equity ratio of

52.91% of permanent capital, and a corresponding debt ratio of 46.8%, with 0.30%

preferred stock. Mr. Denato identified the projected debt issuances, retained earnings,

and equity infusions used to adjust the December 31, 2016 test year balances to derive

this projected capital structure. Mr. Denato acknowledged that in its last electric rate

case order for the company, the Commission expressed its expectation that Consumers

Energy would achieve a balanced capital structure or present a strategy to return to a

balanced structure within the five-year infrastructure plan time period. He testified that it

346 See February 28, 2017 order in Case No. U-17990, page 64. (Emphasis added) 347 See July 31, 2017 order in Case No. U-18124, pages 45-46. (Emphasis added)

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is reasonable and prudent for the company to maintain an equity ratio “slightly higher

than” 50%:

The Company is making significant capital investments over the next five years to maintain and improve utility infrastructure. The common equity balance and equity ratio projected for the test year in this case enables the Company to maintain strong credit ratings and better withstand any shocks in the financial markets, thereby ensuring a smooth implementation of its capital expenditure program. This also enables the Company to prefund its debt maturities to take advantage of low interest rates without jeopardizing the financial ratios. Another reason that the equity ratio proposed in this case is justified relates to how rating agencies view the Company’s equity ratio. Certain credit rating agencies (e.g. Moody’s Investors Service (“Moody’s”)) include securitization debt when calculating debt to equity ratios. Certain credit rating agencies (e.g. Standard and Poor’s (“S&P”)) also consider items such as Power Purchase Agreements (“PPAs”), benefit obligations, and lease as “debt” when calculating debt to equity ratios. Incorporating the projected equity infusion in 2017 and 2018 in the common equity balance enables the Company to maintain reasonable ratios after such adjustments. The Commission recognized that these circumstances support the need for a slightly higher equity ratio in Case No. U-17735. Any reduction to the Company’s equity ratio would weaken Consumers energy’s credit metrics, increasing the risk of a credit downgrade or a deterioration in credit ratings outlook.348

Referencing the peer group selected by Mr. Maddipati in his return on equity analysis,

Mr. Denato testified that they have a comparable equity ratio to Consumers Energy

before rating agency adjustments, but after the S&P adjustments, the average equity

ratio for the peer group is 46.3% compared to 43.3% for Consumers Energy, as shown

in Exhibit A-49.349 He testified that this comparison warrants an unadjusted equity ratio

of 55.6%, but he is proposing a ratio of 52.91% to balance “capital investment plans,

348 See 9 Tr 1340. 349 See 9 Tr 1341.

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credit metrics, and customer rate impacts,” and is consistent with recent rate case

results.350 Going forward, Mr. Denato testified:

Over the next five to ten years, as the term of some of the company’s sizeable PPA’s expire, the rating agencies’ adjusted equity ratios could improve. In addition, as the Company’s significant capital investment program decelerates to more normal levels, the need for an equity ratio slightly higher than 50% will be less critical.351 ABATE and the Attorney General objected to the company’s projected capital

structure. Ms. LaConte testified that a capital structure with 52.1% equity and 47.6%

debt is a more appropriate capital structure for the company, consistent with her proxy

group averages, and with the Commission’s instructions. After reviewing the

Commission’s February 28, 2017 order in Case No. U-17990, she testified that common

equity ratio the company proposes in this case is slightly higher than the 52.87% equity

ratio approved in that case and is otherwise too high:

It can maintain its strong credit ratings and implement its capital expenditure program with a lower equity ratio, while at the same time taking advantage of low interest rates. A higher common equity ratio will increase costs to ratepayers because equity is more expensive than debt.

* * *

Consumers’ proposed capital structure is not moving towards a more balanced, 50/50 debt-to-equity ratio as previously ordered by the Commission. Instead, Consumers is proposing a higher equity ratio. This proposal is moving in the wrong direction to achieve the Commission’s goal.352

She testified that her recommended proxy group equity ratio of 52.1% will result in a

lower cost of capital for ratepayers while allowing the utility to maintain its strong credit

ratings and implement its capital expenditure program.

350 See 9 Tr 1341. 351 See 9 Tr 1341. 352 See 12 Tr 2274-2776.

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Mr. Coppola similarly objected to the increased equity ratio in the company’s

projected capital structure compared to the capital structure adopted in the February 28,

2017 order. He recommended an equity ratio of 50%, explaining:

Most of the items raised by Mr. Denato to justify a higher common equity ratio are not unique to Consumers Energy or are insignificant. For example, the Company’s lease obligations of $99 million at June 30, 2017 are insignificant in a total permanent capital structure of $12.6 billion (less than 0.8% and shrinking each year). Power purchase agreements are not unique to the Company. Most electric utilities have power purchase agreements with power suppliers. The Company also has not been able to quantify the obligations under the purchase power agreements or how rating agencies specifically take them into consideration. . . . . [A 50%] equity ratio is consistent with the common equity level of the peer group used to evaluate the cost of the common equity. It is critical to align the capital structure with the calculation of the cost of common equity because investors take the level of debt in the capital structure into account when evaluating the stock price they are willing to pay. Less debt and more equity reduces financial risk. Therefore, calculating a peer group cost of equity at a higher level than the Company has in its capital structure would overstate the cost of equity rate.353

He also testified that the financial transactions between Consumers Energy and its

parent corporation cannot be ignored, because CMS Energy controls the utility’s capital

structure.354 He reviewed changes in the utility and parent capital structure from 2006

to 2016, and presented a chart showing the significant difference in equity ratios for the

two companies, concluding:

My analysis clearly shows that CMS is using a form of double leverage by using debt capital to make its equity infusions into Consumers Energy, Although a strong argument could be made that the common equity capital of the Company should be less than 50% given the evidence I have presented, the Commission certainly should not permit a capital structure with common equity capital above 50%.355

353 See 12 Tr 2580-2581. 354 See 12 Tr 2582. 355 See 12 Tr 2585.

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Mr. Coppola testified that excluding a company that only recently issued equity capital

(Dominion Resources) from his proxy group, the average equity ratio is 49%, and

explained the significance as follows:

The cost of equity for those companies in the peer group is highly dependent on the financial risk reflected in their capital structure. Thus, it is critical to synchronize the capital structure of the Company to peer group average as closely as possible in order to have consistency with the cost of equity capital derived from those peer group companies. The Company’s proposed equity capital ratio of nearly 53% creates a disconnect that is not acceptable and is also more costly to customers.356 In his rebuttal testimony, Mr. Denato asserted that the company had complied

with the Commission’s order in Case No. U-17990 by presenting extensive new

quantitative evidence and rationale in direct testimony why it is necessary to maintain

an equity ratio slightly higher than 50%. He testified that the company does plan to

reach a balanced capital structure in the future, again citing the expected expiration of

sizeable PPAs including the then-pending Palisades early termination and securitization

application in Case No. U-18250, resulting in an equity ratio of 52.64%:

The Company has taken a substantial step in this current case with a recommended common equity ratio of 52.64%, 46 basis points lower than the equity ratio of 53.1% approved in Case No. U-18124. This reduction reflects the expected termination of the Palisades PPA during of the second half of the test year of this case.357

He also testified that the company had changed its projected equity infusions, and he

presented a five-year plan showing a gradual reduction in equity infusions and a

decrease in the equity ratio from 52.5% in 2018 to 50% in 2023.358 The capital structure

with the 52.64% equity ratio and the company’s debt and equity costs is presented in

his Exhibit A-106. 356 See 12 Tr 2586. 357 See 9 Tr 1378. 358 See 9 Tr 1378-1379.

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Mr. Denato also specifically addressed Mr. Coppola’s analysis of the impact of

CMS Energy’s capital structure, testifying that the timing and amounts of long-term debt

and equity issued by CMS Energy have no bearing on the timing and amount of equity

infusions made into Consumers Energy.359 He also disputed that the lower average

equity ratio in Mr. Coppola’s proxy group is relevant to a determination of the

appropriate capital structure for Consumers Energy, referencing his Exhibit A-49 to

show the effect of different treatment of cost elements of the capital structure on a

ratemaking versus a financial basis.360

Addressing Ms. LaConte’s recommendations in his rebuttal testimony, he

asserted that she had not provided details or analysis to support her conclusion that the

company would maintain its credit ratings with a lower equity ratio. He also noted that

her recommended equity percentage of 52.1%, is very similar to the proxy group

average for the proxy group selected by Mr. Maddipati, but further asserted it would not

be sound ratemaking to rely solely on the capital structure of other utilities.361

In its brief, Consumers Energy urges the Commission to adopt its revised capital

structure with an equity ratio of 52.64%.362 It argues that, in light of the Commission’s

July 31, 2017 decision in Case No. U-18124, “Consumers Energy has accelerated its

efforts to formalize and implement a strategy for rebalancing its equity ratio.”363 The

company does not cite the company’s decision not to terminate the Palisades PPA

early, following the Commission’s September 22, 2017 decision in that case.

359 See 9 Tr 1379-1380. 360 See 9 Tr 1381, 1384. 361 See 9 Tr 1384. 362 See Consumers Energy brief, pages 85-87, 89-96. 363 See Consumers Energy brief, page 86

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Staff recommends that the Commission adopt the capital structure recommended

by Consumers Energy.364 In its reply brief, it argues:

Staff has adopted the Company’s position on the common equity balance, which will reduce its forecasted common equity ratio to 52.64%. . . . This puts the Company on track “to be back to a common equity ratio of about 50% by the end of the five-year period contemplated by the Commission” in recent orders.365 The Attorney General and ABATE/Gerdau each urge the Commission to reduce

the equity percentage in the capital structure in accordance with the testimony of their

witness.366 They both cite the Commission’s recent order in Case No. U-17990.

MEC/NRDC/SC, in their reply brief, endorse ABATE’s recommendations, arguing that

the Commission should adopt a capital structure with a 52.1% equity ratio. They argue

that the company’s failure to address the Commission’s February 28, 2017 order in

Case No. U-17990 is inexcusable.367 They further argue that the Commission has not

authorized the company to retain an equity-heavy capital structure for the next five

years without further justification, contending that Consumers Energy did not take

advantage of the opportunity the Commission provided for the company to present

further analysis:

The Company explains that its proposal to reduce equity infusions by $100 million per year is to achieve balance after five years. In other words, the strategy is to take the smallest annual steps possible to achieve balance after five years. There is no explanation or support for why $100 million per year equity infusion reductions are acceptable to the Company or rating agencies, but larger reductions over fewer years would be unacceptable. In support of the Company’s original proposed 52.91% equity ratio, Mr. Denato testified that “[a]ny reduction to the Company’s equity ratio would weaken Consumers Energy’s credit metrics, increasing the risk of a credit downgrade or a deterioration in credit ratings outlook.”

364 See Staff initial brief, page 66. 365 See Staff reply brief, page 2, quoting Consumers Energy’s brief at page 91. 366 See Attorney General initial brief, pages 37-39; see ABATE/Gerdau initial brief, pages 6-7. 367 See MEC/NRDC/SC reply brief, page 19.

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And yet, the Company has proposed six annual $100 million equity infusion reductions to reduce the equity ratio, and such financial consequences have not apparently materialized. There is no basis upon which the Commission may conclude that more significant reductions would cause such consequences, either.368

In a footnote, MEC/NRDC/SC note that Mr. Denato’s initial testimony referred to a five-

to-ten-year period over which rating agency adjusted equity ratios could improve, while

in his rebuttal testimony, he referenced only a five-year period.369

This PFD concludes that the company’s revised capital structure comports with

the Commission’s expectations as articulated in Case No. U-17990, and recommends

that the Commission defer consideration of a hypothetical capital structure to future rate

cases. At least in its rebuttal testimony, the company did state a plan to return to a

balanced capital structure over an approximately-five-year period.370 And the company

reduced the equity percentage in its capital structure below the level approved in Case

No. U-17990, as well as below the level approved in Case No. U-18124.

Nonetheless, two caveats are appropriate regarding the company’s stated

rationale for its gradual reduction in its equity ratio. First, as noted above, Consumers

Energy in its brief does not tie the company’s projected equity ratio in this case to the

early termination of the Palisades PPA. However, in his testimony, Mr. Denato testified

that Company’s reduced recommended equity ratio of 52.64% “reflects the expected

termination of the Palisades PPA during the second half of the test year of this case.”

371 Moreover, on cross examination Mr. Denato recognized that termination might not

occur: “I mean, for example, you know, Palisades, when we put this plan together, we

368 See MEC/NRDC/SC reply brief, page 22, citing Denato testimony at 9 Tr 1378 and 1340 with emphasis added (citations omitted). 369 See MEC/NRDC/SC reply brief, pages 21-22 at n 82, citing 9 Tr 1341, 9 Tr 1378. 370 See 9 Tr 1378-1379. 371 See 9 TR 1378.

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had Palisades terminating, you know, in 2018, and now it doesn’t look like that’s going

to happen.”372 In addition, Mr. Denato was equivocal regarding the company’s

commitment to the reduced equity infusion:

Q. Is it possible that the timing and amount of these equity ratio reductions could change? A. Yes. Significant changes in utility capital investments or PPA obligations could change the extent and timing of the Company’s planned equity ratio reductions.373 Second, as the discussion above shows, Mr. Denato focused heavily on the

rating agency calculations of debt and equity ratios as the basis for the company’s

current plan to reduce its reliance on power purchase agreements and increase its

reliance on generation assets over the next five years.374 However, the rating agencies’

designation of PPAs and securitized costs as debt seem relatively artificial and

detached from any consideration of the risk involved.375 For example, the securitization

under 2001 PA 141 comes with a commitment from the Commission that ratepayers will

repay the costs, and PPA costs are recovered by the utility through the PSCR process,

including the provisions of MCL 460.6j(13). On the other hand, as Mr. Maddipati

testified: “Generation assets carry greater risk, both operationally and financially, and

therefore companies without meaningful generation assets are not good comparisons to

Consumers Energy’s electric business.”376 It is difficult to believe that lenders or

investors are more interested in the technical debt ratios constructed by the rating

372 See 9 TR 1401-1402 (Emphasis added) 373 See 9 TR 1379. 374 See 9 Tr 1402-1403. 375 Note, too, that the equity ratios presented in his Exhibit A-49 reflect companies that Mr. Maddipati has chosen using as one of the criterion that they have substantial generation assets, so they may not have a representative component of PPAs relative to all electric utilities. Consumers Energy’s proxy group is discussed below in connection with the cost of equity. 376 See 10 Tr 1761; also see 10 Tr 1796, 1803.

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agencies than with the overall riskiness of the utility. Nonetheless, since Mr. Maddipati

has indicated that the additional risks associated with generation may require a higher

return on equity, it is not clear that the company’s strategy is well-considered to

minimize the cost of capital.

For these reasons, given the uncertainty Mr. Denato expressed and given the

potential risks associated with the company’s strategy, this PFD recommends that the

Commission require further analysis of the company’s plans to reduce its capital

structure in its next rate case, or in its IRP, to ensure that it is not making decisions

likely to increase its overall cost of capital, all else equal. This PFD recognizes that the

Commission will also evaluate the company’s capital structure in its pending gas rate

case in accordance with the instructions the Commission gave in Case No. U-18124

quoted above. Nonetheless, since the motivation for the company’s plan seems to

involve primarily electric utility operations, its focus on PPAs and securitization as debt

and its plans to increase reliance on generation, it is reasonable for the Commission to

expect a thorough analysis in the company’s next electric rate case.

B. Cost of Equity

As noted above, Consumers Energy is requesting an authorized return on

common equity (or ROE) of 10.50%. This represents a 40-basis point increase over its

current authorized ROE of 10.10% set by the Commission in its February 28, 2017

Order in U-17990. The Company also argues that if the return is to be set lower than the

Company’s recommended 10.50%, then it should be set no lower than the currently

authorized level of 10.10%.

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Staff argues that the ROE should be set at 9.80% based on an ROE range of 9%

to 10%. The Attorney General proposes an allowed ROE of 9.75%, within a range of

9.50% to 9.75%. ABATE/Gerdau recommend an ROE of 8.60% within a range of

7.40% to 9.70%. Walmart does not make a specific recommendation but asks the

Commission to consider customer impact and the information presented by Mr. Tillman

in his testimony. In their reply brief, MEC/NRDC/SC argue that the Commission should

accept ABATE’s recommended return on equity of 8.60%.

Witnesses for Consumers Energy, Staff, the Attorney General, and ABATE

testifying on the appropriate rate of return on equity each employed a variety of models

using groups of proxy companies chosen to be comparable to Consumers Energy. The

analysts make their final recommendations by reviewing the range of costs produced by

the models along with other information including rates of return authorized by other

state commissions, the analysts’ views of the relative riskiness of Consumers in

comparison to the proxy companies, and other factors they identify.

In the discussion that follows, the quantitative analyses presented by Consumers

Energy, Staff, the Attorney General, and ABATE are reviewed, beginning with the

selection of the proxy group in section 1, then turning in section 2 to the flotation cost

adjustment that is incorporated in Mr. Maddipati’s quantitative analyses, with the DCF,

CAPM, risk premium and comparable earnings analyses reviewed in sections 3 through

6. Other considerations raised by the witnesses are reviewed in sections 7 and 8,

followed by an evaluation of the arguments of the parties and recommendation in

section 9.

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1. Selection of a Proxy Group

The starting point for several of the quantitative analyses is the selection of a

proxy group. In his quantitative analysis for Consumers Energy, Mr. Maddipati identified

a proxy group of 13 publicly traded electric companies using the criteria that each

company must: (i) have regulated generation capacity greater than 2,000 MW; (ii) have

net Property Plant and Equipment between $5 billion and $60 billion; (iii) be paying

common stock dividends at a payout ratio in the last 12 months at 60% or greater; (iv)

not be a recent merger target or be engaged in significant restructuring; and (v) have

bonds rated at or above a minimum investment grade of Baa3 by Moody’s Investor

Services and BBB- by S&P.377

In her quantitative analysis for Staff, Ms. Bankapur identified a proxy group of 11

publicly traded electric utility companies based on five criteria: 1) must be in SIC code

4911 (electric services) or SIC code 4931 (electric and other services); 2) net plant from

$5 billion to $40 billion; 3) Standard & Poor and Moody’s investment grade bond ratings;

4) currently paying stock dividend to shareholders; and 5) not involved in mergers or

major corporate buyouts. 378

Mr. Coppola for the Attorney General selected a proxy group of 16 electric utility

companies, beginning with the 40 electric utilities included in the Value Line Investment

Survey, and additionally required that they have revenues from their electric business of

above $1.75 billion and below $20 billion; further, he excluded companies that either

have stopped paying dividends or have experienced a recent significant decline in

377 See 10 Tr 1761, Exhibit A-9, Schedule D-5, page 1. 378 See 11 Tr 2332–2333, Exhibit S-4, Schedule D-5.

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earnings, companies involved in merger activity, corporate reorganizations, and

companies with large foreign assets or in financial distress.379

Ms. LaConte for ABATE chose a proxy group based of companies that have the

following characteristics: they consistently pay positive, quarterly cash dividends; they

are covered by more than one equity analyst; they have electric revenues greater than

70% of total revenues; they have a Moody’s credit rating of Baa3 or higher; they have a

large market capitalization as defined by Value Line Investment Survey (Value Line);

they have positive earnings growth by at least two of the following analysts: Value Line,

Yahoo! Finance, or Zacks Investment Research (Zacks); and they are not involved in

any merger or acquisition related activities within the past six months.380

A review of the proxy lists shows that nine companies appear on each of the

Company’s, the Staff’s and the Attorney General’s proxy lists. The inclusion or

exclusion of the remaining companies are in dispute.

Mr. Coppola testified that he excluded two companies that are in Mr. Maddipati’s

proxy group, Great Plains Energy because it is involved in a potential merger with

Westar and has encountered regulatory opposition, and NiSource because it is

classified as a natural gas distribution company by Value Line in its “Natural Gas Utility

Industry” industry group with 85% of its customers being natural gas customers. He

characterized Mr. Maddipati’s inclusion of these companies as “highly inappropriate.”381

He also identified five companies he included that were not in Mr. Maddipati’s group,

characterizing them as “appropriate comparables.”

379 See 12 Tr 2591, Exhibit AG-26. 380 See 12 Tr 2746. 381 See 12 Tr 2592.

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Ms. LaConte testified that her proxy group includes two companies not included

in Mr. Maddipati’s group (American Electric Power Company and Duke Energy

Corporation), and she excluded four companies he included in his proxy group: Edison

International, Great Plains Energy Incorporated, NiSource, Incorporated, and OGE

Energy Corporation. As did Mr. Coppola, she testified that she excluded Great Plains

Energy because it has been in merger talks with Westar Energy, and she excluded

NiSource because its natural gas services account for 66% of its revenue. She testified

that she excluded Edison International because it purchases 83% of its power, and she

excluded OGE Energy Corp. because it has a 26% stake in Enable Midstream Partners,

a natural gas master limited partnership. She also testified that she included American

Electric Power and Duke Energy Corporation in her group as both meet her proxy group

criteria.382

In his rebuttal testimony, Mr. Maddipati contended that the additional five

companies on the Attorney General’s list are inappropriate and should not be

considered. In reliance on his criterion that each proxy company have a dividend

payout ratio of 60% or more, Mr. Maddipati asserts that American Electric Power should

be excluded. He also testified that Consolidated Edison, Eversource Energy, PSEG,

and Vectren should be excluded as these “do not own enough generation assets [coal

and gas plants], which present unique operational challenges and risks.”383 Regarding

Staff’s proxy group, he objected to Ms. Bankapur’s inclusion of Eversource Energy for

the same reason noted above and he objected to her inclusion of SCANA Corp, which

he contends is facing the potential abandonment of a large nuclear plant and is thus

382 See 12 Tr 2747-2748. 383 See 10 TR 1803.

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“not comparable in terms of risk to Consumers Energy.” He testified: “The primary

differences between Staff’s criteria and mine are that I excluded companies undergoing

significant restructuring and that do not own significant generation assets.”384

Regarding ABATE’s proxy group, he objected to Ms. LaConte’s inclusion of AEP and

Duke Energy “because neither is closely comparable to Consumers Energy”. In support

of his testimony, he stated that AEP does not have a dividend payout ratio of at least

60%, and Duke Energy because it “greatly exceeds” his $60 billion maximum net plant

criterion.385

Mr. Maddipati defended his inclusion of NiSource and Great Plains Energy in

response to Mr. Coppola’s and Ms. LaConte’s critique:

With regard to NiSource, Inc and Great Plains Energy Incorporated, both companies met all of the criteria as laid out in my direct testimony at the time of filing. While Great Plains Energy Incorporated has subsequently announced an acquisition, it was not known to the market at the time of my analysis and does not, therefore, distort the results. Because both companies meet all of the screening criteria of the proxy group, they should be included in the analysis. Careful consideration of the risks faced by each of the companies in the proxy group is critical to ensure they are comparable to the risks and circumstances faced by Consumers Energy.386 2. Flotation Costs

As an element of each of his quantitative analyses, Mr. Maddipati included a

flotation cost adjustment. He explained this adjustment as follows, citing a book by

Roger A. Morin entitled New Regulatory Finance (the Morin book):

The flotation cost adjustment is described by Roger A. Morin in chapter 10 of his book New Regulatory Finance. Because markets are not

384 See 10 Tr 1796. 385 See 10 Tr 1813. 386 See 10 Tr 1803-1804. He subsequently acknowledged on cross-examination that an announcement of Great Plains’ acquisition of Westar occurred on May 31, 2016, before he filed his testimony in this case. See 10 Tr 1873.

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frictionless, flotation costs represent the discounts that must be provided to place new securities into the market. Dr. Morin cites numerous empirical studies which estimate flotation costs and provides a range of 5% to 10% for flotation costs (New Regulatory Finance, page 323). To estimate the adjustment, one multiplies the estimate for flotation costs by the dividend yield. I have used the low end of Dr. Morin’s range of 5% and multiplied by the current dividend yield, as seen in Exhibit A-9 (SM-1), Schedule D-5, page 8, column (h). The flotation cost is calculated individually for each member of the proxy group and ranges from 15 to 19 basis points depending on the proxy company.387

He acknowledged that the Commission has only permitted the recovery of flotation

costs for Consumers Energy’s own debt issuances, but asserted:

Inclusion of flotation costs ensures equity investors fully recover the costs associated with future and previous equity issuances.388

He drew this distinction between debt and equity flotation costs:

The Company pays underwriting, legal, and rating agency fees when issuing debt as well as issuing the bonds at a discount to the public. These costs are included in Company witness Denato’s Exhibit A-9 (AJD-4), Schedule D-2. These costs are reflected as an upward adjustment to the cost of debt which is represented by the difference in the coupon shown in column (d) and column (i). Flotation costs for equity are similar but they are not reflected in the income statement of the Company and therefore without a flotation adjustment would be unrecovered. Dr. Morin describes the recovery in his book by saying,

“In the case of bonds… flotation costs are recovered over the life of the bond in two steps: (1) flotation costs are amortized over the life of the bond and the annual amortization charge is incorporated into revenue requirements, in much the same way that funds invested in utility plant are recovered through depreciation charges; and (2) the unamortized portion of flotation costs is included in rate base, and a return is earned on the unamortized costs, in the same way that a return is earned on the undepreciated portion of a utility’s plant. The recovery continues year after year until the recovery process is terminated, regardless of whether the utility raises new debt capital…. Unlike the case of bonds, common stock has no finite life so that flotation costs cannot be amortized and therefore must be recovered

387 See 10 Tr 1763. 388 See 11 Tr 1764.

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by way of an upward adjustment to the allowed return on equity.” (Emphasis added.)389

Citing the Commission’s rejection of flotation costs in Case No. U-14347, he again cited

the Morin book:

While flotation costs were excluded at the time, the principal argument against the use of flotation costs by the other parties was that Consumers Energy is not a publicly traded utility and, therefore, does not incur the costs. Dr. Morin directly addresses this false assumption on page 333 of his book saying,

“[T]he contention [is] that a flotation allowance is inappropriate if the utility is a subsidiary whose equity capital is obtained from its parent. This objection is unfounded since the parent-subsidiary relationship does not eliminate the costs of a new issue, but merely transfers them to the parent. It would be unfair and discriminatory to subject parent shareholders to dilution while individual shareholders are absolved from such dilution. Fair treatment must consider that if the utility subsidiary had gone to the capital marketplace directly, flotation costs would have been incurred.” (Emphasis added.)

Dr. Morin makes it very clear that flotation costs of a subsidiary are well-founded and justified. Furthermore, several jurisdictions have authorized flotation costs for utilities that are not publicly traded. The use of flotation costs for utilities that are not publicly traded is supported by academic literature, market practitioners, and other regulatory jurisdictions. The Company asks that the Commission reconsider its earlier exclusion of flotation costs.390 Mr. Coppola and Ms. LaConte disputed the company’s use of a flotation cost

adjustment, both citing the Commission’s order in Case No. U-14347. Mr. Coppola

further explained:

Regarding flotation costs, as noted on pages 33 and 34 of Mr. Maddipati’s testimony, Commission precedent in this area (Case U-14347) is that flotation costs should not be allowed in setting the ROE of Consumers Energy since it is not a public company. Also, as discussed earlier in this testimony, a significant portion of the equity infusions in Consumers

389 See 10 Tr 1764. 390 See 10 Tr 1764-1765.

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Energy are being funded by CMS debt issued in the public markets (not new CMS equity issued in the public markets). Accordingly, even if the Commission were to reconsider this issue in this case, Mr. Maddipati has presented no new credible evidence to justify reversing the Commission’s prior decision on this matter.391 3. DCF Model

The discounted cash flow (DCF) approach equates the market price of a stock to

the present value of the stream of dividend payments an investor expects to receive.

The cost of equity is the discount rate necessary to reduce the future cash flows to the

current market price.

a. Consumers Energy

Mr. Maddipati used the standard or constant growth formulation of the discounted

cash flow model, and applied to two different growth rate assumptions. He explained

that he used average stock prices over the period January 6 to February 17, 2017, with

the latest annual dividend amounts, adjusted by the growth rate for his dividend yield.

For his DCF analysis, Mr. Maddipati used two alternative methods for estimating the

future growth rates: analyst projections for dividends over the next three years, and the

mid-point of company long-term growth.392 The calculations using the analyst dividend

growth projections resulted in an average ROE of 10.56% within a range of

8.22% - 13.78 %, and the calculations using company guidance resulted in an average

ROE of 10.33% within a range of 8.46% to 14.13%.393 As indicated on Exhibit A-9, both

calculations applied a floatation cost adjustment.

391 See 12 Tr 2594. 392 See 10 TR 1777. 393 See Exhibit A-9, Schedule D-5, p. 8.

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b. Staff

Ms. Bankapur testified that she used the most recent quarterly dividend and the

most recent 3-month stock price for each of the proxy companies to determine the

dividend yield. She testified that she used a combination of earnings and book value

growth estimates from Yahoo! Finance, Zachs, and Value Line. She testified that she

used an adjusted DCF model referred to as the semi-compounding model that

recognizes that the timing of dividend increases varies by company, explaining that in

this model version, the first-year dividend payments are adjusted by half the growth

rate.394 The cost of equity estimates resulting from her DCF analysis range from 7.27%

to 9.21%, with an average of 8.5% and a median of 8.74%.

c. Attorney General

Mr. Coppola presented his DCF analysis results in Exhibit AG-26.395

Mr. Coppola used the standard single-stage or “compound growth” formulation of the

DCF model in his analysis. His used stock prices based on average values for the

month of July 2017, and projected dividends from Value Line for 2018. His long-term

growth rates are taken from on Value Line earnings projections through 2020 and

analysts’ projected growth in earnings per share. The average return on equity for his

proxy group using this method and these inputs was 9.08%.

In discussing his results, Mr. Coppola explained the differences between his

results and the results derived by Mr. Maddipati. In addition to Mr. Maddipati’s addition

of a flotation cost adjustment, he testified that stock market prices have increased

significantly since Mr. Maddipati filed his testimony, reducing the dividend as a

394 See 11 Tr 2334-2336. 395 See 12 Tr 2592-2594.

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percentage of price.396 He also attributed a portion of the difference to Mr. Maddipati’s

inclusion of Great Plains in the proxy group,397 and Mr. Maddipati’s use of outdated

earnings growth estimates for Edison International and PG&E.

Mr. Coppola also testified to his view of the usefulness of this estimation method:

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 9.7%. 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 gas 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 in determining the cost of common equity. 398

d. ABATE

Ms. Laconte used both a single-stage or constant-growth DCF model as well as

a multi-stage formulation which incorporates consideration of three different growth

rates, near-term, intermediate term, and long-term.399 For the constant growth model,

she used the average stock prices from June 2017 reported by Yahoo! Finance, with

growth rates based on the forecast growth in earnings from three sources, Yahoo!

Finance, Value Line, and Zacks, as shown in Exhibit AB-7. For beginning dividends,

Ms. LaConte used Value Line projections for 2017.400 For her multi-stage model,

Ms. LaConte used analyst forecasts for the near-term growth rate, the long-term

projected growth in GDP for her long-term growth rate, and an interpolation of those two

396 See 12 Tr 2594. 397 See 12 Tr 2594-2595. 398 See 12 Tr 2596. 399 See 12 Tr 2748. 400 See 12 Tr 2749.

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for the intermediate term growth rate. She reported results for the single-stage model

ranging from 7.9% to 9.7%, with a mean of 8.6% as shown in Exhibit AB-7; she reported

results for the multi-stage model ranging from 7.6% to 8.0%, with a mean of 7.8% as

shown in exhibit AB-10.

e. DCF Disputes

Ms. LaConte objected to Mr. Maddipati’s use of dividend growth forecasts in his

DCF analysis. Ms. LaConte explained:

Mr. Maddipati’s first DCF analysis relies on the consensus growth in dividends per share. Investors’ growth expectations typically rely on trends in earnings, which will support future dividends. Even Mr. Maddipati admits: “…a Company may have dividend growth that outpaces earnings growth, consistently outperforms guidance, or have irregular and other one-time dividends, all of which would cause the DCF model to misstate return on equity.”401

Similarly, she testified:

His second DCF analysis relies on the growth outlook as provided in investor presentations for the companies in his proxy group. Most are based on forecasted growth in dividends, not earnings and are not representative of earnings forecasts. For example, as shown on WP-SM-10, page 6, Great Plains Energy’s growth rate is based on forecast dividend growth of 5%-7%, whereas the forecast earnings growth rate is 4%-5%. The earnings forecast is similar to the IBES Consensus forecast of earnings growth rate of 4%. Again, investors’ growth expectations typically rely on trends in earnings, which will support future dividends.402

In his rebuttal testimony, Mr. Maddipati challenged the DCF analyses offered by

the Staff, the Attorney General and ABATE as incorrectly using some form of earnings

growth instead of dividend growth as the analysis calls for:

The correct input to the DCF model is dividend growth which is uncontested by Staff or any other witness in this case. Correcting Staff’s DCF analysis for just this singular input by applying dividend growth results in an average ROE of 9.69%, a full 119 basis point improvement

401 See 12 Tr 2770. Emphasis in original. 402 See 12 Tr 2770-2771.

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over Staff’s initial estimates (see Exhibit A-124 (SM-4), page 3, compared to Staff Exhibit S-4, Schedule D-5, 5 page 5). 403

Additionally, while undertaking these DCF analyses, in his rebuttal testimony

Mr. Maddipati contended that the DCF analysis may not be reliable in determining a true

ROE given “current market conditions”, and challenged the use by Staff, the Attorney

General and ABATE of the DCF model, accusing each of the witnesses of a

“mechanical” application of the model in violation of the standards of Hope and

Bluefield.404 For example, he testified:

FERC noted in Opinion 531 and reiterated in Opinion 551 that a mechanical application of quantitative models such as the Discounted Cash Flow (‘DCF’) Model, in light of the current actions taken by the Federal Reserve, raises questions as to whether the standards in Hope and Bluefield are met.

‘We find that current capital market conditions may cause the mechanical application of the DCF methodology to produce an ROE that does not meet the requirements of Hope and Bluefield.’

The Attorney General and ABATE witnesses relied heavily on a mechanical application of the DCF methodology which may not meet the standards in Hope and Bluefield.”405 4. CAPM/ECAPM

The Capital Asset Pricing Model (CAPM) is also frequently used in estimating the

cost of equity capital. It posits that because investors can manage certain risks with a

diverse portfolio, the required return for a security consists of a risk-free rate of return

403 See 10 Tr 1798-1799. Also see 10 Tr 1808 (“Mr. Coppola acknowledges that dividend growth is the appropriate input on page 95, line 6, of his direct testimony, but he nevertheless applies short-dated earnings estimates instead.”) Also see 10 Tr 1813 (“Ms. LaConte criticizes my application of dividend growth over earnings growth, but on page 9 of her testimony, even Ms. LaConte specifically acknowledges that the model is defined as ‘(1) the current dividend rate, plus (2) the expected growth in dividends.’ Interestingly, Ms. LaConte continues to apply expected earnings growth instead of dividend growth rates and criticizes my correct application of dividends as a main concern associated with my DCF analysis.” Emphasis in original.) 404 See, e.g., 10 Tr 1799; 10 Tr 1787-1788. 405 See 10 Tr 1787-1788. Emphasis in original.

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plus a market risk premium that is proportional to the degree of non-diversifiable or

systematic risk of the security. The non-diversifiable risk is designated by beta (β),

which indicates the relative risk of a security as compared to the market as a whole.

a. Consumers Energy

Mr. Maddipati presented a CAPM analyses for its proxy companies using two

different sets of inputs, which he labeled as a “normalized” CAPM and a “low interest

rate” CAPM. He also presented a variation of the CAPM referred to as the Empirical

CAPM or ECAPM, also using two sets of inputs. Mr. Maddipati explained his use of the

two sets of inputs as being required by unique market conditions for which the standard

calculation does not appropriately account.

The source for my market risk premium is Roger Ibbotson’s 2017 Stocks, Bonds, Bills, and Inflation (SBBI) Yearbook. As shown on page 2 of Exhibit A-9 (SM-1), Schedule D-5, the average large company’s total stock market return for the 1926-2016 period was 11.95%. During that same period of time, the average income return of long-term government bonds was 5.02%, and the resulting market premium is 6.93%. The Ibbotson data is often used in developing the market risk premium. . . . The 91-year period from 1926 to 2016 reflects the entire period used in the Ibbotson data. Over short periods of time, the equity risk premium can be quite volatile. However, when calculated using the entire data series, it is relatively stable. It is appropriate in a market risk premium analysis to use the entire period of historical data in order to assess investors’ expectations. “[T]he Ibbotson equity risk premium is an estimate based on historical data which is not appropriate to use with current interest rates in particular during a period where the Federal Reserve is purposefully keeping long-term rates low. Utilizing current risk-free rates requires estimating a current equity risk premium which is very difficult to do. A recently published article by the Federal Reserve indicates that equity risk premiums in low interest rate environments is (sic) much higher – 12% vs. the 6.93% from Ibbotson. To correct for this inconsistency, I’ve calculated the CAPM using two methods which I’ve labeled Normalized CAPM and Low Interest Rate CAPM.406

406 See 10 Tr 1766.

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For his “normalized” CAPM, he used the Ibbotson risk-premium data for the time

period 1926-2016 (6.93%) and the historical risk-free rate over that same time period

(5.02%). For his “low interest rate” CAPM, he used the projected yield on 30-year

Treasury bonds for 2018 of 3.655% based on the average of the 3.65% forecast from

Blue Chip Financial Forecasts and the 3.66% forecast from Global Insight as his risk-

free rate, and he used a market risk premium of 10.03%, based on the average of

Ibbotson risk premium data over the time period 2011-2016. He explained this choice

as follows:

For the equity risk premium, I looked to historical data since 2011, when the Federal Reserve began the most recent efforts to keep long-term interest rates low. I have utilized the average equity risk premium of 10.03% during this period of accommodation (Exhibit A-9 (SM-1), Schedule D-5, page 2, line 56). This value is also consistent (albeit conservative) with observations by the Federal Reserve indicating premiums as high as 12% are appropriate in low-rate environments.407

In his CAPM calculations, Mr. Maddipati used betas taken from Value Line. He also

added a floatation cost adjustment for each calculation. The equity estimates resulting

from the “normalized” CAPM range from 9.34% to 11.44%, with an average of 9.95%;

the equity estimates resulting from his “low interest” CAPM range from 9.84% to

12.86%, with an average of 10.71%.408

After discussing shortcomings in the CAPM, he explained that he also used the

Empirical CAPM, which includes an adjustment alpha (α) to reflect empirical data

indicating that the CAPM tends to overpredict returns for stocks having betas above 1,

and underpredict returns for stocks having betas below 1. He testified that he used an

alpha of 1.5%, “which is the mid-point in the range of 1% to 2% described as

407 See 10 Tr 1767. 408 See 10 Tr 1769.

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reasonable by Roger A. Morin in his book New Regulatory Finance.”409 With this

adjustment, he used the same two sets of inputs he used in his CAPM analysis, and the

same flotation cost adjustment, with the results for the “normalized” ECAPM ranging

from 9.94% to 11.59% with an average of 10.42%, and the results of the “low interest”

ECAPM ranging from 10.44% to 13.01%,with an average of 11.18%.410

b. Staff CAPM

Ms. Bankapur performed two CAPM analyses for its proxy companies, using two

different risk premiums estimated from two long-term time periods, 1926 to 2016 and

1952 to 2016, taken from the Ibbotson data. As shown on page 6 of her Schedule D5,

Exhibit S-4, she used Value Line betas, with an average beta of .68 for the proxy group.

CAPM analyses projected an average ROE of 7.72% within a range of 7.23% to 9.42%,

and an average of 8.18% within a range of 7.65% to 10.07%.411

c. Attorney General

Mr. Coppola conducted one CAPM analysis for his proxy companies, using a

risk-free rate of 3.65%, the risk-free rate Mr. Maddipati used in his “low interest”

analyses, and a risk premium of 6.93%, the risk premium Mr. Maddipati used in his

“normalized” analysis. The Attorney General also used the same Value Line beta

figures as Staff and Consumers Energy. The Attorney General’s CAPM analysis

projected an average ROE of 8.24% within a range of 7.12% to 10.23%.412

Mr. Coppola testified regarding his choice of risk-free rate:

Normally, I would use a historic risk free rate (the current yield on 30 year treasury bonds) which as of early July 2017 approximates 2.90%.

409 See 10 Tr 1770. 410 See 10 Tr 1769, 1770. 411 See 11 Tr 2339, 2340. 412 See 12 Tr 2597, 2598, Exhibit AG-27, page 1.

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However, interest rates have been rising recently and sentiment in the market is fairly universal that interest rates will continue to rise as the Federal Reserve Bank winds down its “quantitative easing” efforts and the United States economy continues to improve. For purposes of this case, I have adopted Mr. Maddipati’s estimated 2017 risk free rate of 3.65%.413

d. ABATE

Ms. LaConte also performed a CAPM analysis. She used two risk-free rates to

produce two sets of results. She used the 90-day average yield on U.S. Treasury

bonds of 2.89%, and she used a long-term forecast for the 30-year Treasury bond of

3.78%.414 For the risk premium, she used the historical risk premium of 6.93% from all

91 years reported by Ibbotson.415 She used Value Line betas for each of the proxy

companies, reporting an average beta of .65. She reported average results of 7.4% and

8.3% for the two different risk-free-rate assumptions.

e. Disputes

Mr. Coppola extensively critiqued both sets of Mr. Maddipati’s inputs:

Mr. Maddipati has developed a market risk premium by using data for the years 2011 to 2016 which is 10.03% (CAPM) and 8.01% (Utility Risk Premium approach). In addition to this being an extremely short time frame, Mr. Maddipati is considering only the recovery years following the 2008 recession. As such, the equity return component he derives to calculate his equity risk premium during this short period of time is inflated and meaningless. For example, if Mr. Maddipati had considered the period 2007 to 2016 to develop a market risk premium for CAPM purposes, he would have included the impact of the 2008 recession and all of the recovery years as well. The result of this average calculation is a return on common equity of 8.75%, an average rate on long term government bonds of 3.44% (very close to the rate he uses for the projected test period) and a market risk premium of 5.32%. Although this would be a very short period of time, and I don’t advocate this approach, at least it would have included both up and down cycles in the stock market.


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* * *

The 15.71% was derived by Mr. Maddipati by using the average return on equity securities of 18.01% during the ten years from 1942 to 1951 and then subtracting the 2.30% average rate for long term treasury bonds. In addition to this being another short time period, Mr. Maddipati appears to be unfamiliar with the financial and economic history of the United States economy during the World War II period and the period immediately following the war. First of all, the United States during this time entered a period of robust economic expansion with significantly high returns on equity of 18%. Therefore, Mr. Maddipati again is picking out the better recovery years after an economic downturn (the “Great Depression”) which are then enhanced by the effects of the war effort.416

Ms. LaConte also critiqued Mr. Maddipati’s choice of inputs. Regarding his “normalized”

CAPM, she testified:

The Normalized CAPM analysis uses a higher, historical risk-free rate than the forecast rate during the test year of 3.65%. As Mr. Maddipati states, it is difficult to forecast the MRP, therefore a long-term average is appropriate. However, forecasts of the risk-free rate are available for the test year, as demonstrated in Mr. Maddipati’s testimony and should be used to estimate the ROE.417

Regarding his “low interest” CAPM, she testified:

Mr. Maddipati used too short of a time frame to determine the MRP, 2011-2016. A sample of six years is not enough data to represent the MRP. Furthermore, his Low Interest Rate analysis contradicts his statement: “Any analysis that utilizes the Ibbotson equity premium with current risk-free rates is incorrect.”418

Ms. LaConte also objected to Mr. Maddipati’s use of the ECAPM model with the

adjusted betas:

An ECAPM analysis “re-adjusts” the beta to account for the fact that over the long term it has been shown that companies with betas less than one are under estimated; that is, their risk is actually higher than the risk defined by the beta. Companies with betas greater than one are over-estimated; that is, their risk is actually lower than the risk shown by its


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beta. However, the betas used by Mr. Maddipati in his CAPM analyses have already been adjusted and there is no need to perform an ECAPM analysis.419 In his rebuttal testimony, Mr. Maddipati accused each of the other witnesses of

ignoring the standards in Hope and Bluefield by failing to use his inputs, but using a

“projected” interest rate with what he characterized as “backward looking” risk premium

data.420 For example, regarding Ms. Bankapur’s analysis, he testified:

Staff’s analysis utilizes the historical premium with the projected risk-free rate which is incorrect. Staff labeled their CAPM forward-looking but given its use of a backward-looking risk premium, the label is false and misleading. This flawed application is well noted by academic literature, practitioners and regulators as summarized by FERC in Opinion 551:

“Morningstar market risk premium of 6.2 percent, which was based on the arithmetic average difference between stocks and Treasury bills from 1926 to 2013. However, the Morningstar market risk premium relies on historical data and, therefore, any CAPM analyses using the Morningstar market risk premium would be backward-looking.” (Emphasis added.)

Therefore, Staff’s CAPM analysis using a projected risk-free rate requires the determination of the market risk premium in the current environment. 421

He defended his use of the ECAPM also by citing the Morin book,422 and testified that

Ms. LaConte had not provided any additional quantitative analysis of her own, and had

provided no specific academic or regulatory support to justify discounting his

analysis.423 Mr. Maddipati also objected that the other witnesses did not use the

ECAPM he used.424

419 See 12 Tr 2766. 420 See 10 Tr 1789-1791. 421 See 10 Tr 1797. 422 See 10 Tr 1772. 423 See 10 Tr 1816. 424 See, e.g., 10 Tr 1789, 1792, 1796.

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5. Risk Premium

The risk premium approach attempts to compute the cost of equity by comparing

historical common equity returns to risk-free returns. Consumers Energy, Staff, and the

Attorney General each performed a risk-premium analysis.

a. Consumers Energy Mr. Maddipati performed two risk premium analysis using two sets of inputs

similar to his CAPM analysis: a “normalized” risk premium and a “low interest” risk

premium. For the “normalized” risk premium analysis, he used the risk-free government

bond rate of 5.02% (as he’d used in his CAPM/ECAPM analyses) for four different bond

ratings (A, A-, BBB+ and BBB), and he added an estimate of the historical spread of

corporate bonds to government bonds and the historical spread of utility stock over

utility bonds to derive the cost of equity estimates. For the low-interest version, he used

the spread of 8.01% for electric utility common stocks over utility bonds over what he

characterizes as the “low interest rate period”, added to the projected 2018 risk-free rate

and the estimated corporate spread by bond rating to derive the cost of equity

estimates. As shown in page 7 of Schedule D5, he reported a range of results for

“normalized” version of 10.66% to 11.49%, and a range of results for the “low interest”

version of 12.91% to 13.75%.

b. Staff Ms. Bankapur performed a risk-premium analysis using the historical utility bond

yields for both A-rated and BBB-rated bonds. The details are shown on page 7 of her

Schedule D5, and the resulting equity cost estimates are 8.51% using yields for A-rated

bonds, and 8.86% using yields for BBB-rated bonds. She testified:

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The results of the Risk Premium analysis are slightly lower than one would expect when taking a long term perspective because current bond yields for both A-rated and BBB-rated utility bonds are below historical utility bond yields.425

c. Attorney General

Mr. Coppola’s risk-premium analysis is shown in his Exhibit AG-28. He testified

that he estimated a return on equity of 9.58% using the 4.39% historical spread of

electric utility common stock returns relative to utility bonds from 1932 to 2016 (also

developed by Mr. Maddipati), as well as his projected risk-free rate of 3.65% for the test

year.426 Mr. Coppola explained the difference between his results and Mr. Maddipati’s,

taking issue with his choices as discussed in more detail below.427

d. Disputes

Ms. LaConte objected to Mr. Maddipati’s choice of inputs in his risk premium

analyses for the same reasons she objected to his choices for his CAPM analysis.428

Mr. Maddipati reiterated his objection that the other witnesses did not use his

choice of inputs.429 For example, regarding Staff’s analysis, he testified:

Similar to the differences in our CAPM analysis, Staff applied inconsistent inputs to their Risk Premium analysis. Staff applied projected interest rates to a risk spread that is not reflective of the current environment. Staff calculated the average risk spread since 1932, but the current market environment does not look at all like the average during this time. The current market environment has low interest rates driven primarily by Federal Reserve intervention. My direct testimony noted spreads ranging from 8%-15% for similar market conditions. Using the low end of that range of 8%, I can correct Staff’s risk premium analysis, resulting in a corrected ROE ranging from 12.01%-12.36% (see 15 Exhibit A-124 (SM-4), page 2).430

425 See 11 Tr 2341. 426 See 12 Tr 2599. 427 See 12 Tr 2600-2603. 428 See 12 Tr 2767-2769. 429 See 10 Tr 1789, 1790, 1798, and 1804. 430 See 10 Tr 1798.

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6. Comparable Earnings Analysis

Mr. Maddipati also performed a comparable earnings analysis in which he used

earnings per share and book value per share projections from Value Line to construct

projected rates of return for his proxy group.431 The average projected ROE for the

Company’s proxy group using this method is 10.75%, with a range of 6.00% to

18.56%.432 He cited the Commission’s order in Case No. U-16794 as providing support

for the use of this method.

Mr. Coppola, challenged this methodology as “not an academically sound

approach” and a “useless tool” for determining the cost of common equity. He also

asserted that this methodology is inherently unreliable as being influenced by the very

utilities being analyzed:

As set forth on Exhibit A-9 (SM-1) Schedule D-5, page 9, Mr. Maddipati derives a 10.75% projected average return rate on the book value of common equity for his peer group. He uses this estimated return rate as a determinant of his recommended ROE of 10.50%. Unfortunately, this is not an academically sound approach to determining the cost of common equity for a company. What Mr. Maddipati is doing is simply dividing (1) the projected earnings per share (“EPS”) five years from now for each peer group company (as estimated by Value Line) by (2) the projected Book Value for each such peer group company in question. This exercise perhaps has some use in evaluating how well each peer group company employs capital over longer periods of time but is useless as a tool to set the authorized ROE of a utility company. This method does not take into account investors’ expectations or stock market parameters. The Commission should also recognize the inherent circularity in relying upon this method advocated by the Company. If utility commissions were to rely upon this methodology, utilities in effect would indirectly be setting their own allowed ROE or highly influencing those ROEs by estimating ever increasing [earnings per share].

431 10 TR 1778-1779. 432 Exhibit A-9, Schedule D-5, p. 9.

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In summary, this approach appears to be a feeble attempt to find a cost of capital calculation method to fit a desired level of return on equity. My recommendation is that the Commission should give no weight or reliance to this alternative method.433

Ms. LaConte also characterized the comparable earnings method as overstating the

return on equity, and she testified that to her knowledge, it has not been relied on in

other jurisdictions.434

In his rebuttal testimony, Mr. Maddipati defended his use of this method,

contending that before the DCF and CAPM models were developed, it was “the

standard” for deciding rate cases, and also citing FERC Opinion 551.435

7. Other Authorized Returns

Several witnesses presented information regarding the returns on equity

authorized by other state regulatory commissions. In his direct testimony, Mr. Maddipati

offered a caveat, testifying that there is no accurate or complete source of information

on authorized rates of return.436 He provided information that appears to come from

J.D. Powers linking higher authorized rates of return to higher levels of customer

satisfaction, with the indication that 8 of the 10 results listed are not included in the

Regulatory Research Associates (RRA) database.437 The results range from 10.2% to

13.3%. He testified:

[J]urisdictions with strong regulatory frameworks have higher customer satisfaction as well as higher ROEs. For example, Florida recently increased the ROE for Florida Power & Light, which is the top-rated investor owned utility in the country for customer satisfaction, by five basis points to 10.55%.438

433 See 12 Tr 2603-2604. 434 See 12 Tr 2771-2772. 435 See 12 Tr 1809,1810, 1817. 436 See 10 Tr 1749-1750. 437 See 10 Tr 1750. 438 See 10 Tr 1750.

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Ms. Bankapur included recently authorized returns as reported by Edison Electric

Institute on page 8 of Schedule D5 in her Exhibit S-4, showing averages of 9.89% for

2014, 9.80% for 2015, and 8.77% for 2016.439 Mr. Coppola testified that since 1990, the

rates of return on equity approved by regulatory commissions has been declining. He

presented Exhibit A-29 to show this trend, and testified that from January 2016 through

March 2017, the average allowed return on equity was 9.59%.440 Ms. LaConte

presented a chart showing the trend in authorized rates of return in comparison to the

risk-free rate as measured by the yield on 30-year U.S. Treasury bonds. 441

Mr. Tillman on behalf of Walmart presented data on authorized rates of return

from SNL Financial in his Exhibit WM-3, and broke out averages for vertically-integrated

utilities. He testified that the average authorized return on equity for vertically-integrated

utilities was 9.92% in 2014, 9.75% in 2015, 9.77% in 2016, and was 9.68% as of the

last data he had available for the first part of 2017. He also showed the average

authorized returns in comparison to Commission-authorized returns for the same time

period. He recognized that decisions of other state regulatory commissions are not

binding on the Commission, and that each commission considers the specific

circumstances in each case.442

In his rebuttal testimony, Mr. Maddipati reiterated his earlier testimony regarding

limitations of the RRA data base.443 Addressing Mr. Coppola’s and Ms. LaConte’s

presentations of data regarding authorized rates of return, he testified:

439 Mr. Maddipati testified that the 2016 value appears to be mistyped, 440 See 12 Tr 2605-2606. 441 See 12 Tr 2759. 442 See 12 Tr 2491-2493. 443 See 10 Tr 1792-1793, 1822-1823.

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As I noted, although the RRA database is not complete, since its methodology tends to exclude ROE decisions from alternative rate making, it does provide the equity ratio as a percentage of total capital for the cases for which an ROE decision was made. Although I don’t recommend using the RRA data for determining a comparable ROE, any use of the ROE data must also adjust for the percentage of equity capital authorized to make an appropriate comparison of this data. Adjusting for the differences in equity capital, the ROE authorized since 2016 have averaged 11.7% with a range of 6.8% to 14.2%.444

He presented Exhibit A-122 to support his calculation. He added: “Additionally, per the

data provided in RRA, Consumers Energy’s authorized equity-to-total capital ratio falls

in the bottom quartile of electric rate cases decided since 2016.” 445 He testified that Mr.

Tillman also should have adjusted the return on equity averages “to accommodate for

differing percentages of equity in capital structures.” 446 He testified that had he done

so, Mr. Tillman would have calculated a return on equity of 11.7%.

8. Discussion of Risk and other Factors

A review of the testimony of the witnesses also reveals differing views regarding

the risks faced by Consumers Energy and how those should be considered in setting

the authorized return on equity.

a. Consumers Energy

Mr. Maddipati presented various arguments regarding risk factors the

Commission should consider in support of his recommended ROE, some of which have

already been discussed above, but are summarized here. First, Mr. Maddipati asserted

that authorized ROE is a “key signal” provided by the Commission affecting the

investors’ and the credit ratings agencies’ perception of the Michigan regulatory

environment: 444 See 10 Tr 1793. 445 See 10 Tr 1793-1794. 446 See 10 Tr 1822-1823.

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Based on my interactions with investors and rating agencies, I conclude that they view the authorized ROE as a key signal provided by a utility commission and that the authorized ROE will affect their perception of the Michigan regulatory environment, investment in Consumers Energy, and investment in Michigan. While investors view Michigan’s regulatory environment as constructive, they are counting on continued stability in its regulatory decisions. If investors and credit rating agencies were to perceive the regulatory environment as deteriorating, this would quickly undercut the positive view that they currently hold.447

Conversely, the Company asserts that setting the ROE at 9.80% or lower, as

recommended by the Staff, the Attorney General, and ABATE, would send a

“dangerous signal” to investors that would undercut the progress that has been made in

improving investor perceptions of the Michigan regulatory environment.448 He testified:

As I noted in my direct testimony [at 10 Tr 1752, line 5], one factor in determining ratings is consistency and predictability of regulatory outcomes. There is nothing either consistent or predictable about lowering the ROE by 30 to 150 basis points.449 Second, Mr. Maddipati contends that various market and risk considerations

mandate a higher ROE than might otherwise be appropriate. In that regard, he

highlighted several circumstances in the national and world economies that he believes

are adding to investors’ risk perceptions, focusing on the low interest rate environment

and the prospects for interest rates to increase:

There is a consensus among economists that interest rates will continue to rapidly rise and revert to normal levels relatively soon, as indicated by various interest rate forecasts. While the Federal Reserve will try to make this process as smooth as possible, a sudden, abrupt rise in the interest rates cannot be ruled out. It is hard to predict the timing of such abrupt movements, and this adds additional risks that are not captured by using the average projected interest rates.450

447 See 10 Tr 1755-1756. 448 See 10 Tr 1794; also see 10 Tr 1800. 449 See 10 Tr 1785. 450 See 10 Tr 1756.

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He testified that “a large source of uncertainty is when, and by how much, the Federal

Reserve will make its next hike in short-term interest rates,” and further stated:

Analysts agree that when interest rates begin to rise, they increase quickly and in an unpredictable manner. This volatility leads to higher risk which, in turn, demands a higher required return on investments.451

In his rebuttal testimony, Mr. Maddipati, argued that no witness in this case has rebutted

his direct testimony documenting the expectation of investors and rating agencies

regarding Michigan’s regulatory environment. Mr. Maddipati acknowledged

Ms. LaConte’s testimony as follows:

Q: Ms. LaConte also presents an additional risk analysis. Do you agree with her view and dependence on this material? A. No. Ms. LaConte’s risk analysis simply states that electric utilities in general have lower business risk than the market average. This is fairly straight forward and quite meaningless, as it is also the reason why I selected electric utility companies when selecting a proxy group. I am not advocating in this case for an ROE to be set at a level comparable to the broader market -- my quantitative analysis is reasonable, objective, and well supported. Every single utility in my proxy group has an excellent business risk profile, so her risk analysis does not serve a purpose in rebutting my direct testimony.452

b. Staff

After reviewing the standards in Hope and Bluefield, Ms. Bankapur testified that

consideration should be given to both investors and ratepayers when establishing a just

and reasonable rate of return.453 Ms. Bankapur testified that “[t]he utilities earnings

should be sufficient enough to ensure investor confidence in the financial soundness of

the enterprise, as well as support its credit and raise capital. The rate of return should


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also reflect economic and financial market conditions.”454 In formulating her

recommendations to the Commission, she testified to her conclusion that Consumers

Energy is of comparable risk to the proxy group. She testified that Consumers Energy’s

A rating of Consumers Energy’s secured debt “suggests that is has strong capacity to

meet its financial commitments, but is somewhat more susceptible to the adverse

effects of changes in circumstances and economic conditions than obligors with higher

ratings.” She similarly reviewed Moody’s Aa3 rating and Fitch’s A+ rating.455 In

presenting Staff’s recommendation, Ms. Bankapur testified that it is largely based on the

results of her quantitative studies, but also on her professional judgment, and in

consideration of all the factors identified by the company. 456

c. Attorney General

In addition to presenting his quantitative analyses, Mr. Coppola provided his

views of the current economic conditions facing Consumers Energy. He testified that

the Michigan economy has recovered from the most recent recession and interest rates,

which have been at stable lower levels, are beginning to rise. He testified that these

factors have placed Consumers Energy in a better position with respect to sales levels,

interest rates, and uncollectible sales amounts.457 He also testified that “Consumers

Energy has ample access to capital markets and continues to prosper with actual

returns on equity in the past few years reaching or exceeding its authorized level.”458

He reviewed their recent debt issuances and concluded that the company’s access to

454 See 11 Tr 2331. 455 See 11 Tr 2333-2334. 456 See 11 Tr 2342. 457 See 12 Tr 2604-2605 458 See 12 Tr 2605.

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capital is strong. Mr. Coppola explained the considerations underlying his

recommendation:

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 CECo and how investors perceive those risks, such as serving a territory that is highly dependent upon the automotive industry. Second, as mentioned above, the extent to which investors anticipate higher interest rates is uncertain. As such, while the cost of common equity under the DCF approach is an accurate assessment of expectations for the forecasted test year, the higher interest rates assumed in this case may very well produce a different result should such higher interest rates become a reality. In this regard, a potential 10% correction in utility stock prices due to higher interest rates would produce a 0.40% increase in the cost of capital under the DCF approach. I am also cognizant that the Commission may be reluctant to set an ROE for the Company at the true cost of equity in the 9.0% area. As shown in Exhibit AG-29, regulatory commissions in the most recent decisions have granted an average ROE of 9.50%. Therefore, I am recommending an ROE rate in the range of 9.50% to 9.75% in this case, as a gradual transition to the true cost of equity.459 Mr. Coppola directly addressed Mr. Maddipati’s testimony regarding the concern

of investors:

In his direct testimony, Mr. Maddipati states that there is much concern among investors and research analysts regarding a lower ROE becoming a reality at Consumers Energy. On page 21 of his testimony, Mr. Maddipati discusses rating agency and analyst concerns regarding lower ROEs and cites just one report noting ‘ROE creep as a primary area of concern’ in that report. In response to a discovery request, the Company provided the analyst report noted by Mr. Maddipati. The research report by Wolfe Research aptly titled “I’m alright, don’t worry ‘bout me” proceeds to talk about the 10.1% ROE received by the Company in Case No. U-17990 but does not raise any concerns about this level of approved return of equity.460

459 See 12 Tr 2606-2607. 460 See 12 Tr 2607-2608.

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Mr. Coppola also addressed the question of whether the Commission should be

concerned that establishing an ROE of less than 10% will lead to impairment of the

Company’s ability to access the capital markets:

The Company has made this argument in this and prior rate cases, but the evidence shows that companies in other jurisdictions receiving ROE decisions below 10% have had ample access to the capital markets. Exhibit AG-29 shows that most of the companies in this category have accessed the capital markets on a competitive basis since receiving an ROE below 10%. Similarly, there is no evidence equity investors have abandoned utilities that have been granted ROEs below 10%. On the contrary, stock investors continue to migrate to utility stocks recognizing that authorized ROEs are still above the true cost of equity. For example, the stock of Ameren (parent of Ameren-1 Illinois which was granted an authorized ROE of 8.64%% in December 2016) traded at 1.9 times book value at the end of March 2017. Similarly, the stock of OGE Energy (parent of Oklahoma Gas & Electric which was granted an ROE of 9.50% in a rate case on March 20, 2017) traded at 2.1 times book value at the end of March 2017. These examples and other evidence simply dispel the myth that the Company must receive an ROE above 10% or it will face dire consequences in the financial markets.461

d. ABATE

Ms. LaConte also testified that Consumers Energy’s risk profile may affect its

estimated ROE. She looked at Standard and Poor’s business risk assessments:

Standard and Poor’s (S&P) business risk assessments range from “excellent” (highest) to “vulnerable” (lowest). As a regulated utility, Consumers’ business risk profile is rated as excellent. S&P uses five basic characteristics to determine business risk, including regulation, markets, operations, competitiveness and management. Regulated electric utilities are usually viewed as a very low risk industry since they have a defined service territory that is generally not affected by competition, they provide an essential service, and have regulators that want to support the utility’s financial profile.462

461 See 12 Tr 2608-2609. 462 See 12 Tr 2754.

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Ms. LaConte also testified regarding how the Commission is rated from an investor’s

perspective and how that rating affects consumer risk:

The Michigan Public Service Commission (MPSC) is rated A/1 by Regulatory Research Associates (RRA). This places the MPSC at an above average range of the rating scale. When viewed from an investor’s perspective, an A/1 rating means that the MPSC has an above average constructive, medium-risk regulatory climate. In the May 2017 update of Michigan’s Regulatory Evaluation, RRA stated: “As it has been for the last few years, Michigan regulation remains reasonably constructive from an investor perspective.463

She also discussed options available to Consumers Energy to reduce regulatory lag,

including its use of a projected test year and frequent rate cases filings. As noted

above, Mr. Pollock also testified that use of a projected test year reduces risk.464

Turning to the economy, she testified that the economic outlook is becoming

more stable and that market volatility is decreasing.465 She quoted the Wall Street

Journal from July 2017:

A key gauge of market volatility hit its lowest level in almost 24 years Friday as stock indexes smashed records. The CBOE Volatility Index, known as Wall Street’s “fear gauge” or VIX, slid for the sixth straight session to 9.51, the third lowest close in history and its nadir since December 23, 1993. The index uses options bets on the S&P 500 index to measure expected stock swings over the next month. It tends to reflect risk when investors are anxious and stocks are falling.466

Ms. LaConte also presented information showing that the cost of capital for utilities is

decreasing. At 12 Tr 2758, she compiled a bar chart showing historical betas for

electric utilities for each year from 2006 through 2016. She testified that betas have

463 See 12 Tr 2755. 464 See 12 Tr 2644. 465 See 12 Tr 2756-2757. 466 See 12 Tr 2756-1757.

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fallen by 21% since the high shown for 2007, and concluded that the market views

electric utilities as less risky than in the past.467

e. Walmart

Walmart’s witness Mr. Tillman recommended that the Commission should

carefully consider the impact on customers in evaluating the return on equity, citing his

Exhibit WM-2. Mr. Tillman testified that the Commission has recognized the use of a

projected test year reduces regulatory lag and thus reduces risk to the utility. He

testified that the inclusion of CWIP in rate base also reduces risk to the company.468 As

discussed above, he also presented information regarding the rates of return on equity

authorized by other state regulatory commissions in his Exhibit WM-3.

9. Evaluation

In their briefs, the parties rely heavily on the analysis and testimony of their

witnesses as discussed above. Consumers Energy argues that the Commission should

accept Mr. Maddipati’s recommendations, and relies on his testimony that the

recommendations of the other analysts do not meet the requirements of Hope and

Bluefield. It further argues that any return on equity below 10.10% would not be

reasonable.

In its initial brief, addressing the argument of the Attorney General and Walmart

that its proposed ROE is “out of step” with the national downward trend of authorized

ROEs, Consumers Energy argues:

Once again, intervenor analyses of recent authorized ROEs fail to distinguish between those authorized ROEs granted to companies that have a poor track record of customer satisfaction and ROEs granted to companies that are leveraging a healthy business to customer service that

467 See 12 Tr 2758-2759. 468 See 12 Tr 2490-2491.

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meets or exceeds expectations. Good regulation appropriately reflects the importance of competitive ROEs, which properly provide utilities the tools to provide great customer satisfaction. Instead of aiming for that goal, intervenor analyses seek to “average down” the Company’s ROE by comparing Consumers Energy to companies that have poor performance with their customers and operate in unconstructive regulatory environments.469 Staff disputes Consumers Energy’s contention that its recommendation does not

meet the standards of Hope and Bluefield, or that it has mechanically applied the

quantitative models. Staff notes that its recommended return on equity is well above

the simple average of the results produced by its models. Staff argues that that it has

given consideration to both investors and ratepayers, and that the company’s criticisms

should be disregarded.

ABATE/Gerdau argue that the Commission should accept Ms. LaConte’s

analysis and recommendations. They acknowledge that her recommended return on

equity of 8.6% is lower than what the Commission has authorized in recent years, but

cite the evidence she presented that utilities have lower risk than they had in the past.

They challenge the risk premium/risk-free rate combinations in Mr. Maddipati’s CAPM

and risk-premium analyses, the growth rates used in his DCF analyses, his use of the

“comparable earnings” method, and his flotation cost adjustment. ABATE/Gerdau also

argue that the Attorney General and Staff recommended returns that are too far above

the results of their own analyses. MEC/NRDC/SC, in their reply brief, support

ABATE/Gerdau’s position and recommend a return on equity of 8.60%.

In reviewing the different analyses presented by the witnesses and the briefs of

the parties, it has long been recognized that there is no precise mathematical formula to

469 See Consumers Energy initial brief, page 115.

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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).470

This PFD finds that Staff’s analysis is objective and consistent with the analytic

framework relied on by the Commission in past cases, reasonably reflects economic

conditions expected in the test year, and should be adopted. Staff’s quantitative

analyses rely on a reasonable proxy group, and reasonable inputs to the quantitative

models, with recognition that higher interest rates are expected. The Attorney General’s

analysis also reaches similar results. Ms. Bankapur also testified that she considered

the company’s credit ratings, need for capital, and other factors presented in

Mr. Maddipati’s testimony. Staff’s analysis also properly excludes flotation costs,

consistent with the Commission’s prior decision.

While Mr. Maddipati characterizes his analysis and recommendation as

objective, and while he contended that the other witnesses were not objective, this PFD

finds that Mr. Maddipati’s testimony does not demonstrate objectivity.

Looking first at the proxy group selection, while each analyst should have some

flexibility in identifying an appropriate proxy group, for example in choosing the size

range to include, Mr. Maddipati unreasonably defended his choices of a company that is

470 Opinion, U-17990, 28, 2017, p. 66.

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largely a gas utility and a company that has been engaged in merger activity since

2016. Witnesses for the Attorney General and ABATE testified that two companies

should be excluded from the Company’s list. Mr. Coppola explained that NiSource is

classified as a natural gas distribution company, and both he and Ms. LaConte

explained that the company obtained the majority (66%) of its revenues from its gas

operations. Mr. Maddipati’s response was to assert that the company met the criteria

he specified for the proxy group, so it should be included.471 In addition, as discussed

above, both testified that Great Plans Energy is involved in a potential merger, and has

issued capital and incurred additional costs in preparation for the merger. When the

merger activity of Great Plains was pointed out in Mr. Coppola’s and Ms. LaConte’s

testimony, Ms. Maddipati initially claimed that the announcement of the acquisition had

not been made at the time he filed his testimony and therefore it was sufficient for him to

use the Great Plains data.472 In cross-examination, however, he acknowledged that the

announcement of the acquisition of Westar by Great Plains occurred in May of 2016.473

Mr. Maddipati provided no credible justification for keeping NiSource or Great Plains in

his proxy group after the errors had been pointed out to him.

Yet, Mr. Maddipati testified that the proxy groups chosen by each of the other

analysts did not meet the standards of Hope and Bluefield.474 In doing so, he insisted

that each proxy group should exclude companies that do not have a 60% dividend

payout ratio. Mr. Maddipati’s criterion that each proxy company have a dividend payout

ratio of 60% or more is different from the Staff’s and the Attorney General’s criteria that

471 See 10 Tr 1803. Note that he used a Bloomberg adjusted beta for the CAPM/ECAPM analyses because there was no Value Line beta for NiSource. See 10 Tr 1768. 472 See 10 Tr 1803. 473 See 10 Tr 1873. 474 See 8 Tr 1796, 8 Tr 1803-1804, 1813.

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each proxy company generally pay dividends. While Mr. Maddipati asserts that this

requirement ensures that the proxy group only includes companies with “similar

earnings retention practices”, he does not offer any reasons why similar earnings

retention practices is material to whether a company should be included in a

representative proxy group in this case. Indeed, he articulated an expectation that

companies that are planning significant capital investment would have a lower dividend

payout ratio than companies that are not planning significant capital investment.

Turning next to the flotation cost adjustment that adds approximately 17 basis

points to the results of the company’s modeling, this PFD finds that Consumers Energy

has not justified a change in the Commission’s prior determination that flotation costs

are not recoverable. In its December 22, 2005 order in Case No. U-14347, the

Commission rejected the application of such an adjustment for this utility:

The Commission also finds that the exclusion of flotation costs is appropriate. The Commission is persuaded that these costs are not costs incurred by the regulated utility. Consequently, it is not appropriate to include these costs in the calculation of Consumers’ return on equity.475

Mr. Maddipati has not justified a different result by his reliance on the Morin book, either

as to the general principle of cost recovery or the amount. While Consumers Energy

argues that “fairness” to Consumers Energy’s shareholder, CMS Energy, requires the

imputation of flotation costs, this ignores that CMS Energy chooses how to fund its

equity investment in Consumers Energy through retained earnings, equity, or debt. In

using a stand-alone capital structure for Consumers Energy, for example, the

Commission does not impute to ratepayers any of the benefits Mr. Coppola discussed

475 See December 22, 2005 order, page 24.

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from the parent company’s reliance on a greater percentage of debt in its capital

structure.

Another dispute between the parties involves the choice of inputs for the DCF

model. Ms. Bankapur, Mr. Coppola, and Ms. LaConte used estimates of projected

earnings growth in their DCF models. Mr. Maddipati used estimates of projected

dividend growth in his analysis, and criticized the other witnesses for using earnings

growth.476 Ms. LaConte explained that growth expectations are typically formulated

based on trends in earnings that will support future dividends, and she quoted

Mr. Maddipati’s direct testimony acknowledging the errors introduced by reliance on

dividend estimates.477 In the quoted portion of his direct testimony, Mr. Maddipati

stated:

[A] Company may have dividend growth that outpaces earnings growth, consistently outperforms guidance, or have irregular and other one-time dividends, all of which would cause the DCF model to misstate return on equity. These aspects must be kept in mind while interpreting the results of DCF analysis.478

Mr. Maddipati’s explanation on rebuttal was that the DCF model explicitly refers to

dividend growth, which is not persuasive. He also acknowledged on cross-examination

that the FERC opinion he cites heavily in his testimony used earnings growth in the

DCF model.479

Mr. Maddipati also contends that little reliance should be placed on the DCF

model, although as discussed above, he also performed a DCF analysis. In arguing

that the model results should be rejected or receive little consideration, he cites two

476 See 10 Tr 1789, 1798-1799, 1808, 1813; also see Consumers Energy initial brief, page 111. 477 See 12 Tr 2770; also see ABATE/Gerdau initial brief, page 13. 478 See 10 Tr 1778. 479 See 10 Tr 1846-1847.

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FERC opinions, Opinion 531 and 551, for the principle that “mechanical application of

the DCF model would result in a return inconsistent with Hope and Bluefield.”480 In

Opinion 531, FERC concluded that its previously authorized one-step DCF analysis

(using only short-term growth projections) should be changed to a two-step analysis

(averaging both short-term and long-term growth estimates). In addition, FERC decided

that it may consider whether market anomalies may affect the reliability of the DCF

analysis, and, if so, where within the DCF-analyzed proxy group ROE range a utility’s

ROE may be set. However, rather than having the presence of any such anomalies

negate the applicability of the DCF analysis as Consumers Energy implies, FERC

reiterated the propriety of the DCF model and indeed cautioned that alternative

methodologies (such as risk premium analysis and CAPM) may be considered only to

provide a comparison to the DCF analysis in order to assess whether the authorized

ROE should be moved from the mid-point of the DCF-analyzed ROE range:

[W]hile the DCF model remains the Commission’s preferred approach to determining allowed rate of return, the Commission may consider the extent to which economic anomalies may have affected the reliability of DCF analyses in determining where to set a public utility’s ROE within the range of reasonable returns established by the two-step constant growth DCF methodology.481

The opinion also stated:

In considering these other methodologies [risk premium analysis, the CAPM, and expected earnings analyses], we do not depart from our use of the DCF methodology; rather, we use the record evidence to inform the just and reasonable placement of the ROE within the zone of reasonableness [defined by the low and high estimates for the members of the proxy group] established in the record by the DCF methodology.482

480 See 10 Tr 1789. 481 Opinion 531 at par. 41, p. 21. 482 Opinion 531 at par. 146, p. 70.

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First, this PFD finds that Mr. Maddipati’s assertion that witnesses for Staff, the

Attorney General, and ABATE engaged in a purely mechanical application of the DCF

model is unsupported, since each of the witnesses gave careful thought to the selection

of inputs, and formulation of the model, as well as the conclusions to draw from the

results. Second, the language from the FERC opinions Mr. Maddipati quotes

references Federal Reserve actions that Mr. Maddipati acknowledged are being phased

out, with interest rates expected to rise. Third, the language Mr. Maddipati quoted, also

quoted in section 7 above, only indicates that the DCF and other models “may” cause

mechanical application of the models to not meet the required standards. Fourth, on

April 14, 2017, the D.C. Circuit Court of Appeals vacated FERC Opinion 531 and

remanded the matter to the FERC for further proceedings.483

The primary dispute between the parties regarding the inputs to the CAPM and

risk premium analyses involves Mr. Maddipati’s choice of risk-free rate and risk-

premium combinations. As discussed above, Mr. Maddipati believes that the Federal

Reserve’s quantitative easing has created such an anomalous situation that historical

risk premiums are not appropriate. As Consumers Energy argues in its brief:

Despite the well-documented intervention by central banks discussed above, which renders the assumptions behind the traditional CAPM and Risk Premium models inaccurate, Staff, Attorney General, and ABATE witnesses nevertheless each perform CAPM analyses using projections of yields on United States Treasury Bonds reflecting the current non-market based administered interest rates and historical risk premiums that are not reflective of investor expectations under current market conditions. 11 TR 2338-2339; 12 TR 2597-2598, 2752-2753. These treasury rates and risk premiums are not tied to current market forces, as Mr. Maddipati points out in his testimony. 10 TR 1742-1749. Similarly, Staff and the Attorney General each perform Risk Premium analyses that also fail to adjust the risk premium to current market conditions. 11 TR 2341; 12 TR 2599. Mr. Maddipati testified:

483 See Emera Maine v Federal Energy Regulatory Comm’n, 854 F3d 9 (2017).

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“[I]t has also been long recognized that there is no precise mathematical formula to determine a single appropriate ROE. However, reliance on analysis that is clearly flawed and fails to take into consideration current interest rates and market conditions certainly does not meet the standards of Hope and Bluefield. On page 8, lines 14 and 15 of my direct testimony, I recommended the Commission should ‘disregard any analysis that simply inputs numbers into quantitative models without acknowledging and addressing the inherent assumptions.’ Staff, the Attorney General, and ABATE witnesses did precisely that. Their analysis relied on quantitative models whose assumptions they simply failed to validate. Doing so makes the analysis subject to model risk and simply renders the output unreliable for determining a fair ROE that meets the standards established in Hope and Bluefield.” 10 TR 1786-1787.

Because each of these parties fails to adjust for artificially low treasury rates or historical risk premiums that do not correspond to current market conditions, their respective CAPM and Risk Premium analyses understate the Company’s required ROE and should be rejected.484 This PFD finds that Mr. Maddipati has not justified his choice of inputs for the

CAPM or risk premium analysis. While he disputes that historical risk premiums can be

applied to current or projected interest rates, his solution to use a fully-historical risk-

premium and risk-free rate based on 90 years of Ibbotson data lacks methodological

support, as does his solution to use the projected risk-free rate with only six years of the

Ibbotson risk-premium data from the years 2011 to 2016. In his direct testimony,

explaining why he used 90 years of Ibbotson risk-premium data, Mr. Maddipati

acknowledged that when calculated over short periods of time, the equity risk premium

can be very volatile.485

As he focuses virtually exclusively on the quantitative easing to the exclusion of

all other economic factors that may affect the relationship between risk and return, while 484 See Consumers Energy initial brief, pages 109-110. 485 See 10 Tr 1766.

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also acknowledging (like other witnesses in this case) that the program is winding down

and that economists expect interest rates to rise, Mr. Maddipati’s analysis appears

arbitrary. That the cost of equity capital may be difficult to project does not justify using

a small subset of historical data from a time period that is not expected to look like the

projection period. His reliance on an Ernst & Young paper and a paper issued by the

Federal Reserve,486 neither of which were presented in evidence, is not persuasive

evidence that there is “academic” support for Mr. Maddipati’s choice of inputs.

Likewise, while he asserts that he has support from “other ROE witnesses”, his

reference to an expert for Questar Gas Company in a rate case in Utah in 2016 who

used a “normalized” risk-free rate adjustment similar to his adjustment is not persuasive.

Instead, Staff’s analysis looks at risk premiums both over the entire duration of the

Ibbotson data, but more importantly, over the period from 1952 forward, to provide

consistency in Staff’s analysis.

Turning to the comparable earnings analysis presented by Mr. Maddipati, this

PFD understands the comparable earnings analysis has been recognized by the

Commission as an appropriate methodology to use in establishing a rate of return,

although as Ms. LaConte testified, it is not commonly used.487 However, as noted

previously, in this case Mr. Maddipati’s comparable earnings analysis produces a very

large range of return estimates among his proxy group, with the projected return on

equity for Dominion Resources calculated as 18.56%. This ROE is over 170% of the 486 Mr. Maddipati testified that the Federal Reserve study provided that risk premiums may “be as high as” 12% in low-interest-rate environments. See 10 Tr 1767. The record does not include the referenced study. 487 In Case No. U-16794, the Commission considered Mr. Rao’s “Value Line book value” analysis, which appears to be similar to Mr. Maddipati’s analysis. Also see Order, U-14347, December 22, 2005, p. 14 (“The DCF and CAPM models are widely used by regulatory agencies in deciding what rate of return to permit regulated utilities to earn, as are the risk premium and comparable earnings approaches.”)

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average comparable earnings ROE for the company’s proxy group. As such, this PFD

believes it is appropriate to reject Dominion’s projected ROE using this methodology for

purposes of this case. If the Dominion ROE is excluded, the average ROE for the

company’s proxy group is reduced from 10.75% to 10.10%. Indeed, the fact that

eliminating the projected ROE for one company from Consumers Energy’s proxy group

of thirteen companies results in the average ROE dropping by 65 basis points further

demonstrates that Dominion’s ROE is an extreme outlier that should not be included in

this analysis. Mr. Coppola discussed Dominion in the context of his capital structure

recommendations. He testified that Dominion “only recently issued new common equity

in the open market and is not representative at 29.4%[;] the peer group’s average

common equity ratio is 49%.” He further testified: “The cost of equity for those

companies in the peer group is highly depended on the financial risk reflected in their

capital structure.”488 It should be noted that Dominion Resources is not included in the

Staff’s proposed group of proxy companies.

Responding to testimony regarding authorized returns on equity by other

commissions, Mr. Maddipati presented Exhibit A-122 as a rebuttal exhibit. He testified

“any use of the [Regulatory Research Associates] data must also adjust for the

percentage of equity capital authorized to make an appropriate comparison of the

data.”489 On this basis, he increased the authorized returns provided by RRA for each

of the other utilities to the rate that would have been required to produce the same

earnings if applied to a capital structure with 40.79% equity, the equity percentage RRA

488 See 12 Tr 2585-2587. 489 See 10 Tr 1793.

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reported for Consumers Energy.490 The difference is not trivial; his adjustment changes

the average reported return on equity from 9.73% to 11.7%.

He subsequently acknowledged that the 40.79% equity capital ratio was taken

from Consumers Energy’s ratemaking capital structure. He acknowledged that it

therefore reflected ratemaking adjustments such as the provision for deferred income

tax. He then acknowledged he did not know what the data from the other jurisdictions

include.491

This adjustment is unjustified because the increased returns on equity

Mr. Maddipati reports in column k of this exhibit implicitly undo the important ratemaking

adjustments that are accomplished by using the ratemaking capital structure for

Consumers Energy. As Treasurer of Consumers Energy, Mr. Maddipati must have an

understanding of the purpose of the ratemaking capital structure, which he chose to

ignore in preparing this exhibit.

As a final observation, this PFD notes Mr. Maddipati’s testimony that Staff’s

recommended return on equity does not meet the standards of Hope and Bluefield,

even though it only results in a 30 basis point reduction to the authorized return on

equity. He testified:

Staff’s recommendation 9 of 9.8%, 30 basis points less than the presently authorized level of 10.1%, is based on flawed quantitative analysis, does not assure confidence in the financial soundness of the utility, does not support the ability to attract capital, and therefore does not meet the standards set forth in Hope and Bluefield.492

This ALJ understands that Mr. Maddipati strongly desires a higher return on equity.

However, for Mr. Maddipati, as Treasurer of CMS Energy and Consumers Energy, to 490 See 10 Tr 1867-1868. 491 See 10 Tr 1868-1869. 492 See 10 Tr 1794 emphasis added.

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claim that a relatively small, 30-basis-point reduction in the cost of capital for

Consumers Energy would “not assure confidence in the financial soundness of the

utility” calls into question his objectivity and judgment. The Commission issued its order

in Consumers Energy’s last rate case on February 28, 2017. In that case, Staff

identified a range of reasonable returns for Consumers Energy of 9.00% to 10.00%.

The Commission explained its findings:

The Commission finds that an ROE of 10.10% will best achieve the goals of providing appropriate compensation for risk, ensuring the financial soundness of the business, and maintaining a strong ability to attract capital. The Commission agrees generally with the ALJ’s analysis and his findings that Consumers’ proposed ROE of 10.70% is excessive, while the recommendations of ABATE and the Attorney General are unreasonably low. An ROE of 10.10% is only slightly above the Staff’s proposed range, and, as several of the parties observed, nationally, and in Michigan, ROEs are trending downward. Further, Michigan’s economy has improved considerably since Consumers’ ROE was set at 10.30% in 2012. In summary, the Commission finds that an ROE of 10.10% appropriately balances the interests of the company with the interests of its ratepayers, and will ensure investor confidence while protecting customers from unnecessarily burdensome rates.493 Based on the discussion and findings above, this PFD finds that Staff’s analysis

is objectively reasonable and consistent with past Commission decisions and its

recommended rate of return is reasonable, consistent with the requirements of Bluefield

and Hope, and should be adopted. Consumer’s requested return on equity is premised

on flawed modeling and unjustified assumptions and is outside the range of

reasonableness for Consumer’s. This PFD recognizes that the models produce results

which are generally below a 10% rate of return, but Staff’s 9.8% recommended return

also considers the utility’s continuing need for capital.

493 See order, pages 75-76.

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C. Overall Cost of Capital

There are no disputes among the parties regarding the long-term or short-term

debt costs, or the preferred stock rate to use in computing an overall costs of capital.

Using Consumers Energy’s revised capital structure with an equity percentage of

52.64%, with the return on equity of 9.80% recommended above, the revised cost of

long-term debt of 4.68%, a preferred stock cost rate of 4.50%, and a short-term debt

rate of 3.55% results in an overall weighted cost of capital of 4.81% as shown on

Attachment D.

VII.

ADJUSTED NET OPERATING INCOME

Net operating income (NOI) is calculated by subtracting the company’s operating

expenses including depreciation, taxes, and allowance for funds used during

construction (AFUDC), from the company’s operating revenue. Adjusted NOI includes

the ratemaking adjustments to the recorded test year NOI for projections and

disallowances.

A. Sales Forecast and Revenue

1. Residential sales

Mr. Breuring presented Consumers Energy’s residential sales forecast for the

test year. Explaining the residential sales forecast, he testified:

The Company was required under the 2008 Energy Law, Public Act (“PA”) 295, to help its electric customers reduce their energy usage by at least one percent per year. In 2016, State lawmakers reinforced the use of demand-side resources, such as EE, by amending the law to encourage utilities to expand the use of demand-side resources beyond the mandated floors. The Governor signed the 2016 Energy Laws, PA 341 and 342, on December 21, 2016. Although the Company is still required to

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help its customers reduce energy waste by at least one percent per year under the law, it is also encouraged to cost effectively expand its use of demand-side resources. As such, the Company has updated the electric deliveries forecast based on the Company’s commitment to help customers reduce energy waste by at least 1.5 percent per year beginning in 2017.494

Mr. Coppola reviewed the company’s sales projections, and concluded the

residential customer sales projection understated expected sales. He looked at

historical weather-adjusted sales data showing an average decline in per-customer

consumption of 0.3%, with actual declines in only two of those years, and increases in

the other three. He acknowledged the company’s plans to increase energy efficiency

program spending, noting too that the actual programs for 2017 are not planned to

change.495 He testified that the company’s 1.5% projected reduction in customer

consumption due to energy efficiency measures includes a 1% base decrease and a

.5% additional decrease from the additional effort, but testified:

If the assumed base energy efficiency reduction of 1% was actually occurring to the extent projected by the Company, then we should see steady declines in average usage per customer year over year. The actual data shows this is not happening. The Company’s energy efficiency program began nearly a decade ago with the enactment of 2008 PA 295. Therefore, either customers are not achieving the energy efficiency savings projected by the Company or other underlying energy consumption factors are occurring which offset most or all of the energy efficiency sales reductions. In either case, the Company’s projections of a decline in average sales per residential customer of 2.1% in 2017 and 1.1% in 2018 are not realistic.496

Mr. Coppola therefore recommended using the historical .3% rate of decline applied to

the 2016 actual per customer consumption through the test year, combined with the

494 See 8 Tr 1208. 495 See 12 Tr 2511-2512. 496 See 12 Tr 2510-2511.

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company’s projected customer count, to recommend a sales volume of 12,485,015

MWh, shown in Exhibit AG-2.497

In his rebuttal testimony, Mr. Bruering testified:

[T]he forecast uses economic indicators to capture the growth [expectations], as well as historical monthly electric deliveries. These factors, when combined with 1.5% energy efficiency, bring the residential growth rate down to the figure that I forecasted. As such, I believe the overall projected growth rate for the test year is reasonable.498

Further, he disputed Mr. Coppola’s skepticism that the company’s energy waste

reduction efforts would have the significant effect ascribed:

Mr. Coppola believes that since the Company does not plan on changing the structure of the currently approved energy efficiency programs, that the Company will not increase the energy efficiency savings. However, as explained by Company witness Theodore A. Ykimoff in his direct testimony in Case No. U-17771 (Amended EO Plan), “the Company expects to exceed the electric and gas statutory savings targets of 1.00% and 0.75% by at least 0.57% and 0.29%, respectively.” Additionally, pursuant to Public Act 342 of 2016, there are no spending caps associated with Energy Waste Reduction investment as long as the Company is delivering a cost effective portfolio of programs. As part the Company’s Amended Plan filing in Case No. U-17771, the Company requested additional investment to deliver increased energy savings and that incremental investment was approved. Mr. Coppola also believes that “it is difficult to give any credence” that the same programs will be able to generate a greater degree of savings even though the programs have been regularly producing greater than 1% savings historically.499

Consumers Energy argues that the Attorney General is ignoring numerous

values and the extensive analysis Consumers Energy considered as part of its

modeling, and failed to consider the energy efficiency savings resulting from the

increased energy efficiency spending approved in Case No. U-17771.500 It argues that

its energy efficiency efforts have regularly been producing savings greater than

497 See 12 Tr 2507-1513. 498 See 8 Tr 1213. 499 See 8 Tr 1213-1214. 500 See Consumers Energy brief, pages 120-122.

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1% historically (page 121). In its rely brief, it characterizes the Attorney General’s

adjustment as simplistic, based on a simple average of historical numbers, and

reiterates its argument that the Attorney General’s recommendation fails to consider the

multitude of factors and the energy efficiency efforts Consumers Energy considered.501

This PFD finds that Consumers Energy has not adequately justified the

1.5% adjustment to its forecast to reflect increased energy efficiency efforts.

Consumers Energy acknowledges that its programs have regularly been producing

savings of 1% per year, but neither accounts for the effects already included in the data

nor explains why the data does not reflect equivalent rates of decreased consumption.

Clearly the company’s past efforts to reduce per capita consumption by 1% annually

have not resulted in equivalent or corresponding annual decreases in actual per capita

consumption. As Mr. Coppola testified, the most logical explanation is that there are

other factors influencing per capita consumption that the company has not accounted

for. Consumers Energy has made no effort on this record to demonstrate the predictive

power of its modeling, or any basis for its adjustment other than the commendable

target it has set in Case No. U-17771. The company’s argument that Mr. Breuring took

into account more factors and is thus not “simplistic” is unpersuasive given that the

record does not show exactly what factors he considered or how he considered them.

Consumers Energy cites Mr. Breuring’s testimony at 8 Tr 1204-1205:

The electric deliveries and peak demand forecasts are prepared using a combination of econometric and end-use techniques. Typically, a six-step process is used in developing the electric deliveries forecast. The first step in the process is gathering the class-level historical monthly electric delivery, monthly customer counts, monthly number of billing days, monthly binaries to account for temporal cycles, and daily temperature information. Most observations are entered directly into the modeling


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framework as dependent and explanatory variables. The daily temperature information, however, is transformed to monthly HDD and CDD variables prior to entering the modeling framework. The second step is importing the Michigan population, industrial production, manufacturing employment, and automotive employment variables from IHS Markit into the sales modeling framework. The third step is importing electric use forecasts for wholesale, electric vehicles, polycrystalline production, and energy savings from the Company’s Smart Energy and Energy Efficiency (‘EE’) programs. These forecasts are exogenous to the modeling framework and were either adopted by the Commission in prior electric rate cases, reflect current industry expectations, or are based on end-use analyses. The fourth step is reviewing the imported observations to identify data issues before running the econometric models. In situations when erroneous data is observed, it is either corrected where possible or removed from the models. The fifth step is executing the regression functions and reviewing the corresponding statistical metrics. The final step in the sales forecasting process is to combine the regression forecasts with the external forecasts imported in step three.

While Consumers Energy argues that this shows the extensive analysis the company

performed, this testimony acknowledges exactly what Mr. Coppola focused on: “The

final step in the sales forecasting process is to combine the regression forecast with the

external forecasts imported in step three,” which are “exogenous to the modeling

framework.” Moreover, this general explanation and the discussion of the company’s

energy efficiency goals quoted above is essentially all the supporting explanation

Consumers Energy provided for its residential sales forecast. Not only did Consumers

Energy not justify its combination of its modeling results with its exogenously

determined energy efficiency projection, it did not justify its modeling framework or

regression results.

Thus, this PFD finds that Mr. Coppola’s reliance on the 0.3% historical rate of

declining use per customer is more reasonable for ratemaking than the company’s

projection that per-customer consumption will decrease at an annual rate of 1.6%.

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2. RIA and RSC Customers

Staff recommended an adjustment to the projected number of RIA and RSC

customers. Regarding the senior citizen rate, Mr. Isakson recommended using the

2016 average monthly customer count, explaining:

Customer counts for the RSC provision vary slightly from month to month in 2016, but setting the customer count to the annual average allows the Company to recover revenue to provide the provision throughout the test year. Additionally, because customers are automatically enrolled in the RSC provision, it is unlikely that the overall annual customer count will vary significantly unless Michigan becomes a popular retirement destination in the near future502.

Regarding the income-assistance rate, Mr. Isakson testified there has been a steady

decrease in customers taking the RIA provision over the previous 5 years. He

recommended using the 2016 average monthly customer count of 47,990.503

In its rebuttal filing, Consumers Energy adopted Staff’s projected customer count

for the residential senior citizen provision.504 Consumers Energy continues to dispute

the number of low-income customers that will be enrolled in the RIA program in the test

year. In his rebuttal testimony, Mr. Breuring responded that the company’s projected

count of 53,000 RIA customers is conservative given enrollment data for the first seven

months of 2017.505 He presented a chart showing enrollment increasing monthly from

January through July of 2017, with an average enrollment of 57,492.

In its brief, Staff argues that data over only seven months of a calendar year is

not fully reliable, since there may be effects seen over a full 12 months not reflected in

the partial year. Nonetheless, this PFD finds that the company’s projected customer

502 See 11 Tr 2234. 503 See 11 Tr 2234. 504 See Myers, 7 Tr 796. 505 See 8 Tr 1214.

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count is reasonable to rely on for ratemaking purposes. Acknowledging that the partial

year of data for 2017 may not be fully representative of what is likely to happen over the

course of the year and into the projected test year, the 57,492 average is significantly

above the company’s projected test year count of 53,000, and each month shows an

increase over the prior month, rather than showing any volatility.

B. Fuel & Purchased Power Expense

Consumers Energy’s projected fuel and purchased power expense is shown in

Exhibit A-8, Schedule C1, line 5, on both a total company and jurisdictional basis.

Ms. Walz presented projected fuel and purchased power expenses, with alternate

projections depending whether the Commission approved the company’s proposed

Palisades buy out and securitization plan in Case No. U-18250. With that case

resolved, there is no dispute among the parties. Staff incorporated the same values in

its analysis, as shown in Exhibit S-3, Schedule C1. No party took issue with the

projections.

C. Other O&M Expenses

Consumers Energy presented a breakdown of its projected test-year O&M

expense projections in Exhibit A-8, Schedule C5. The company initially requested an

O&M expense allowance of $627,602,000, which it has reduced to $613,875,000, a

reduction of $13.7 million as shown in Attachment C to its brief.

As shown in Exhibit S-3, Schedule C5, Staff’s initial filing recommended

operating expenses of $538,288,000; in its brief, Staff revised its O&M expense

recommendation to $587,187,000, or approximately $27 million below the level

Consumers Energy is now requesting, based on the adjustments presented in

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Attachment C to Staff’s initial brief. The Attorney General recommended an O&M

expense reduction of $76.7 million to the company’s initially-filed request, or an O&M

expense projection of approximately $550,902,000.

1. Projected Expense Savings

As Mr. Welke testified, Staff initially recommended a 2% overall reduction in

O&M expenses to reflect cost-reduction measures the company told its shareholders it

was planning to implement.506 He acknowledged that the company stated in discovery

that it did not have an operating plan to achieve the savings. He also testified that the

company’s investment in a lean operating system called CE Way should facilitate these

savings. He explained the calculations underlying Staff’s recommended adjustment to

reflect these savings.

In rebuttal testimony, Mr. Denato testified that the company does not have

specific, detailed operating plans to achieve these cost reductions.507 He testified that

the investor presentation Staff relied on “is based on a long-term, historical trend and a

broad longer-term goal.”508 He stated: “Future cost reductions should not be

incorporated into ratemaking before they can be supported, known or measurable.”509

He also pointed out that the savings estimates presented to investors were

accompanied by the disclaimer that they were subject to risk and uncertainty.510

Mr. Denato testified that over the last six years, Consumers Energy has achieved

average cost reductions of 2.3% per year, but the reductions have not been consistent

506 See 11 Tr 2463-2466. 507 See 9 Tr 1363-1375 508 See 9 Tr 1364. 509 See 9 Tr 1364. 510 See 9 Tr 1364.

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year-to-year, presenting a chart from 2011 forward.511 He also acknowledged that the

company’s goal is to continue the reduction, while stating that investments are required

to realize O&M savings, and explaining the sources of upward pressures on costs. He

opined that Mr. Welke had not fully considered the factors causing cost increases in

making his recommendation.512 He also contended it was duplicative of certain other

Staff adjustments.

In its initial brief, Staff indicated that it is withdrawing this proposed adjustment,

but summarizes its position as follows:

Based on information that the Company provided, Staff cannot . . . determine the impact these savings will have on the revenue requirement, and the Company cannot either. The Company admits, however, that there are projected savings that are not incorporated in the revenue requirement in this case. (11 TR 2463.) The Company also admits that its Board-reviewed budget includes $71 million in an “unresolved task,” which it says is for “O&M Reductions” for 2017 and 2018. (9 TR 2466.) And despite not having an “operational plan” to capture these savings, the Company admits that “there [is] a large number of initiatives going on to focus on O&M in 2018.” (8 TR 1105.) Although Staff recommended, in testimony, that the Commission reduce the Company’s revenue requirement to capture the savings it told shareholders it could achieve, Staff is backing away from this recommendation since the Company did not provide enough information to calculate the savings. Instead, Staff recommends that the Company quantify, it its next rate case, the savings it achieves after the “large number of initiatives going on” have had time to work. If these initiatives do not yield results, Staff recommends that the Commission require the Company to explain why.513 In its reply brief, Consumers Energy reviewed some of the record testimony,

disputing that there are a “large number” of initiatives under way. The company cited

the CE Way initiative discussed by Mr. Torrey and Mr. Harry as a company-wide

511 See 9 Tr 1365. 512 See 9 Tr 1367. 513 See Staff brief, pages 91-92.

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initiative aimed at reducing O&M by 2-3% annually after the initial five-to-ten-year

journey, but distinguished Ms. Hill’s testimony as addressing a cost-reducing initiative

only within her department.514 Consumers Energy further responds:

The Company submits that Staff’s proposal, coming as it did very late in the proceedings and after the close of the record, is not sufficiently well defined for the Company or the Commission to understand what initiatives the mandate would apply to, how Consumers Energy would be expected to quantify the results of those initiatives, or whether it would be possible to do so. The Company believes that there may be some meaningful opportunity for collaboration with Staff on this issue, but it is premature for the Commission to include Staff’s vague proposal as part of its final order in this case. Instead, the Company is willing to commit that it will work with Staff to share information regarding the various company-level initiatives Consumers Energy is working on in order to promote O&M cost savings. The Company is receptive to feedback from Staff, in the context of that collaborative, to help identify the information that would be most helpful to them in order to understand the Company’s efforts and track the results.515

This PFD concludes that both suggestions are reasonable. The company’s generally

successful efforts to reduce O&M costs once rates are set is an example of “regulatory

lag” that benefits the utility. Because capital investments funded by ratepayers drive

some of these costs savings, it is reasonable for the utility to keep Staff informed on its

progress, as Consumers Energy offered in its reply brief as quoted above. It also does

not seem onerous for the utility to provide a report in its next rate case summarizing its

cost-cutting initiatives to date.

In the sections that follow, the arguments of the parties are discussed in order of

the line items in Exhibit A-8, Schedule C5.

514 See Consumers Energy reply brief, pages 122-124. 515 See Consumers Energy reply brief, page 124.

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2. Electric Distribution O&M (Exhibit A-8, Schedule C5, line 1)

Mr. Bordine testified in support of the company’s proposed electric distribution

system O&M expense projections. As described above, he reviewed system

performance metrics including CAIDI, SAIDI and SAIFI both with and without major

events. His Exhibit A-14 shows total electric distribution division O&M expenses offset

by $19.2 million of savings attributable to the AMI investment, explained by

Mr. Warriner. Exhibit A-15 shows projected spending for four departments within the

division: energy operations, energy delivery, operational and financial planning and

performance, and customer operations excluding uncollectible write-offs. Exhibit A-16

has the programmatic breakdown for each of the four departments. Staff and the

Attorney General recommend reductions in the projection for line-clearing expense; the

Attorney General also recommends a reduction for the Smart Energy-MTC cost

projections transferred from Mr. Warriner’s responsibility.

a. Vegetation Management (Exhibit A-16, line 8)

As shown in line 8 of Exhibit A-16, Mr. Bordine testified that Consumers Energy

is projecting it will spend $66.5 million in the test year on its line-clearing program,

$59.9 million of which will be spent on the low-voltage distribution (LVD) system. He

testified that this level of spending, adjusted for inflation, was recommended by an

outside consultant in March of 2014, and equates to a seven-year clearing cycle.516

To support the reasonableness of the company’s requested electric distribution

system funding level, he provided a cost-comparison of Consumers Energy to other

utilities in Exhibit A-18 based on FERC Form 1 reports showing Consumers Energy in

the second quartile of distribution system O&M expenditures per customer. Focusing 516 See 6 Tr 380-381.

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on the importance of line-clearing, he also provided various benchmark statistics for a

group of utilities compiled by CN Utility Consulting, Inc., comparing Consumers Energy

to the other utilities by descriptive measures including tree-trimming cycle length, tree-

related outages, trees per LVD system mile, line-clearing cost per LVD system mile, and

average annual cost per customer. He concluded that Consumers Energy’s line-

clearing operation is funded well below average for the participating utilities, per mile

and per customer, and that this funding level adversely impacts reliability.517 He

testified that the funding level Consumers Energy is requesting for the test year would

provide for a 7-year clearing cycle as recommended by a 2014 third-party report.

Mr. Laruwe recommended that the Commission authorize the level of expense

most-recently authorized in Case No. U-17990, adjusted for inflation, plus an additional

allowance of $1 million to address problem trees outside the right-of-way, for a total

expense allowance of $51.8 million. He explained Staff’s concerns both with the

company’s commitment to spending all provided funding and with its ability to

significantly increase its efforts.518 He explained the difficulty obtaining workers, and his

concerns that company’s plan calls for 50-60 hour work weeks for its labor force,

“weather permitting.”519 He also explained Staff’s concern with the company’s

commitment:

Since the Commissions last approved program increase in 2013 the Company has underspent $26 million and deferred what Staff estimates to be 3,628 miles of trimming. In 2016 it was the first year that the Company actually spent the Commission’s most recent Commission approved program spending budget for the tree trimming program. The reasoning behind this habitual underspend was, according to the Company, due to higher storm expenses and a need to adjust spending in other programs

517 See 6 Tr 384-386. 518 See 11 Tr 2387-2390. 519 See 11 Tr 2388.

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to address these issues. Staff believes this explanation as to why the Company consistently fails to spend approved tree trimming budget is unreasonable and imprudent. Tree trimming is undeniably the most important customer facing operations and maintenance program the utility runs. Given the importance of this program, including it in the consideration of programs to cut spending is imprudent.520 Mr. Coppola also reviewed the history of expenditures in this category. In

Mr. Coppola’s opinion, recent increases in line clearing spending have not made a

difference in the cumulative outage minutes experienced by customers.521 He also

questioned the company’s commitment to spend the necessary amount to achieve the

level of line clearing it believes is required to significantly reduce outages.522 He

recommended a test-year line-clearing allowance of $50.8 million, which he

characterized as the highest amount spent by the company in recent years, and a

$2.3 million increase over the amount approved in Case No. U-17990.

In his rebuttal testimony, Mr. Bordine agreed with Mr. Laruwe’s testimony

regarding the importance of expenditures in this area, and he agreed that Consumers

Energy has not always spent rate case funding levels due to higher service restoration

(storm) expenses.523 Citing information included in Exhibit S-16, he testified that since

2013, the company has exceeded the combined service restoration and line clearing

expenses provided for in rates by an average of $8 million annually.524 Mr. Bordine

disputed that the company faces any difficulty obtaining resources to accomplish the

520 See 11 Tr 2388-2389. 521 See 12 Tr 2516. 522 See 12 Tr 2517. 523 See 6 Tr 443. 524 See 6 Tr 443.

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tree-trimming, and asserted that the company is committed to allocating the resources

necessary.525

Mr. Denato also addressed this expense element in his rebuttal testimony,

disputing that the company’s underspending on tree-trimming in past periods was

unreasonable or imprudent, and pointing to overspending in other areas, including

storms, and testified that the company’s O&M spending for 2017 to date was above

rate-case authorized amounts.526 He testified that the company has spent $13 million

more than authorized so far in 2017, including $55 million on storms, or $20 million

more than authorized.527 Mr. Denato also objected to the characterization of the

company’s underspending in the tree-trimming program as an imprudent managerial

decision:

Company underspending in one or two O&M categories for a certain period cannot be observed in isolation. The Company needs to manage the business as a whole, balancing over-spending in some programs and under-spending in others based on emergent priorities as circumstances change throughout the year, some portions of which (storms for example) are out of the Company’s control. The Company’s overall goal is to provide safe, excellent operations while providing exceptional value and service to customers.528 This PFD finds that Staff and the Attorney General have correctly concluded that

Consumers Energy has not established its commitment to spend the projected amounts

during the test year. While the company relies on a third-party report, that report was

obtained in 2014, and the company’s expenditures since then have been only

$37 million in 2015 and $50.8 million in 2016, with 2017 expenditures projected to be

525 See 6 Tr 443-444. 526 See 9 Tr 1375-1376; also see Maddipati, 10 Tr 1824-1825 addressing the grid modernization capital spending. 527 See 9 Tr 1369. 528 See 9 Tr 1375-1376.

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$48.1 million. The monthly expenditure projections in A-35 are not persuasive that the

company is committed to increased reliability spending in future months. While

Mr. Bordine himself seems sincerely commitment to the spending plan he presented, on

cross-examination he acknowledged that he does not control the funding determinations

for these expenditure categories, and does not know how those levels are

determined.529 The Commission can further consider the company’s commitment to

distribution system reliability including vegetation management when it reviews the

company’s five-year distribution system plan.

b. Smart Energy-MTC (Exhibit A-16, line 20)

Mr. Coppola also took issue with projected $8.3 million O&M expenses on line 20

of Exhibit A-16 for the smart energy program, citing a 41% increase over 2016 levels.530

He testified that the company had not explained the rationale for this level of increase,

and recommended that the Commission adopt the 2016 expenditure level. In his

rebuttal testimony, Mr. Bordine disputed that the company had not provided an

explanation for the projected expenditures:

On page 2 of 3 of Exhibit AG-5 (Discovery Response No. 18322-AG-CE-173), the Company provided an explanation that the Smart Energy – MTC O&M costs were primarily the cost of software maintenance for Advanced Meter Infrastructure (“AMI”) meters and the cost of remote communications with AMI meters. As operational costs associated with AMI meters, the increase results directly from the increase in the number of AMI meters installed during the test year compared to the historical 2016 actual. The direct testimony of Company witness Lincoln D. Warriner indicates on page 10, line 11, that cumulative meter upgrades were 45.3% complete at the end of 2015 and 74.9% complete at the end of 2016. On average, the calendar year 2016 cumulative meter installations represent 60.1% of the total full AMI implementation ((45.3%+74.9%)/2=60.1%). The test year time period will be 100% complete with electric meter upgrades; therefore, the increase in O&M costs is explained by the increase in

529 See 6 Tr 463-464. 530 See 12 Tr 2518-2519.

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cumulative electric meter upgrades. These operating costs are reasonable and prudent as they are necessary to maintain AMI meter functionality and utilization of communications infrastructure.531 In his brief, at pages 15-16, the Attorney General does not address Mr. Bordine’s

rebuttal testimony. Consumers Energy argues in its reply brief that Consumers Energy

explained the reason why test year expenses were projected to be greater than 2016

costs.532 This PFD finds that it is reasonable to accept the company’s explanation,

which was provided in discovery.

3. Energy Resources (Generation) O&M (Exhibit A-8, Schedule C5, line 2)

Both Staff and the Attorney General recommend adjustments to the

environmental operating category of expenses: Staff recommended an adjustment of

$4.7 million as explained by Mr. Evans; Mr. Coppola recommended two adjustments to

the O&M expense projections included on Exhibit A-60, one for the environmental

operating expense projection, and one for the residential demand program.

MEC/NRDC/SC also recommend that the Commission exclude O&M costs for the

Medium 4 units that are avoidable under an early retirement scenario.

a. Environmental Operating Expense (Exhibit A-60, line 3)

Mr. Evans recommended a reduction of 30% or $4.7 million to the company’s

test year expense projection of $15.5 million to reflect what he characterized as chronic

underspending in this category.533 He testified that this underspending had also been

addressed in Case No. U-17990, and reviewed subsequent information showing

underspending for 2016. Explaining the magnitude of Staff’s adjustment, he testified:

531 See 6 Tr 448. 532 See Consumers Energy reply brief, page 127. 533 See Evans, 11 Tr 2297-2299.

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1) During the time period of 2013 – 2016, the Company only spent 58.7% of its total projections in this category; and 2) the average of the percentages of actual vs projected spending is 65.9. Staff’s downward adjustment is therefore less than the amount of over-projecting that has occurred since 2013 on a total spending vs total projection basis, and on an average percentage basis.534 Mr. Coppola recommended an adjustment to the environmental operating

expense projection. He testified the company is projecting a $7.2 million increase from

2016 spending levels, in part related to the installation of new facilities to comply with air

quality regulations. He found the $4.5 million increase projected to Spray Dry

Absorbers unjustified, citing Exhibit A-38 to show that most installations were completed

in 2015 and early 2016. He testified that as of May 2017, the company had spent only

$4.8 million, which equates to an annual expenditure of $11.5 million in comparison to

the projected $14.6 million. He therefore recommended a $3 million reduction to reflect

this level, testifying that the resulting $12.3 million expense allowance is $4.2 million

above 2016 levels, a 48% increase.535

In her rebuttal testimony, Ms. Hill responded that her Energy Resources group

expenditures from 2013 to 2016 were 97.8% of the total O&M expenses included in

rates, presenting Exhibit A-112:

[W]hile Consumers Energy may spend less than projected on some individual categories, as a whole Energy Resources allocates its resources in a reasonable and prudent manner to provide safe and reliable service to its customers.536

She presented discovery responses showing budget reallocations resulting from

operational changes such as delayed Air Quality Compliance Strategy projects, and


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showing that non-fuel O&M is managed “as a fleet.”537 She also testified that using

2017 expenditures of almost $7 million through July, the company is on track to spend

“at least” 84% of the filed 2017 projection of $14.6 million. She similarly responded

regarding Mr. Coppola’s analysis, also explaining how the company forecasts its

environmental O&M expenses.538

In its brief, Consumers Energy relies on Ms. Hill’s rebuttal testimony.539 It argues

that budgets can change and that budget reallocations are common, and also

emphasizes that 2017 is the first full year of operation for the AQCS system at the

Campbell plant.540 In its brief, Staff argues that the company has over-projected its

environmental O&M expense in the past and is likely to do so again. Staff quotes the

Commission’s February 28, 2017 order in Case No. U-17990, finding that the company

had overprojected its environmental O&M expense requirements in Case No. U-17735,

and Staff then cites the same order as providing $15.35 million for environmental O&M

for 2016, while the company spent only $8.32 million.541 Staff reviews Ms. Hill’s rebuttal

testimony explaining that budget reallocations were made in 2016, and argues that the

company did not identify the specific reallocations.542 Staff argues that it is

unreasonable to expect ratepayer funding for an O&M expense that year after year is

used for other activities and projects which may or may not have been determined to be

reasonable and prudent by the Commission. Next, Staff addresses Ms. Hill’s rebuttal

argument that the expenses should be viewed as part of a whole. Citing her rebuttal

537 See 8 Tr 1088-1089, Exhibits A-110, A-111, andA-113. 538 See 8 Tr 1092-1093. 539 See Consumers Energy brief, pages 137-138. 540 See Consumers Energy brief, pages 137, 139. 541 See Staff brief, pages 82-83. 542 See Staff brief, pages 83-84, citing Exhibit A-110 and A-111.

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Exhibit A-112, Staff argues that it does not dispute that Consumers Energy spent 97.8%

of the total O&M provided in rates between 2013 and 2016, but argues that the

Commission should not find this fact persuasive because the broad-level approach the

company is advocating deprives the Commission of the ability to meaningfully review

the company’s spending plans:

While Staff is not contesting these facts, the Commission should still reject this “look at the total” argument. If the Commission were to accept this argument, the Company and other utilities could argue that chronic over-projecting (or over- spending) within individual categories does not matter, as long as spending within the parent category is close to its projection. The end result is that the notion of projected costs within individual, bottom-level categories would become meaningless, and only the projections of a handful of top-level parent categories would matter. Since this would cause a loss of credibility and transparency regarding the utilities’ spending plans during the test year, the Commission should reject this argument.543

Staff also addresses the company’s claim that Staff did not consider that 2017 is the

first full year of the operation of the Air Quality Control System at the Campbell plant,

arguing that the company did not explain how that will affect its spending in the test

year.544 Staff also argues the Attorney General’s adjustment is too small.

In its reply brief, Consumers Energy argues that the Commission should not

reduce the expense projection without considering the company’s overall actual energy

resources group O&M spending.545 It further responds to Staff’s argument:

Staff contends that the Commission should reject this argument because of Staff’s belief that “projected costs within individual, bottom-level categories would become meaningless.” Staff’s Initial Brief, page 85. Considering Energy Resources O&M spending as a whole does not make the individual categories “meaningless,” but rather permits Consumers Energy the flexibility to make reasonable and prudent decisions to operate

543 See Staff brief, pages 84-85. 544 See Staff brief, pages 85-86. 545 See Consumers Energy reply brief, pages 112-114.

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the business and to respond to emergent circumstances in order to provide safe, reliable, world class service to customers.546 This PFD recommends that the Commission adopt Staff’s recommended

adjustment. That the company is only 84% below projected spending levels for 2017,

according to information Consumers Energy presented in rebuttal, while in the middle of

an ongoing rate case, is not persuasive that the company’s expense projection for the

test year should be accepted. Likewise, that the company spent some of the money not

spent as projected in Case No. U-17990 on Jackson and Zeeland plant activities, along

with additional sums, does not justify the company’s claim that its environmental O&M

expense base should be considered to include those items. Exhibit A-110 states in item

4 that “Minor expenses (originally budgeted in Case No. U-17990 as Environmental

Operations) for Decommissioning activities and operations of the Zeeland and Jackson

Generating Plants were assigned to Base O&M.”547 Then the discovery response

states: “Due in part to the changes in item 4, Energy Resources 2016 Actual Base

O&M was more than $5 million higher than projected in Case No. U-17990.”548 Nothing

in this information indicates that the projected environmental O&M expense level

recommended by Staff should be $5 million higher. Note that the “base O&M” expense

level that included the $5 million historical expense has been separately determined for

the projected test year.

Exhibit A-112 showing total O&M expense for energy resources from 2013

through 2016 in comparison to rate case amounts shows actual spending for all

generation categories below projected levels for each of the years, but on average, only

546 See Consumers Energy reply brief, page 113. 547 See Exhibit A-110, emphasis added. 548 See Exhibit A-110, emphasis added.

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a little over 2% below. This is not persuasive evidence that Consumers Energy should

have a greater environmental expense allowance than recommended by Staff. The 2%

difference over the 4 years equates to $13.5 million, and does not establish that Staff’s

overall projected level of spending for this category is unreasonable.

b. Avoidable Major Maintenance Expense (Exhibit A-60, line 6)

MEC/NRDC/SC recommend the exclusion of all avoidable O&M expenses for the

Medium 4 units.549 As shown in Exhibit A-119, they identify one maintenance project

with an estimated cost of $175,000 for the Campbell plant. Because this PFD

concluded that the company’s analysis of the Medium 4 retirement scenarios was

inconclusive, and recommended that Consumers Energy be required to complete and

submit further analysis both on a stand-alone basis and as part of its IRP analysis, this

PFD concludes that it is unnecessary to make such a minor adjustment in the

company’s projected major maintenance O&M expenditures, which are projected to

total $26.3 million in the test year.

c. Residential Demand Response Program (Exhibit A-60, line 4)

After noting the company’s projected expenses of $4.8 million in 2017 and

$5.9 million for the projected test year for demand response activities, Mr. Coppola

recommended a reduction of $1.1 million in the projected expenditures for this category,

noting that 2016 spending was only $1 million.550 For the residential demand response

programs to be funded, the Air Conditioning Peak Cycling and the Time of Use (TOU)

programs, he testified that the company’s projected enrollment figures are overly

optimistic. He reviewed 2017 program expenditures through May of 2017 of

549 See MEC/NRDC/SC brief, page 41. 550 See 12 Tr 2522-2523.

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$1.5 million, which he annualized to $3.7 million, and recommended that the

Commission include this current level of expenditure in the test year O&M expense

projections.

As discussed above, Ms. Hill provided rebuttal testimony indicating the company

had enrolled 20,000 customers in the AC load control program by the end of July 2017,

with a target of 26,000 by December 2017. She testified that the company has enrolled

9,000 customers in its time-of-use programs through July of 2017, and is projecting

23,000 by the end of the year. Mr. Warriner also provided rebuttal testimony regarding

the company’s projected enrollments.551 Ms. Hill did not directly respond to

Ms. Coppola’s testimony that the company’s spending through May 2017 appears to be

lagging behind projected values, but instead addressed the company’s current and

projected enrollments as discussed above.552 The Attorney General does not discuss

this rebuttal testimony in his brief.

As discussed above, this PFD found Staff’s recommendation to limit the AC load

control program based on prior Commission orders to be reasonable. Nonetheless, the

Commission has encouraged the company to engage in demand response activities,

and has set in place a framework for reviewing those activities. There are also, as

discussed below, myriad additional activities that Consumers Energy ought to take.

Because the company will be accountable through the process provided in Case No.

U-18369 for its spending choices for O&M funding provided in rates, this PFD

recommends that the Commission allow the projected $5.9 million expenditure.

551 See 6 Tr 328. 552 See 8 Tr 1094.

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4. Information Technology (Exhibit A-8, Schedule C5, line 4)

The company’s proposed expense level of $53.9 million for the projected test

year is shown in Exhibit A-74. Mr. Coppola objected to the projected $9.2 million

increase in this category over 2016 levels, citing Exhibit AG-9 to show that the

company’s projection reflects 39% or $4.3 million increase in “staffing” and a similar

increase of $4.6 million for “contract costs.” He testified that Exhibit A-73 does not show

an increase in the number of employees, and shows an increase of only 4 contractors.

He acknowledged a discovery response from the company indicating that the

implementation of 4 new IT systems in June 2016 will cause higher maintenance costs

of $2.1 million in the test year. He recommended accepting the projected increase for

the maintenance expense and rejecting the remaining $7.1 million of the projected

increase.553

In his rebuttal testimony, Mr. Varvatos testified that the expenses were not

developed based on employee and contractor counts, but by project planners using

staffing as a cost element, along with managed services, contracts, and business

expenses. While the Attorney General argues that the company has failed to support its

expense projection,554 Consumers Energy argues that the Attorney General’s proposed

reduction is “based on an erroneous comparison of unrelated matters.”555

This PFD finds that it is reasonable to consider the company’s presentation in

Exhibit A-73 as an oversight and adopt the expense projection based on Mr. Varvatos’s

explanation, but in future cases, the Commission should expect better consistency in

reported staffing and contractor levels. 553 See 12 Tr 2529-2530. 554 See Attorney General brief, pages 22-23 555 See Consumers Energy brief, page 150.

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5. Employee Benefit Expense (Exhibit A-8, Schedule C5, lines 6 and 12)

Mr. Kops presented the company’s projected expenses for its pension funding

and other post-retirement employee benefit expenses (OPEB). His Exhibit A-65

provides line items 1 and 7. He testified that the company’s pension expense is

determined using an actuarial analysis. He testified that there are four components to

the analysis: 1) service cost, representing the value of the benefits earned during the

year; 2) interest cost, used to discount the stream of future benefits to a present value;

3) the expected return on plan assets; and 4) amortization of gains or losses, prior

service costs, and any transitional amounts.556 He testified that in order to determine

the company’s total obligation and annual expense, the actuary relies on a number of

assumptions determined by the company including the interest or discount rate,

mortality table, salary change, expected return on plan assets and expected future

contributions needed under the Pension Protection act.557 He testified that the pension

plan expense shown on line 1 of Exhibit A-65 also includes plan administration fees

Pension Benefit Guarantee Corporation premiums. He also explained how costs are

allocated between gas and electric operations, and identified reasons for the decrease

in costs from 2015 to 2016 and the projected increases in 2017 and 2018.558 He

testified that the premiums are due unless the company makes a pension plan

contribution, and as of September 1, 2017, it has no plans to make a contribution.559 As

discussed in section a below, Staff takes issue with the company’s projected increase in

Pension Benefit Guarantee Corporation premium expense, while the Attorney General


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takes issue with a recent change in the discount rate used to project pension and OPEB

expenses.

a. PBGC Premiums

Staff recommended one adjustment to the pension expense projection for

Pension Benefit Guarantee Corporation insurance premium and actuarial fees.

Mr. Welke reviewed the history of expenditures for this category and testified that they

had been in the range of $.9 to 1.3 million. He testified that the company’s projection of

$4.9 million is outside the historical range of experience, and recommended a

$1.1 million adjustment.560 He presented Exhibit S-7 in support of this adjustment.

In his rebuttal testimony, Mr. Kops testified that PBGC flat and variable premium

rates are increasing for 2017 and 2018, and testified that his rebuttal Exhibit A-120,

providing the Aon Hewitt actuarial projections for Pension expenses for 2018 and 2019,

contain the revised figures. He further explained that the variable premium was not

required in 2016 because the market value of plan assets exceeded its liability, but is

projected the PBGC liability to exceed the market value of assets in both 2017 and

2018.561

In its brief, Staff argues that the company has overprojected expenses for this

category for many years, citing Case No. U-16191. Staff argues that its projected

expense is at the highest level experienced historically.562 Consumers Energy relies on

Mr. Kops testimony, acknowledging the higher expense projections, but contending that

Mr. Kops provided a reasonable explanation for the increase.563 After reviewing

560 See 11 Tr 2456-2457. 561 See 10 Tr 1974-1975. 562 See Staff brief, pages 87-88. 563 See Consumers Energy brief, pages 152-153.

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Mr. Kops’s testimony carefully, this PFD concludes that the company has established a

reasonable basis for its expense projection in this category.

b. Discount Rate

Mr. Coppola took issue with the company’s estimate of pensions and other post-

retirement benefit expense (OPEB), recommending a reduction of $18.3 million in the

company’s projected expenses for these two categories. Mr. Coppola based his

recommendation on a review of the interest rate used to discount the projected stream

of benefit payments, the “discount rate”. He testified that Consumers Energy lowered

the discount rate, making the present value of the company’s pension and OPEB

benefits and its payment obligations look larger, without supporting the change. He

testified that Consumers Energy claimed to rely on an Aon Hewitt study, but would not

provide the study in discovery, citing confidentiality concerns. He then performed his

own analysis using corporate bond returns, and concluded that the discount rate should

not be changed.564

In his rebuttal testimony, Mr. Kops disputed that the U.S. Treasury rate is

relevant, stating that the accounting standards clearly require investment grade

corporate bond rate be used in establishing account expenses for Pension and OPEB

plans.565 He disputed that the company has managed to increase the discount rates

between rate cases, contending that the company uses the pension and OPEB

expenses supported by it most-recent year-end From 10K filing, although it will “review

the economic markets and significant events or know changes since the last year-end

Pension and OPEB plan measurements and may update” its expense projections if it

564 See 12 Tr 2547-2542. 565 See 10 Tr 1976.

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files a rate case mid year.566 He further testified that “any changes made in projected

Pension and/or OPEB expense for mid-year updates are supported in writing by the

company’s actuary.567

Mr. Kops also testified that the confidentiality of the Aon Hewitt yield curve should

not lead to the conclusion that the company’s discount rates are unsupported because

Aon Hewitt follows corporate accounting rules. He testified that 2017 OPEB expense

increased in 2017 because of the use of a lower yield discount curve “reflective of

market conditions,” and a significant increase in claims costs “at the time the 2017

OPEB expense was projected by the company’s actuary.568

This PFD finds that Consumers Energy has failed to support its choice of

discount rate for the projected pension and OPEB expenses. By refusing to provide the

yield curve that it claims to have relied on in choosing the discount rate, Consumers

Energy precluded the parties from testing its assertion. The Commission has been

clear that MRE 702 requires the utility to provide such information. The general

trustworthiness of Aon Hewitt is entirely irrelevant because Consumers Energy did not

provide the evidence necessary for the parties to verify that its choice of discount rate

accurately reflected the Aon Hewitt yield curve. Moreover, as Mr. Kops clearly stated in

his direct testimony, Consumers Energy, not the actuaries, chooses the discount rate to

be applied:

In order to calculate the plan’s total pension benefit obligation and annual ASC 715 expense, the actuary uses a number of assumptions including discount rate, mortality table, salary change, expected return on plan assets, and expected future contributions needed to avoid at-risk status under the Pension Protection Act. The assumptions used by the actuary


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are determined by the Company each year and reviewed by the Company’s auditors.569

Mr. Kops did not attempt to independently support the choice of discount rate.

Additionally, he acknowledged that the choice of discount rate had been made at the

end of 2016, and that it was the company’s choice in this rate case not to update the

discount rate, notwithstanding that the projected test year includes only the fourth

quarter of 2017 as well as the first three-quarters of 2018.

6. Supplemental Retirement Plans (lines 7 and 9 of Exhibit A-8, Schedule C5)

Mr. Kops presented testimony in support of the company’s recovery of projected

costs for supplemental executive retirement plans, one for covered employees in the

Defined Benefit Supplemental Executive Retirement Plan plan and one for covered

employees in the Defined Contribution Supplemental Executive Retirement Plan. Both

Staff and the Attorney General recommended that these expenses be excluded.

Subsequently, Consumers Energy withdrew its request for $11.4 million for long-term

incentive restricted stock plan expense, as discussed in Ms. Myers’s rebuttal

testimony.570 This PFD therefore considers this issue resolved.

7. Uncollectible Accounts Expense (line 14 of Exhibit A-8, Schedule C5)

Consumers Energy projects uncollectible expenses of $21.6 million for the test

year, based on a three-year average as calculated in Mr. Harry’s Exhibit A-55, offset by

smart grid savings of $6.4 million based on Mr. Warriner’s analysis.571

Mr. Welke presented Staff’s primary recommendation regarding uncollectible

expense. He recommended a $2 million reduction to projected uncollectible accounts

569 See 10 Tr 1933 (emphasis added). 570 See Myers, 7 Tr 795-796; also see Exhibit A-131. 571 See Harry, 6 Tr 566.

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expense to reflect the company’s May 3, 2017 presentation to its Board of Directors.

He testified that Staff believes the revised presentation is consistent with new collection

practices such as the “turn-on” compliance program and efforts to reduce arrearages.

He also testified that Staff has an alternative presentation based on the five-year

average bad-debt loss ratio, applied to Staff’s recommended revenue projection, offset

by Staff’s projected smart-energy savings, for a net reduction of $412,500 in the

company’s projection.572

Ms. Fromm analyzed the uncollectible accounts expense for Staff, and concluded

that the bad-debt loss ratio has been declining such that Staff does not believe a three-

year average approach is appropriate.573 She used 2016 net write-offs of

$19.195 million, offset by the incremental smart grid benefit of approximately $4 million

to derive a test year projection of $15.188 million, as shown in her Exhibit S-13.4,

page 7.

In his rebuttal testimony, Mr. Harry cited the Commission’s November 19, 2015

order in Case No. U-17335 to show that the Commission has previously rejected

reliance on an internal budget projection. He testified that the budgets “often includes

target assumptions that reflect a degree of uncertainty,” and that this budget in

particular “is unsupported by any calculation methodology.” He also testified to the

benefits of using a three-year average, with the smart-grid adjustment. He

acknowledged that the full impact of the smart grid is not fully reflected in the three-year

average, but recommends a consistent approach. Based on the company’s consistent

support for a three-year average, he also recommended against using Mr. Welke’s

572 See 11 Tr 2457-2458. 573 See 11 Tr 2356-2357.

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five-year average. He also recommended against using the results of Ms. Fromm’s

analysis, because it did not rely on averaging.

Staff argues that the circumstances presented here are different, arguing that the

historical data is not reliable given the recent programs the company has undertaken.

This PFD acknowledges that Ms. Fromm’s analysis shows that the smart-grid

adjustment combined with the three-year average may not fully capture for the test year

the company’s cost-reduction efforts. Nonetheless, for the reasons explained by

Mr. Harry, this PFD recommends that the Commission continue to use the three-year

average, adjusted for expected smart-grid savings. A key advantage of the consistent

use of the three-year average is that it reduces rate-case disputes, and will eventually

reflect the appropriate level of improved activity by the company. Because this PFD

recommends continuation for at least one more year of the company’s business-case

analysis, however, the same information should be available in the company’s rate case

for further review.

8. Injuries and Damages (Exhibit A-8, Schedule C5, line 15)

Consumers Energy projected test year injuries and damages expense using a

five-year average. Mr. Harry presented this projection in his Exhibit A-56, showing

historical expenses for 2012 through 2016 separately for injuries and damages, internal

legal costs, and workers compensation to support the calculation of the five-year

average. Neither Staff nor the Attorney General objected to the company’s projection of

$4.4 million. In its reply brief, the RCG argues that Consumers Energy is essentially

asking for regulatory asset treatment for these expenses:

RCG further asserts that the Commission should reject CECO proposals to adopt or continue a regulatory asset for electric injuries or damages

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including liability for damages arising from successful lawsuits against CECO. In an incomplete fashion, CECO presents this proposal in part through Witness Harry, and includes this request in its brief at p 171.574

The gravamen of the RCG’s argument appears to be that it is not appropriate to provide

an expense allowance for injuries and damages:

Approval of such an injuries and damages request would relieve CECo of responsibility for substantially all electrical injuries and damages associated with their operations and business decisions and would make such costs mere “pass throughs” to ratepayers without having any control, an outcome which does not promote utility risk accountability and transparency.575 The RCG does not provide an alternative recommendation for this category of

expense. This PFD finds that the five-year average is appropriate for inclusion in rates

in this case. While the five-year average should reduce volatility and the difficulty of

projecting costs in this category, parties are free to challenge the appropriateness of

including any particular liability payment in the historical data and no one presented any

such concern. Additionally, nothing in the record suggests that this expense projection

creates an adverse incentive regarding safety. Instead, Consumers Energy presented

testimony that it has an excellent safety record.

9. Payment Programs (Exhibit A-8, Schedule C5, line 17)

Mr. Morales testified that various methods of customer payments are currently

included in rates. His Exhibit A-67 shows customer payment costs of $1.3 million in

2015. Mr. Morales testified that the projected $7.2 million in test year costs for payment

programs reflect the company’s September 2016 decision to waive the $6.25 fee it had

been charging for credit and debit card payments.576 He testified that with the

574 See RCG reply brief, page 7. 575 See RCG reply brief, page 8. 576 See 9 Tr 1538-1540.

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elimination of the fee, more customers are paying their bills using credit or debit cards,

identifying an 85% increase in the number of transactions. He also explained that as of

January 2017, customers wishing to make a one-time payment by credit card no longer

need to go through the customer call center. He testified: “The Company believes

these expanded customer payment options will improve customer satisfaction, but as

more customers move to paying their utility bill using credit or debit cards, the

Company’s costs will increase because the cost of accepting card payments is more

expensive than most other types of customer payments.”577

Mr. Coppola took issue with the company’s projected increase in the cost of

customer payment programs arising from its September 2016 decision to waive credit

card fees for all customers. He testified that the projected $5.2 million increase over

2016 levels of $2.1 million to fund the additional credit-card fees anticipated under this

program should not be accepted without projected decreases in uncollectible

expense.578

Mr. Harry, who sponsored the company’s uncollectible expense projection,

addressed Mr. Coppola’s recommendation in his rebuttal testimony. He testified that

Consumers Energy does not believe there will an impact on uncollectible accounts

expense because the fee was not a barrier to payment of the customer’s bill to avoid

shut-off.579 He also testified:

Mr. Coppola assumes that the increase in card payments is primarily from low income qualified customers that are simply transferring their risk of nonpayment to the credit card company, but provides no data to support this assumption. Low income customers represent a relatively small percentage of Consumers Energy’s customer base. Mr. Coppola uses

577 See 9 Tr 1540. 578 See 12 Tr 2526-2529 579 See 6 Tr 580.

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unsupported assumptions and assertions as the basis for his position that expansion of Consumers Energy’s card payment programs will significantly reduce uncollectible expense.580 While Consumers Energy is likely correct that the fee-free credit-card payment

option is attractive to customers, and the company’s policy may well result in a greater

number of credit card payments than experienced in 2016, Consumers Energy is only

speculating regarding the benefits of the fee-free policy. Mr. Morales expressly

disputed Mr. Coppola’s assumption that the program would help lower uncollectible

expense. On cross-examination, he acknowledged that the company does not have

information on the customers who are using this service.

On the other hand, the fee-for-service approach by definition assigns the costs to

the customers who cause the costs. This PFD finds that Consumers Energy has not

established that the benefits to a subset of customers in terms of convenience justify the

6-fold increase in payment processing costs for all customers. Since the company

disputes the Attorney General’s contention that the policy will reduce uncollectible

expense,581 this PFD recommends that the Commission provide the company with an

opportunity in its next rate case to explain and justify the policy, while holding test year

expense projections in this case to historical levels as recommended by Mr. Coppola.

10. Customer Experience (Exhibit A-8, Schedule C5, line 18)

Exhibit A-67 also shows the company’s projected $25.6 million in O&M expenses

for the test year under the customer experience category. Mr. Morales explained the

“Digital Customer Experience” program as part of a strategy to meet “growing customer

580 See 6 Tr 581. 581 See AG brief, pages 21-22.

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expectations.”582 He presented research on internet use, and also consumer research

regarding energy providers. He testified that the cost in Exhibit A-67 is the “operational

cost to support and maintain digital operations to meet customer expectations.”583

Mr. Coppola took issue with projected increases in this category of expenditure of

66% for 2017 and 166% for 2018. He recommended a $9.3 million reduction to the

digital experience program, characterizing the company’s explanation of proposed

expenditures of $11 million as vague and conceptual, and further characterizing the

company’s response to a Staff audit request as incomprehensible. He testified that the

bulk of the cost increases appear to be for labor and contractors, but it is not clear what

these costs will accomplish to justify the expense. His recommended adjustment

continues into the test year the level of expenditures actually made in 2016.584

In his rebuttal testimony, Mr. Morales disputed Mr. Coppola’s assessment. He

stressed the importance of the DCE platform, and testified that because it did not exist

three years ago, the associated costs are not reflected in the historical data. He

testified that contractors and not internal labor will be used; he testified that an all-new

website was launched in 2015, and described some of the work done subsequently.

For 2016, he testified expenditures “consisted of leading continued major capital project

launches while simultaneously developing a foundational team to operate core functions

of the website and build experience at measuring site performance and gathering

customer feedback.” For 2017, he testified that the company:

(i) implemented an effective feedback and rapid enhancement process; (ii) executed new capabilities ranging from the ability to target customers with specific messaging to sending proactive, two-way communication alerts;


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(iii) designed and launched customized digital campaigns; and (iv) created new website content. In addition, digital projects were undertaken to increase awareness and use of online account management (logins are expected to increase 16% in 2017 at frequency levels that exceed industry average), bill due date changes (approximately 75% of customer engagement from digital channel), and other product and service options that are known to be important to our customers.585

He described test year activities as follows:

The 2017-2018 test year expenses, as discussed in response to Staff Audit 29 Request No. 124 cited on page 27 of Mr. Coppola’s direct testimony, allow for an “increasingly mature use of the digital channel to support company operations, customer behavior analytics, targeted campaigns, personalized messaging, increased self-service support and management of new digital capabilities within the digital team.” This is referencing the evolving maturity of our capabilities to take advantage of our digital properties for the benefit of our customers and the cost-effectiveness of building increased adoption within this channel of choice. These activities, specifically, will include:

• Provide additional customer feedback and analytics; • Leverage targeting capabilities to direct the most effective

messages to the right customers through existing and new personalization parameters. This includes identifying customer segments, testing message effectiveness using built in A|B testing, and designing/deploying targeted messages to add customer value;

• Create targeted online campaigns that help customers from

online and offline media efforts to maximize awareness, education, and conversion into programs/options of interest; and

• Increase features and effectiveness of online account

management and online capabilities.586 Mr. Morales measures progress and benefits to date by pointing to the number of alert

signups, mobile device usage in storms, customer satisfaction, the ability to deploy

custom digital campaigns by business owners, and targeted-messaging capability.587


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While it appears that Mr. Morales has outlined an ambitious undertaking, it is

difficult to assess the benefits and costs of the company’s expense request on this

record. Noting that the Attorney General did not address Mr. Morales’s rebuttal

testimony,588 and reading Mr. Morales’s testimony to indicate there is ongoing

contractual work on the company’s website, this PFD recommends that the Commission

include the expense projections, with the caveat that future funding requests for such

activities include details regarding the commitments the contractor or contractors have

made regarding the work that will be performed and how it will be evaluated, other

performance metrics the company intends to use to determine whether the identified

projects have been satisfactorily completed, as well as a benefit-cost analysis, to

facilitate a more meaningful review of the company’s plans than can be made on this

record.

11. Incentive Compensation (Exhibit A-8, Schedule C5, line 20)

Consumers Energy requested recovery of two incentive compensation programs

in this case, with projected expenses totaling $14.8 million. The long-term incentive

compensation plan awards restricted stock shares to officers and directors and key

salaried employees, based on financial performance and longevity. The annual

employee incentive plan (or EICP) provides additional monetary compensation to non-

union employees based a mix of financial and operational metrics. Staff, the Attorney

General, and ABATE presented testimony opposing recovery of most or all of the

requested funding.

Mr. Welke recommended excluding the costs of the long-term restricted stock

incentive plan, and the portion of projected costs associated with the financial measures 588 See AG brief, pages 19-21.

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included in the EICP, testifying that incentive plans that primarily relate to financial

measures should be excluded from the revenue requirement because they primarily

benefit shareholders.589

Mr. Coppola recommended that the Commission reject the total projected

$14.8 million in expenditures for the company’s incentive compensation programs,

including the EICP for officers and the EICP for non-officer employees and the long-

term stock incentive plan for officers, board members, and key employees.590

Regarding the EICP, he testified that the program for officers is entirely based on

financial performance measures. He reviewed the program for non-officers, and

testified that the operating performance metrics that account for 50% of the payout only

require that 6 out of 12 be met before 100% payout, testifying that the requirements

have been weakened since 2011. He also testified that the several of the new

measures this year are not difficult. He also took issue with the estimated benefits,

characterizing the estimates presented as based on stale data. He cited Exhibit AG-10

to show that even if all performance measures are met, the expected payout would be

only $1.77 million. Regarding the long-term stock incentive plan, he testified that the

$11.4 million projected for the test year is not tied to customer service or operating

measures, and should be rejected as the Commission has consistently done in prior

cases.

Mr. Pollock testified:

[I]ncentive compensation based on achieving certain operational goals may be a reasonable and necessary expense which may benefit ratepayers. However, incentive compensation targeted to achieve certain financial goals is only for the benefit of shareholders and provides little, if

589 See 11 Tr 2463. 590 See 12 Tr 2531-2547.

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any, benefit to ratepayers. Thus, the latter expenses should not be charged to ratepayers.591 Consumers Energy subsequently withdrew its request to recover the projected

expenses for the long-term incentive programs, and is asking only to recover the

projected $3.4 million for its EICP. Citing Ms. Conrad’s testimony, Consumers Energy

argues that its overall compensation levels are reasonable with the inclusion of the

incentive compensation, characterizing it as a management prerogative to determine

how to pay a reasonable level of compensation, and further arguing that incentive pay is

a standard industry practice that is common and effective. It further argues that the

operational measures provide benefits to customers, citing Mr. Stuart’s analysis.592

Citing Ms. Conrad’s testimony and Mr. Maddipati’s testimony, Consumers Energy

argues that customers benefit from maintaining a healthy utility that can raise funds for

capital investments on reasonable terms and conditions.593

Staff and ABATE/Gerdau argue that the company should only recover the

expenses associated with the operational measures, while the Attorney General argues

that none of the expenses should be recovered.

In its brief, Consumers Energy cited the Commission’s prior decisions accepting

the projected costs associated with the operational measures for inclusion in rates, and

relies on Ms. Conrad’s testimony and Mr. Maddipati’s testimony to support recovery of

the costs associated with the financial measures.

This PFD recommends that the Commission follow the decision it made in the

company’s last two rate cases and include only the projected costs associated with the

591 See 12 Tr 2644. 592 See 7 Tr 1008-1013. 593 See Consumers Energy’s brief, at pages 163-165.

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operational measures. While the company did not fully address Mr. Coppola’s concerns

regarding the revised measures and the reduced number of measures that must be met

for 100% payout, the Commission’s inclusion of these expenses is relatively new, and it

is reasonable for the Commission to continue to fund the operational measures portion

of this program, pending review in the company’s next rate case. Regarding the

financial measures, this PFD finds that Consumers Energy has not provided any new

evidence or persuasive argument for ratepayers to provide funding for these measures.

Mr. Maddipati’s generic statement that ratepayers benefit from a financially healthy

utility, clearly something the Commission has considered before, and his assertion that

a financially healthy utility “helps to provide customers with better service,”594 in no way

addresses the potential adverse impacts from financially motivating company

employees to focus on company profits.

12. METC Easement Revenue

As discussed above, the resolution of the dispute between Consumers Energy

and METC before FERC has an expense component as well as a rate-base component.

Consistent with the agreed-on treatment acknowledged by Staff and the company, O&M

expenses should be adjusted.

D. Other Expenses

This section includes a discussion of depreciation and amortization expense, as

well as taxes and AFUDC. While there are differences in the amounts calculated by the

company, Staff, and the Attorney General, those differences are due to differences in

recommendations regarding other rate elements. Only the RCG challenges the

depreciation and amortization expense, arguing that the Commission should eliminate 594 See 10 Tr 1822.

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the regulatory asset it authorized in Case No. U-17990 for income taxes for the City of

Detroit. The RCG relies on Mr. Peloquin’s testimony at 11 Tr 2119-2222. Consumers

Energy relies on Mr. VanBlarcum’s rebuttal testimony at 7 Tr 862-864. For the reasons

explained in Mr. VanBlarcum’s testimony and in Consumers Energy’s brief, this matter

was resolved by the Commission in the last rate case, and the RCG has presented no

new evidence to justify reconsidering the authorized accounting treatment for this

expense.

E. Adjusted Net Operating Income Summary

Based on the foregoing discussion, this PFD estimates a jurisdictional net

operating income of $575,084,000 as shown on Attachment C.

VIII.

OTHER REVENUE-RELATED ITEMS

Among the other revenue related items disputed by the parties are the

company’s request for a regulatory asset for demand response costs, addressed in

section A below, as well as other demand response related items in section B, while

AMI and smart grid issues are discussed in sections C, D, and E and the on-lion

interconnection queue is discussed in section F.

A. Regulatory Asset for Demand Response Costs

Ms. Myers’ direct testimony identified the following benefits of Consumers

Energy’s alternate proposal to create a regulatory asset for demand response

expenditures, subject to reporting and reconciliation requirements:

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There are several advantages of creating a regulatory asset. First, from an accounting perspective, all of the DR Program costs can be recorded in one place. Company witness Harry will give further reasoning to the accounting aspect of creating a regulatory asset. Second, the regulatory asset will balance out the revenue requirement with the average service life of the programs. This will smooth out the longer-term capital costs with the short-term (one year) O&M costs, thereby, smoothing out the customer impact over the average life. This regulatory asset approach will allow the Company recovery of its investments over a reasonable period of time while not overburdening customers by smoothing out the collection period for the program costs. Third, the regulatory asset will centralize the costs which will streamline reviews for MPSC Staff (“Staff”) auditors. Finally, this will allow the Company to continue its investment in the DR programs which will reduce future capacity needs and will benefit the customers through lower power supply costs.595

She testified that the company envisions the regulatory asset having characteristics of

both the regulatory asset and review structure for the company’s manufactured gas

plant (MGP) remediation costs, and the company’s Enhanced Infrastructure

Replacement Program (EIRP). She explained that the regulatory asset would be

included in rate base, with amortization recovered as part of net operating income. She

cited the February 1, 2017 report Consumers Energy filed in Case No. U-18013 in

support of her testimony that demand response costs show a steady progression over

time, rather than the volatility in spending often shown by expenses covered by a

tracking mechanism. She testified that like the EIRP, the company will provide annual

reporting, but unlike the EIRP, there will be no need for a separate surcharge. She

testified that the annual reports could be filed in Case No. U-18013, and if a review

determines that any cost item was not reasonable and prudent, the company would

exclude that item from rate base in future rate cases:

The Company will apply a carrying cost to the disallowed amount equal to the Company’s authorize pre-tax overall rate of return at the time of the disallowance. While there may be regulatory lag in between general rate

595 See 7 Tr 774-775. Mr. Torrey also identified these benefits in his testimony. See 7 Tr 645.

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cases, customers will be made whole through lower rates, by the disallowance plus the carrying costs for the time period when disallowance was ruled on to the time when rates are reset.596 Exhibit A-50 presents the capital and other ratemaking cost elements for the

commercial and industrial (C&I) demand response program, incorporating the capital

expense projections sponsored by Mr. Morales, while Exhibit A-51 illustrates the

accounting and ratemaking treatment if the Commission approves a regulatory asset for

recovery of these costs in comparison to the standard ratemaking treatment. Ms. Myers

testified that capital and O&M expenses for the C&I and residential demand response

programs would be included in the regulatory asset. She testified that the 12-year

amortization is based on the average service life for the principal capital asset

categories. She testified that with the regulatory asset treatment, the revenue

requirement in the current rate case would be reduced by $7 million, including the

removal of demand response costs already included in rate base. Mr. Harry also

testified regarding the treatment of ongoing costs under this proposal and the specific

accounting approvals required.597

Staff, ABATE/Gerdau, and the RCG oppose this treatment. Ms. Simpson

explained Staff’s recommendation that the Commission defer consideration of

regulatory asset treatment for these expenses:

On May 11, 2017 the Commission issued an order in Case No. U-18369 that, “directs the Commission Staff (Staff) to convene a workgroup dedicated to proposing a framework for the evaluation and cost recovery of DR investments[.]” With the guidance provided by the Commission order, Staff recommends that any alternative recovery proposal for demand response be addressed in the workgroup forum which will allow all interested parties to be stakeholders in the process. To avoid conflict between the proposals in U-18369 and the instant case, Staff

596 See 7 Tr 777-778. 597 See 6 Tr 572-573.

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recommends that the Commission reject the Company’s alternative recovery method.598 Mr. Pollock noted that regulatory asset treatment would guarantee full recovery

of all prudently incurred costs, and provide for a rate of return on the unamortized

balance, including a return on incentives paid to plan participants.599 He testified that

regulatory assets are an exceptional form of ratemaking usually reserved for

extraordinary or non-recurring items:

DR costs are recurring in nature and are recognized in setting rates. As previously stated, $19.3 million of DR-related incentives would be recovered in Consumers’ proposed rate design. It is also unnecessary to consolidate cost recovery for the sole purpose of facilitating a review of the DR programs.600 In her rebuttal testimony, Ms. Myers took issue with these objections.

Responding to Staff’s recommendation to defer this issue pending the work group, she

testified:

First, in the event that the Commission identifies a preferred alternative to the regulatory asset approach after reviewing the results of the workgroup in Case No. U-18369, then the use of the regulatory asset on a go-forward basis could easily be discontinued. Second, establishing a demand response regulatory asset to track and reconcile the Company’s Demand Response Program O&M eliminates the lag between when the Company increases its investment in demand response marketing, education, and pilots and when it recovers its program expenses. If the Commission is interested in promoting demand response programs beyond the Company’s currently planned level, then having a demand response regulatory asset would provide an effective means for expediting when the Company would be willing to increase its investment in demand response marketing, education, and pilots. Absent a regulatory asset, the Company would be required to postpone any increase in investments, beyond those approved in rates, until it was approved in a subsequent rate case. The Company proposed alternative recovery of the Demand Response


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Program O&M will contribute to the success of the Demand Response Program.601 .

Responding to Mr. Pollock’s testimony that regulatory assets are not commonly used to

allow recovery of recurring costs, she testified that the past use of regulatory assets

does not limit the Commission’s discretion to approve a regulatory asset in this case.602

In their brief, ABATE/Gerdau cite the Commission’s February 3, 2009 order in

Case No. U-15751 as characterizing a regulatory asset approach as an “extraordinary

measure.” They contend that there is no justification for adopting an extraordinary

measure for demand response, and that a regulatory asset is not required to facilitate

review of those costs.603 ABATE/Gerdau also argue that the company’s proposal will

lead to an overrecovery of $1.1 million by recovering incentives paid to retain customers

through rates and through the regulatory asset.

In its brief, Staff agrees with Mr. Pollock’s testimony that the regulatory asset

would include O&M expenses that are normally not included in rate base because they

do not have a useful life that spans many years. Staff argues that although the

regulatory asset would smooth out the demand response investment over the 12-year

amortization period, the company would earn a return on the unamortized balance for a

period longer than the benefits. Staff also argues that the Commission’s September 15,

2017 order in Case No. U-18369 adopts a three-phase framework for evaluating,

collecting, and reconciling all costs associated with investments in demand response.604

The RCG argues that the Commission should defer consideration of the

regulatory asset “for further review and study,” raising questions about the need and

601 See 7 Tr 791. 602 See 7 Tr 793. 603 See ABATE/GERDAU brief, pages 19-22. 604 See Staff brief, pages 43-45.

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efficacy of the residential demand response programs, and longevity of recovery in view

of potential technological innovation.605

In its brief, Consumers Energy reviews details of the company’s proposal,

including a provision for annual review of the included costs:

Ms. Myers explained that if, during the annual review process, specific costs are determined to not be recoverable, the Company would exclude those costs when the Company builds its rate base in the next general rate case. 7 TR 777. While the specific items will still be part of the regulatory asset, the Company will make a manual adjustment to exclude the identified non-recoverable costs and will adjust its amortization expenses to exclude the amortization associated with these costs. 7 TR 777. Moreover, Ms. Myers explained that if the Company does not file a general rate case for a period of time greater than a year after the conclusion of this case, the Company will exclude the costs, at the amount which is indicated to not be recoverable, from its rate base and from depreciation expense. 7 TR 777. The Company will also apply a carrying cost to the identified non-recoverable amount equal to the Company’s authorized pre-tax overall rate of return at the time of the disallowance. 7 TR 777-778.606

In its reply brief, Consumers Energy relies on Ms. Myers’s rebuttal testimony

discussed above. It also disputes ABATE/Gerdau’s characterization of the regulatory

asset as a tracker, arguing that the company’s proposed method of cost recovery and

review “is important because the Company’s ability to provide successful DR options to

customers depends on the ability to recover prudently incurred costs,” and arguing that

consolidation of cost review for demand response costs “is important due to the

numerous proceedings (e.g., general rate cases, PSCR cases, and annual filings)

where these costs are currently reviewed and the increased complexity of regulating

increased DR in Michigan due to PA 341 and PA 342.”607 Consumers Energy also

605 See RCG brief, pages 16-17. 606 See Consumers Energy brief, page 182. 607 See Consumers Energy reply brief, pages 147-148, also citing the Commission’s May 11,2017 order in Case No. U-18369, pages 3-4.

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disputes ABATE/Gerdau’s claim that the company’s proposed ratemaking treatment

would result in double recovery, committing that it would remove the costs identified by

ABATE/Gerdau from rate design if the regulatory asset is approved.

Consumers Energy responds to Staff’s reliance on the Commission’s September

15, 2017 order in Case No. U-18369 by arguing that the regulatory asset is still useful:

The Company does not agree that approval of the DR regulatory asset in this case will create conflict with the proceedings in Case No. U-18369. While Staff is correct that the Commission has recently approved a three-phase review process for DR costs (i.e., IRPs, general rate cases, and reconciliation proceedings) in Case No. U 18369, the approval of the three-phase review process does not preclude approval of the Company’s proposed DR regulatory asset. The Company’s DR regulatory asset could be used in conjunction with that approach. Furthermore, since there will be a gap between when DR reviews can begin in an IRP case and the conclusion of this proceeding, regulatory asset treatment can provide a bridge to ensure appropriate cost recovery and reviews of DR Program costs before the Commission’s three-phase DR review plan can begin. Ms. Myers also explained that use of the regulatory asset can easily be discontinued in coordination with the outcome of Case No. U-18369. 7 TR 791.608 This PFD recommends that the Commission deny regulatory asset approval in

this case, in recognition of the process provided for in Case No. U-18369. As Staff

argues, in its September 15, 2017 order in Case No. U-18369, the Commission adopted

a three-phase approach that Staff had recommended, which provides for demand

response costs that are reviewed and approved in an IRP to be included in rates set in

general rate cases:

The three-phase approach is a multi-step process where DR proposals, including program costs and benefits, are evaluated in the IRP. Once DR plans are approved as part of the IRP, the DR programs costs are considered approved and are included in rates in a utility’s next general rate case. In between IRP proceedings, a provider may propose changes to DR programs or pilots, and these changes will be evaluated and approved in rate cases and must be included in the next IRP. The third


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phase involves a reconciliation of the DR program costs and customer participation rates (i.e., demand savings achieved) that will occur annually in a manner similar to that used in the provider’s EWR reconciliation, with rates and participation reconciled against the levels approved in the IRP.609

Addressing the transition time before costs can be approved through an IRP, and are

approved only in rate cases, the Commission provided:

Because utilities are not required to file IRPs until early 2019, and are unlikely to file them before the conclusion of the legislation implementation efforts underway by the Commission, an interim mechanism is necessary to bridge the gap between the current, rate case centered and the future, IRP-based regulatory paradigm. As such, the Commission finds that the reconciliation process described by the Staff and approved in this order is a reasonable transition between the present and future. Rather than reconcile capital and O&M costs approved in IRPs and rate cases, respectively, until an IRP is approved by the Commission, there shall be annual, stand-alone reconciliation cases as explained by the Staff, that match actual spending on DR programs with the amounts approved in the previous general rate cases. This mechanism will apply to all ongoing and future rate case applications.610

While Consumers Energy argues that a regulatory asset created in this case can be

terminated, the effort in managing the regulatory asset as described by Ms. Myers and

quoted above does lend itself well to a gap-filling bridge or temporary measure,

particularly when the Commission has expressly provided a transitionary process.

There have also been questions raised regarding the life of the assets and the duration

of the benefits associated with the costs that would be included in the regulatory asset

under Consumers Energy’s proposal, making the choice of an amortization rate

problematic.

609 See September 15 order, page 5. 610 See September 15 order, pages 9-10 (emphasis added).

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B. Other Demand Response Program Issues

As noted above, Staff takes issue with certain aspects of Consumers Energy’s

residential demand response program. This is discussed in section 1 below.

1. Residential Demand Response Program Parameters

In discussing the three programs the Consumers Energy has grouped together

under the label Peak Power Savers, including two time-of-use (TOU) options, one

focused on peak usage and one focused on critical peak usage, and the AC cycling

program, Ms. Simpson testified that Staff supports the programs with certain changes

she identified. First, she explained that Staff would like to see the company provide

some form of shadow billing or trial to customers before they are committed to a full

year of the program. In response, Mr. Hurd testified that MCL 460.1095 requires

program participants remain in the program for a full year.611 He testified that if the

Commission believes the statute can reasonably be permitted to allow a trial period,

Consumers Energy requests that any trial period be a minimum of 6 months or through

the end of the summer months, whichever is longer. Mr. Hall also testified that

Consumers Energy does not have the capability for shadow billing.612

In response to Mr. Hall’s testimony, in its initial brief, Staff recommends that the

company further investigate the option of shadow billing in some form, indicating that

there are options other than the creation of a new website and SAP program as Mr. Hall

discussed. MEC/NRDC endorse Staff’s recommendation, arguing that shadow billing

would increase customer knowledge of time-of-use rates and likely result in increased

611 See 9 Tr 1506. 612 See 7 Tr 893.

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cost savings and in delivering the benefits regarding demand reduction.613 In

recommending a trial period, Staff agrees that the trial period should include the

summer months, but also argues:

The length of Company’s suggested trial period defies the basic reasoning behind a trial period. The concept of a trial period is for a customer to fully understand the impact of a TOU rate on their bill and be able to withdraw from the rate if the customer decides that the rate is not best for them. Staff is not advocating for customers to have the ability to repeatedly sign-up and withdraw, but to simply try the rate out one time before making a one-year commitment. This debate highlights the reason Staff recommends shadow billing or a trial period. The Company continues to resist providing any way for customers to make informed decisions about rate selection and therefore customers are more likely to continue with the status-quo.614 Second, Ms. Simpson testified that Staff would like to see additional marketing

and educational materials from the company to increase participation in current

programs or to pilot additional programs:

Staff believes that the Company could make demand response for residential and small commercial customers more accessible by increasing its marketing and education efforts to promote enrollment and pilot additional demand response programs.615

Mr. Warriner responded to this recommendation, testifying that the company is open to

increasing its demand response efforts, but its funding requests in this case do not

provide for such efforts. He further recommended consideration of such issues in the

demand response workgroup case, Case No. U-18369.616 In its brief, Consumers

Energy argues:

[T]he Company has not requested in this proceeding to expand its marketing, education, or pilots. 6 Tr 337. In its September 15, 2017 order in Case No. U-18396, the Commission adopted a framework for the

613 See MEC/NRDC/SC brief, pages 28-29. 614 See Staff brief, pages 47-48. 615 See 11 Tr 2446. 616 See 6 Tr 337-338.

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evaluation and cost recovery of DR investments. Future funding and recovery of additional DR marketing, education, and pilots will be conducted pursuant to the Commission-approved framework.617 This PFD recognizes that Staff’s two programmatic concerns are related, both

addressing the company’s efforts to market successful programs, with a minimum of

customer confusion or dissatisfaction. Regarding shadow billing or a trial period, this

PFD finds Staff’s recommendation that the company explore shadow-billing options to

be reasonable, and consistent with Staff’s interest in the educational materials available

to customers. Consumers Energy’s response in Exhibit S-12.2 does not suggest a very

comprehensive set of explanatory materials has been compiled for this program.

Surprisingly, Consumers Energy interprets Staff’s recommendation regarding marketing

and educational materials to pertain exclusively to new or pilot programs, when the ALJ

reads Staff’s recommendation as also addressing marketing and educational materials

used for the existing AC and time-of-use demand response programs. Note that

Consumers Energy has projected O&M spending of $5.9 million for these programs in

the test year, and is projecting significantly increased enrollment. The company should

have responded to Staff’s concerns with an explanation of the marketing and

educational materials it already has in use for existing programs.

Turning to the potential for a trial period, MCL 460.1095 provides in key part:

[E]lectric providers whose rates are regulated by the commission and whose rates include the cost of advanced metering infrastructure shall offer commission-approved demand response programs. The programs may provide incentives for customer participation and shall include customer protection provisions as required by the commission. To participate in a program, a customer shall agree to remain in the program for at least 1 year.

617 See Consumers Energy brief, page 70.

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Staff’s recommendations are clearly aimed at the customer-protection provisions of this

statute, and should not interfere with the requirement that a customer agree to remain in

the program for at least a year. At heart, the one-year provision contemplated here is

essentially a contractual provision, leaving it to the Commission to specify the

consequences for early termination. The statutory one-year commitment requirement

does not mean that no matter what, under all circumstances, because the customer

“agreed” to remain in the program, there are no alternatives. Note that Consumers

Energy’s form contract for its commercial and industrial demand response program in

Exhibit A-68 has a force majeure clause in section 12, and also makes clear in section 8

that participants are not penalized for failing to shed load when requested, although

future incentive payments will be reduced. Legal remedies for breach of contract rarely

require specific performance.

Thus, for example, the Commission could establish a limited trial period within

which a customer could choose to leave the program, but if they leave after that, they

would forfeit any rate-related benefits they received by participating. As another

example, the Commission could establish a hardship exemption for customers who

develop health issues that make participation more onerous, such as the need to run

medical equipment continuously, or who have other significant changes in circumstance

that make successful participation in the program unusually difficult. While the

appropriate customer protections can be refined over time through the process provided

for in Case No. U-18369, and while the Commission should expect the company to work

with Staff to help avoid customer confusion or misunderstandings, it is appropriate in

this rate case to provide some minimal customer protections until more refined

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decisions can be made regarding the appropriate trial period and/or a method for

shadow billing. Considering Staff’s recommendations and the company’s concerns, this

PFD recommends that the tariff provide that customers who agree to participate in the

program for one year may nonetheless withdraw from the program within the first three

months of the first year they are enrolled without penalty, but if they withdraw after that,

they would forfeit any rate-related benefits they received by participating that year.

2. Accounting

Ms. Simpson also addressed the accounting for the AC switches to be used in

the program. She expressed concern that the AC switches had been included in a

FERC account with an average life of twenty-five years, when they may have

significantly shorter lives when air conditioners are replaced or customers move, or due

to obsolescence.618 She recommended that the company use a depreciation or

amortization life of 5 years, rather than the 25-year rate associated with that account. In

his rebuttal testimony, Mr. Warriner objected to Staff’s proposed accounting change,

contending that the FERC accounts should control the accounting, and that depreciation

rates should only be set in depreciation cases.619

In its brief, Staff reviews the basis for its concern that the practicalities of the load

control program limit the longevity of the AC switches. Staff continues to recommend

that the assets be accounted for in an account that can be amortized over five years,

but states:

For these reasons Staff recommends that the Company record AC switches in an account which is amortizable over a five-year period. Staff understands that such issues are generally addressed in a depreciation

618 See 11 Tr 2443; also see Exhibit S-12.4 619 See 6 Tr 333-335.

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case, and for this reason recommends the Commission revisit this issue when the Company files its next depreciation case.620

Based on the arguments of the parties, this PFD recommends that the Commission

accept Staff’s final recommendation to revisit this issue when the company files its next

depreciation case, but in the interim, require that Consumers Energy record the AC

switches in their own subaccount, so that the life expectancy can be tracked and

separately evaluated in the company’s next depreciation case. Note that Exhibit S-12.3

shows that the AMI meters Consumers Energy booked in FERC Account 370 were put

in a separate subaccount.

3. Commercial and Industrial Customer Program

Mr. Morales testified regarding the company’s demand response program for

large commercial and industrial customers, which is assigned to the customer service

department at Consumers Energy. The capital costs are in Exhibit A-66. Mr. Morales

distinguished this program from an interruptible rate, and explained that the only

financial consequences to customers participating in the program who do not shed load

is the loss of the capacity and energy incentive payments and the risk of being

withdrawn from the program. He further reviewed the benefits of the program.

Ms. Simpson testified that Staff is not recommending any changes to the

program at this point. Mr. Jester testified for MEC/NRDC/SC on this issue,

recommending that the programs be expanded to residential and small commercial

customers. He also took issue with the rate design, as discussed below. Another is

whether program should be available to other customers. Consumers Energy argues

that MEC/NRDC/SC have shifted their position in arguing that the program should be

620 See Staff brief, page 43.

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available to all customers.621 This PFD recognizes that MEC/NRDC/SC have not

shifted their position, but nonetheless recommends that the process provided for in

Case No. U-18369 is more appropriate to pursue an expansion of these particular

programs.

C. Smart Energy/ AMI

Mr. Warriner presented the company’s business case update for the AMI

program, explaining the changes since the last update, and how the company is

assigning responsibility for key elements of the program. He testified that Consumers

Energy will complete installation of the AMI meters in the test year, and requested that

the company be relieved of the obligation to file another business case benefit/cost

analysis.

Staff and the Attorney General opposed the company’s request to stop its

business case reporting regarding the AMI implementation. Mr. Coppola testified that

the point has not yet been reached where the cumulative benefits to customers have

exceeded the cumulative revenue requirement to customers. He recommended that the

Commission reject the request.622

In its brief, Staff recommends that Consumers Energy continue to update its

business case, but be relieved of the obligation to address it in the five-year distribution

plan, and make it a standalone report.623

This PFD recommends that the Commission simply continue the business case

reporting obligation for one more rate case, so that Consumers Energy can file a

comprehensive report when the installation has been completed. In making this 621 See Consumers Energy brief, page 73; 622 See 12 Tr 2572-2573. 623 See Staff brief, page 64.

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recommendation, the ALJ notes that Mr. Warriner’s update in this case contained

several changes that he discussed. If the program has reached an equilibrium, the

Commission should expect to see a report which is very similar to the report presented

in this case. Note that it was the company’s management decision to transfer the

programmatic responsibility for parts of the AMI-related programs prior to the

completion of the installation.

D. Smart Meter Consumption

The RCG presented two witnesses who testified regarding the energy

consumption of the AMI meters. Mr. Peloquin testified that this home has been vacant

for several years, with a gas-fired furnace and hot water heater. He testified that the

only appliance that consumer electricity is the furnace, and the thermostat is set at

40° F so the furnace does not run in the summer. He testified that a smart meter was

installed at the home in 2016, and presented Exhibit RCG-1 to show the natural gas and

electric consumption there. He testified that following the smart-meter installation,

warm-month consumption increased to 15kWh per month from zero, and winter

consumption increased from a high of 19kWh per month to a high of 52 kWh per month,

or an average increase of 30 kWh per month. He concluded that the meters are

causing a significant increase in energy consumption. As discussed in section II above,

Mr. Bathgate testified that each smart meter will consume approximately 2.37 kWh per

day, which equates to an annual cost of approximately $120 per customer.624

In its brief, the RCG asks that the Commission investigate the increased electric

consumption caused by smart meters and the resulting increased costs to individual

624 See 11 Tr 2193-2194.

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customers and the cost of service overall.625 It argues that the existence of such energy

consumption runs counter to statutory energy waste reduction goals and is also relevant

to the benefit-cost analyses of the program. The RCG also asks the Commission to

investigate the health and safety of the AMI meters.

Mr. Arcienega testified that the meters comply with American National Standard

Institute standard C12.20, including section 5.5.4.8 Test 8: Internal Meter Losses (the

internal energy usage of a meter, or burden energy), which limits the internal electric

burden to 5 watts. He further stated that compliance is required by the Commission’s

technical standards, R 460.3308, and in addition, testified that the Metering Technology

Center at the company tested whether the meters register energy consumption over a

70-hour period, and determined that no consumption registered.626 See 6 Tr 265-266.

He testified that the electrical burden for the specific meters Consumers Energy has

deployed is 2.981 watts (not kilowatts). Mr.Warriner also presented information on

standard household appliances to show that Mr. Bathgate’s estimates of AMI-meter-

energy-consumption are off by an order of magnitude. He testified:

The meter electrical internal burdens estimated by RCG witnesses Peloquin and Bathgate do not reflect reasonable estimates. Mr. Bathgate states on page 2, line 33 of his direct testimony that a smart meter consumes 865 kWh per year. This estimate would indicate that a smart meter requires more energy than an average 19.0 to 21.4 cubic feet refrigerator or freezer manufactured for sale in the United States between 2011 and 2015.627

Mr. Warriner also confirmed that the meter energy consumption would be included in

electric distribution system line losses.628

625 See RCG brief, pages 14-15. 626 See 6 Tr 266. 627 See 6 Tr 324. 628 See 6 Tr 323-324.

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This PFD finds that Mr. Acienega and Mr. Warriner have established that the

meters are not registering consumption attributable to the operation of the meter, i.e.

“on the customer side.” This PFD also finds their testimony persuasive that the line-side

electric burden is not of the magnitude Mr. Bathgate has estimated. The company has

offered to work with Mr. Peloquin to determine what is causing the meter on his house

to register consumption, which is a reasonable solution since this PFD finds that the

meter readings at the house are not caused by the AMI meter.

Nonetheless, in seeking to revise the opt-out charge in accordance with the

Commission’s order in Case No. U-17990, or as that order may be modified in this case,

Consumers Energy should expect to identify any difference in the energy consumption

between the transmitting AMI meters and non-transmitting or analog meters. Regarding

the RCG’s request for an investigation of the health and safety of the AMI meters, there

is no new evidence on this record to warrant an investigation. The RCG is always free

to present the Commission’s staff with any information it chooses.

E. Smart Grid Reporting Metrics

In her testimony, Ms. Fromm recommended that Consumers Energy smart grid

reporting be separated from the five-year distribution plan required in Case No.

U-17990, and parallel the reporting provided by DTE Electric. It appears Staff and the

company are now in agreement. Mr. Warriner agreed to the separate reporting, but

requested to move the date from February 15 to March 31.629 In its brief, Staff agrees

to the March 31 date.630

629 See 6 Tr 328. 630 See Staff brief, pages 64-65. Also see Consumers Energy reply brief, page 45.

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F. On-line Interconnection Queue

Ms. Baldwin recommended in her direct testimony that the company provide a

public list of interconnection applications on its website.631 She identified a list of

information that she recommended be provided, with monthly updates, and she testified

that she had been encouraged by the company’s initial response to Staff’s audit request

inquiring about an interconnection queue, Exhibit S-15.

Ms. Martinez provided rebuttal testimony indicating that Consumers Energy

agrees with Staff’s recommendations with certain clarifications and refinements:

Staff’s recommendation is that Consumers Energy post on its website monthly updates on an “initial set” of generator interconnection request information. The word “initial” creates several questions. For example, it is unclear if it is Staff’s expectation that the information to be posted may change over time and when the Commission may require a permanent process be developed and implemented. Also, Staff’s recommendation includes no time bounds for the information that would be displayed on this list. For instance, there is no indication of a point in time that would be considered the starting point for which information must be included on the list. Similarly, there is no indication of a future point in time where a completed application or an application that is stagnant due to lack of communication from the applicant would be removed from this list.632

She also identified privacy and practical concerns with some of Staff’s requests. In its

brief, Staff acknowledges the privacy and practicability concerns identified by

Ms. Martinez in her rebuttal testimony. Staff indicates that it fully supports a

collaborative to develop an online interconnection queue, but recommends that the

company begin to provide some information as soon as possible.

ELPC supports Staff’s proposal. In its brief, it states: Like Staff, ELPC is

encouraged by the Company’s response to Staff’s audit request and supports

collaboration between the Company and DTE to establish a public interconnection 631 See 11 Tr 2315. 632 See 7 Tr 990.

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queue.633 In its initial brief, Consumers Energy expresses a clear preference for

resolving all issues related to the interconnection queue through a workgroup,

recommending that the Commission initiate a separate docket to establish the

workgroup, with a goal of producing a list that is consistent for all utilities.634

Staff, in its reply brief, indicates that “Staff is now aware, however, that the

Company has since updated its website to provide all the information Ms. Baldwin

requested, except for Tariff, Project Location Zip Code, Current Point of Interconnection,

Substation ID, and Circuit ID.”635 Staff notes that it appreciates the company’s efforts,

and no longer requests an order from the Commission requiring the company to provide

the information identified in Ms. Baldwin’s testimony. Instead, Staff recommends that

the Commission encourage the parties to continue collaboration to improve and expand

on the information included in the list.

Based on the work of the parties toward resolving this dispute, this PFD

recommends that the Commission accept Staff’s most recent recommendation to

merely encourage the parties to continue working cooperatively on this issue, while

deferring for a later date the question whether a separate docket should be opened to

formally initiate a workgroup.

IX.

REVENUE DEFICIENCY SUMMARY

Based on the rate base, cost of capital, and adjusted net operating income as

presented above, Consumers Energy’s jurisdictional revenue deficiency for the

projected test year is estimated to be $30,138,000. 633 See ELPC brief, page 4. 634 See Consumers Energy brief, pages 22-23. 635 See Staff reply brief, pages 22-23.

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X.

COST OF SERVICE, RATE DESIGN, AND TARIFF ISSUES

A. Capacity Costs

Several of the parties presented testimony addressing the identification,

allocation, or collection of capacity costs under MCL 460.6w. On November 21, 2017,

the Commission issued its order in Case No. U-18239, which largely resolved the

disputed issues on this record related to the capacity charge. Significantly, the

Commission determined a method for establishing the capacity charge. The

Commission then set the capacity charge at $300.59 per megawatt-day. The

Commission specified the term and applicability of the charge. The Commission

adopted the allocation method for allocating the capacity charge revenue requirement

recommended by Staff, and the Commission adopted the year-round rate design for

collecting the charge recommended by Consumers Energy. After specifying these

details, and recognizing that final tariffs could not be determined for June 1, 2018 until

this pending rate case was resolved, the Commission directed Consumers Energy to file

revised tariffs in that docket, Case No. U-18239, within 30 days of the Commission’s

order in this case. Thus, the tariffs Consumers energy files in this rate case, Case No.

U-18322, do not need to reflect the capacity charge; the Commission will separately

address the new tariffs containing the capacity charges in Case No. U-18239. The

Commission further required Consumers Energy to file a reconciliation of the forecasted

amounts under MCL 460.6w(3)(b) as a separate presentation in its annual power supply

cost recovery proceeding, and directed the company to file a standalone contested case

for the review of the state reliability mechanism capacity charge by April 1, 2018, and

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annually thereafter, unless the utility expects the annual review to be taking place in a

rate cost or PSCR case that will conclude by December 1 of each year.

As this ALJ reads the Commission order, there is no need in this rate case PFD

to address revised allocation methods for capacity related costs, or revised rate design

to collect those costs, because the Commission has determined those issues, with the

potential for revisiting them in a future case.

B. Allocation of Residential Discounts

In its filing, Consumers Energy proposed to allocate the costs associated with

discounts to residential income assistance (Rate RIA) and residential senior (Rate RS)

customers under on a total cost-of-service basis, consistent with the Commission’s June

7, 2012 order in Case No. U-16794. ABATE/Gerdau argue that the costs should be

allocated on the basis of total distribution costs. Mr. Pollock recommended this change

because he believes it is more consistent with the way the charges are applied (per

customer per month), and because he believes the purpose of the charge is to provide

relief from “customer charges that are purported to have a more adverse impact on

senior citizens and low-income customers.”636 Ms. Collins endorsed this proposal in her

rebuttal testimony: “The Company does agree that the senior citizen and low income

discounts are applied on a customer basis and, therefore, would be more appropriately

allocated using the customer-related cost-of-service allocation.”637

Mr. Isakson recommended against making this change. He testified: “Simply

because the RIA and RSC discounts are applied to the residential customer charge

636 See 12 Tr 2666. 637 See 10 Tr 2024.

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does not mean the discounts are related to distribution customer-related costs.”638 He

attested to the equitable nature of a total cost of service allocation, and he noted that

the Commission has flexibility to change how the discounts are provided to eligible

customers. He also noted that ABATE/Gerdau recommended an allocation based on

total cost of service in Case No. U-16794.639 In its brief, ABATE/Gerdau do not

expressly address Mr. Isakson’s testimony.640 This PFD finds that ABATE/Gerdau have

not established a good reason to revise the allocation of the residential discounts, in

light of Mr. Isakson’s explanations.

C. Demand Line Loss

As noted above, Mr. Bordine presented an updated line loss study that Ms.

Aponte used in her cost-of-service study. Mr. Pollock recommended the use of demand

line loss factors to restate the 4CP and 12CP demand allocators from the meter to the

generator:

Consumers Energy applied the energy loss factors to the meter-level 4CP and 12CP demands. This is incorrect because the energy loss factors reflect average usage throughout the year. Consumers should have used the peak or demand loss factors to recognize the losses are higher during peak usage periods.641

He presented revised allocators in is Exhibit AB-2. Mr. Jester also made a similar

recommendation, presenting his calculations in Exhibit MEC-11 with a summary chart at

9 Tr 1579:

I recommend that the Commission adopt proper use of the demand loss factors from the revised line loss study in the cost of service determination

638 See 11 Tr 2241. 639 See 11 Tr 2241-2242. 640 See ABATE brief, page 29. 641 See 12 Tr 2658.

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in this case because it is correct and makes a material difference in the costs allocated to customer classes.642 In her rebuttal testimony, Ms. Aponte testified that Mr. Pollock and Mr. Jester had

applied the demand loss factors to the class peak, which she asserted is inappropriate

because demand line loss factors are based on the company’s monthly system peak.643

She also testified that the 4CP 75/25 allocators in Exhibit AB-2 are slightly different from

those used in Exhibit AB-4. And she objected to this approach because it has what she

considers the inappropriate consequence of also modifying the allocation of distribution

costs.644

Mr. Jester also recommended that the company be required to provide in future

line loss studies a determination of the losses appropriate for calculating each of the

cost allocators used in the cost of service study:

Because line losses as a percentage of load vary with load, each of these cost allocators should reflect different line loss factors that are consistent with the definition of the allocator. Such results will generally be more accurately determined and transparently presented if the line loss study produces an intermediate work product consisting of hourly deliveries and losses to each component of Consumers Energy’s system.645

In response, Mr. Bordine testified that the hourly load data Mr. Jester identified is not

available for each system component, but only for the transmission and HVD system

components.646 He explained how the company accounts for LVD system losses in the

absence of direct hourly data. He testified that this method uses all available data and

has been approved by the Commission. Ms. Aponte also objected to a requirement that

the company be required to produce the analysis, but testified: 642 See 9 Tr 1579. 643 See 7 Tr 703, 706. 644 See 7 Tr 703-704, 706. 645 See 9 Tr 1580. 646 See 6 Tr 452.

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The Company is not opposed to considering improvements to its current methodology of applying line loss factors in the development of allocators in a future rate case, as long as they are consistent with cost causation principles and their application is reasonable.647 ABATE/Gerdau do not address Ms. Aponte’s testimony in their brief.648

MEC/NRDC/SC acknowledge her testimony that the demand loss factors should be

applied to each monthly peak. They argue that the company’s line loss adjustments to

the monthly peaks based on energy are clearly wrong, and that Consumers Energy did

not provide monthly demand loss factors in its cost of service study. They also question

why a correlative change in distribution costs is objectionable. MEC/NRDC/SC also

argue that the company did not object to Mr. Pollock’s and Mr. Jester’s revisions to the

12CP allocator using the demand loss factors. They recommend that the Commission

require Consumer Energy to revise its cost of service study to apply the demand loss

factors to the 12 CP allocator data, and require the company to apply demand loss

factors for peak allocators in future studies.649

In its reply brief, Consumers Energy objects to revising either the 12CP or 4CP

allocator in this case.650 Consumers Energy acknowledges that it is open to considering

the proposed change in allocator, but argues that additional analysis is required to

determine the differences between the average and monthly calculations, how common

this method is, and the full impact of the proposal. The company asks that the

Commission not adopt the proposed allocator change in this case. This PFD finds that

Consumers Energy’s requested accommodation for additional time to evaluate the

proposal is a reasonable one, given the limitations on the data available to adjust the

647 See 7 Tr 707. 648 See ABATE/Gerdau brief, pages 22-25. 649 See MEC/NRDC/SC brief, pages 54-56. 650 See Consumers Energy reply brief, pages 178-179.

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monthly peaks. Therefore, this PFD recommends that the Commission direct

Consumers Energy to present its analysis of the proposed refinement in its next case.

The company should also provide a calculation of demand loss factors for peak

allocators in its next rate case, or explain why it is unable to.

D. Interruptible Credits

Mr. Pollock also took issue with the allocation of credits provided to interruptible

customers under the company’s residential and C&I demand response programs. He

testified that the credits are allocated using the 4CP 75/25 allocator, but the interruptible

customers are included in the 4CP measurement. Testifying that Consumers Energy

does not plan capacity resources to serve interruptible load, he presented a derivation

of the allocation factors excluding the interruptible load in his Exhibit AB-3. He

presented a chart showing changes in the allocation percentages by class.651

Ms. Aponte disputed that Mr. Pollock’s proposal is a material change in the allocation of

interruptible credits between the major classes. She testified that the credits in the

company’s cost-of-service study are allocated using the production cost allocator, and

achieve “very similar” results, such that it is not reasonable to create an additional

allocator.652 In their brief, ABATE/Gerdau do not address Ms. Aponte’s rebuttal

testimony.653 This PFD accepts Ms. Aponte’s conclusion that the results of the two

approaches are very similar with no need to create a new allocator.

E. Intersystem Sales Allocator

Ms. Aponte proposed a change in the allocation of MISO energy sales revenue,

from a capacity-based allocation to an allocation based on energy, contending that this 651 See 12 Tr 2661-2262. 652 See 7 Tr 704-705. 653 See ABATE/Gerdau brief, pages 25-27.

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change will “follow the nature of the transaction.”654 Ms. Walz also testified in support

of this change, referring to line items in Exhibits A-78 and A-79:

The economic sale of energy, shown on line 55, occurs when there is a surplus of generation (net of customer demand) which costs less to produce than the market price being paid for power. Energy sold strictly for reliability purposes to MISO is shown on page 3, line 57. MISO must ensure that sufficient resources, including spinning reserves, are available and online to meet the forecasted MISO load for each hour of the next operating day. We have estimated the amount of increased generation at the generating units that MISO uses for this purpose and have represented it as a sale. Energy sales to MISO, either for economic or reliability purposes are an output of the PROMOD IV production cost model simulation. The nature of those credits is strictly energy-related and they include no revenues for the sale of capacity. The PROMOD IV documentation for the energy sales shown on lines 55 and 57 explains the outputs as follows:

“This is the process by which energy is bought and sold by companies on an economic basis to help reduce production costs for the buyer and provide a profit to the seller.”655

Similarly, Mr. Pollock testified in support of the company’s proposal:

Intersystem sales are made from available generation capacity resources that were dispatched by MISO because these resources were lower in cost than other generation resources available at that time. There is no firm commitment to sell a fixed amount of power over a specific time period, which are the essential characteristics of a capacity sale. Further, Consumers has determined that only 5% of the projected test-year intersystem sales were reliability-driven.656

Mr. Revere explained Staff’s view that the revenues should be allocated based

on 4CP 75/25 on the same basis as the underlying production costs. He explained:

The costs associated with purchasing energy from the market when the Company’s plants produce less than its customers use are included in rates as an energy cost, appropriately. The revenue produced from energy sales into the market resulting from plants producing above the use of the Company’s customers should be included as an offset to the cost of the

654 See 6 Tr 687. 655 See 6 Tr 534 (emphasis in original). 656 See 12 Tr 2716.

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capacity used to produce that energy. In fact, Section 6w(3)(b) of Act 341 expressly requires revenue from “all energy market sales” be included as an offset to the cost of capacity. Beyond the statutory requirement, it is the appropriate disposition of such revenue, as it is the additional capital expenditure over that of a CT which enables the production of energy at a cost low enough to make money in the market. Therefore, revenue from such sales should be used to offset the higher capital expenditures required to enable them.657

In her rebuttal testimony, Ms. Aponte responded:

Mr. Revere recognizes that intersystem sales are revenue produced from energy sales, which is the nature of these transactions as explained by Company witness Walz in her direct testimony. Therefore, intersystem sales have been correctly classified by the Company as a non-capacity-related item.658 While this PFD concludes that the Commission’s November 21, 2017 order in

Case No. U-18239 resolves this allocation issue for all practical purposes consistent

with Staff’s recommendation, it is ineluctably clear that Staff’s analysis is the correct

one. The energy that is available to sell is attributable to the existence of the underlying

capacity, and the costs and benefits should be allocated accordingly. Note that Ms.

Walz seems implicitly to recognize this in her testimony because she explains that the

energy sale takes place due to a “surplus of generation”.659 That energy is being sold,

not capacity, is irrelevant.

F. Distribution System Cost Allocations

Mr. Jester also called for an investigation of distribution system cost allocations

for future cases. Although he provided several reasons for his concern, among those

reasons, he testified:

657 See 11 Tr 2419; also see Putnam, 11 Tr 2407. 658 See 7 Tr 702-703. 659 See 6 Tr 534.

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[A]llocating distribution system costs entirely based on class peaks fails fundamental logic in that substantial portions of the distribution system are unrelated to demand. I have reviewed a number of “minimum-system” or “zero-intercept” analyses of distribution system costs, and generally not more than 60% of distribution system costs are found to be demand-related. While I reject the common utility position that the remaining 40% or more of the distribution system costs are “customer-related” costs that should be recovered as fixed costs, I do find persuasive that such analyses show that a substantial portion of distribution system costs are not “demand-related”.660

Mr. Revere also addressed this recommendation in his rebuttal testimony, agreeing that

the Commission should require Consumers Energy to reexamine the allocation of

distribution system costs in its next general rate case:

Staff has had growing concerns that the current allocation of distribution costs does not properly reflect the manner in which costs are incurred to serve customers. MEC-NRDC witness Jester’s concerns and recommendations on appropriate allocations may or may not align. In order to ensure that allocations properly reflect the manner in which costs are caused, and provide a starting point for any interested parties to make appropriate recommendations thereon, the Company should be required to reexamine the allocation of distribution system costs in its next general rate case.661 In their briefs, MEC/NRDC/SC and Staff urge the Commission to adopt this

recommendation.662 MEC/NRDC/SC cite the Commission’s statutory obligation under

MCL 460.11 to “ensure the establishment of electric rates equal to the cost of providing

service to each customer class.” MEC/NRDC/SC cite the availability of more-detailed

data with the installation of the AMI meters, and Consumers Energy’s plans for

substantial capital investment in its distribution system. MEC/NRDC/SC argue that a

reasonable forum for undertaking this evaluation may be in the evaluation of the long-

660 See 9 Tr 1591 661 See 11 Tr 2429-2450. 662 See MEC/NRDC/SC brief, pages 59-65.

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term distribution system plan Consumers Energy will shortly file. Citing the last

Consumers Energy and DTE Electric rate cases, MEC/NRDC/SC explain:

The Commission recently issued an order in those cases recognizing that “continuously evolving technology and customer expectations will require a more comprehensive approach to developing a ‘no regrets’ distribution plan.” The Commission also recognized that long-term distribution planning may facilitate ratemaking processes and “the development of potential new approaches to provide greater regulatory certainty”. The Commission bifurcated distribution planning, requiring the utilities’ initial five-year distribution plan to emphasize the near-term priorities of ensuring safety and reliability in the distribution system. And the Commission required Staff to convene stakeholders for the development of the framework for future distribution plans, reporting back its findings by September 1, 2018. The deep examination of long-term distribution system planning by the utilities, stakeholders, and the Commission, as required by the Commission’s October 2017 order in Case Nos. U-17990 and U-18014, provides an opportunity for utilities, stakeholders, and the Commission to obtain a more informed understanding of cost causation associated with the distribution system, as well as to modernize its revenue requirement and cost of service study practices to be consistent with distribution system planning practices. The Commission may require that the framework for distribution planning process should include consideration of the cost causation aspects of the distribution system.663 Consumers Energy does not agree that it should perform this analysis, citing the

NARUC Manual in Exhibit S-17:

According to the NARUC Manual, the Company’s allocation of distribution costs based on customer class peaks is an appropriate and acceptable allocation method. The NARUC Manual states that because “load diversity at distribution substations and primary feeders is usually high,” the “customer-class peaks are normally used for the allocation of these facilities.” . . . Just as with MEC/NRDC/SC’s proposal related to line loss factors, the Company is not opposed to evaluating and considering improvements to cost allocations. See 7 TR 707. Consumers Energy continually evaluates its COSS methodology, and seeks to develop a COSS in each rate case that is consistent with the principles of cost causation and that will be

663 See MEC/NrDC/SC brief at pages 64-65.

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reasonably applied. See 7 TR 707. The Company’s next rate case will include the Company’s proposed COSS, and Staff and MEC/NRDC/SC will have the opportunity to review the COSS, perform discovery related to the COSS, and make any COSS counter-proposals, including proposing alternatives to the Company’s allocation of distribution costs. The Commission should not place an additional burden on the Company to perform a separate analysis of distribution cost allocations; the Company will use the cost allocations it determines are appropriate, and Staff and MEC/NRDC/SC will be able to perform their own cost allocation analysis and make their own cost allocation proposals. 664

In its reply brief, Staff expressed a concern with MEC/NRDC/SC’s proposal to consider

distribution system cost allocations in the context of review of the five-year distribution

system plan:

Staff disagrees with MEC’s position that the ongoing distribution planning process is the appropriate venue to consider inputs for distribution cost allocation. (MEC’s Initial Br, pp 64–65.) While this process may provide helpful information about how the Company makes decisions that affect distribution system costs, only in a rate case may that information be used to allocate costs. Should the Commission agree with MEC that distribution costs may be allocated outside of rate cases, a separate forum would be more appropriate given the significant differences between distribution planning and cost allocation processes.665 This PFD recognizes that Consumers Energy is in the process of finalizing the

distribution system plan called for in Case No. U-17990, and embarking on a significant

investment in its distribution system, indicating that this is likely an opportune time to

consider as well questions of cost causation and allocation. While Staff is correct that

distribution cost allocations should not be determined outside a rate case, that does not

mean they cannot be evaluated by interested parties outside a rate case. As this record

shows, obtaining and analyzing pertinent data can be time consuming. Note that

Consumers Energy and MEC/NRDC/SC reached an agreement toward the end of the

664 See Consumers Energy reply brief, page 179-180. 665 See Staff reply brief, page 33.

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hearing to submit surrebuttal and sur-surrebuttal testimony to allow for the consideration

of additional data. Future rate cases will be conducted in a ten-month time frame,

further shortening the time for analysis.

This PFD is also concerned that merely directing Consumers Energy to explore

alternatives to the current allocation method would not provide sufficient guidance to be

fair to the company or to ensure useful results. By providing for some exploration of

alternative allocation methods outside the context of a rate case, even if no general

consensus is reached, the Commission should expect a better, more well-considered

record in the subsequent rate case in which alternatives are presented to the

Commission.666 For these reasons, this PFD recommends that the Commission follow

the suggestion in MEC/NRDC/SC’s brief as quoted above to establish a collaborative

proceeding to identify and evaluate alternate methods for the allocation of distribution

system component costs, but in deference to Staff’s concern, separate from the review

of the company’s distribution system planning Given the pace at which Consumers

Energy has been filing rate cases, it is not feasible to expect significant work to be done

on this issue before the company’s next rate case filing.

G. Residential Rate Design

In anticipation of capacity charges approved under MCL 460.6w, Staff

recommended that rates be designed to collect those charges in a way that reflected

how the costs are assigned. Mr. Revere testified that for rates with demand charges,

Staff recommends on-peak billing demand in summer months. For other rates, Staff

recommended that the capacity charges be recovered through summer on-peak usage. 666 Given the short time periods recently between the issuance of a rate case order and the filing of another rate case, it seems unrealistic to expect this analysis to be completed by the rate case after this one.

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Thus, for residential customers, Staff recommended eliminating the “inverted block”

residential rate design and replacing it was rates for on-peak summer usage, and other

usage.667

Mr. Jester also looked at rate design as an opportunity to send price signals

related to the allocation of the underlying costs. He recommended that capacity and

energy cost recovery be shifted to summer rates for residential customers.

As a general strategy, I recommend allocating these costs to billing determinants that are controllable by the customer and that accurately predict the customer’s contribution to the statistics on which cost allocation is based. Constructing rates on this basis will send price signals to customers that will enable them to optimally reduce the Company’s total cost given the customer’s value for various billing determinants. It will also allocate costs associated with each cost allocator to each customer as accurately as possible given a set of billing determinants. More specifically, the costs allocated to a customer class based on a statistic used in the cost of service study should be allocated to billing determinants within a class based on a regression that predicts the individual customer’s contribution to the cost allocation statistic given the customer’s billing determinants. Because that regression will provide the most accurate prediction of the customer’s contribution to allocated costs based on the billing determinants, it will provide the most accurate allocation of costs to each customer within the class. By minimizing the error with which costs are allocated to each customer based on the available billing determinants, it will minimize intra-class cross subsidies. Because the unit prices of billing determinants are likely to closely reflect customer power usage factors that also drive cost allocation, pricing billing determinants in this way will also provide relatively clear cost signals to customers.668

He explained that he performed regression analysis on a sample of residential

customers and concluded:

[A]ll costs for production plant assigned to the Rate RS class, generally allocated based on the 4CP statistics, should be recovered through summer rates with essentially the same cost per kWh in both the first 600 kWh per month and the excess kWh per month for each customer. This would result in a significant reduction of winter rates and increase in

667 See Revere, 11 Tr 2422-2426. 668 See 9 Tr 1592.

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summer rates compared to the Company’s proposed design of Rate RS.669

Consumers Energy strenuously objected to these proposals. In his rebuttal

testimony, Mr. Hall expressed a concern that the proposals are not practicable:

Time of use rates are currently billed based on interval meter data and are considered part of the Company’s complex billing system. System capacity for these types of rates was designed and tested for a maximum of 420,000 accounts per year. Exceeding this capacity with 1.5 million residential customers moving to complex billing would require extensive infrastructure and application architecture changes. In addition, a change of this nature would require functional testing, system integration testing, load testing, and performance testing with SAP complex billing module as well as our bill generation and print software. The same level of testing would be required for the customer website bill presentation and the contact center Customer Relationship Management bill presentation. A change of this magnitude could be implemented with appropriate funding, however a phased implementation would be the Company’s recommended approach.670

Ms. Collins first objected to the concept of aligning rate design to reflect cost

responsibility. She testified: “Utility capacity service is provided all year, not just during

the summer months; as such, capacity-related costs should be collected from customer

through rates year round.”671 She also characterized Staff’s proposal as a dramatic

change, and expressed concern that the rate design could create unnecessary

hardships for customers in summer months, disrupt industrial customer planning, and

affect the company’s ability to recover its costs.672 While she acknowledged that Staff’s

rate design might provide better price signals, she contended it should be offered on an

optional basis, or phased in over a number of years.673 Regarding Mr. Jester’s

testimony, Ms. Collins took issue with his regression analysis. She likewise testified

669 See 9 Tr 1599. 670 See 7 Tr 984. 671 See 10 Tr 2022. 672 See 10 Tr 2022. 673 See 10 Tr 2023.

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that he was confusing rate design with the determination of cost responsibility.674 She

testified that his analysis would be more useful if he attempted to allocate the costs of

peaking units into the summer months. She also testified that he ignored the impact on

low-income and fixed-income customers.675

Mr. Jester presented surrebuttal testimony after obtaining a sample of RIA and

RSC customer data. Ms. Collins presented sur-surrebuttal responding to this testimony.

She reiterated her concerns that the summer rate impacts could pose hardships for

customers and she questioned whether the sample sizes he used for his regressions

were a sufficient basis on which to draw conclusions.676

In its reply brief, Consumers Energy argues that the “over-emphasis” on cost

causation has led to proposed rate designs that do not address all attributes of a sound

rate structure. The company cites James C. Bonbright, et al, Principles of Public Utility

Rates (1988).677

Because this PFD concludes that the Commission’s November 21, 2017 order in

Case No. U-18239 resolved the rate design question for the capacity charge

established in that case, reserving consideration of alternatives to future cases, this

PFD concludes that the Commission’s order as a practical matter resolves the issue for

this rate case as well. Nonetheless, recognizing the potential importance of this rate

design in light of Mr. Revere’s and Mr. Jester’s testimony, this PFD recommends that

Consumers Energy be directed to present a plan in its next rate case for attaining the

capability to implement time-of-use rates such as summer on-peak rates for residential

674 See 10 Tr 2031. 675 See 10 Tr 2031-2032. 676 See 10 Tr 2035-2036. 677 See Consumers Energy reply brief, pages 184-188.

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customers, including the necessary educational materials and customer service training,

with information on the applicable costs and timeframes for implementation.

H. Rate GPD

Consumers Energy proposed that all capacity-related costs (100%) be collected

through a demand charge, an increase from the 75% used in Case No. U-17990. As

noted above, Staff recommended that capacity charges for demand-billed customers be

collected through summer on-peak demand charges. Similar to the discussion of

residential rate design above, Consumers Energy objected to the summer-peak

approach, characterizing it as a “dramatic rate change,” without adequate assessment

of the revenue risk, or the 60% increase in summer rates for secondary and primary

customers.

Mr. Pollock recommended an increase in the summer-winter demand charge

differential, from $1 to $4. Ms. Collins testified that Consumers Energy opposes that

proposal, characterizing it as a dramatic change, with no analysis of customer impacts

or changes in behavior that of customer impact or changes in behavior that could affect

the company’s ability to recover its revenue requirement.678

Kroger also objected to this proposal, recommending it remain at $1. Kroger also

expressly objected to Staff’s proposed rate design claiming that Staff is shifting recovery

of demand related costs into energy charges. In his rebuttal testimony, Mr. Townsend

explained his concern:

I recommend that the elements of Staff’s rate design proposal that recover demand-related power supply costs through an energy charge and that recover capacity costs through a summer-only demand charge be rejected

678 See Collins, 10 Tr 2024-2025; also see Consumers Energy brief, pages 214-215; reply brief, pages 195-196.

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by the Commission. Such modifications would constitute a radical and unnecessary 17 change in rate design that would result in unwarranted intra-class cost shifting 18 among bundled service customers.679

In its brief, Staff states:

For the purposes of this case, Staff is willing to accept that the total amount of costs currently collected through power supply demand charges that is not collected through the capacity charge for demand billed schedules be collected through non-capacity demand charges. In this way, at least the same amount of costs will be collected through demand charges as in currently approved rate design. In Staff’s opinion, increasing the amount of costs collected through demand charges not related to capacity should be dealt with separately from the SRM issues, and should therefore be decided in a future case.680

For the reasons explained above, this PFD concludes that the collection of capacity

charges through summer-only demand charges as a practical matter has been resolved

by the Commission’s decision in Case No. U-18239, which adopted Consumers

Energy’s rate design, as well as by Staff’s proposal as presented above.

I. Rate GPD Transmission Costs

Consumers Energy, ABATE, Kroger, and HSC agree that transmission costs

allocated to the Rate GPD class should be recovered through a demand charge, but as

a separate line item.681 Staff raised no objection to this proposal, nor did any other

party. On this basis, this PFD recommends that the Commission approved the separate

demand charge for transmission cost recovery as part of the Rate GPD rate design.

J. Rate GPD Voltage Levels

Mr. Townsend testified regarding the voltage-level rate design for Rate GPD,

contending that it overrecovers the rate design target for voltage level 3, while

underrecovering the rate design target for voltage level 1. In its brief, Kroger 679 See 6 Tr 241-242. 680 See Staff brief, pages 109-110. 681 See Collins, 10 Tr 2024, 2027; Pollock, 12 Tr 2671; HSC brief, pages 3, 10-11; Townsend at 6 Tr 236.

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characterizes the rate design as “arbitrary and unreasonable.” Consumers Energy

disagrees, asserting that it has used the same rate design as approved in Case No.

U-17990.682 Since the Commission approved this rate design earlier this year, this PFD

concludes that the rate design used in Case No. U-17990 should be continued in this

case.

K. Rate GPD/GP Crossing-point Adjustment

Following the Commission’s order in Case No. U-17990, Consumers Energy

performed a study on the elimination of the interclass crossing point between Rate GP

and Rate GPD. In designing rates, Ms. Collins testified that she maintained the

crossing-point, using a 45% load factor, because Consumers Energy believes that it is

more efficient that contacting each customer to offer to move them to another rate.

Staff also recommended maintaining the crossing point. Although Ms. Collins identified

an error in Staff’s initial calculations, the briefs of the parties confirm that both agree to

the 45%-load-factor crossing point.

In Staff’s initial testimony, Mr. Isakson explained that to maintain the crossing-

point adjustment at 45% with Staff’s revenue requirements and cost allocations, Staff

moved costs from Rate GP to Rate GPD. As noted above, Consumers Energy

identified an error in Staff’s calculations. Kroger also expressed concern over the

direction of the cost transfer. In its reply brief, Staff argues that the focus should be on

the principle, to which Kroger does not object, rather than on the direction of the cost

shifting necessary to achieve that result.683

682 See Consumers Energy reply brief, page 196. 683 See Staff reply brief, page 31.

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L. Rate EIP

The Energy-Intensive Primary rate (Rate EIP) is designed for full-service metal-

melting customers or other energy-intensive industrial load. Customers on this rate

schedule face critical-peak-pricing events during which they will pay LMP-based prices

if they do not curtail their usage.684 Ms. Collins addressed the capacity adjustment for

the Energy-Intensive Primary rate design:

The load profile that was used for EIP customers in the COSS assumes reduced loads during the high-peak summer pricing periods, and thus results in a low allocation of capacity costs to these customers. The Company believes it is reasonable to assume some diversity of load for the EIP class at the time of the coincident peak, and therefore an adjustment is made so that EIP customers are allocated a reasonable share of the capacity costs. As a result, the Company is proposing that approximately $5.2 million of capacity costs be allocated to EIP. This allocation will result in a slight increase for the EIP class, while still recognizing that EIP customers are assuming a level of price risk related to the critical peak component that is designed into the EIP Rate.685

Mr. Isakson testified that Staff agreed with the company’s method. In her rebuttal, Ms.

Collins noted that Staff had not updated its adjustment to reflect Staff’s revenue

requirement and cost-of-service study. Staff acknowledges the error, and no other party

addressed this rate, resolving this dispute.

M. Rate GSG-2

Rate GSG-2 is a standby rate for large customers with their own generation.

There are only approximately a dozen such customers. A substantial amount of

testimony and briefing were devoted to the proper establishment of rates and tariffs for

Rate GSG-2. By way of background, in its November 19, 2015 order in Case No.

U-17735, the Commission created a workgroup at Staff’s urging to study various issues

684 See November 19, 2015 order, Case No. U-17735, pages 106-109. 685 See 10 Tr 2001.

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concerning standby service and rates, including how standby rates are currently

developed, how other states have addressed standby rates, and an evaluation of

methods that better reflect the costs and benefits of serving customers with self-service

power.686 In this current rate case, Ms. Baldwin presented the August 2016 workgroup

report as Exhibit S-15.2, and the June 2017 supplement report as Exhibit S-15.1. In its

February 28, 2017 order in Case No. U-17990, the Commission rejected a revised rate

design for Rate GSG-2 that Consumers Energy proposed in its rebuttal testimony, and

directed the company to provide a study comparing the power supply costs and

revenues associated with standby customers for its next rate case, “to support its

assertion that this rate is cost-based.”687

In this case, Consumers Energy proposed a change in the rate design for this

rate in its initial filing, as explained by Ms. Collins. She testified that the company

completed the study required by the Commission’s order in Case No. U-17990 that

compares the Rate GSG-2 revenue at current rates to the costs as determined in the

cost-of-service study.688 While the study, Exhibit A-85, shows that the Rate GSG-2

customers are paying more than their total allocated embedded cost of service, she

testified that this is attributable to the use of the 4CP allocation, which may not align

with the times the standby customer is using capacity. She testified that the exhibit also

shows the Rate GSG-2 customers are paying half the embedded costs on a dollar-per-

kW basis that other customers served at the same voltage level are paying.

She testified that the rate design has historically used demand charges based on

the highest contracted capacity, which has been the Palisades PPA, and then explained 686 See November 19, 2015 order in Case No. U-17735, pages 110-111. 687 See February 28,2017 order in Case No. U-17990, pages 146-147. 688 See 10 Tr 2004.

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that with the planned termination of that PPA, Consumers Energy is proposing to

determine demand charges based on the company’s embedded cost of capacity.689

She cited the per-kW cost of capacity as presented in Exhibit A-11, and testified that the

cost of capacity should be reflective of the company’s embedded cost of service as

allocated to comparable customer-types in the approved cost-of-service study. She

stated that the capacity charge for Rate GSG-2 customers will continue to reflect the

number of on-peak days the customer takes standby service during the month.

ABATE/Gerdau objected to the company’s proposal. Mr. Pollock recommended

against the change in the Rate GSG-2 rate design, citing the company’s study that it is

already recovering its embedded cost of service, and testifying the company’s current

proposal would more than double the power supply demand charge.690 He also

objected that the tariff does not recognize the different characteristics of backup and

maintenance power, and objected the use of a 10% adder to LMP energy price for

summer on-peak use, citing DTE Electric’s tariff and the standby rate workgroup

supplemental report.691 He also recommended clarification of the proration language.692

MCA also objected to the company’s proposals. Mr. Dueweke testified to the

importance of reasonable standby rates and transparent and comprehensible tariffs to

the decision whether to undertake a potential cogeneration project, further testifying that

Consumers Energy’s rates are excessive and the tariff is not transparent.693 He also

recommended a further evaluation of the distribution charge component of the rate

design. Ms. Scripps also objected to the company’s proposals, presenting a

689 See 10 Tr 2013-2014. 690 See 12 Tr 2636-2637, 2678-2680. 691 See 12 Tr 2637, 2680-2684, 2689. 692 See 12 Tr 2638. 693 See 6 Tr 190-199.

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comparison with other utility standby tariffs, and endorsing the recommendations in the

standby workgroup supplemental report. 694

Mr. Jester testified for MCA, ELPC, and MEC/NRDC/SC regarding the Rate

GSG-2 rate design and tariff. He objected to Consumers Energy’s proposed rate

change:

Witness Collins claims that current GSG-2 customers are paying half of what “comparable” customers served at the same voltage level are paying for. The correct comparison, however, is stated in the Commission’s Order from the last rate case: a study that “compares power supply revenue from Rate GSG-2 customers to power supply costs caused by these customers, in order to determine whether current demand charges reflect the cost to serve standby customers.” In other words, the comparison the Commission requested is between the costs a standby customer causes and the revenue a standby customer generates. This is the appropriate comparison.695

He recommended an alternate rate design, testifying that the capacity charges for Rate

GSG-2 should not be more than the product of the forced outage rate for the customer

times the average cost of capacity for that customer. He cited the Public Utilities

Regulatory Policy Act (PURPA) in support of his contention that the tariff must be

nondiscriminatory. Mr. Jester also recommended that customers with solar self-service

generation be able to take service under the Rate GSG-2 tariff or under the tariff to

which they would otherwise be assigned. He testified: “These customers need power

from the Company virtually every day rather than just during an outage of self-service

generation.”696

Ms. Baldwin testified that in this case, Staff is recommending that the

Commission consider two of the recommendations in the standby workgroup


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supplemental report, items 6 and 7, addressing solar generation. Testifying that

customers with solar generation projects need power every day, she recommended that

the company allow customers with solar self-generation to take service under the Rate

GSG-2 tariff or under the General Primary Time-of-Use rate (Rate GPTU).697. She

explained that she is still reviewing and considering additional recommendations for

standby service tariffs.698

In her rebuttal, Ms. Collins repeated the rationale for the change that she

presented in her direct testimony. She then emphasized: “[S]tandby customers only

pay for this capacity on a prorated basis, based on the number of on-peak days the

standby customer actually uses the capacity. . .This is not an option offered to GPD

customers who are charged for capacity based on their monthly highest demand

established during on-peak hours.”699 She also testified that the tariff allows a customer

to arrange for service for scheduled maintenance outages, to avoid paying an additional

10% of LMP during the summer billing months. She also objected to Mr. Pollock’s

recommendation to waive the “on-peak demand ratchet” for maintenance power.

Addressing Mr. Dueweke’s testimony, she contended that Rate GSG-2 customers are

not paying more than their fair share under the company’s proposals.700 She also

specifically disputed that prorating delivery demand charges would be reasonable,

contending that the cost of distribution facilities in place to serve a customer does not

change based on the amount of time the customer uses the system. She also objected

to his proposal to set charges based on the approved cost-of-service-study, noting her


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earlier testimony that the cost of service study uses coincident peaks, which may not

correspond to the time the Rate GSG-2 customers are taking service.701 She similarly

responded to Ms. Scripps, asserting that the company has an obligation to propose

cost-based rates, and thus a comparison to other jurisdictions is not relevant. She

addressed Mr. Jester’s testimony, testifying that his proposed rate design is appropriate

for a “reservation charge,” which the company has not proposed.702

In his rebuttal testimony, Mr. Hurd stated that Consumers Energy is willing to

adopt Ms. Baldwin’s recommendation to retain eligibility for solar customers to take

service also under time-of-use rates, but as a pilot for a minimum of five years, to

“provide the Company with the time and data necessary to make a determination as to

whether this is an appropriate rate design for standby service based on their actual

experience.”703 Also, acknowledging Mr. Jester’s reference to PURPA, he testified that

Rate GSG-2 is available more broadly than just to Qualifying Facilities under PURPA

and language in the tariff indicating that Consumers Energy has the right to refuse to

contract for the purchase of energy is therefore appropriate.704

Ms. Aponte also testified in rebuttal, disputing that a historical cogeneration

outage rate if 5% can be used to allocate system costs, and responding to Ms. Scripps’s

analysis by stating that the other utilities in the analysis not from Michigan may be abler

to include subsidies or incentives to reduce cost-based rates. She also testified that

Ms. Scripps’ reference to “reservation fees” is incorrect because Consumers Energy

does not use a reservation. She also testified that the delivery charges in the

701 See 10 Tr 2030. 702 See 10 Tr 2032. 703 See 9 Tr 1507. 704 See 9 Tr 1508-1509.

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company’s rate design reflect the fixed distribution costs that are ready to serve standby

customers at all times, as necessary to avoid a subsidy.705

In his rebuttal testimony, Mr. Pollock endorsed Mr. Dueweke’s recommendation

regarding the proration of delivery demand charges, cecommending that the

Commission require Consumers Energy to review the New York standby rate design

and conduct a further analysis of the distribution system.706

Mr. Krause also filed rebuttal testimony to address the testimony of

Mr. Dueweke, Ms. Scripps, Mr. Jester, and Mr. Pollock regarding distribution system

costs for Rate GSG-2. He testified that distribution system use is currently measured by

the non-coincident peak demand of the customer for rate design purposes, while class

peak at a given level of the system is used to allocate costs to each class. He cited

recommendation 3 from the supplemental standby working group report, and asserted

that because Staff does not have the projected metered demand for the standby

customers, it cannot design rates on that basis. It recommended that the Commission

require Consumers Energy to provide actual and projected peak metered demand

billing determinants for GSG-2 customers, including any ratchet that would be applied,

and if the company chooses to rely on contracted demand, require it to provide

justification, It recommended that in this case, distribution charges continue to be

charged as they have been,707

The parties’ recommendations are generally consistent with the testimony of their

witnesses. In its initial brief, Consumers Energy argues that it is revising its Rate GSG-

2 rate “to align the power supply capacity charges with the Company’s embedded 705 See 7 Tr 708-710. 706 See 12 Tr 2733. 707 See 11 Tr 2367-2369.

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cost.”708 It responds to Mr. Pollock’s testimony by arguing that a subsidy will be created

if the company’s rate design is rejected. It addresses his concern with backup and

maintenance power differences by arguing that its tariff does allow customers to avoid

the additional 10% LMP adder during the summer billing months by scheduling

maintenance in advance. It addresses his concern with the 10% LMP adder by arguing

it incents customers to schedule maintenance in advance or to schedule maintenance in

the non-summer months.709

Consumers Energy responds in part to Mr. Dueweke’s recommendation to rely

on historical outage rates by arguing that the data show a “load profile change,” from no

on-peak load requirements in 2013 and 2014, to some on-peak demand in 2015 and

2016, and further, that load profiles can change significantly as new load is added, as

Ms. Aponte testified.710 It responds in part to Ms. Scripps’s testimony by relying on

Ms. Aponte’s rebuttal testimony that the other utility standby charges identified in Exhibit

MCA-4 may allow the use of incentives or subsidies to reduce standby rates.711

Consumers Energy argues that MCA has not offered any evidence that suggests the

company’s proposed Rate GSG-2 rate is not cost-based.712 It also argues that MCA

has not offered any cost-based alternatives. Further, Consumers Energy defends its

use of an LMP energy price in reliance on Ms. Collins’s testimony that it holds all

customers harmless for the cost of energy that standby customers take, and thus avoids

subsidization. It disputes that distribution costs should be prorated in any way, arguing

708 See Consumers Energy brief, pages 216-218. 709 See Consumers Energy brief, pages 218-219. 710 See Consumers Energy brief, page 203. 711 See Consumers Energy brief, page 204. 712 See Consumers Energy brief, page 222.

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that would not be consistent with cost-based ratemaking.713 It disputes that it should

rely on its cost of service in setting power supply charges due to the limited number of

customers, contending this supports it use of a dollars-per-kW charge equivalent to that

paid by comparable full-service customers.714 It also renews its offer to allow standby

solar customers to take service under Rate GPTU as a five-year pilot.715

ABATE/Gerdau argue in their brief that the Rate GSG-2 rate increase should be

rejected for the reasons articulated in Mr. Pollock’s testimony, that the different

characteristics between backup and maintenance power should be recognized, that the

proration provisions of the tariff should be clarified, and that the 10% summer energy

price adder should be rejected. MCA argues that the increase in capacity costs is

contrary to its cost-of-service analysis, and cites Mr. Jester’s testimony that it is

misleading to refer to full service customers as comparable. It further argues that

Ms. Scripps’s apples-to-apples comparison shows that Consumers Energy has the

second-highest standby charges in months with no outages, and Mr. Dueweke’s

testimony that the company’s tariffs discourage investment in cogeneration projects.

Regarding distribution rates, MCA endorses Mr. Pollock’s call for a study of the New

York standby rate design. MCA endorses the recommendations in the standby

workgroup reports and recommends that the Commission adopt the principles set forth.

In its reply brief, MCA disputes Consumers Energy’s suggestion that there is any trend

in the on-peak usage data. MCA also cites provisions of PURPA to argue that rates

713 See Consumers Energy brief, pages 220-223. 714 See Consumers Energy brief, pages 22-222. 715 See Consumers Energy brief, pages 224-225.

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should be non-discriminatory and based on accurate data and consistent system-wide

costing principles.716

Citing Mr. Jester’s testimony, ELPC argues that customers with solar generation

should not be required to use Rate GSG-2, but should be allowed to take supplemental

service under the tariff they would otherwise be assigned to. It does not find the five-

year trial proposal to allow the use of time-of-use rates satisfactory.

In its brief, Staff agrees with the company’s pilot to allow customers with solar-

generation to take service under Rate GPTU.717 Staff endorses Ms. Aponte’s testimony

recommending continued use of the same method for measuring and charging

distribution system costs. Staff urges the Commission to adopt Mr. Krause’s

recommendations, presented in rebuttal testimony, regarding the distribution system,

including requiring Consumers Energy to provide actual and projected peak metered

demand billing determinants, and, if Consumers Energy does recommend prorating

distribution charges based on contract demand, require the company to provide

justification, citing recommendation 2 from the standby rate workgroup report.718

In its reply brief at page 26, Staff agrees with ABATE/Gerdau that the

Commission should not approve the company’s proposed Rate GSG-2 charges

because the current rates are recovering the company’s cost of service. In their reply

brief, MEC/NRDC/SC agree with MCA that Consumers Energy’s proposed rate design

should be rejected, and agree that the rate design should be improved in the future.

They also agree with ELPC that supplemental service and Rate GPTU should be

available to customers with solar generation. 716 See MCA brief, pages 4-6. 717 See Staff brief, pages 131-133. 718 See Staff brief, pages 128-129.

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Consumers Energy addresses Rate GSG-2 further in its reply brief at pages 196-

203. It views the reference to principles of gradualism in ABATE/Gerdau’s initial brief as

concession that rates need to be updated as the company proposes to avoid creating a

subsidy.719 It argues that it adequately recognizes the difference between backup and

maintenance service in its tariff, defends the use of the 10% LMP adder, and argues

that the proration language was clarified in Case No. U-17990 and thus

ABATE/Gerdau’s concerns have been resolved.720 Responding to MCA, it argues that

Ms. Collins justified the company’s rate design proposal because fairness requires the

power supply charges to reflect the same per-kW embedded cost of capacity as full-

service customers, and reiterates its view that MCA has not offered any evidence that

its proposal is not cost-based.721 It argues its distribution rates appropriately reflect the

cost of the distribution system that is in recommendations in MCA’s brief are

unsupported and without merit.722

After reviewing the arguments of the parties, this PFD recommends that the

Commission reject Consumers Energy’s proposed changes to the rate design for Rate

GSG-2, because the revenues from this rate are already above the fully-allocated cost.

Consumers Energy has not justified its assertion that rates for Rate GSG-2 and for

comparable full-service customers should be the same on a dollar-per-kW basis, or that

its new proposed power supply demand charges are compatible with its LMP-based

energy charges, including the 10% adder for summer use.

719 See Consumers Energy reply brief, pages 196-197. 720 See Consumers Energy reply brief, pages 197-198. 721 See Consumers Energy reply brief, pages 198-199. 722 See Consumers Energy reply brief, pages 200-202.

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Regarding the distinction between backup power and maintenance power, this

PFD notes that Consumers Energy’s tariff requires 6 months to almost 10 months of

advance notice for customers scheduling maintenance outages to avoid the 10% adder

in the summer months, which is significantly different from DTE Electric’s tariff. The

company has not justified this in conjunction with its proposed rate change. By rejecting

the company’s rate change, the question of the appropriate advance notice requirement

can be addressed further in the company’s next rate case. A review of the supplement

workgroup report in Exhibit S-15.1 shows several recommendations:

1. To assist with standby service tariff transparency, a clear and concise description of the tariff structure and each term used should be included with the tariff. Utilities should work with staff and stakeholders to ensure a good understanding of 1) the standby service tariff; 2) information available on the company’s website; and 3) the company’s preferred process for developers and customers to get standby service questions answered. 2. Table 1 highlights the inconsistency in standby service tariffs across the state. Staff recommends that the Commission develop a cost-of-service-based standardized framework for standby service tariffs where possible. Staff recognizes there may reason to deviate from the standard. Any differences should be justified and supported by the company. 3. For customers taking both supplemental and standby service, the standby service tariff should be structured to allow the standby capacity and delivery demand charges to be structured to recognized the demand interactions between supplemental and standby service (net load). 4. Standby service tariffs, including the monthly customer charges, should be reviewed and, if necessary, updated in each utility’s rate case to ensure they are based on the most up-to-date cost of service principles. Daily capacity demand charges and the use of generator reservation fees and how the fee relates to the daily demand charge/pro-rated daily demand charges should be considered and discussed by the parties. 5. Standby service tariffs should include a reasonable capacity price differential to encourage scheduled maintenance, which is turn may reduce unscheduled outages. Limiting options to only off-peak time periods may not result in least cost to the utility.

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6. Time of use charges for capacity and energy should be an available option for standby service customers. 7. The method for determining the solar standby tariff billing criteria should be made clear on the tariff. Customers with solar generators should have the option to stay on their supplemental service rate schedule provided it has a demand charge for delivery services. A time of use charge for capacity and energy should be considered for these customers.723

Consumers Energy’s comments are included in Attachment D to the report, and do not

expressly argue that any of the recommendations are erroneous, instead indicating that

the report “does a good job at explaining the various components of standby rates,” and

characterizing recommendation 7 as “a surprise.” This company filed its case before this

report was issued, and before the provisions of 2016 PA 341 took effect.

To address the questions of the appropriate future rate design and tariff

provisions for Rate GSG-2 in its next rate case, this PFD recommends that Consumers

Energy be directed to provide its review and analysis of the recommendations in the

supplemental standby workgroup report, including an explanation of how it considered

the recommendations in its recommended rate design and tariff for Rate GSG-2, i.e.,

whether it rejected the recommendation or incorporated it in some way, and why.

Recommendations 6 and 7 are related to the issue of rate schedule options for

standby customers. This PFD recommends that the Commission adopt the pilot

approach agreed to by Staff and Consumers Energy for customers with solar

generation, with the proviso that Consumers Energy present an evaluation of the

ongoing pilot in each of its subsequent rate cases, so that the parties can consider

whether to recommend additional changes in the eligibility of standby customers for

723 See Exhibit S-15.1, page 23.

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other rate schedules. The parties should also be encouraged to continue discussing

this issue.

Regarding the disputes over distribution rates, this PFD recommends that the

Commission require the information requested by Mr. Krause in its next rate case.

Because this PFD recommended above that the Commission provide for the further

exploration of cost allocation methods for distribution system components, this PFD

does not recommend any specific additional analysis related to distribution system

charges for standby customers.

N. Rate GSG-2 Power Supply Revenues

Related to the above discussion, Mr. Pollock objected to Consumers Energy’s

failure to project power supply revenue from the Rate GSG-2 customers. Consumers

Energy, in its brief at pages 124-125, treats the issue Mr. Pollock raised in his testimony

as one of revenues included in calculation of net operating income, but ABATE/Gerdau

argue in their brief at pages 27-29 that it is a question of cost of service, arguing that

although Consumers Energy included Rate GSG-2 power supply revenues in its net

operating income calculation, it did not include any Rate GSG-2 power supply revenues

in determining the target revenue requirements by customer class.

Consumers Energy cites Mr. Breuring’s testimony at 8 Tr 1215, and argues:

ABATE witness Pollock suggested that the Company did not project any power supply billing demand for the GSG-2 rate class and therefore, failed to account for all of the power supply revenues under its proposed rate design. This is incorrect. Mr. Breuring explained that the Company’s forecasting methodology incorporates a multitude of variables to base its electric deliveries on. . . . These projections do not include future design changes or forecast revenues for proposed rates. . . . While ABATE appears to suggest that the standby service revenues should be considered by the company, this suggestion is not possible to implement because the Company cannot accurately predict when customers’

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generators will be down and require services from the Company. . . ABATE’s criticism is therefore meritless.724

Staff supports Consumers Energy’s position regarding the cost of service study,

although it does not support the company’s rate design for Rate GSG-2 as discussed

above. This PFD recommends that the Commission adopt Consumers Energy’s

revenue allocation for this case, recognizing that this PFD has recommended no

change in the Rate GSG-2 rate design, but further recommends that the Commission

direct Consumers Energy to develop some method to project the Rate GSG-2 billing

demand in its future rate cases.

O. Customer-specific Delivery Charge

Consumers Energy proposed a customer-specific rate for very large customers

with at least 100 MW of demand. Ms. Collins testified:

For extremely large customers served on the Company’s Primary rate schedules, the Company’s delivery charges, which are based on allocated distribution costs for the class, will collect a disproportionate amount of revenue from this customer because of their large electric load. The Company is proposing that in the circumstances when the customers’ load exceeds 100 MW of load, the Company determine an appropriate maximum demand charge that better reflects the costs to serve that customer. The Company proposes to design a maximum demand charge based on a revenue requirement for distribution that reflects the cost of the investment serving the customer. The Company is proposing that the rate reflect an annual revenue requirement based on the original cost of the facilities, levelized over the asset life of the facilities in place to serve the customer. The delivery rate would also include Operation and Maintenance overheads at a level consistent with the costs other customers pay in that rate class. If the Company makes additional investment to serve new load at the site, or if additional investment is required based on the customer’s revised energy needs or requested changes, or Company overheads change, the rate could be revised in future rate cases.725

724 See Consumers Energy brief, page 124. 725 See 10 Tr 2011-2012.

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HSC witness Mr. Gorman testified that this rate was designed for HSC as Consumers

Energy’s largest customer.726 He also testified the charge allocated to HSC should be

further reduced to remove a portion of the allocated overheads.

Mr. Isakson testified that Staff objects to the proposal, in party on the basis that

the company did not properly respond to the Commission’s order in Case No. U-17990

to examine issues related to a joint-ownership substation credit for Rate GPD. He also

objected that the size of load does not sufficiently differentiate a customer from its peers

served in the same fashion. Mr. Pollock testified that the company should offer a

customer-specific delivery charge to any customer served from dedicated facilities, and

expressed other concerns.727

In her rebuttal testimony, Ms. Collins agreed with Mr. Gorman’s proposed

adjustment, and presented Exhibit A-105 to accomplish the reduction. Ms. Collins

disagreed with Mr. Pollock’s recommendation on the basis that there are many

customers served from dedicated facilities and this approach would not be feasible.

Ms. Collins also disagreed with Staff’s concerns, contending that the company explored

some of the concerns previously raised by HSC and taken measures to address some

of those concerns.728 She agreed that ordinarily a large load is not a sufficient

differentiating factor, but distinguished “extraordinarily large” customers. She also

testified that HSC has a unique relationship with Consumers Energy that differentiates it

sufficiently to justify a customer-specific delivery charge.729


U-18322 Page 323

Mr. Gorman also provided rebuttal testimony in support of the rate. He disputed

that the charge was designed for large customers, but for large customers for whom

Consumers Energy has dedicated distribution facilities. He reviewed the testimony he

proved in Case No.U-17990, and testified that the proposed rate is consistent with the

Commission’s order in that case. He also testified:

Mr. Isakson identifies a principle which I think is appropriate in determining whether or not the customer-specific charge should be approved. At pages 8 and 9 of his testimony, he states that a substation ownership credit or a customer distribution charge should reflect a rate design that recovers Consumers’ costs for providing distribution service to the customers served under the approved rate. This rate design principle is precisely the reason why Consumers needs to implement a customer-specific distribution charge for its Rate GPD rate class. The customer-specific distribution rate is made available to customers whose distribution service from Consumers cannot be accurately priced at Consumers’ GPD distribution rate even with a substation ownership credit. The resulting charges in Consumers’ last rate case resulted in HSC paying distribution charges that are substantially out of line with Consumers’ distribution cost incurred to serve HSC.730 HSC argues that the charge as revised through Mr. Gorman’s testimony and Ms.

Collins’s rebuttal testimony is a cost-based charge. It argues that its concern in Case

No. U-17990 was with the level of its distribution costs. HSC argues that Staff does not

dispute that the GPD rate overrecovers costs from HSC, and argues that in cross-

examination, Mr. Isakson testified that if the rates in conjunction with facilities

agreements HSC has signed overrecover Consumers Energy’s costs to provide the

delivery service, then the facilities agreements should be changed.731 It argues that

Consumers Energy and HSC experts have carefully analyzed Consumers Energy’s

730 See 11 Tr 2113. 731 See HSC brief, citing Exhibits HJSC-12 and HSC-18.

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proposal and determined that the proposed rate as revised, appropriately compensates

Consumers Energy for its delivery service to HSC.732

In its brief, citing Mr. Isakson’s testimony, Staff argues that the impetus for the

Commission’s order in Case No. U-17990 requiring Consumers Energy to explore

concerns raised by HSC stemmed from HSC’s argument that Consumers Energy

should offer the same discount provided to Rate GSG-2 customers for transmission-

connected substation ownership, while another concern was how customers served by

multiple substations may be affected by substation ownership credits. Staff disputes

that the proposed customer-specific delivery charge addresses the Commission’s

concerns in Case No. U-17990, and argues that it is not appropriate to design rates for

individual customers.

Staff addresses Mr. Gorman’s rebuttal testimony asserting that the charge is not

exclusively for large customers, pointing to the language in Consumers Energy’s

proposed tariff that indicates the rate is only available to customers whose load exceeds

100 MW at any single site.733 Staff argues that Staff’s proposed standard rate GPD and

substation credit are cost-based, and that it is appropriate to design rates to recover

costs for similarly situated customers: “HSC is served a Company-owned substation at

the distribution level, as are other customers on rate GPD, and should therefore be

allocated similar distribution costs as those other customers on rate GPD.”734

ABATE/Gerdau also addressed this issue in their briefs. They argue that they

are not opposed to the concept of a customer-specific delivery charge, but for the

reasons explained by Mr. Pollock, do not believe the proposed charge meets the 732 See HSC brief, pages 4-9. 733 See Exhibit A-11, page 41; see Staff brief, pages 124-125. 734 See Staff brief, page 125.

U-18322 Page 325

requirements that such a charge be fully transparent and non-discriminatory. In addition

to a concern that on its face the charge is limited to “very large” customers, with no

reason provided for the limitation, ABATE/Gerdau argue that the carrying charge rate

lacks transparency because it is unclear how the levelized carrying charge rate

associated with the dedicated facilities will be calculated, and because Consumers

Energy did not identify the corresponding dedicated facilities and corresponding

revenues associated with the charge.735

Consumers Energy argues in response to Staff’s concerns that it did address the

Commission’s directive in Case No. U-17990 because it has satisfied HSC. It further

argues that there is no question of discrimination, because the charge is equally

applicable to all customers meeting the size requirement, and believes that sufficient

detail has been provided in the statement that the charge would be based on the

levelized cost of Consumers Energy’s investment in facilities directly service HSC, plus

its share of O&M overheads.736 The company also agreed to remove the HSC load

from the distribution cost allocation to Rate GPD.

In its reply brief, Staff acknowledges that it did not analyze the impact of

Consumers’ existing distribution rates on HSC, or whether Consumers Energy’s existing

rates overrecover the costs to provide delivery service to HSC. Staff argues instead:

The fundamental nature of rate design necessitates that at any one moment, the Company is over recovering from some customers. Likewise, at that same moment, the Company is under recovering from others. This is a narrow, short-run view of rate design. Rates are designed to recover all costs to serve similarly situated customers from the same customer pool. To ensure the utility can provide safe, reliable, and affordable energy, rates must be designed for the long-run.

735 See ABATE brief, pages 33-36. 736 See Consumers Energy brief, pages 192-195.

U-18322 Page 326

For example, a customer may be paying over their customer-specific cost of service because the assets used to serve the customer are fully depreciated, their service lines require little-to-no maintenance, or the customer pays their bill in full with no need for account services. But if utility invests in infrastructure to serve that same, specific customer by upgrading distribution equipment, installing new metering, or performing vegetation management, then suddenly the customer will be paying less than their specific cost of service.737

Staff goes on to argue that even if Consumers Energy is overrecovering from HSC at

the moment, that does not imply that overrecovery will continue or that it necessitates a

unique customer-specific charge: “[A]bsent the customer-specific delivery charge, the

Company will one day under recover costs from HSC when investment in HSC’s

dedicated facilities is required by the Company.”738

This PFD finds Staff’s and ABATE/Gerdau’s analysis persuasive, and

recommends that the Commission reject the customer-specific delivery charge. This

PFD finds that the basis for the charge is not transparent. Moreover, the tariff language

proposed by Consumers Energy is quite open-ended. As shown in Exhibit A-11 at page

41, it provides:

For customers whose load exceeds 100,000 kW at any single site, the Company shall determine the Maximum Demand Capacity Charge. It shall be based on the dedicated distribution facilities required to serve the customer as well as allocated overheard costs. The Substation Ownership Credit shall not apply to this rate.

Also, Consumers Energy did not make a commitment that the rate would change if the

costs change. Ms. Collins testified:

If the Company makes additional investment to serve new load at the site, or if additional investment is required based on the customer’s revised energy needs or requested changes, or Company overheads change, the rate could be revised in future rate cases.739

737 See Staff reply brief, pages 21-22. 738 See Staff reply brief, page 22. 739 See 10 Tr 2011-2012 (emphasis added).

U-18322 Page 327

This puts a burden on Staff and other parties to monitor the relationship between

Consumers Energy and its largest customer to an unusual degree.

As Staff argues, the proposal does not appear to be consistent with ratemaking

principles. While the company acknowledges it is not practical to set individual rates for

each GPD customer, one can readily envision a series of requests from each of the

next-largest customers for their own “customer-specific” delivery charge, and reliance

on the 100 MW threshold to deny consideration of such rates appears arbitrary based

on this record.

P. Commercial and Industrial Customer Rate Design

As discussed above, Mr. Morales testified to the capital and O&M costs

associated with Consumers Energy’s commercial and industrial customer demand

response program. He identified three categories of expenses: marketing and customer

acquisition expenses, which include the expenses associated with the customer

enrollment process; operations expenses, which include the infrastructure to manage

and validate participation; and the incentive payments, which the company proposes to

recover through the PSCR process.740 He seemed to indicate that the enrollment and

operations expenses were considered in determining the amount of the credit:

As referenced above, the two different payments made to customers are for capacity and energy supply. The combination of capital, operational, and incentives provide this capacity resource at, or below, projected market prices based on CONE.741 Mr. Jester testified regarding the company’s rate design for the commercial and

industrial demand response program, testifying that he strongly supports the use of

740 See 9 Tr 1536-1537. 741 See 9 Tr 1537.

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demand response programs, but also testifying that payments to participating

customers should be net of costs, to properly reflect the benefits of the load shedding:

[T]he Company proposes that the costs of the demand response program be allocated to all customers, on the basis that it is a capacity resource. While all customers should pay costs of capacity resources, in proportion to their causation, in this case where only participating customers receive a rate credit and only certain classes of customers can participate, the Commission needs to ensure that the program does not unreasonably shift costs onto other customers. I recommend that the Commission order the Company to recover the costs of the demand response program from program participants alone, either as an explicit charge or an offset to any rate benefits that are provided to program participants for their participation.742

He further explained that total benefit of the demand response program to the company

and its customers is the difference between the avoided capacity costs and the costs of

marketing the program.743

In his rebuttal testimony, Mr. Morales disagreed with his recommendation and

contended that he was ignoring the benefits of the program to all customers.744 He

testified:

Mr. Jester correctly assumes that the net benefit to all customers is the difference between the avoided capacity costs and the costs of marketing and operating the program. However, it appears that Mr. Jester is assuming the credit to customers participating in the Demand Response Program is greater than the cost of marketing and operating the program. This is incorrect. The capacity credit the Company has proposed to provide is based on the market value of a MW of power in the Midcontinent Independent System Operator, Inc. (“MISO”) market for the Planning Year in question. The market value of a MW of capacity in the MISO market is exactly the same regardless of the source, including demand response. Consumers Energy uses market prices, which are widely published in the public domain, as reference points when the Company constructs its portfolio, fulfilling the


U-18322 Page 329

capacity obligation with resources of different types at or below the competitive market price.745

In his rebuttal testimony, Mr. Isakson interpreted Mr. Jester’s recommendation to be that

all program costs and benefits directly to program participants:

First, the benefits of demand response, as described by Mr. Jester as avoided costs, are realized by all customers, and therefore cannot be allocated to only one customer type. All power supply customers rely on the Company to provide the capacity necessary for safe, reliable electric service, and the composition of that capacity includes demand response. Prescribing the specific capacity associated with demand response to only DR program customers is impossible, because all customers are provided capacity through the Company’s resources, regardless of whether those resources are supply-side or demand-side. Second, DR customers should be considered to act in a dual role for the Company. DR customers are utility customers, for whom the Company must provide capacity. Those same DR customers are also providing a capacity resource to the Company. Rates must be designed to compensate DR customers for the resource they provide to the Company, just like the Company is compensated for providing supply-side resources to meet capacity needs. The DR customer, therefore, should be entitled to both the benefits of their resource as a utility customer, and the benefits of acting as a resource. If DR rates are designed to include all of the net benefits of DR, then it both ignores the practical use of DR as a capacity resource for all customers and it distorts the DR customer’s compensation for the value of their resource.746 This PFD concludes that the parties are miscommunicating on this issue. Both

Mr. Morales and Mr. Jester seem to agree that the net benefit to customers is the

difference between the avoided costs and the costs of marketing and operating the

program. Thus, it seems that the credits to the program participants should be based

on the avoided costs less the costs of operating the program. Nothing in the briefs of

the parties seems to shed any light on this dispute. This PFD recommends that the

Commission instruct Consumers Energy that credits to program participants may not

exceed the net benefits to customers after considering the enrollment and operating 745 See 9 Tr 1546. 746 See 11 Tr 2243.

U-18322 Page 330

costs, and require Consumers Energy to demonstrate in its next rate case that

ratepayers benefitted from the program, after considering enrollment and operating

costs and credits to program participants.

Q. AMI Opt-Out Tariff

There are several disputes regarding the AMI opt-out tariff, as discussed in

sections 1 through 3 below.

1. RCG Request to Eliminate Opt-out Charges

The RCG argues that the tariff should be revised based on Mr. Bathgate’s and

Mr. Peloquin’s testimony that the meters consume a significant amount of electric

energy that increases customer bills and the cost of service generally.747 The RCG

argues that the opt-out charges should be eliminated for customers who agree to read

their own meter, and perhaps agree to participate in a budget plan.748 The RCG also

argues that the tariffs should be abolished due to the Commission’s lack of jurisdiction,

duty to set just and reasonable rates, and other legal and constitutional limitations.

For the reasons discussed above in connection with the RCG’s call for

investigation of the AMI meter electric consumption, the record does not support

modifying the tariff on this basis.749 The RCG’s arguments regarding tariff revisions are

not based on new evidence, and present arguments the Commission has already

considered and rejected. Consumers Energy argues in its brief and reply brief that the

courts have also affirmed the Commission’s orders regarding the opt-out tariffs, rejected

claims that the Commission lacks authority to approve the tariff, and rejected arguments

747 See RCG brief, pages 12-13. 748 See RCG brief, page 13. 749 See 6 Tr 266, 323-324.

U-18322 Page 331

that it violates constitutional requirements or other legal requirements.750 For these

reasons, this PFD declines to recommend the tariff changes sought by the RCG.

2. Consumers Energy Request to Revise Tariff Language

Consumers Energy also requests Commission approval to revise the language,

but not charges, included in the opt-out tariff. The tariff currently provides: “Customers

electing a non-transmitting meter will pay the following charges per premises.”751

Mr. Hurd testified:

The proposed language within this tariff is currently open to interpretation, which is why the Company is proposing to clarify this language in both sections. The initial inception of this language was for the Company to be compensated for the maintenance costs pertaining to maintaining these legacy meters when a customer chooses to retain non-transmitting metering equipment. It would be impractical to apply one opt-out charge per premises, since this provision can be applied to an apartment complex or any location with banks of meters installed. Based on Staff witness Fromm’s interpretation, one customer’s decision to opt out could impact multiple customers at a property who may want to have the Company’s Advanced Metering Infrastructure technology. Additionally, if a customer has multiple accounts where they would like to retain their current meter equipment, then each account should contribute to the cost of sustaining the Opt-Out Program – regardless of proximity. This aligns with how the Company’s opt-out charges were developed as the charges were designed on a per meter basis.752 Staff opposes Consumers Energy’s request in part, and proposes an alternative.

Ms. Fromm testified:

Staff agrees that it is reasonable to apply the up-front charge by billing meter, because the costs included in that charge are specific to the installation of the legacy meter. However, the monthly charge is based on meter reading and testing costs, which are related to the number of customers rather than the number of meters. Staff, therefore, recommends that the ongoing monthly charge continue to be applied by premises, rather than by meter.753

750 See Consumers Energy brief, pages 227-230; Consumers Energy reply brief, pages 208-216. 751 See Exhibit A-11, page 7. 752 See 9 Tr 1506; Also see Consumers Energy brief, pages 225-227. 753 See 11 Tr 2350; also see Staff reply brief, pages 130-131.

U-18322 Page 332

This PFD finds that any revision to the tariff beyond the modifications

recommended by Staff should be deferred until the charges for the opt-out tariff are

reconsidered. Ms. Fromm’s analysis that the initial charge was intended to apply per

meter and that the tariff should be modified accordingly appears reasonable. Once the

subject turns to the monthly meter reading charge, given that the tariff language

expressly states “premises” and that the company’s argument in support of changing it

is stated as “each account should contribute to the cost of sustaining the Opt-Out

program,” it appears to be more appropriate to defer consideration of that change until

the opt-out charges are revised and the Commission can ensure consistency between

the monthly charges and the monthly costs. Staff and the company do agree that the

term “premises” should be clarified to exclude multi-unit dwellings, so Mr. Hurd’s

concern as quoted above is resolved with that change. For these reasons, this PFD

recommends that the Commission accept Staff’s recommended tariff revisions.

3. Consumers Energy Request to Delay Opt-out Tariff Charge Revision

The last issue regarding the AMI opt-out tariff is Consumers Energy’s request to

defer the filing of an updated out-out charge until its next rate case. Mr. Warriner

acknowledged the Commission’s order in Case No. U-17990 requiring that the company

recalculate the AMI opt-out charges in either its next rate case filed after full

deployment, or in a contested case filed six months following full completion, whichever

is sooner.754 He testified that he believes the best proceeding to update AMI opt-out

charges would be a general rate case, to utilize rate case test year meter reading and

AMI capital and investment expenses. He asks that the Commission’s order be

754 See 6 Tr 317.

U-18322 Page 333

modified accordingly.755 No party expressly objected to his request. Nonetheless, this

matter is clearly committed to the Commission’s discretion.

XI.

OTHER MISCELLANEOUS ITEMS

In its motion dated October 13, 2017, Consumers Energy proposed transcript

corrections to portions of Volumes 9 and 10. No party has objected to Consumers

Energy’s proposed transcript corrections and this PFD finds they should be made.

XII.

CONCLUSION

Based on the foregoing discussion, this PFD recommends that the Commission

adopt the findings, conclusions and recommendations set forth above, including the

findings and recommendations on rate base, capital structure, cost of capital, and

operating revenues and expenses leading to an estimated revenue deficiency of

approximately $30.1 million, with an authorized return on equity of 9.80% and an overall

cost of capital of 5.81%, as well as recommendations regarding various accounting

requests, ratemaking mechanisms, cost of service allocations, rate design, and tariff

modifications, as well as recommendations for additional reporting and analysis.

755 See 6 Tr 315.

U-18322 Page 334

MICHIGAN ADMINISTRATIVE HEARING SYSTEM For the Michigan Public Service Commission _____________________________________ Sharon L. Feldman Administrative Law Judge

Issued and Served: January 8, 2018

MICHIGAN PUBLIC SERVICE COMMISSION PFDCase No.: U-18322

Consumers Energy Company Appendix AComputation of the Electric Revenue Deficiency for the Test Year Ended September 30, 2018($000)

Applicant PFD PFD PFDLine Description Source Projection (Brief) Adjustments Projection Jurisdictional

(a) (b) (c) (d) (e) (f)

1 Rate Base CE Brief, App B, p 2 10,301,772$ (55,152)$ 10,246,620$ 10,203,659$

2 Adjusted Net Operating Income CE Brief, App C, p 3 535,394 38,701 574,095 575,084

3 Overall Rate of Return Line 2 / Line 1 5.20% 0.41% 5.60% 5.64%

4 Required Rate of Return CE Brief, App F, p 1 6.09% -0.29% 5.81% 5.81%

5 Income Required Line 1 * Line 4 627,792 (32,905) 594,887 592,393

6 Income Deficiency/ (Sufficiency) Line 5 - Line 2 92,398 (71,606) 20,791 17,308

7 Revenue Multiplier CE Brief, App A 1.6377 0.0000 1.6377 1.6377

8 Revenue Deficiency/ (Sufficiency) Line 6 * Line 7 151,318$ (117,268)$ 34,050$ 28,345$

9 FERC Docket No. ER16-188 Rev. Req. CE Brief, App A 1,800 - 1,800 1,793

10 Total Revenue Deficiency/ (Sufficiency) Line 8 + Liine 9 153,118$ (117,268)$ 35,850$ 30,138$


Consumers Energy Company Appendix BProjected Rate Basefor the Test Year Ended September 30, 2018($000)

Applicant PFD PFD PFDLine Description Source Projection (Brief) Adjustments Projection Jurisdictional

(a) (b) (c) (d) (e) (f)

1 Total Utility Plant Exhibit: A-7 (JRF-7) 14,794,636$ (57,462)$ 14,737,174$ 14,678,105$

2 Depreciation Reserve Exhibit: A-7 (JRF-8) 5,193,519 (2,309) 5,191,210 5,171,465

3 Net Utility Plant Line 1 - Line 2 9,601,116$ (55,152)$ 9,545,964$ 9,506,640$

4 Sales and Use Tax Adjustment WP-JRF-68 included above - - -

5 Retainers & Customer Advances Exhibit: A-2 (JRC-5) (28,475) - (28,475) (28,456)

6 Adjusted Net Utility Plant Sum Lines 3 - 5 9,572,641 (55,152) 9,517,489 9,478,184

7 Working Capital Exhibit: A-7 (JRF-9) 729,131 - 729,131 725,474

8 Total Projected Rate Base Line 6 + Line 7 10,301,772$ (55,152)$ 10,246,620$ 10,203,659$


Consumers Energy Company Appendix CProjected Net Operating Incomefor the Test Year Ended September 30, 2018($000)

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p) (q)

Line AdjustedNo. Description (Witness) NOI AFUDC NOI

Company Filed (Brief)1 Operating Income 4,214,455 26,096 52,842 4,293,393 2,145,445 613,875 610,623 171,921 30,213 1,236 40,133 149,606 3,763,052 530,342 5,052 535,394

PFD Adjustments

2 - - - - - - - 3 Sales Revenue 17,300 17,300 28 1,020 5,688 6,736 10,564 10,564 4 - - - - - - 5 Cap Ex Adjustments Impact (Appendix E) (3,241) (746) 6 235 1,311 (2,434) 2,434 2,434 6 Electric Distribution (Laruwe) (14,652) 23 864 4,818 (8,947) 8,947 8,947 7 Fossil & Hydro Generation (Evans) (4,658) 7 275 1,531 (2,844) 2,844 2,844 8 Pension (Welke) - - - - - - 9 Uncollectibles (Welke) - - - - - - 10 Incentive Compensation (Welke) (2,202) 4 130 724 (1,345) 1,345 1,345 11 - - - - - - 12 Customer Care - Payment Program (AG) (5,200) 8 307 1,710 (3,175) 3,175 3,175 13 Employee Benefits - Pension - Discount Rate (AG) (9,000) 14 531 2,959 (5,496) 5,496 5,496 14 Employee Benefits - OPEB - Discount Rate (AG) (7,000) 11 413 2,302 (4,274) 4,274 4,274 15 - - - - - - 16 Proforma Interest - 2 57 317 375 (375) (375) 17 Interest Synchronization - - - - - - - - - 0 0 2 - (3) - (3) 18 Total Adjustments 17,300 - - 17,300 - (42,712) (3,241) (746) - 104 3,832 21,361 (21,401) 38,701 - 38,701

19 PFD NOI - Test Year 4,231,755 26,096 52,842 4,310,693 2,145,445 571,164 607,382 171,175 30,213 1,340 43,965 170,967 3,741,651 569,043 5,052 574,095

20 PFD Jurisdictional NOI - Test Year 4,232,479 - 52,776 4,285,255 2,124,106 569,161 604,461 170,769 30,049 1,326 44,044 171,275 3,715,191 570,064 5,021 575,084

State Income

Tax

Revenue Expenses NOI

Sales Revenue

Wholesale Revenue

Other Electric

Revenue Total Power

Supply Costs FIT Total Other O&M

Depreciation

& Amort. R&PP

Tax

Other General Taxes

Other (or Local) Taxes

Consumers Energy Company PFDOverall Rate of Return Summary Case No.: U-18322Projected Capital Structure & Cost Rates Appendix Dfor the Test Year Ended September 30, 2018

13-Month % of % ofAverage Permanent Total Cost Permanent Total of Revenue Pre-Tax

Line Description Source ($000) Capital Capital Rate Capital Capital Debt Multiplier Basis(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k)

1 Long Term Debt Exhibit: A-9 (AJD-1) 5,880,452$ 47.06% 36.55% 4.68% 2.20% 1.71% 1.71% 1.71%

2 Preferred Stock Exhibit: A-9 (AJD-1) 37,315 0.30% 0.23% 4.50% 0.01% 0.01% 1.6377 0.02%

3 Common Equity Exhibit: A-9 (AJD-1) 6,578,683 52.64% 40.89% 9.80% 5.16% 4.01% 1.6377 6.56%

4 Permanent Capital 12,496,450 100.00% 7.37%

5 Total Short Term Debt Exhibit: A-9 (AJD-1) 160,700 1.00% 3.55% 0.04% 0.04% 0.04%

6 Deferred FIT Exhibit: A-9 (AJD-1) 3,339,901 20.76% 0.00% 0.00% 1.6377 0.00%

Deferred JDITC/ITC7 Long Term Debt Exhibit: A-9 (AJD-1) 43,266 0.27% 4.68% 0.01% 0.01% 0.01%8 Preferred Stock Exhibit: A-9 (AJD-1) 307 0.00% 4.50% 0.00% 1.6377 0.00%9 Common Equity Exhibit: A-9 (AJD-1) 48,310 0.30% 9.80% 0.03% 1.6377 0.05%

10 Total Capitalization 16,088,933$ 100.00% 5.81% 1.76% 8.39%

Weighted Cost

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