STATE OF MICHIGAN BEFORE THE MICHIGAN … › documents › mpsc › U18424.comppfd...STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * * PROPOSAL FOR DECISION

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

* * * * *

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 July 2, 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 July 18, 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 July 27, 2018.

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 HEARINGSYSTEMFor the Michigan Public Service Commission

_____________________________________July 2, 2018 Suzanne D. SonnebornLansing, Michigan Administrative Law Judge

In the matter of the application of )Consumers Energy Company for ) Case No. U-18424authority to increase its rates for the )distribution of natural gas and for )other relief. )

Suzanne D. Sonneborn

Digitally signed by Suzanne D. Sonneborn DN: cn=Suzanne D. Sonneborn, o=MAHS, ou=MAHS PSC, [email protected], c=US Date: 2018.07.02 14:46:00 -04'00'

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

* * * * *

PROPOSAL FOR DECISION

Issued and Served: July 2, 2018


TABLE OF CONTENTSPage

I. PROCEDURAL HISTORY .............................................................................. 1

II. OVERVIEW OF THE RECORD …………………………………………………. 6

A. Consumers Energy …………………………………………………………… 6B. Staff …………………………………………………………………………… 28C. Attorney General ……………………………………………………………. 46D. ABATE …………………………………………………………………………48E. RESA …………………………………………………………………………. 50F. RCG …………………………………………………………………………... 51G. Rebuttal ………………………………………………………………………. 52

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

IV. RATE BASE.................................................................................................. 71

A. Net Utility Plant ........................................................................................ 731. Gas Transmission And Distribution Capital Expenditures .................. 73

a. New Business ............................................................................... 74i. Mains, Services, And Meter Stands .................................. 74ii. Large New Business Projects ............................................ 75iii. Customer Attachment Program ......................................... 77

b. Regulatory Compliance Program ................................................. 78i. Pipeline Integrity Program ................................................. 78ii. Pipeline Integrity – TOD Program ...................................... 88iii. MAOP Program ................................................................. 89

c. Material Condition Program .......................................................... 92i. VSR Program ………………………………………………… 93ii. Material Condition Non-Modeled Program ……………….. 97iii. Material Condition Renewals Program ……………………. 98iv. EIRP Reporting ………………………………………………101

d. Capacity/Deliverability Program ……………………………………101i. TED-I Program ……………………………………………… 102

(a) Mid-Michigan Citygate Station ……………………… .. 102(b) South Oakland Macomb Network …………………… . 103(c) Pressure-Limiting Devices …………………………….. 104

ii. TED-I Major Projects ………………………………………. 108iii. Regulator Stations – Distribution Program ……………… 110

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e. Gas Operations Other Program ………………………………….. 112

2. Gas Compression And Storage Capital Expenditures …………….. 112a. St. Clair And Freedom Compressor Stations …………………… 113

i. St. Clair Compressor Station ……………………………... 113ii. Freedom Compressor Station ……………………………. 114

b. Other Compression And Storage Projects ……………………… 115c. Well Rehabilitation …………………………………………………. 117

3. Business Services Capital Expenditures ……………………………. 1194. Information Technology Capital Expenditures ……………………… 119

a. Staff …………………………………………………………………... 120i. DCE Website And Field Service Solution Projects ……. 121ii. Canceled Projects…………………………………………. 126 iii. Meter Reading Hardware Costs……………………………129iv. Additional Reporting - Future IT Project Submissions …. 132

b. Attorney General ……………………………………………………. 1375. Gas AMI/ AMR …………………………………………………………. 1396. Contingency Costs …………………………………………………….. 1487. Capital Expenditure Updates In Rebuttal …………………………….1528. Accumulated Provision For Depreciation (Depreciation Reserve)…1559. Construction Work In Progress ………………………………………. 156

B. Working Capital ……………………………………………………………..1561. Calculation Of Cost Of Gas Sold And Gas Stored Underground ….159

C. Unamortized Manufactured Gas Plant Balance …………………………160

D. Rate Base Summary ……………………………………………………… 163

V. CAPITAL STRUCTURE, COST OF CAPITAL, AND RATE OF RETURN .164

A. Test Year Capital Structure ………………………………………………. 1651. Common Equity Balance ……………………………………………… 165

a. Staff ………………………………………………………………….. 167b. Attorney General …………………………………………………… 170c. ABATE and RCG …………………………………………………… 174

2. Long-Term Debt Balance ……………………………………………… 1753. Short-Term Debt Balance ……………………………………………... 1754. Deferred Federal Income Tax ………………………………………… 1755. Other Capital Structure Balances …………………………………….. 175

B. Cost Rates ………………………………………………………………….. 1761. Return On Common Equity …………………………………………… 176

a. Consumers Energy ………………………………………………… 178b. Staff ………………………………………………………………….. 181

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c. Attorney General …………………………………………………… 185d. ABATE ………………………………………………………………. 188e. Rebuttal ……………………………………………………………… 190f. Recommended ROE ………………………………………………. 195

2. Long-Term Debt Cost Rate ………………………………………….... 2083. Short-Term Debt Cost Rate …………………………………………… 2094. Other Cost Rates ………………………………………………………. 209

C. Overall Rate of Return ……………………………………………………. 209

VI. THROUGHPUT ………………………………………………………………... 210

VII. ADJUSTED NET OPERATING INCOME …………………………………… 214

A. Operating Revenue Forecast …………………………………………….. 2151. Sales Revenue …………………………………………………………. 2152. Transportation Revenue ………………………………………………. 2173. Miscellaneous Revenue ……………………………………………….. 217

B. Cost Of Gas Sold …………………………………………………………... 217

C. Lost And Unaccounted For Gas And Company Use Gas ……………... 218

D. Other Operations And Maintenance Expenses …………………………. 2191. Gas Transmission And Distribution O&M Expense ………………… 219

a. Pipeline Integrity Expense ………………………………………… 222b. Leak Repair and Survey Expense ……………………………….. 225c. MAOP Transmission Expense ……………………………………. 225d. Meter Reading Expense …………………………………………… 226

i. Staff ………………………………………………………….. 226ii. Attorney General …………………………………………… 229

2. GCS And Gas Management Services O&M Expense ……………... 2293. Business Services O&M Expense ……………………………………. 2324. Corporate Services O&M Expense …………………………………... 2325. Information Technology O&M Expense ……………………………… 2326. Pension And Benefits Expense ………………………………………. 2327. Incentive Compensation Expense ……………………………………. 2378. Gas AMR Expense …………………………………………………….. 2439. Customer Experience O&M Expense ……………………………….. 24410.Customer Payment Program O&M Expense ………………………... 24711.ASP O&M Expense ……………………………………………………. 25012.Manufactured Gas Plant Direct Project Management Costs ……… 25213.Gas Uncollectible Expense ……………………………………………. 252

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14.Injuries and Damages Expense ………………………………………. 253

E. Depreciation And Amortization – Non MGP …………………………….. 255

F. Manufactured Gas Plant Amortization Expense …………………………255

G. Taxes ………………………………………………………………………… 256

1.Tax Cut and Jobs Act of 2017 ………………………………………….. 256

H. Allowance For Funds Used During Construction ……………………….. 259

I. Calculation of Adjusted Net Operating Income (Approximated) ………. 260

VIII. OTHER REVENUE RELATED ISSUES……………………………………… 260

A. Revenue Decoupling Mechanism…………………………………………. 260

B. Investment Recovery Mechanism………………………………………… 2611. Staff ……………………………………………………………………… 2622. Attorney General ……………………………………………………….. 2643. Recommendation ………………………………………………………. 265

C. MGP Remediation-Related Expenditures ……………………………….. 267

D. End-User Transportation Pooling Program ……………………………… 270

E. Gas Customer Choice Billing ……………………………………………... 276

F. Daily Balancing Study ……………………………………………………… 279

IX. REVENUE DEFICIENCY SUMMARY ........................................................ 282

X. COST OF SERVICE, RATE DESIGN, AND TARIFF ISSUES ................... 282

A. Cost Of Service ..................................................................................... 2821. ABATE ............................................................................................. 2842. Lansing Board of Water and Light ................................................... 2873. RCG ................................................................................................ 288

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B. Rate Design .......................................................................................... 2891. Residential Customer Charge – Residential Rates A and A-1.......... 2902. Excess Peak Demand Charge – Residential Rate A-1 .................... 2923. 4 % ATL for Rate XLT and Rate XXLT ............................................ 292

C. Tariff Issues .......................................................................................... 294

XI. ACCOUNTING TREATMENT …………………………………………………. 296

A. RDM Accounting Request ………………………………………………… 296

B. Regulatory Accounting For Investments In Cloud-Based Technologies Accounting ……………………………………………………297

XII. CONCLUSION ........................................................................................... 298

APPENDICES A THROUGH E

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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

* * * * *

PROPOSAL FOR DECISION

I.

PROCEDURAL HISTORY

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

natural gas rate application requesting a $178.194 million revenue increase, and other

relief.1 The rates requested in the application are based on a projected 12-month test

year ending June 30, 2019 and, if granted, would represent Consumer Energy’s seventh

increase in its gas rates in the last eight years.2

According to Consumers Energy, the need for the requested rate relief is due to:

(i) ongoing investments in gas utility assets in order to provide safe, reliable, and efficient

service to customers, and to comply with environmental and legal requirements; (ii) a

1 This revenue increase amount has since been revised downward by the Company to $82.775 million.Consumers Energy’s Initial Brief, p. 1; Appendix A. 2 Prior rate increases include: MPSC Case No. U-15986, May 17, 2010 Order; MPSC Case No. U-16418, May 26, 2011 Order; MPSC Case No. U-16855, May June 7, 2012 Order; MPSC Case No. U-17197, MPSC December 6, 2013 Order Approving Withdrawal; MPSC Case No. U-17643, January 13, 2015 Order; MPSCCase No. U-17882, April 21, 2016 Order; and MPSC Case No. U-18124, July 31, 2017 Order.


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reduction in miscellaneous revenues from programs and services; and (iii) changes in the

cost of capital.3 In addition, Consumers Energy’s application requests, among other

things, that the Commission: (1) adopt the utility’s fully-projected sales forecast for the

projected test year; (2) increase the utility’s return on common equity from 10.10%4 to

10.50%; (3) approve two ratemaking adjustment mechanisms to address “variability of

revenues attributable to factors which are, in general, largely driven by factors beyond the

control of the Company,” which the Company refers to as the “Gas Revenue Decoupling

Mechanism” (RDM) and the “Investment Recovery Mechanism” (IRM), respectively; and

(4) grant various accounting authorizations and approve modifications to the rates, rules,

and regulations as described in the Company’s direct testimony and exhibits.5

Staff, Consumers Energy, and potential intervenors attended the November 28,

2017 prehearing conference. Intervention was granted on that date to Attorney General

Bill Schuette (Attorney General), the Association of Businesses Advocating Tariff Equity

(ABATE), the Midland Cogeneration Venture Limited Partnership (MCV), the Lansing

Board of Water and Light (LBWL), the Retail Energy Supply Association (RESA), and the

Residential Customer Group (RCG). The parties agreed to a schedule complying with

the time limits of MCL 460.6a.6 The parties also stipulated to the terms and conditions

set forth in Consumers Energy’s Proposed Protective Order filed with the utility’s

application. Under the Protective Order, entered on December 5, 2017, certain testimony

3 Consumers Energy’s October 31, 2017 application, p. 3, paragraph 7. 4 The utility’s current 10.10% return on common equity was authorized by the Commission’s final order issued July 31, 2017 in Case No. U-18124. 5 Consumers Energy’s October 31, 2017 application, pp. 9-10.6 Section 6a(5) of Public Act 286 requires the Commission to issue its final order within 10 months following receipt of a complete rate case filing, lest the application be considered approved. MCL 460.6a(5).

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and exhibits relied upon by the parties were deemed Confidential Information and entered

under a separate record.

On February 8, 2018, the Attorney General filed a Motion to Compel Discovery

Responses from Consumers Energy Company. While the Administrative Law Judge set

a hearing date of February 28, 2018 for oral argument on this motion, the Attorney

General subsequently withdrew the motion.

In keeping with the schedule established at the November 28, 2017 prehearing,

Staff and intervenors Attorney General, ABATE, RESA, and the RCG filed direct

testimony and supporting exhibits on February 28, 2018. Consumers Energy, Staff and

ABATE filed rebuttal testimony on March 21, 2018. On March 16, 2018, Staff filed a

Motion to File Revised Testimony of Nathan J. Miller and, because no party objected to

Staff’s motion, the Administrative Law Judge issued a ruling on March 21, 2018 granting

the motion. One motion to strike testimony was also filed – specifically, ABATE moved

to strike portions of the direct and rebuttal testimony of Consumers Energy’s cost of

capital witness, Srikanth Maddipati. Consumers Energy filed a written response to

ABATE’s March 26, 2018 motion and the motion was argued at the outset of the third day

of the evidentiary hearings. 7 Finally, on March 29, 2018, RESA filed a Motion to File

Surrebuttal Testimony, along with the proposed surrebuttal testimony. Following a written

response by Consumers Energy on April 3, 2018, oral argument was held on the motion

at the outset of the first day of the evidentiary hearings.8

7 After hearing argument on April 6, 2018, ABATE’s Motion to Strike Portions of Consumers Energy Company’s Direct Testimony and Rebuttal Testimony of Srikanth Maddipati was denied in its entirety. 4 Tr797-801.8 The ALJ’s ruling permitted all of Mr. Mehling’s proposed surrebuttal testimony, and allowed Consumers Energy to also file the sur-surrebuttal testimony of Elizabeth Curtis, conditioned on the ALJ’s and RESA’s

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Evidentiary hearings were held on April 4, 5, 6, 9, 10, and 11, 2018. Eighteen

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

the remaining 32 witnesses was bound into the record without the need for them to

appear. During the hearing, Consumers Energy offered the testimony of 25 witnesses,

and entered into evidence Exhibits A-1 through A-155, inclusive.

Also during the hearing, the Attorney General provided the direct testimony of

Sebastian Coppola, an independent business consultant, and Exhibits AG-1 through AG-

80. ABATE provided the direct testimony of Jeffry Pollock and the direct and rebuttal

testimony of Billie S. LaConte, both energy advisors and consultants in the field of public

utility regulation, and Exhibits AB-1 through AB-23. RESA provided the direct testimony

of Matthew S. White, general counsel with Interstate Gas Supply, Inc., and John Mehling,

a senior regional operations manager with Direct Energy Business. Through these

witnesses, RESA entered Exhibits RES-1, RES-2, and RES-3, with Exhibit RES-4

admitted as a hearing room exhibit. RCG provided the direct testimony of William A.

Peloquin, a certified public accountant and consultant in utility regulation cases, and

Exhibits RCG-1, RCG-2, and RCG-3, while also admitting during the hearing Exhibits

RCG-4 through RCG-7, with Exhibit RCG-8 admitted following the conclusion of the

hearing upon agreement of the parties. Finally, Staff offered testimony from 18 witnesses.

Through these witnesses, Staff entered Exhibits S-1 through S-21, inclusive.

In accordance with the established schedule, Consumers Energy, Staff, the

review of the proposed sur-surrebuttal testimony, following which the proposed sur-surrebuttal testimony was admitted. See 2 Tr 33-34; 5 Tr 1225.

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Attorney General, ABATE, RESA, RCG, and LBWL filed initial briefs on May 9, 2018.9 All

parties also filed reply briefs on May 25, 2018.10

The evidentiary record in this proceeding is contained in 2655 pages of transcript

in 7 volumes and 426 exhibits admitted into evidence. This PFD follows the standard

organization: after an overview of the record in section II, the test year is addressed in

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

In order to ensure compliance with the statutorily imposed timeframe for deciding

this case, MCL 460.6a(5), the evidence and arguments necessary for a reasoned analysis

of the disputed issues are expressly addressed in the Proposal for Decision, but not all of

the material presented in this case will be expressly discussed. The various parties’

summaries of the evidence and arguments in support of their respective positions are

fully set forth in their brief and reply briefs, and the underlying basis for the same can be

found in the evidentiary record. Therefore, while this PFD has considered the entire

record in arriving at the findings and conclusions expressed below, only those arguments,

testimony, and exhibits that are necessary for a reasoned analysis of the disputed issues

will be specifically addressed in the PFD.

9 RCG’s initial brief was filed on May 10, 2018 at 12:05 a.m, outside of the 5:00 p.m. deadline. However, on May 30, 2018, this ALJ issued a ruling granting RCG’s May 23, 2018 motion to extend the time for filing RCG’s initial brief.10 Consumers Energy’s Reply Brief is inadvertently titled “Initial Brief of Consumers Energy Company.”

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Il.

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 $178 million

initially filed to $82.775 million in its initial brief, based largely on positions the company

took in rebuttal testimony.11 The utility’s revised rate request is based on a jurisdictional

rate base of approximately $5.4 billion, a return on equity of 10.75% with an overall rate

of return of 6.17% and total projected operating expenses of $1.4 billion.12 As noted

above, Consumers Energy presented the testimony of 25 witnesses and 155 exhibits in

support of its rate request. The direct testimony is reviewed briefly below, while the

rebuttal testimony is reviewed in section G. Cross-examination testimony is discussed

throughout as necessary to describe and resolve disputed issues.

Lisa M. DeLacy, Executive Director of the Smart Energy and Gas Automated Meter

Reading Program, presented the status of the company’s ongoing installation of meter

technology upgrades throughout the company’s service area.13 Ms. DeLacy also testified

to support the reasonableness and appropriateness of the company’s projected O&M

11 Consumers Energy’s initial brief, Appendix A.12 Id.13 Ms. DeLacy’s testimony, including her rebuttal testimony, is transcribed at 2 Tr 37-105.

U-18424Page 7

expenses associated with the installation of gas modules and related activities, as well as

the company’s projected capital expenditures for AMI and AMR gas module installation

and related activities, and for AMR software and system development investments. Ms.

DeLacy also presented rebuttal testimony.

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 and retirees.14 His Exhibit A-43 presented the actual and

projected O&M expenses broken down by benefit category for 2016, 2017, 2018 and the

12 months ended June 30, 2019.15 He reviewed the process for determining the

company’s pension expense, recent contributions to the pension plan made by the

company, and a new Financial Accounting Standard Board (FASB) standard the company

adopted as of January 1, 2017. He also addressed cost projections for the company’s

Defined Contribution Company Plan (DCCP) a closed pension plan for employees hired

on and after September 1, 2005, and for the company’s Employee Savings Plan (ESP),

a 401k plan, as well as health care, life insurance and long-term disability plans for active

employees. the 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. He similarly

14 Mr. Kop’s testimony, including his rebuttal and cross-examination testimony, is transcribed at 2 Tr 106-170.

U-18424Page 8

reviewed the projected expenses for the company’s retiree health care and life insurance

benefit obligations (OPEB), which are subject to the same newly adopted FASB

accounting standard as applied to the pension costs. Mr. Kops also presented rebuttal

testimony and was cross-examined.

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

Consumers Energy, presented the revenue requirement calculations supporting the

company’s filed revenue deficiency, as shown in Exhibit A-11, including the development

of its projected rate base of $5.4 billion, as shown in Exhibit A-12, and the development

of the adjusted net operating income of $225.4 million, as shown in Exhibit A-13.16 His

exhibits also include comparisons to the historical test year results and the associated

schedules. In addition to presenting and reviewing the development of the revenue

requirement, rate base and adjusted net operating income, Mr. Coker 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. He also

presented the calculation and reconciliation methodology for the investment recovery

mechanism, as shown in Exhibit A-76. Mr. Coker also presented rebuttal testimony.

Deborah S. Pelmear, Principal Financial Analyst for Consumers Energy Company,

testified to provide the gas pricing information relied upon to establish the 13-month

average volume and cost of gas stored underground, as well as provide the average cost

of gas sold.17 Her Exhibit A-64 lists the company’s June 2016 through June 2019

16 Mr. Coker’s testimony, including rebuttal, is transcribed at 2 TR 274-204.17 Ms. Pelmear’s testimony, including rebuttal, is transcribed at 2 TR 205-211.

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underground gas storage volumes and dollars, projecting a 13-month average volume of

working gas in storage of 122,300 MMcf and a 13-month average cost of $367,864,128

($3.008 per Mcf). She further testified that the company’s projected average cost of gas

sold for June 2018 through June 2019 is $3.094/Mcf ($695,309/224,699). Ms. Pelmear

also provided rebuttal testimony.

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

support the projected property tax costs for the test year, and to explain the derivation.18

His Exhibit A-72 shows 2018 estimated property tax expenses of $97.0 million, allocated

to the gas portion of the company’s business, and a projected increase of $17.6 million in

2019.

Several witnesses presented testimony to support the company’s projected capital

and operating and maintenance (O&M) expense projections through the June 2019 test

year. Christopher T. Fultz, Director of Project Management for Transmission, Distribution,

and Facilities at Consumers Energy, testified to support the company’s inclusion of

“contingency [a]s a legitimate and forecastable cost of a project”, particularly in the

context of the capital expense projections for the Transmission Enhancement for

Deliverability-Integrity (TED-I) gas transmission pipeline projects on the 2800 and 100 A

lines and to the upgrade projects at the St. Clair and Freedom Compressor Stations.19

His Exhibit A-12, Schedule B-5.6, and Exhibits A-26 through A-29 provide a summary of

actual and projected gas capital expenditures for these major projects, as well as the

monthly capital expenditures for each TED-I pipeline project in the years 2017, 2018, and

18 Mr. VanBlarcum’s testimony is transcribed at 2 TR 212-217.19 Mr. Fultz’s testimony, including rebuttal and cross-examination, is transcribed at 2 TR 218-283.

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2019. Mr. Fultz also presented rebuttal testimony and was cross-examined.

Heather L. Rayl, Senior Rate Analyst in the Rates and Regulation Department of

Consumers Energy, presented the company’s proposed rate design, as well as an

explanation of the allocation of revenues to the various rate schedules.20 She

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

residential rates, general service rates, transportation rates, and Rate Schedule General

Lighting (GL). Her Schedule F-2.2 of Corrected Exhibit A-16 shows the calculation of the

revenue targets used for designing rates, including proposed adjustments, to the test year

revenue requirement by rate schedule. Her Schedule F-3 of Corrected Exhibit A-16

shows the calculation of the test year proposed gas rates required to collect the revenue

requirement derived from the test year calculation of rate design targets shown in

Schedule F-2.2, for each rate schedule, based on billing determinants from Mr. Keaton,

which are used in Ms. Miles’ tariff revisions.

For the residential rates, Ms. Rayl explained the company’s proposed increase of

the monthly customer charge for residential customers billed under Rate Schedules A

and A-1 to $15.90 per month, as supported in the residential customer COSS in Schedule

F-1a to Corrected Exhibit A-16. She also presented the company’s proposed increase of

the Excess Peak Demand Charge for residential Rate A-1 customers to $0.0913 per

MCF, as shown in Schedule F-2.1 to Corrected Exhibit A-16. She described the

development of the company’s proposed increases to the current GS-1 and GS-2 master

customer charges and decrease to the GS-3 master customer charge to $16.00, $86.00,

20 Ms. Rayl’s testimony, including her rebuttal, is transcribed at 2 TR 284-311.

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and $546.00 per month, respectively, as shown in Schedule F-2.1 to Corrected Exhibit A-

16. She also explained the company’s proposed decrease to the Rate ST master

customer charge and increases to the Rate LT and Rate XLT master customer charges

to $546.00, $2,630.00, and $11,120.00 per month, respectively, as shown in Schedule F-

1a to Corrected Exhibit A-16. She testified that the company’s proposed rate increase

for the transportation class is higher than the rate increase for the other rate schedules

because the company is seeking to move this class closer to its total cost to serve so as

to reduce the current subsidization by other customer classes as a result of the

transportation class’s under-contribution.

Ms. Rayl also described the company’s development of its proposed pilot XXLT

rate to serve customers with annual usage of at least 4 Bcf, who require a lower

Authorized Tolerance Levels (ATL). Referencing the COSS sponsored by Mr. Saenz,

Ms. Rayl noted that the study indicates that the cost per Mcf of serving customers in the

proposed pilot XXLT class is lower than the per-Mcf cost of serving XLT customers. She

identified as the second basis for the new pilot rate the fact that customers who currently

qualify for this rate are gas-fired electric generating units, whose operating characteristics

and economics are significantly different than typical gas industrial load.

Her Exhibit A-68 contains the calculation of the test year discount and carrying

costs from the Customer Attachment Program, which are also used in Ms. Miles’ CAP

tariff sheet revisions. Ms. Rayl also testified in support of the company’s proposed

revenue decoupling mechanism (RDM), which uses the same methodology as the RDM

approved by the Commission in its July 31, 2017 order in Case No. U-18124. Ms. Rayl

also described the company’s proposed investment recovery mechanism (IRM) as

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authorizing the company to collect additional revenues associated with incremental

capital spending beginning July 1, 2019 through June 30, 2020. Her Exhibit A-77

illustrates that the company proposes to collect the revenue requirements associated with

the IRM based on a per customer surcharge for each of the sales rate schedules. Ms.

Rayl also presented rebuttal testimony.

Eric J. Keaton, Principal Rate Analyst in the Planning, Budget & Analysis

Department of Consumers Energy, presented the company’s forecasted gas delivery and

customer count levels used to design the test year rates in the company’s filing, supported

by the schedules in Exhibits A-5 and A-15.21 He explained the current weather

normalization process and the company’s gas forecasting progress, as well as the

regression analysis on which the gas forecasts are based. He testified that natural gas

deliveries are expected to increase by 0.4% per year from 2017 through 2021. His

Schedules E-1 and E-2 of Exhibit A-15 show projected deliveries and output for individual

classes. He also testified that the company’s total customer counts are projected to

increase 1.6% from 2016 through the June 2019 test year, and 0.5% per annum over the

next five years, with the most growth occurring in the residential class, as supported by

Schedules E-5 and E-6 in Exhibit A-15. His Schedule E-9 shows the 2017 excess peak

demand consumption associated with residential multi-dwelling service. Mr. Keaton also

presented rebuttal testimony and was cross-examined.

Mr. Torrey is Vice President of Rates and Regulation for Consumers Energy.22 He

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

21 Mr. Keaton’s testimony, including his rebuttal and cross-examination, are transcribed at 2 Tr 312-340.22 Mr. Torrey’s testimony, including his rebuttal, is transcribed at 2 Tr 342-387. .

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

reflected in both price and service, and corporate citizenship/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 he described the company’s

progress toward that goal.23

Mr. Torrey also identified the driving factors behind the company’s request. He

indicated that $158 million, or 89% of the request, is attributable to infrastructure

investments in system reliability, environmental compliance projects, and enhanced

technology programs. He further indicated that $10 million of the company’s rate relief

request is due to projected financing costs, reflecting a higher return on equity net of

reduced debt costs, and a revenue decrease of $8 million primarily due to a reduction in

miscellaneous revenues from programs and services. He also highlighted operational

successes, including the company’s expanded storage system, as well as reviewed

elements of the company’s projected $2 million decrease in total O&M expenses from

current rate levels, including in the areas of health care costs, retirees’ supplemental

coverage, and meter technology.

Mr. Torrey also provided an overview of the testimony of the other company

witnesses and noted that the following items in the company’s filing are presented in part

as a result of the Commission’s order in Case No. U-18124: detailed analysis and

extensive explanation for transmission, storage, distribution, and technology capital

expenditures and O & M expense; analysis and support for the company’s AMI and AMR

23 2 Tr 346-350.

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Programs; and a breakdown of expenditures by project into greater detail, including:

contractor, labor, materials, business expenses, contingency, and other. He also

described how the company’s filing has complied with the new filing requirements set

forth in the Commission’s July 31, 2017 order in Case No. U-18238 to address the 10-

month timeframe for general rate cases under the 2016 energy law. Mr. Torrey also

testified regarding the customer impacts of the company’s proposal, presenting

benchmarks for comparison purposes. Finally, he described the company’s adjustment

mechanism proposals, noting that the proposed gas revenue decoupling mechanism and

the mechanics of the proposed investment recovery mechanism are the same as those

approved by the Commission in Case No. U-18124. Mr. Torrey also presented rebuttal

testimony.

Amy M. Conrad, Director of Compensation for Consumers Energy, presented the

costs the company seeks to recover for its annual employee incentive compensation plan

(EICP) and its long-term incentive plan also known as the restricted stock plan.24 In her

testimony, Ms. Conrad provided a general overview of the company’s compensation

philosophy, which considers these incentive plans part of an employee’s market-based

compensation. She also discussed the design of the EICP, including a review of the

operational and financial metrics, the incentives, and the customer-related benefits that

result from use of these plans. With Exhibits A-17, A-18, and A-19, Ms. Conrad set forth

the EICP performance measures, a summary of requested expenses, and a target pay

level market analysis, respectively. Ms. Conrad also provided rebuttal testimony.

24 Ms. Conrad’s testimony, including her rebuttal, is transcribed at 2 Tr 388-439.

U-18424Page 15

Danielle Hill is the Director of Portfolio and Performance Management for

Generation Engineering and Services – Energy Resources, Portfolio and Performance

Management at Consumers Energy.25 She presented testimony reviewing the functions

of the company’s gas compression storage and gas management services, and in support

of the company’s projected capital and O&M expenses for these areas, as shown in her

Exhibits A-41, A-42, and A-12, Schedule B-5.2. Ms. Hill also emphasized the importance

of GCS and GMS to the company as a foundation for both maintaining affordable prices

and for ensuring adequate supplies of natural gas to customers during long, cold winters

– and noting that the storage fields hold approximately 45 percent of the gas supply

needed by customers through a typical winter. Ms. Hill explained that the company’s

requested test year GCS and GMS O&M expenses, set forth in her Exhibit A-41, were

calculated following an evaluation and prioritization of the maintenance plans required to

maintain and improve each station and field. She also discussed the components of

“base O&M” costs, which include labor and non-labor expenses that are predictable and

relatively stable from year to year. She also presented the company’s projected capital

expenditures in Exhibit A-12, Schedule B-5.2, along with 2016 actual capital

expenditures, grouped by: compression sites, storage fields, storage new wells, and well

rehabilitation. She testified that the major drivers of the $15.5 million projected capital

expenditures for six months of 2017, $85.5 million for 12 months ending June 30, 2018,

$75.1 million for the 12 months ending June 30, 2019, and $176.5 million for the 30

months ending June 30, 2019 are improved system reliability, deliverability, system

25 Ms. Hill’s testimony, including her rebuttal, is transcribed at 2 Tr 441-478.

U-18424Page 16

integrity, safety, and customer service. Ms. Hill also presented rebuttal testimony.

Jeffrey J. Shingler, Executive Director of Electric Operations LVD for Consumers

Energy, testified regarding the gas business portion of the Business Services group’s

capital projects for asset preservation, transportation equipment, and computers and

other equipment.26 He presented the company’s projected capital costs in his Schedule

B-5.4 to Exhibit A-12 and the company’s projected O&M costs in his Exhibit A-70. Mr.

Shingler described the types of expenditures included in the projected capital costs set

forth in Schedule B-5.4. He also explained the function of the gas business services and

the support services and calculated expenses included in Exhibit A-70.

Daniel G. Shirkey, Utility Metrics Director in the Quality Lean Office Department at

Consumers Energy, testified to support the company’s requested recovery of expenses

associated with its Employee Incentive Compensation Plan (EICP).27 He discussed the

operational performance goals and thresholds, and testified to the customer benefits from

meeting these goals. Mr. Shirkey’s Exhibit A-71 contains the performance measures. He

testified that quantification of the customer benefits is difficult for some metrics, but he

presented the company’s quantitative analysis of five key metrics (employee safety;

distribution reliability; generation reliability; quality improvement; and productivity

improvement), concluding that substantial benefit accrues to the customer. He described

the operational metrics in the 2017 EICP, as set forth in his Exhibit A-71, and testified that

the quantification of operational benefits obtained prior to 2017 illustrates how customers

26 Mr. Shingler’s testimony is transcribed at 2 Tr 480-488.27 Mr. Shirkey adopted the direct testimony originally filed by R. Michael Stuart. His direct testimony, and Mr. Shirkey’s rebuttal, are transcribed at 2 491-514.

U-18424Page 17

benefit from the EICP, a conclusion that Mr. Shirkey maintains also applies to 2017. Mr.

Shirkey also provided rebuttal testimony.

Andrew G. Volansky, Senior Rate Analyst II in the Rates and Regulations

Department of Consumers Energy, presented the 2016 historical test year revenue

requirement calculation and the associated historical test year schedules in his Exhibits

A-1 through A-4.28 He testified that, based on his review of these schedules, he calculated

a historical test year gas revenue sufficiency of $35,282,774 for the year ended

December 31, 2016.

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

Energy, testified in support of the following: (i) the company’s O&M expense projection

for Corporate Services, including uncollectible expense and injuries and damages

expense; (ii) accounting approval for the use of regulatory assets or regulatory liabilities,

as needed, for the Revenue Decoupling Mechanism (RDM), and accounting authority to

accumulate IT project implementation costs for cloud-based solutions in Plant Account

303, Miscellaneous Intangible Plant; and (iii) the company’s compliance with the

guidelines for intercompany transactions between affiliates as ordered by the

Commission.29

Total corporate services test year O&M expense projections are shown in Exhibit

A-30, along with historical expenses, with adjustments reflecting normalizations and

disallowances in Exhibit A-31. Mr. Harry explained the projected uncollectible accounts

expense as a product of the thee-year average bad-debt loss ratio and test-year revenue,

28 Mr. Volansky’s testimony is transcribed at 2 Tr 517-525.29 Mr. Harry’s testimony, including his rebuttal and cross-examination, is transcribed at 3 Tr 537-585.

U-18424Page 18

with an adjustment for the estimated impact of the Smart Grid/AMI benefits as shown in

Exhibit A-32. He also explained that the projected injuries and damages expense is

based on a five-year average of actual expense for the years 2012 through 2016, as

shown in Exhibit A-33. He also explained the company’s remediation and direct project

management costs at former MGP sites, as shown in Exhibit A-34, as well as company’s

proposed ratemaking treatment for MGP environmental costs in this case. Mr. Harry also

presented the company’s request for accounting approvals, including a request related to

the company’s proposed implementation of a RDM, as well as a request for deferred

regulatory accounting treatment related to cloud-based technology investments. Finally,

Mr. Harry presented Exhibits A-35 through A-39 to demonstrate the interrelationship of

various affiliated companies that had transactions with the company relative to providing

and receiving services or commodities, as well as how such billing activity and payments

for services are classified by the company. Mr. Harry also presented rebuttal testimony

and was cross-examined.

Heather M. Prentice, Director of Environmental Compliance, Risk Management &

Governance in the Environmental and Laboratory Services Department for Consumers

Energy, presented testimony to support the company’s projected expenditures related to

the company’s environmental response activities at its former MGP sites.30 As shown on

her Exhibit A-65, the company has identified 23 sites that formerly housed MGPs at which

the company has a present or former ownership interest. She testified that the company

will incur environmental response activity costs at all 23 sites during the period January

30 Ms. Prentice’s testimony, including her cross-examination, is transcribed at 3 Tr 586-634.

U-18424Page 19

2016 through December 2018. She presented Exhibit A-66 to show the actual and

projected costs for such activities and explained the basis for them and how they were

determined. Ms. Prentice was also cross-examined.

Luis F. Saenz, Senior Rate Analyst II in the Rate Analysis and Administrative

Section of the Rates and Regulation Department for Consumers Energy, testified to

present the company’s gas Cost of Service Study (COSS) by rate class for the 12-month

period ending June 30, 2019.31 Mr. Saenz presented the company’s projected test-year

cost-of-service studies in Exhibit A-16, with Version 1 in Schedule F-1 and Version 2 in

Schedule F-1a. He explained that the development of the test year cost studies followed

the Commission’s Rate Case Filing Requirements approved in Case No. U-18238.

Schedules F1 and an alternate version in Schedule F1.1. He also explained that the test

year allocation schedules are based on forecasted test year rate class sales data

provided by Mr. Keaton. From this information, Mr. Saenz testified he used a combination

of revenues, sales, or customer counts associated with each class and divided by the

total revenues, sales, or customer counts to develop the allocation percentages

accordingly. He also identified the changes proposed by the company for the 2018 test

year cost study in Version 2 – specifically, a new pilot transportation rate, XXLT, intended

to capture transportation customers with a volumetric usage of 4 Bcf or higher on an

annual basis, exclusive of contiguous accounts. He explained that under the proposed

pilot XXLT rate, the cost per Mcf of serving XXLT customers would be 6% lower than the

cost per Mcf to serve Rate XLT customers, and, because the qualifying customers for the

31 Mr. Saenz’s testimony, including his rebuttal and cross-examination, is transcribed at 3 Tr 635-682.

U-18424Page 20

XXLT rate would not require the same storage capacity as the other transportation

customers, they would have a lower ATL (4%), resulting in the use of less storage overall

by the transportation rate classes. Mr. Saenz testified that this proposal would shift

$323,000 from the transportation class to the residential class ($229,000) and general

service class ($94,000) and, because the company maintains that Version 2 of the cost-

of-service-study provides more rate options to transportation customers, it should be used

to determine the rate class revenue design targets.

Mr. Saenz also presented Schedule F-1b of Exhibit A-16 to show the ratios of rate

base and expense accounts that are used as an input for the test year COSS calculations,

noting that the methodology of developing and using historic rate base and expense ratios

in this case is the same as the one approved by the Commission in Case No. U-18124.

He also performed a COSS scenario that involved the removal of all storage costs from

transportation customers, which scenario resulted in a $33.1 million shift of storage costs

from the transportation class to the residential and general service rate classes, as shown

in Exhibit A-69. He also presented Exhibit A-68 to show the allocation by rate class of

the incremental revenue requirement for the 12 months ending June 30, 2020 provided

by Mr. Coker, using the allocation factors from the Version 2 cost-of-service study. Mr.

Saenz explained that the type of investment (transmission or distribution) determined the

allocation factors applied to the incremental revenue requirement for the period and the

results were then used to calculate the monthly IRM surcharge, as supported by Ms. Rayl.

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

Karen Miles, Senior Rate Analyst I in the Rates and Regulation Department for

Consumers Energy, provided testimony addressing proposed changes to the company’s

U-18424Page 21

gas tariffs.32 She presented a summary of the tariff changes in her Exhibit A-46, with a

redlined version of the tariffs in Schedule F5 of Exhibit A-16. She explained the proposed

addition of the pilot XXLT rate for the extra extremely large transportation customers as

explained by Ms. Rayl. She explained language added to clarify that service may be

denied to a customer enrolled in the company’s shutoff protection plan if customer

responsibilities are not met. She also explained new language allowing the company to

automatically move a customer in default on their lump sum contribution to the CAP

program to the monthly payment plan after 180 days. Ms. Miles explained proposed

changes to the carrying cost and discount rates for the CAP (to 11.26% and 7.73%,

respectively), as detailed in Mr. Denato’s Exhibit A-14 and Ms. Rayl’s Exhibit A-67. She

also explained the IRM surcharge changes as proposed by Ms. Rayl. She explained

proposed changes regarding the low-income assistance credit (LIAC), including removal

of the restriction on the number of participants, and removal of the current requirement

that the monthly credit not exceed the current bill in order to ensure that any resulting

credit balances are applied to future utility charges. Ms. Miles explained a proposed

language change to address the change in percent of Allowance for Use and Loss as

discussed by Ms. Palkovich. She also explained a proposed language change to remove

reference to “Excess Pipeline Costs Surcharge” because the historical collection of these

excess capacity costs pursuant to Staff’s proposed Excess Pipeline Supply Charge

(EPSC) in Case No. U-8678 is no longer necessary because long-term pipeline supply

contracts have since expired. Ms. Miles also provided rebuttal testimony and was cross-

32 Ms. Miles’ testimony, including her rebuttal and cross-examination, is transcribed at 3 Tr 683-722.

U-18424Page 22

examined.

Christopher J. Varvatos, Executive Director of Business Technology for

Transmission, Engineering & Operations Support for Consumers Energy, testified in

support of projected Information Technology (IT) capital and O&M expenditures.33 He

described the IT department and 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-73 contains recent actual and projected test-year O&M expenses, and his Schedule B-

5.5 to his Exhibit A-12 contains the recent and projected capital expenses for the IT

department. He testified that the 10.3% increase in O&M expense projections compared

to 2017 levels is primarily to maintain and support investments made in 2017, as well as

due to one-time O&M expenses associated with capital investment projects. He described

the programs included in the capital expense projections set forth in Schedule B-5.5 to

Exhibit A-12, and presented Exhibit A-74 to show the categories included for each of the

projects now being classified by the company according to a business capability

framework developed by the UNITE consortium of approximately 20 large utilities,

including Consumers Energy. Mr. Varvatos also presented Exhibit A-75, which is an

analysis performed by the company to examine two primary alternatives to expand

disaster recovery capabilities and address constraints/risks, and which forms the basis

for the company’s planned implementation of a third party co-location alternative for the

backup recovery center location. Mr. Varvatos also provided rebuttal testimony and was

33 Mr. Varvatos’s testimony, including his rebuttal and cross-examination, is transcribed at 3 Tr 724-782.

U-18424Page 23

cross-examined.

Srikanth Maddipati, Treasurer and Vice President of Investor Relations for

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

capital, as well as to provide clarification regarding the financial incentives in the

company’s employee incentive compensation plan (EICP) program.34 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 table showing authorized returns for 13 companies. Mr. Maddipati

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 investors’ assessment and expectations for the

regulatory environment in Michigan. He discussed the role of volatility in the financial

markets and how it impacts risk and the cost of capital. He explained how the company’s

significant capital investment program will impact the appropriate ROE to be determined

in this case. He presented a quantitative analysis using a group of proxy companies,

shown at page 14 of his Schedule D-5 in Exhibit A-14, based on his selection criteria. He

34 Mr. Maddipati’s testimony, including his rebuttal and cross-examination, is transcribed at 4 Tr 801-1066.

U-18424Page 24

performed nine different analyses or variants of analyses, including a Capital Asset

Pricing Model (CAPM) analysis utilizing a normalized risk-free method and a low interest

rate method, 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 also

presented rebuttal testimony and was cross-examined.

Andrew Denato, Assistant Corporate Controller for Consumers Energy and its

parent company, CMS Energy, presented his recommendations regarding the capital

structure for ratemaking based on the company’s actual capital structure as of July 31,

2016, adjusted for projected changes in debt, equity, deferred income taxes, and

Investment Tax Credit (ITC) through the end of the test year ending on June 30, 2019.35

He presented this projected capital structure in Schedule D-1 of Exhibit A-14, which

shows equity as 52.49% of permanent capital.

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

$320 million from the July 31, 2017 level to reflect retained earnings of $174 million

projected from August 2017 through June 2019, and equity infusions of $146 million

through the same period. He explained how he estimated retained earnings, and he

explained that the planned equity infusions of $100 million each in January 2018 and

January 2019 are reflected in the equity balance for the test year. Mr. Denato also

explained that he increased the average debt balance by $631 million, reflecting several

planned retirements and debt issuances through June 30, 2019, as shown on page 2 of

35 Mr. Denato’s testimony, including his rebuttal and cross-examination, is transcribed at 4 Tr 1066-1153.

U-18424Page 25

Schedule D-1a to Exhibit A-14. He testified that the planned debt issuances in September

and November 2017 are part of a private placement bond purchase agreement, and the

planned debt issuances in May 2018, August 2018, and May 2019 “have been determined

based on the Company’s financing plans after evaluating cash and liquidity requirements

for the Company.”36 He testified that the resulting equity percentage of 52.49% “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.”37 He testified that with the company’s deceleration of its significant

capital investment program to more normal levels, the need for an equity ratio slightly

higher than 50% will be less critical. Acknowledging the Commission’s order in Case No.

U-18124, Mr. Denato testified that the company has progressed in this direction with a

recommended common equity ratio that is “61 basis points lower than the equity ratio of

53.1% approved in Case No. U-18124.”38

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. 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 4.68% as shown in his Schedule D-2 of Exhibit A-14, using projected costs of 5.5%,

5.5%, and 6.5% for debt issuances to be made in May 2018, August 2018, and May 2019,

36 4 Tr 1084.37 Id. at 1079.38 Id. at 1081.

U-18424Page 26

respectively. He estimated a short-term debt rate at 3.53%, shown in his Schedule D-3

of Exhibit A-14, and explained the two components of which the short-term debt costs are

comprised: short-term debt – revolver/commercial paper, and short-term debt –

renewable liability. 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 6.11% on an after-tax basis. In his Exhibits A-23, A-24, and A-

25, Mr. Denato presented current and historical credit ratings with associated outlooks for

the previous five years, recent public utility corporate bond issuances, and peer company

equity ratios. Mr. Denato also presented rebuttal testimony and was cross-examined.

Lauren E. Youngdahl, Executive Director of Customer Services for Consumers

Energy, testified regarding O&M expense projections for the company’s customer

experience organization, “digital customer experience” program, and customer payment

programs.39 She presented Exhibit A-47 to show the O&M costs related to the customer

experience and customer payment programs, as well as the ASP margin available to

offset revenue requirements, for the test year ending June 30, 2019. She described the

customer experience organization as comprised of customer services, marketing and

strategy, and digital customer experience. She presented Exhibit A-48 to show the costs

for this program for the years 2016, 2017, 2018 and the 12 months ended June 30, 2019.

She also 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 operational efficiencies. She explained

39 Ms. Youngdahl adopted the direct testimony originally filed by Julio Morales. His direct testimony, and Ms. Youngdahl’s rebuttal, are transcribed at 5 Tr 1166-1222.

U-18424Page 27

that the $7.5 million test year O&M expense request shown in Exhibit A-47 for the

customer payment program reflects the company’s September 1, 2016 elimination of the

$6.25 convenience fee for credit card payments. She also 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. Ms. Youngdahl also provided rebuttal testimony and was cross-examined.

Elizabeth A. Curtis, Director of Gas Transportation and Measurement for

Consumers Energy, presented the company’s study of the benefits and costs associated

with daily balancing of end use transportation (EUT) customers’ supplies and deliveries

in compliance with the settlement agreement reached in Case No. U-17900.40 She

provided an overview of the EUT program, and explained the genesis of the Daily

Balancing Study offered by the company in its filing, as well as the costs associated with

daily balancing and the resulting need for and benefits from additional storage allocation.

Ms. Curtis also provided rebuttal and sur-surrebuttal testimony and was cross-examined.

Mary Palkovich, Vice President of Gas Engineering and Supply for Consumers

Energy, presented testimony to support the company’s projected capital and O&M

expenses related to its gas transmission and distribution.41 As shown in her Exhibit A-

49, Ms. Palkovich testified that the company’s total gas transmission and distribution

operations O&M projected expense request is $167.4 million for the test year. She

testified that the request is comprised of projected expenses related to the following: day-

40 Ms. Curtis’s testimony, including her rebuttal, sur-surrebuttal, and cross-examination, is transcribed at 5 Tr 1223-1296 and 5 Tr 1479-1500.41 Ms. Palkovich’s testimony, including her rebuttal and cross-examination, is transcribed at 5 Tr 1297-1476 and 5 Tr 1501-1549.

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to-day operations in the gas division; inspections and remediation of transmission pipeline

segments; leak repair and survey; compliance with maximum allowable operating

pressure (MAOP) regulations; meter reading; smart energy direct O&M benefits;

estimating customer bills; lost and unaccounted for gas (LAUF) and company use gas;

the gas portion of ongoing financial budgeting and cost management functions associated

with the smart energy/advanced meter infrastructure (AMI) program investment. Turning

to the total gas transmission and distribution capital expenditures that resulted in 2016

and are projected for the years 2017, 2018, and the six months ended June 30, 2019

($378,484,000, $421,254,000, $554,727,000; and $249,015,000), she explained that

these amounts, shown in Exhibit A-12, Schedule B-5.3, are based upon the requirements

to meet customer reliability, ensure public safety, and to maintain system deliverability.

Ms. Palkovich described the following major programs of which these capital expenditures

are comprised: new business; asset relocation; regulatory compliance; material condition;

capacity/deliverability; and gas operations other. She further noted that the Company has

identified contingency expenditures within two programs: (i) the TED-I Projects

Transmission Program, in the amounts of $1,650,000 in 2018 and $243,000 within the six

months ending June 30, 2019; and the T&S Citygates Program in the amount of $250,000

in 2018. Ms. Palkovich also provided rebuttal testimony and was cross-examined.

B. Staff

Staff’s filing recommended a revenue sufficiency of $6,539,000 on a jurisdictional

basis, based on a return on equity of 9.60%. In its initial brief, Staff revised its revenue

sufficiency to $1.7 million. Staff presented the direct testimony of 17 witnesses, one of

whom provided rebuttal testimony along with that of one additional witness as discussed

U-18424Page 29

below in section II.G.

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 sufficiency, projected gas net operating income, federal income

tax adjustment, potential automatic meter read (AMR) deferred debit accounting

treatment, and pension and other post-employment benefits (OPEB) adjustments,

incorporating the recommendations of other Staff witnesses.42 The revenue requirements

calculation is shown in his Exhibit S-1, with projected net operating income in Schedule

C-1 to Exhibit S-3, including reference to each Staff witness sponsoring and explaining

each adjustment. Mr. Nichols testified that Staff included the impacts of the Tax Cuts and

Jobs Act on current tax expense only, recommending that the impacts of the Act on

deferred taxes instead be addressed in Case No. U-18494. He testified that Staff,

specifically Ms. Fromm, is recommending that costs related to AMR not be recovered in

current rates. He also testified that Staff’s audit has resulted in reductions in the pension

and OPEB O&M expenses for the projected test year and corresponding increases in

working capital, as shown in Schedule C-5 to Exhibit S-3 and Schedule B-4 to Exhibit S-

2.

Jay Gerken, Manager of the Rate Base Unit in the Commission’s Financial

Analysis and Audit Division, presented Staff’s total projected rate base for the test year

of $5,210,016,000, as shown in Exhibit S-2, Schedule B-1, reflecting a decrease of

$258,026,000 from the company’s $5,468,042,000 projection. He also presented Staff’s

42 Mr. Nichols’s testimony is transcribed at 6 Tr 2093-2103.

U-18424Page 30

total projected utility plant and depreciation reserve for the test year of $7,737,433,000

and $3,207,637,000, respectively, as shown in Exhibit S-2, Schedule B-1, and explained

that the decreases from the company’s projections of $7,984,821,000 and

$3,222,237,000 are comprised of adjustments by Staff (Ms. Creisher, Ms. Fromm, and

Mr. Frazier) to the company’s historic and projected capital expenditures in various

categories addressed in their respective testimonies. Mr. Gerken testified that Staff’s

projected working capital of $662,139,000, as shown in Exhibit S-2, Schedule B-1, is an

increase from the company’s $656,995,000 projection, and Staff’s projected net

unamortized MGP of $21,596,000 is a decrease from the company’s $51,978,000

projection. Mr. Gerken also supported Staff’s adjustment to decrease by $3,092,000 the

company’s projected property tax expense.

Addressing the capital structure, Mr. Gerken recommended the following: (i)

removal of customer deposits and security deposits in the amounts of $8 million and $17

million, respectively, because the origin of these deposits renders a more appropriate

inclusion of them in the company’s working capital; (ii) recognition of any required interest

accrued or paid on these deposits as an expense in the company’s test year revenue

requirement computation; (iii) removal of $17 million of other interest bearing accounts.

Addressing working capital, Mr. Gerken supports adjustments for the inclusion of the

company’s FERC account 235 – security deposit amounts, FERC account 242 –

customer deposit amounts, and FERC account 242 – GCC supplier deposit amounts.

Finally, he testified to support Staff’s recommended adjustment to recognize in working

capital the amount of $293,000 in required interest expenses related to the inclusion of

the aforementioned deposit amounts, noting that this adjustment is contingent upon the

U-18424Page 31

Commission finding it appropriate to include such items in working capital.

Stacy Harris, Auditor in the Commission’s Financial Analysis and Audit Division,

presented Staff’s projected working capital for the test year ending June 2019, which, at

$662,139,000, reflects an increase of $5,144,000 from the company’s projected net gas

working capital requirement.43 Ms. Harris explained the difference as a result of a

reduction to accounts receivable, an increase to deferred debits, and an increase to other

current liabilities. Regarding the accounts receivable, Ms. Harris testified that the

company has confirmed in response to Staff’s discovery request that the non-current CAP

installment receivables gas of $6,488,075 was inadvertently included in test year working

capital.

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

O&M expense projections. Cynthia Creisher, Public Utilities Engineer in the Gas

Operations Section of the Commission’s Operations and Wholesale Markets Division,

presented testimony in support of Staff’s recommended adjustments to the company’s

proposed O&M expenses for the following departments or programs: gas division; gas

compression, storage and gas management services; pipeline integrity inspections and

remediation; and maximum allowable operating pressure (MAOP) transmission.44

Regarding gas division expenses, she testified that, although generally supportive of the

methodology used by the company to derive the projected O&M expenses, Staff

recommends the company’s proposed expense of $111,182,000 be adjusted based on

2017 actual O&M expense levels not previously available to the company at the time of

43 Ms. Harris’s testimony is transcribed at 6 Tr 2034-2037.44 Ms. Creisher’s testimony is transcribed at 6 Tr 1837-1896.

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its filing, and that Staff’s inflation factor be applied in calculating the expense levels, as

shown in Exhibit S-11.0, resulting in a projected expense level of $105,420,000.

Regarding the company’s proposed O&M expenditures of $12,105,000 related to its

pipeline integrity program, Ms. Creisher testified that while Staff generally supports the

proposed work related to the program, it finds that not all proposed expenses are

reasonable and prudent. Specifically, she testified that Staff finds that the company has

not met the federal requirements for the use of Electro-Magnetic Acoustic Transducer

(EMAT) as an acceptable method to detect stress corrosion cracking (SCC). She also

testified that the allowable costs for the magnetic-flux leakage (MFL) assessments of Line

400 and Line 1200B be reduced consistent with the company’s other pipeline assessment

costs using aMFL or cMFL. Based on these reductions and the removal of costs related

to EMAT assessments, the proposed expense level for the test year should be adjusted

to $9,938,100, as shown in Exhibit S-11.1.

Ms. Creisher also testified to Staff’s recommended removal of the company’s

proposed O&M expenses and capital expenditures related to the MAOP transmission

program – specifically, those expenses related to hydrotesting, replacement, and

upgrades intended to address the Pipeline Safety, Regulatory Certainty, and Job Creation

Act of 2011 and PHMSA Advisory Bulletins ADB-11-01 and ADB-2012-06. According to

Ms. Creisher, the recommended removal of these expenses, as shown in Exhibit S-11.1,

is based on Staff’s determinations that the company: (i) should have but failed to perform

a review of records related to pipelines operating at greater than 40% of the specified

minimum yield strength to ensure the existence of adequate records in support of MAOP

documentation; and (ii) has not demonstrated that the proposed hydrotesting in 2018 of

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Lines 1070, 1020, and 1600, and replacement of pipe and fittings for Lines 1200B, 1200,

3070, and the Lahser Lateral are necessary absent further information on the pressure

test deficiencies for projects citing pre-1965 pressure tests and operating histories, and

to the extent the projects entail design or material verification issues subject to pending

regulations.

Regarding gas compression, storage (GCS) and gas management services (GMS)

O&M expenses, Ms. Creisher testified that Staff recommends the company’s proposed

base expense of $23,095,000 for the test year be adjusted based on 2017 actual O&M

expense levels not previously available to the company at the time of its filing, and that

Staff’s inflation factor be applied in calculating the expense levels, as shown in Exhibit S-

11.2, resulting in a projected base O&M expense level of $22,457,000.

Ms. Creisher also testified to Staff’s recommended adjustments to the company’s

proposed capital expenditures related to: pipeline integrity, material condition, mid-

Michigan pipeline projects, and pressure-limiting device projects. With respect to the

pipeline integrity program, she testified that Staff generally supports the company’s

proposed level of capital expenditures related to the transmission program but, as

discussed in Mr. Miller’s testimony, continues to have concerns similar to those raised in

Case No. U-18124 regarding “certain practices related to remediation of anomalies found

during integrity assessments.”45 She testified that because the federal rulemaking

process to incorporate rule changes impacting this area has not yet been completed, it is

not reasonable to include capital expenditures related to work that could be affected by

45 6 Tr 1869.

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the pending Notice of Proposed Rule Making. She presented Exhibit S-11.3 to show

Staff’s proposed adjustments to reduce the company’s 2019 Pipeline Integrity – TOD total

capital expenditures from $14,387,100 to $3,203,850, and reduce the Company’s 6-

month period ending June 30, 2019 prorated capital expenditures from $5,795,703 to

$1,290,640, resulting in in a projected capital expenditure of $4,374,000 for the test year

ending June 30, 2019.

Ms. Creisher also described Staff’s adjustments to the company’s proposed capital

expenditures related to the material condition program as follows: (i) a reduction of the

company’s proposed test year level of $22,859,000 for the material condition non

modeled program to $20,153,000, as shown in Exhibit S-11.4; (ii) a reduction of the

company’s proposed test year level of $15,888,000 for the material condition renewals

program to $13,955,000, as shown in Exhibit S-11.4; and (iii) increase the length of the

vintage service replacement program from a 10-year to a 20-year period, effectively

reducing the number of services and amount of capital expenditures projected by half,

resulting in a projected capital expenditure of $8,196,000 in the six months ending

June 30, 2018, and $21,905,000 in the test year ending June 30, 2019, as shown in

Exhibit S-11.4. She also shared Staff’s recommendation that as part of the annual

reporting requirements of the EIRP Performance Report Requirements, the company

report the total service line leaks remediated by leak cause type to include a breakdown

of the material type and remediation method through repair or replacement similar to the

matrix shown in Exhibit S-11.25.

Regarding the company’s proposed capital expenditures related to the Mid-

Michigan Pipeline gate station projects, Ms. Creisher testified that, absent an application

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for approval to construct and operate pursuant to Public Act 9 of 1929, the company

should only be allowed to recover capital expenditures related to design and engineering

of the Mid-Michigan Pipeline – specifically, $31,000 in engineering costs as shown on

page 3 of Exhibit A-63. As for the company’s proposed capital expenditures related to

pressure limiting device (PLD) projects, she testified that Staff has concerns similar to

those raised by Staff in Case No. U-18124 that the company has not provided adequate

information to demonstrate that the PLD projects were not instances where the company

was not in compliance with the requirements of 49 CFR 192.195 due to pipeline

construction, interconnections, modifications, assessment of class location changes, or

other such changes where the Company should have properly evaluated and determined

the need for PLDs many years ago. She testified that the Commission supported Staff’s

position in that case that the PLD projects should not be borne by ratepayers and Staff’s

position is unchanged, resulting in As shown in Exhibits S-11.5 and S-11.6, pages 1 and

4, Staff proposes the company’s proposed capital expenditures be adjusted from

$2,030,000 to $1,090,000 in 2016, from $11,568,000 to $2,033,000 in 2017, from

$9,918,000 to $11,568,000 in 2018, with the amount of $1,669,000 unchanged for the 6

months ending June 30, 2019.

Finally, Ms. Creisher testified that, although the investment recovery mechanism

(IRM) proposed by the company was approved by the Commission in Case No. U-18124

for 2018 and 2019, the IRM has not resulted in the realized benefits of reduced frequency

of general rate cases or any reduction in the resources associated with regulatory

proceedings. She testified that if the Commission nonetheless finds the proposed IRM

reasonable, Staff supports inclusion of the VSR program in the IRM. She testified

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however that Staff does not support inclusion of the TED-I distribution and transmission

projects in the IRM because the significant drivers of these projects are the South

Macomb Oakland Network projects, planned for between 2018 and 2020 and thus not

representative of the proposed IRM operating years, and the PDL projects, which Staff

has recommended be excluded from recovery of capital expenditures. Staff recommends

that, if an IRM is approved, the IRM expenditures be adjusted to be in line with Staff’s

recommendations for the projected test year expenditure levels of $4,374,000 for Pipeline

Integrity – TOD program and $21,905,000 for the VSR program. She testified that Staff

recommends recovery of incremental spending for the years ending June 30, 2020, and

June 30, 2021, with annual capital expenditures totaling $186,420,000, as shown in

Exhibit S-11.7. She testified that Staff recommends that the spending flexibility spending

cap of 3.2% between IRM programs as ordered by the Commission in Case No. U-18124

should remain in effect, including the requirements that EIRP spending must be at a

minimum of $75,000,000 per year.

Kevin Spence, Public Utilities Engineer in the Gas Operations Section of the

Commission’s Operations and Wholesale Markets Division, presented Staff’s

adjustments to the company’s proposed capital expenditures related to the New Business

program and the St. Clair Compressor Station upgrade project.46 He testified that Staff

supports the New Business program but, as shown in Exhibit S-18.2, recommends that

the costs related to the large agri-business customer and the Lansing BWL project be

disallowed because legal contracts have not yet been executed, rendering the projects

46 Mr. Spence’s testimony is transcribed at 6 Tr 2122-2130.

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speculative. Regarding the St. Clair project, he testified that while Staff supports the need

for the upgrade, Staff recommends that costs related to a 2017 fire incident and costs

related to project contingency should be disallowed. He explained that the company did

not provide sufficient evidence that the costs resulting from the fire incident were firmly

established calculations. The recommended adjustments are shown in Exhibits S-18.4

and S-17.0.

Michelle Edelyn, Auditor in the Revenue Requirements section of the

Commission’s Financial Analysis and Audit Division, presented Staff’s MGP amortization

expense for the projected test year.47 She explained that the $30,382,000 difference

between the company’s projected deferred net unamortized balance of $51,978,000 and

Staff’s calculated amount of $21,596,000 is due to the company having used projections

through the June 30, 2019 test year and Staff having used actual invoiced expenditures

through the end of December 2016 in accordance with the Commission’s guidance in its

March 11, 1996 order in Case No. U-10755 that it cannot determine deferred expenses

to be reasonable and prudent until after Staff’s review of the expenses incurred. Ms.

Edelyn also testified that the company should be allowed to recover an amortization

expense of $4,669,000 and direct project management costs of $781,078.

Robert Frazier, a consultant with Utegration LLC, testified in support of Staff’s

recommended adjustments to the company’s proposed Information Technology (IT)

capital expenditures and O&M expenses.48 He testified that the company has not

adequately justified the digital customer experience (DCE) project. He recommended

47 Ms. Edelyn’s testimony is transcribed at 6 Tr 1898-1905.48 Mr. Frazier’s testimony is transcribed at 6 Tr 1908-1935.

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that the requested capital and O&M expenses of $8,067,495 and $219,236, respectively,

for the gas portion of this project be reduced to $2,542,875 and $154,125, respectively,

as shown in Exhibit S-14.4. Because the company has already exceeded these costs,

Mr. Frazier testified that no additional funding should be approved beyond the historic

period. Regarding the company’s field service solution project, Mr. Frazier testified that

because the company did not provide adequate information on efficiency improvements

to justify the expense for this project, Staff recommends that only 67% of the company’s

labor and 50% of its contractor costs, overhead and AFUDC be approved – resulting in a

total disallowance of $2,675,000 from the company’s total of $6,758,263 in capital

expenditures, as shown in Exhibits S-14.5 and 14.1. He testified that Staff also

recommends a 6% reduction to overall requested amounts for all IT projects based on

what Staff has determined to be the company’s prior precedent of historical project

cancellations. Alternatively, Mr. Frazier testified that the Commission should at least deny

recovery of $6,210,516 from projects in the current case since that amount is already in

rate base but not spent. Mr. Frazier also testified that the costs for certain NERC/CIP

projects should be disallowed, as shown in Exhibit S-14.1, inasmuch as the company has

since acknowledged these projects are electric-only and should not have been included.

Mr. Frazier explained Staff’s concern with the company’s overall project administrative

procedures as lacking attention to detail, thus warranting Staff’s recommendation that, for

all future rate cases, the company: (i) track and submit project expenditures pursuant to

internal-use software rules set forth in his testimony; and (ii) implement a project “approval

to proceed” document with certain information included for categorization and tracking.

Finally, Mr. Frazier described in detail the benefits and services associated with cloud-

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based IT services and testified that the company should be allowed to capitalize the cost

of developing cloud computing, but all costs for the service rendered after implementation

should be treated as O&M expenses.

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

Operations and Wholesale Markets division of the MPSC.49 In her testimony, Ms. Fromm

discussed several concerns that Staff has with the company’s gas Automated Meter

Reading (AMR) program, ultimately recommending that all AMR costs be disallowed or,

alternatively, that the company be prohibited from accelerating depreciation of its meters

in the future should the company deem an AMI solution a more prudent path forward

before the end of the AMR meters’ 20-year life. Ms. Fromm also addressed the use of

contingency allowances in the company’s capital expense projections generally,

recommending that the Commission exclude all contingency expenditures as shown in

Exhibit S-17.0. Ms. Fromm also recommended a disallowance of $234,611, as shown

in Exhibit S-17.3 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 projected meter reading O&M

expense, recommending that the company’s 2015 actual meter reading expense be

adjusted by 37% to reflect the cost to read meters not yet with an AMI or AMR solution,

resulting in a test year meter reading expense of $6.786 million, as shown in Exhibit S-

17.2. She also recommended that the company not be allowed to any increase from the

historic year for customer services labor costs or for marketing & strategy contractor,

49 Ms. Fromm’s testimony is transcribed at 6 Tr 1938-1964.

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labor, and business expenses, testifying that the company is failed to provide any work

output that results from these departments in these areas. These recommended

disallowances of $149,000 and $3,750,600, respectively, are shown in Exhibit S-17.1.

Because of this lack of work output, Ms. Fromm also recommended that, in future cases

in which the company requests recovery, the Commission require the company to submit

specific tasks that these departments perform.

James La Pan, Public Utilities Engineer in the Commission’s Regulated Energy

Division, presented Staff’s recommendations on the company’s recovery of remediation

activity expenditures at the company’s 23 manufactured gas plant (MGP) sites.50 He

testified that Staff recommends the company be allowed to recover $5,402,158 of the

$52.3 million requested in its filing. As shown in Exhibit S-8.0, Staff’s recommendation

allows for recovery of actual expenses incurred by the company from January 2016

through December 2016 and, consistent with the Commission’s order in Case No. U-

10755, excludes from recovery the company’s 2017 and 2018 estimates for MGP

remediation response activities that have not yet been performed,

Brian Welke, Manager of Income Analysis Unit of the Commission’s Regulated

Energy Division, presented testimony in support of Staff’s recommended adjustments to

incentive compensation and injuries and damages O&M expenses.51 As shown in

Schedule C5 of Exhibit S-3, Mr. Welke recommended eliminating $1.16 million from the

company’s projected incentive compensation expenses associated with the attainment of

financial performance metrics, and allowing only that portion related to the achievement

50 Mr. La Pan’s testimony is transcribed at 6 Tr 2084-2091.51 Mr. Welke’s testimony is transcribed at 6 Tr 2132-2141.

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of non-financial goals, or $590,000. Mr. Welke also recommended that the company base

its projected injuries and damages expense on a five-year average (2012-2016) of

account 925, rather than the company’s proposed methodology, resulting in an

adjustment of ($1,645,000), as shown in Schedule C5 of Exhibit S-3. He also testified

that Staff supports the company’s regulatory accounting request to capitalize project

implementation costs related to cloud-based technologies.

Kevin Krause, Auditor in the Rates and Tariff Unit of the Commission’s Regulated

Energy Division, presented Staff’s identification of an error in the company’s inclusion of

Asset Management Agreement (AMA) revenue in the company’s Other Gas Revenue,

the removal of which was agreed to by the company and results in an increase of

$7,678,000 to Other Gas Revenue.52 He also testified that the company’s proposed

revenues and expenses related to Value Added Services is a reasonable projection.

Nathan Miller, Supervisor of the Gas Safety and Infrastructure Unit of the

Commission’s Gas Operations Section, presented Staff’s recommendations regarding

the company’s practices to remediate minor pipe anomalies discovered through the

transmission integrity management program with pipe segment replacement lengths in

excess of 50 feet.53 He testified that Staff recommends capitalization disallowances for

2016 and 2017 in Pipeline Integrity – (Transmission) expenditures.54 He also testified

that Staff recommends a disallowance from the 2017 Pipeline Integrity Inspections and

Remediations O&M expenditures, as shown in Confidential Exhibit S-12.30. He also

52 Mr. Krause’s testimony is transcribed at 6 Tr 2076-2082.53 Mr. Miller’s confidential testimony is transcribed into a Confidential record at 6 Tr 1643-1694, and his cross-examination is transcribed at 6 Tr 1695-1704.54 Staff’s recommended disallowances are shown in Confidential Exhibits S-12.24 and S-12.30.

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testified that Staff recommends disallowances of 68.95% of the company’s projected

capital expenses for the remaining projected bridge and test years in the Pipeline Integrity

– (Transmission) category. He testified that if the Commission agrees with Staff’s

recommended disallowances, adjustments will need to be made for the projected test

period – specifically, an increase in O&M expenses for pipeline integrity. Mr. Miller further

testified that these recommendations are in addition to the revenue requirement filed by

Mr. Nichols. Finally, should the Commission disagree with Staff’s recommendation that

the company’s remediation digs be categorized as O&M expenses, Staff provides

alternative recommendations.

Kirk Megginson, Financial Specialist in the Revenue Requirements Section of the

Commission’s Financial Analysis & Audit Division, testified regarding the ratemaking

capital structure and cost of capital.55 He utilized Consumers Energy’s projected capital

structure balances for long-term debt, short-term debt, preferred stock, deferred federal

income taxes and job development investment tax credits, but recommended revisions to

the company’s projected common equity, customer deposits and other interest bearing

accounts. He testified that Staff recommends a $40 million reduction to the company’s

proposed common equity balance of $6,702,778 based on Staff’s determination that the

January 2019 equity infusion was not reasonably explained and counter to the

Commission’s directive in Case No. U-18124. He testified that Staff supports removal of

the customer deposits and other interest bearing accounts balances. He also testified

that Staff recommends lower long-term and short-term debt cost rates of 4.57% and

55 Mr. Megginson’s testimony, including his cross-examination, is transcribed at 6 Tr 1708-1830.

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3.14%, respectively, rather than the company’s proposed $4.68% and 3.53% as Staff’s

estimates represent more accurate cost rates than those of the company. Mr. Megginson

testified that based on his analysis, the cost of equity for Consumers Energy is in the

range of 8.70% - 9.70%, and he recommended an authorized return of 9.60% for the

company. After reviewing the applicable standards, he explained the analysis she

conducted, including the selection of a proxy group, parameters and choice of inputs for

the financial models he used, and the model results for his DCF, Capital Asset Pricing

Model (CAPM), and risk-premium analyses. The results of his analyses are summarized

on page 13 of Schedule D5 of Exhibit S-4. Mr. Megginson was also cross-examined.

Nora Quilico, Public Utilities Engineer with the Commission, testified to support an

updated average cost of gas of $3.001/Mcf for the projected July 2018-June 2019 test-

year, which is a reduction of 9.3 cents from the company’s filed amount.56 She testified

that this revision, as shown in Exhibit S-13.1, is warranted by the current market price of

gas and the national supply/demand situation. Ms. Quilico also testified to support an

updated combined (GCR/GCC) 13-month average cost of gas in storage with a

corresponding 13-month average storage volume, as shown in Exhibit S-13.2, which

reflect Staff’s recommended reliance on amounts that are based on consistent

assumptions and time snapshots.

Katie Smith, Economic Analyst in the Energy Waste Reduction Section of the

Commission’s Electric Reliability Division, presented Staff’s recommendation related to

the company’s proposed revenue decoupling mechanism (RDM).57 She testified that

56 Ms. Quilico’s testimony is transcribed at 6 Tr 2106-2113.57 Ms. Smith’s testimony is transcribed at 6 Tr 2115-2120.

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Staff does not oppose the company’s proposed RDM because it meets the criteria

necessary for an RDM to result in just and reasonable rates for the recovery of lost sales

associated with energy waste reduction (EWR). She also testified that the proposed RMD

is the same RDM that was requested by the company and approved by the Commission

in Case No. U-18124.

David Isakson, Departmental Analyst in the Rates and Tariffs section of the

Regulated Energy Division, presented Staff’s gas cost-of-service study.58 He sponsored

Schedules F1 and F1a, summarizing Staff’s cost-of-service study results following review

and analysis of the company’s two cost-of-service studies, and explained the adjustments

Staff made to them. He testified that the company included two separate studies to show

that the proposed XXLT rate has a different cost to serve than the existing XLT rate. He

testified that Staff agrees with the company’s method of adjusting storage capacity

allocation as a result of the new 4% ATL for the proposed XXLT rate. He testified that

Staff is largely unopposed to several elements of the company’s cost-of-service study,

with customer charges based on the Commission’s previously approved method,

excluding appliance service plan expenses. He explained that because these expenses

are not directly related to the attachment of customers to the company’s system, they

were removed, as shown in Schedule F1a to Exhibit 6. And he testified that Staff

recommends leaving unchanged the residential customer charge of $11.75, since the

calculation for this charge would otherwise be greatly affected by several of Staff’s

adjustments to distribution meter costs. Mr. Isakson also explained Staff’s downward

58 Mr. Isakson’s testimony, including his rebuttal, is transcribed at 6 Tr 2039-2075.

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adjustment to the company’s other gas in kind (GIK) volumes projection, as shown in

Exhibit S-19, noting it is small because the company’s projection is very near the historic

5-year average. He also discussed Staff’s current lack of opposition to the company’s

continued use of the 50% storage capacity – 50% peak month allocation method for

storage costs, the use of design peak day in developing allocation schedules, and

allocating uncollectible expenses on net write-offs. He also provided rebuttal testimony.

Daniel Gottschalt, Departmental Analysis in the Rates and Tariff Section of the

Commission’s Regulated Energy Division, presented Staff’s recommendations regarding

projected revenue, customer count criteria for RIA and LIAC rates, IRM and XXLT energy

efficiency surcharges, proposed tariff changes, and rate design.59 He testified that Staff’s

residential rate design, as shown in Exhibit S-6, Schedule F-2.2, began with Mr. Isakson’s

cost-of-service study results, and adjusted for allocation of RIA and LIAC rates to all

customers based on total cost of service, including Staff’s cost of gas presented by Ms.

Quilico. For all rates except for XLT and XXLT rates, he recommended achieving as

close as possible 50% of the way towards the COSS results. For the XLT and XXLT

rates, he recommended capping increases at or below 25% to reasonably balance the

need to limit the impact of rate increases to prevent rate shock with the need to limit the

impact to other customers of settlements not reflecting the cost to serve. Regarding the

company’s XXLT rate, Mr. Gottschalk testified that Staff finds the design inappropriate as

it is premised on an artificially created cost gap that is unreflective of the cost to serve

these customers. He testified that Staff continues to support the use of a 13-month

59 Mr. Gottschalk’s testimony is transcribed at 6 Tr 2016-2032.

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average to calculate the IRM revenue requirement, as directed by the Commission in

Case No. U-18124. He testified that Staff disagreed with the company’s proposed energy

efficiency surcharge for the XXLT rate, noting it should be the same as ST, LT, and XLT’s

surcharge at the same usage level – and the company has since agreed to Staff’s

correction. Finally, Mr. Gottschalk testified that Staff does not support the company’s

proposed increase of the residential customer charge from $11.75 to $15 per month, and

instead recommends it remain at the present rate.

C. Attorney General

Sebastian Coppola, independent business consultant, testified on behalf of the

Attorney General.60 Mr. Coppola concluded that Consumers Energy has a revenue

deficiency of $54.9 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 the test year totaling $335.2

million, including: a $77.6 million reduction to exclude contingency projections. He also

recommended a total $165.1 million reduction in capital expenditures for new business,

regulatory compliance, material condition, capacity/deliverability, and gas storage and

compression; a $69 million reduction in projections for capital spending on major projects;

and an $18.5 million reduction in IT capital spending projections, and a $4.8 million

reduction in employee benefits, concluding that the company’s projections were not

60 Mr. Coppola’s testimony is transcribed at 7 Tr 2322-2463; his qualifications are transcribed at 7 Tr 2464-2477.

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supported by specific projects or were otherwise inconsistent with historical spending

levels. Mr. Coppola’s reductions are shown in Exhibit AG-40.

In recommending a reduction of $231 million to the rate base for the projected test

year, Mr. Coppola also recommended three adjustments to working capital, to reflect: (i)

adjustments related to lower liability accounts due to revisions made by the company to

pension plan and OPEB expenses after its initial filing; (ii) inclusion of the gas portion of

customer and security deposits as additional liabilities; and (iii) a lower cash balance level

than that proposed by the company. These adjustments would reduce the company’s

working capital by $8.9 million, from $657 million to $648.1 million, as shown in Exhibit

AG-41.

Regarding O&M expense projections, as shown in Exhibit AG-17, Mr. Coppola

recommended a total reduction of $41.7 million in projected test year spending, including:

a reduction in meter reading costs; a reduction to the “customer experience” department

expenses; a reduction to the customer payment program expense; and the elimination of

projected expenses for the company’s incentive compensation plans. He also

recommended a reduction in pension and other-post-retirement benefits (OPEB) based

on the company’s revised schedules using updated assumptions, as well as on Mr.

Coppola’s determination that the company’s reduction in the return rate on plan assets

for 2018 and 2019 was not justified, and his recommendation that the company include

cash contributions to its pension plan in 2018 and 2019. To calculate adjusted net

operating income, Mr. Coppola also recommended that the Commission use a higher

forecast for gas sales and transportation deliveries than recommended by the company,

concluding that the company’s projected decline in deliveries are understated, with Mr.

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Coppola’s revised calculation resulting in an increase in the revenue and operating

income for the test year by $14.3 million.

He further recommended use of an alternative capital structure based on 50% debt

and 50% equity, and an authorized return on equity of 9.50%. 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 the utility’s

proposed expansion of its IRM to include additional capital expenditure programs. And,

he recommended that the Commission instruct Staff to begin collaborative effort among

interested parties to design a transportation daily balancing program.

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, Incorporated.61 He

addressed the company’s two class cost-of-service studies, class revenue allocation, and

the design of the transportation service rate. Regarding the class cost-of-service studies,

Mr. Pollock identified three material flaws: (i) the average and peak (A&P) method is

flawed because it uses January gas throughput instead of a peak demand metric, such

as peak day design (PDD), as shown in Exhibits AB-1 and AB-2, to allocate the vast

majority of transmission and distribution plant-related costs; (ii) distribution mains costs

are improperly classified entirely as demand and commodity-related costs without

recognizing a customer-related portion as ABATE proposes to do with the application of

the “predominant size” method, as shown in Exhibit AB-3; and (iii) the company’s

61 Mr. Pollock’s testimony is transcribed at 7 Tr 2262-2296 and his qualifications are transcribed at 7 Tr 2297-2316.

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proposed allocation of storage plant uses an arbitrary 50%/50% split between storage

utilization and January throughput, rather than using a PDD method, and the allocation

assumes without supporting data that transportation customers use storage to the same

degree as sales customers during withdrawal season. Mr. Pollock also presented a

revised class cost-of-service study, as shown in Exhibit AB-4, to incorporate his

recommendations to spread any revenue increase between the gas sales and

transportation rate groups, and apply gradualism to determine the increases to specific

rate classes within each group. He also presented a revised class revenue allocation, as

shown in Exhibit AB-5, with revised RIA/LIA credits spread to classes based on the

revenue requirements derived from his revised class cost-of-service study.

Regarding the company’s proposed design of the transportation service rate, Mr.

Pollock recommended that the Commission adopt the company’s 4% ATL for not only

Rate XXLT customers but for all transportation service rate customers.

Ms. LaConte is an energy advisor and Associate Consultant for Mr. Pollock’s

firm.62 In her testimony, Ms. LaConte discussed the necessary guidelines used to

determine a fair rate of return on equity. She also reviewed the company’s return on

equity and critiqued Mr. Maddipati’s analysis, including the selection of his proxy group,

and the methods and inputs he applied to the models he used. She also explained why

Mr. Maddipati’s use of a flotation cost adjustment in his ROE estimates is unwarranted.

She testified that, based on her findings, and relying on the national average authorized

return on equity for 2017 of 9.72%, the company’s return on equity of 10.5% overstates

62 Ms. LaConte’s testimony, including her rebuttal and cross-examination, is transcribed at 7 Tr 2157-2260.

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the revenue deficiency and would result in residential customers paying an additional

$12.33 per customer per year. Ms. LaConte also reviewed Mr. Denato’s testimony

regarding the company’s proposed capital structure for use in ratemaking, and

recommended that the Commission lower the company’s proposed common equity ratio

by 100 basis points to 51.49%. She testified that doing so would move the company

closer to its goal of a 50/50 debt-to-equity ratio, as required by the Commission in its order

in Case No. U-18124, and would lower the equity by $128 million and increase the amount

of long-term debt by the same amount, resulting in a decrease in the revenue requirement

of $4.8 million. Ms. LaConte presented Exhibits AB-6 through AB-14 in support of her

testimony. She also provided rebuttal testimony and was cross-examined.

E. RESA

The RESA presented the testimony of two witnesses. Matthew White, general

counsel with Interstate Gas Supply, Inc., testified regarding the company’s “Prominent

Bill Display” box included on its utility consolidated bills of alternative gas supply

customers.63 He recommended that the Commission adopt a tariff amendment

prohibiting the text box as anti-competitive. Alternatively, if the Commission supports the

inclusion of bill messages encouraging customers to explore their pricing options, he

recommended that any price comparisons be excluded from the message and instead

include on both gas cost recovery and gas customer choice customers’ bills guidance on

the location of the MPSC choice webpage.

John Mehling, a senior regional operations manager with Direct Energy Business,

63 Mr. White’s testimony is transcribed at 5 Tr 1553-1562.

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testified to recommend a change in the company’s operational tariff rules to allow

transport end-users to be combined into groups or pools under each supplier’s

discretion.64 Known as “pooling”, Mr. Mehling described the industry practice as the

grouping of transportation service customers that are all being supplied by the same

supplier. He explained the benefits of pooling to transportation customers as including

reduced costs and imbalance fees, expanded flexibility, and increased supplier options.

He testified that pooling should not impact other non-pooling customers or adversely

impact system reliability. He described the benefits of pooling to the utility as including

reduced administrative costs and simplified tracking of imbalance nominations. He also

testified that the practice would not require significant restructuring of transportation

contract terms and conditions. He provided specific tariff recommendations that would

allow for a pooling option for gas transportation customers. Mr. Mehling also

recommended that the Commission reject Ms. Curtis’s suggestion that the company

reduce the ATL to 4% as an alternative to implementing daily balancing, testifying that

there is no evidence that the existing ATLs are ineffective at ensuring that sufficient

quantities of gas are delivered to meet customer usage. His testimony is supported by

Exhibits RES-2 and RES-3.

F. RCG

The RCG presented the testimony of William 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.65 Mr. Peloquin testified to address the affect of

64 Mr. Mehling’s testimony, including his surrebuttal, is transcribed at 5 Tr 1563-1589.65 Mr. Peloquin’s testimony is transcribed at 7 Tr 2643-2653.

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the Tax Cut and Jobs Act of 2017 (TCJA) on the company’s filing. He testified that the

company’s federal income tax (FIT) expense and FIT tax rate should be coordinated with

the company’s revenue reduction case, the first of three case segments to be addressed

in Case No. U-18494, initiated to address the ratemaking effects of the TCJA. His three-

fold recommendation is as follows: (i) the FIT expense should be based on the 21% FIT

tax rate; (ii) the revenue multiplier should be based on the 21% FIT tax rate; and (iii) the

July 1, 2018 revenue reductions should be recognized in this rate case as well.

G. Rebuttal

Three parties presented rebuttal testimony, with RESA and Consumers Energy

presenting additional testimony in the nature of surrebuttal and sur-surrebuttal,

respectively. Consumers Energy witnesses provided rebuttal testimony addressing the

rate base, rate of return, adjusted net operating income, cost allocations, and rate design.

Ms. Delacy’s rebuttal testimony addressed concerns raised by Ms. Fromm and Mr.

Coppola regarding the company’s investments in AMR for gas-only customers and

projections of test year meter reading program expenses.

Mr. Kops’ rebuttal testimony addressed the adjustments recommended by Mr.

Nichols and Mr. Coppola to the company’s proposed pension and OPEB expenses, as

well as rate of return expense adjustments to pension and OPEM and pension plan

contribution recommendations made by Mr. Coppola. Mr. Kops agreed with their

recommendations that the total benefits test year expense should be reduced based upon

the December 31, 2017 pension and OPEB plan actuarial measurements, as shown in

Exhibit A-105. However, Mr. Kops disagreed with Mr. Coppola’s proposed reliance on

the 2017 rate of return on plan assets assumption of 7.0% and his proposal that the

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company be required to contribute $100 million in annual pension contributions in 2018

and 2019.

Mr. Coker’s rebuttal testimony addressed the revenue requirement adjustments

recommended by Mr. Nichols and Mr. Coppola, contending that Staff’s proposed rate

base adjustments in support of a revenue sufficiency are incorrect and contain errors and

Mr. Coppola’s proposed adjustments in support of a $54.9 million revenue deficiency

should be rejected. Mr. Coker also addressed Mr. Peloquin’s calculations of the impact

of the FTJA on the revenue requirement, contending that his calculation contained errors

as it does not correctly reflect the federal income tax expense reduction and includes

unnecessary add backs to the revenue deficiency. Mr. Coker also presented an adjusted

revenue deficiency of $82.775 million, as shown in Exhibit A-80, based on a number of

adjustments in response to Staff’s direct case.

Ms. Pelmear presented rebuttal testimony addressing Mr. Isakson’s concerns with

the company’s other gas in kind (GIK) volume forecast methodology. Disagreeing with

his assertion that the company’s as-filed other GIK test year projection did not adhere to

the five-year historical average approved by the Commission in Case No. U-18124, Ms.

Pelmear presented both the original as-filed projection and a revised five-year average

calculation based on a revised June 2017 actual value, as shown in Exhibit A-126.

Mr. Fultz’s rebuttal testimony addressed the disallowances of contingency

expenditures from the company’s capital expenditures projections recommended by Ms.

Fromm, Mr. Frazier, and Mr. Coppola, as well as recommended adjustments proposed

by Mr. Coppola, Ms. Creisher, Ms. Fromm, and Mr. Spence to the company’s projections

for the Mid-Michigan Pipeline Project, Freedom Compressor Upgrade Project, and St.

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Clair Compressor Upgrade Project. Responding to Ms. Fromm’s testimony that

contingency expenditures cannot be judged for reasonableness or prudence, Mr. Fultz

asserted that such expenses are a “very real, reasonable, expected and forecastable cost

of a project” and “a widely accepted industry practice.” Mr. Fultz also took issue with Mr.

Frazier’s exclusion of contingency from IT capital expenditures without explanation, as

well as Mr. Coppola’s rationale for his proposed contingency disallowances that inclusion

of them in rate base is “neither fair nor reasonable because the amount planned for

contingency may not be spent.” Regarding concerns raised by Ms. Creisher and Mr.

Coppola that the company lacks an Act 9 certificate of necessity for the Mid-Michigan

Pipeline Project, Mr. Fultz stated that such a certificate is not necessary as all costs are

directly attributable to preparing the Act 9 filing. Regarding Mr. Coppola’s concerns that

Phase 2 the Freedom Compressor Upgrade Project has not yet been approved by the

Board of Directors, Mr. Fultz testified that the Board has already approved Phase 1 and

the total projected expenditures for both phases was included in the company’s

infrastructure planning. Regarding Mr. Spence’s proposed disallowance of contingency

costs from the St. Clair Upgrade Project, Mr. Fultz testified that the project is nearing

completion and the remaining project costs thus reflect the actual project costs. Mr. Fultz

testified that the company did agree, however, with Mr. Spence’s recommended exclusion

of $0.45 million related to an August 24, 2017 fire incident. Finally, as shown in Exhibits

A-96 and A-97, Mr. Fultz presented several cost adjustments decreasing the amount of

the capital expenditures originally filed by the company for Line 100A, Line 2800, the St.

Clair Compressor Upgrade Project, and the Freedom Compressor Project – and resulting

in a decrease in the company’s recovery request of $9.283 million.

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Ms. Rayl presented rebuttal testimony addressing rate design changes proposed

by Staff, the Attorney General, ABATE, and RESA. Responding to Staff, Ms. Rayl

testified that she agreed with Mr. Gottschalt’s and Ms. Creisher’s rate design

recommendations as consistent with the methodology proposed by the company but

noted that because Staff’s proposed rates are based on Staff’s different revenue and cost

allocation recommendations, the final rates will require adjustment to reflect approved

revenue requirements and minimize any rate shock. Ms. Rayl disagreed, however, with

Mr. Coppola’s recommendation that the residential customer charge remain at its present

charge or increase by no more than $1, testifying that Mr. Coppola’s proposal is not based

on any cost study. Responding to Mr. Pollock, Ms. Rayl testified she disagreed with his

proposed rates based on ABATE’s proposed rate design revenue and cost allocations

but does agree with Mr. Pollock’s position (shared by Staff) that the 4% ATL option should

apply to all transportation customers. Consequently, Ms. Rayl disagreed with Mr.

Mehling’s position that the 4% ATL option should be rejected, stating that the company

does not believe the proposal is harmful to customers.

Mr. Keaton presented rebuttal testimony disagreeing with Mr. Coppola’s proposal

to exclude the energy efficiency savings adjustment from the forecasted deliveries

forecast, as well as with Mr. Coppola’s 12 months ended June 2019 gas deliveries

forecast. Regarding the former, Mr. Keaton testified that the annual incremental energy

efficiency savings target was prescribed under Public Act 295 of 2008 and approved by

the Commission in the company’s energy efficiency plans and recommendations.

Regarding the latter, Mr. Keaton testified that Mr. Coppola’s forecast is an historical look

at sales trends which, unlike the regression model results relied upon by the company

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that incorporate forecasted economic conditions and energy efficiency savings, is not the

most accurate basis for a sales forecast.

Mr. Torrey’s rebuttal testimony addressed recommendations made by Staff

witnesses, Ms. Creisher, Mr. Miller, Mr. Frazier, and Ms. Fromm, and by the Attorney

General. Mr. Torrey agreed with Ms. Creisher’s adjustments to the company’s IRM

proposal – specifically, excluding the TED-I projects, continuing a spending flexibility cap

of 3.2%, and maintaining EIRP spending of at least $75 million. Mr. Torrey disagreed

with Mr. Coppola’s recommendations regarding the company’s IRM proposal, including

his characterization of the IRM as an automatic recovery of costs, his opinion that the

company’s increase in capital expenditures has increased to unaffordable levels the rates

of many customers, and his criticism of the company’s level of capital expenditures

revealing a lack of financial discipline and budget control.

Regarding Mr. Miller’s recommendation that the Commission deny capitalization

of all remediation dig costs that Staff identified to in fact be maintenance expenses, Mr.

Torrey testified that Mr. Miller’s proposal fails to recognize that the company reasonably

incurred such costs undertaken to comply with federal requirements. In response to the

proposed disallowances to past investments related to IT projects, historical AMR costs,

and historical capital spending for the Well Rehabilitation Program, as recommended by

Mr. Frazier, Ms. Fromm, and Mr. Coppola, Mr. Torrey testified that such disallowances, if

granted, “will lower net income in the year of the disallowance by an equal amount and

will prevent the company from recovery of dollars actually invested for assets being used

to serve the customers.” He explained how these investments were made to the clear

benefit of customers and the impact of the disallowances would be to discourage the

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company from making real time business decisions and investments to benefit the

customer for fear of future disallowance of assets already invested in.

Ms. Conrad’s rebuttal testimony addressed the recommendations of Mr. Welke

and Mr. Coppola to exclude the company’s projected incentive compensation costs from

the revenue requirement in this case. She objected to Mr. Welke’s proposal to exclude

the half of the non-officer EICP expense tied to financial measures, and to exclude the

non-proxy officer EIC expense. In doing so, Ms. Conrad contended that financial

measures do benefit customers because having a financially healthy utility allows the

utility to better meet customer needs at the best price. She further testified that, should

the Commission disagree that 100% recovery from customers of the portion of the EICP

costs that relate to financial measures is appropriate, a 50/50 sharing of the portion of

EICP costs that relate to financial measures should be adopted instead.

Ms. Conrad also disputed Mr. Coppola’s characterizations that: the company’s

proposed $1.8 million of short-term incentive compensation is a “bonus”; that

shareholders and not customers benefit from the short-term incentive compensation; and

that it is difficult to justify such compensation increases against the backdrop of

Michigan’s median household income.

Ms. Hill’s rebuttal testimony addresses the recommended disallowances made by

Ms. Creisher, Ms. Fromm, and Mr. Coppola. Regarding Ms. Creisher’s recommendation

that the projected test year base O&M levels for gas compression, storage, and gas

management services expenses be adjusted based on 2017 actual base O&M expense

levels not available at the time of the company’s filing, Ms. Hill testified that Ms. Creisher’s

recalculation incorrectly identifies two of the three components that comprise total base

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O&M, resulting in an incorrect and insubstantial variance amount. Ms. Hall also disagreed

with Ms. Creisher’s recommended use of inflation factors for the projected test year as

being without support and not based on the needs of the business. Ms. Hall further

disagreed with Ms. Fromm’s recommended disallowance of all contingency expenditures,

as addressed by Mr. Fultz. Regarding Mr. Coppola’s recommended capital expenditure

disallowances of $2.7 million and $1.9 million from the 2017 forecast and 2018 projections

for the Muskegon River Compression project, Ms. Hill testified that his proposal is based

on an incorrect assumption of the 2017 actual expenditures. As for Mr. Coppola’s

recommendation to remove all capital expenditures for the Overisel Compression project,

Ms. Hill finds error with his reliance on a discovery response from the company and an

invalid assumption made by Mr. Coppola based on that response which renders his

analysis of 2017 actual costs irrelevant. As for Mr. Coppola’s recommendation to disallow

$41.2 million of capital expenditures for well rehabilitation, Ms. Hill rejected his assertion

that there has been a lack of evidence and supporting justification for the program,

testifying that the program is in response to safety standards under the PIPES Act of 2016

and American Petroleum Institute standard, API RP 1171, and the Commission approved

recovery of the program funding in Case No. U-18124.

Mr. Shirkey’s rebuttal testimony addressed each of Mr. Coppola’s criticisms in

support of his recommendation that $1.8 million of EICP costs included in the company’s

test year should be disallowed. Mr. Shirkey outlined support for his position that the

customer benefits from the annual incentive compensation exceed the cost to customers,

and that the EICP provides both qualitative and quantitative benefits to customers, while

acknowledging however that the latter benefits are not easy to specifically quantify. He

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also explained his disagreement with Mr. Coppola’s assertions that the meter read rate

and billing accuracy measures are easily achievable and thus should not be included as

EICP performance measures. And he explained his disagreement with Mr. Coppola’s

conclusions regarding the appropriateness of including the regulatory environment

measure and competitive price measure as qualitative benefit measures, as well as Mr.

Coppola’s claim that the new measures are duplicative and not likely to drive higher

operating performance or any visible and critical improvements for customers.

Mr. Harry’s rebuttal testimony addresses Staff’s concerns related to the company’s

proposed deferral and amortization of MGP remediation costs and the company’s

treatment of the injuries and damages expense and treatment of historical capital

spending on the company’s gas AMR program as a deferred debit. Regarding Ms.

Edelyn’s position related to MGP costs, Mr. Harry agreed with her that only incurred,

reviewed, and approved MCP remediation expenses should be included in the deferred

MGP balance and amortized for ratemaking. In response to Staff’s proposed exclusion

of $30.383 million of deferred unamortized MCP costs from rate base, however, Mr. Harry

expressed concern with the regulatory lag this would create. He instead proposed that,

to the extent 2017 MGP invoices can be made available for Staff’s review, this case

include actual expenditures incurred, reviewed, and approved through December 31,

2017 or, alternatively, that actual 2017 expenditures be included, as shown in Exhibit A-

98. Regarding Mr. Welke’s proposed reduction to injuries and damages expense of

$1.645 million, which exceeds the company’s projected amount of $1.618 million, Mr.

Harry testified that Mr. Welke’s reliance on inputs unrelated to the Corporate projection

of injuries and damages in this case is inappropriate because it uses data unrelated to

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the company’s injuries and damages exhibit (Exhibit A-33) to produce a negative

expense. Mr. Harry also disagreed with Mr. Nichols’ proposal that, should the

Commission decide that historical AMR costs not be recovered in current rates but directs

the company to resubmit those costs with additional evidentiary support for potential

allowance in a subsequent rate case, the company be permitted to record those costs as

a deferred debit. Mr. Harry explained that, under generally accepted accounting

principles (GAAP), Staff’s proposal would not prevent the costs from being immediately

expensed or written off because eligibility for deferral requires a finding that it is probable

the cost will be recovered through future revenue from rates and an order allowing deferral

of historical AMR costs is not sufficient on its own to establish this probability. Finally, Mr.

Harry acknowledged Mr. Isakson’s testimony that the Commission had directed the

company, in Case No. U-18124, to begin recording uncollectible expenses by class so

that net write-offs by class can be calculated but that the company lacked sufficient time

between rate case filings to develop a net write-offs allocation schedule. Mr. Harry

indicated that the estimated completion date for that report is April-May 2018.

Mr. Saez’s rebuttal testimony addressed concerns raised by ABATE, Staff, and the

Attorney General regarding the cost-of-service study. With respect to ABATE, Mr. Saez

agreed with Mr. Pollock’s recommendation that the peak design day (PDD) demand, and

not the peak month throughput be used as the peak metric in applying the average and

peak (A&P) methodology when allocating the demand-related costs of transmission and

distribution. His calculation of the updated PDD values is set forth in Table 1 at page 2

of his rebuttal testimony. Mr. Saez also agreed with Mr. Pollock’s use of PDD in lieu of

peak month within the storage allocation calculation, but disagreed as to the necessity of

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the company conducting a detailed storage usage study in this case, or as to the adoption

of Mr. Pollock’s proposed allocation of distribution mains.

Regarding Staff’s recommendations, Mr. Saez agreed with Mr. Isakson that

appliance service plan expenses should be excluded from the customer charge

calculation and addressed his concern regarding the difference between the PDD and the

historic peak in the last 15 years. As for the Attorney General, Mr. Saez disagreed with

Mr. Coppola that there is any contradiction in the amount of the revenue requirement

identified by Ms. Curtis and the amounts presented by Mr. Saez, noting that Mr. Coppola’s

calculations only included storage related cost items from the COSS, which are not all

costs incurred to provide storage services to transportation customers. Finally, Mr. Saez

presented an additional COSS analysis, as shown in Exhibit A-129, to reflect an update

of the ODD value to 3,173 MMcf and to assign an 8.5% authorized tolerance level to the

XXLT rate.

Ms. Miles’ rebuttal testimony addressed the recommendations made by RESA and

Staff. She refuted Mr. White’s concerns that the gas customer choice (GCC) bill text box

is “anti-competitive” and rejected his suggestion that certain GCC information be included

on gas cost recovery (GCR) customer bills as tantamount to requiring the company to

market for the GCC program or for AGSs who participate in the program. Ms. Miles also

disagreed with his proposed tariff changes requiring the company to “refrain from making

any false, deceptive or misleading price comparison between the Supplier-designated

price and the Company’s GCR factor.” As for Staff, Ms. Miles agreed with Mr.

Gottschalk’s recommendation that the excess peak demand charge be moved from the

“customer charge” to the “distribution charge” section on the tariff sheet since it is

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demand-related and assessed on a per Mcf basis.

Mr. Varvatos presented rebuttal testimony to address Staff’s and Attorney

General’s recommendations regarding IT spending adjustments. He disagreed with Mr.

Frazier’s recommendation to disallow DCE Website capital expenditures, testifying that

that it is based on uniformed estimates that overlooked several factors, and reverses the

approval the company received from Staff (Ms. Fromm) in Case No. U-18124 to recover

DCE Website project expenditures. He also objected to Frazier’s recommendation to

disallow Field Service Solution projects capital expenditures, testifying that, while Mr.

Frazier observed that the company did not provide adequate information on efficiency

improvements to justify the expense, the company has since provided Staff with additional

benefits information regarding these projects. Mr. Varvatos further noted that Mr.

Frazier’s proposed disallowance reverses the approval the company received from Staff

(Ms. Fromm) in Case No. U-18124 to recover Field Service Solution project expenditures.

He also rejected Mr. Frazier’s recommended reduction of 6% to the overall requested

recovery for IT projects, testifying that the company did not recover $6.2 million in capital

expenditures in Case No. U-18124 for projects and functionality that were never

implemented because the funds for approved projects with no capital spend helped to

offset the collective over-spend on the other approved projects. Mr. Varvatos further

disagreed with Mr. Frazier’s contentions that: (i) the company’s administrative procedures

are lacking attention to detail with regard to project approvals and accounting; (ii) the

company requires a directive from the Commission to explicitly track project expenditures

per internal-use software rules; and (iii) recovery of future projects should be postponed

until the utility has evaluated any available cloud-based options to determine they are

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more cost-effective.

Responding to the Attorney General, Mr. Varvatos rejected Mr. Coppola’s

assertion that the company has yet to define how or when to proceed with the gas code

compliance program GCCP compliance scheduling phase 3 and phase 4 projects.

However, he agreed with Mr. Coppola’s proposed removal of $4.5 million in 2018 and $1

million in 2019 for the phase 3 and phase 4 projects, respectively, but not because the

company lacked a clear plan, as maintained by Mr. Coppola, but because of a shift in

focus on completion of other concurrent gas projects. Mr. Varvatos also agreed with Mr.

Coppola’s proposed removal of capital expenditures from 2017 for the gas control solution

funding but only for removal of $653,000, not $1.0 million as recommended by Mr.

Coppola. And Mr. Varvatos addressed concerns raised by Mr. Coppola related to the

company’s current backup recovery center.

Mr. Maddipati’s rebuttal testimony took issue with the recommendations of the

other return on equity witnesses, Mr. Megginson, Mr. Coppola, and Ms. LaConte. He

contended they had ignored both the impacts of recent federal tax reform legislation and

legal standards for setting rates of return. Mr. Maddipati further maintained that they had

not consulted with the investment community, and had not used the same models, inputs,

and assumptions he used in formulating their recommendations, thus resulting in flawed

quantitative analyses.

Ms. Youngdahl’s rebuttal testimony addressed concerns raised by Staff and the

Attorney General regarding proposed O&M expenses related to the company’s marketing

and strategy department and with credit card processing fees and ASP margin

contribution, respectively. Disagreeing with Ms. Fromm’s assertion that the company

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failed to identify areas of improvement as a result of additional spending in marketing and

strategy, Ms. Youngdahl rejected Ms. Fromm’s proposed disallowance of $3,950,600 for

this program. Turning to Mr. Coppola’s recommended disallowance of $4,600,000 for

credit card processing fees, Ms. Youngdahl rejected his proposal, testifying that it is

based on general and broad assumptions about credit card companies assuming the risk

of bad debt, as well as an unestablished correlation between credit card transactions and

reduced bad debt expense.

Ms. Curtis’s rebuttal testimony addressed concerns raised by the Attorney General

and RESA regarding daily balancing for transportation customers and a polling option

proposal for suppliers to transportation customers, respectively. She disagreed with Mr.

Coppola’s assertion that there are inequities caused by the current end use transportation

(EUT) program on the GCR cost of gas due to the monthly balancing for transportation

customers. She also rejected his recommendation that the Commission require an

organized collaborative to establish a daily balancing program for the company, testifying

that Mr. Coppola has not shown that daily balancing for EUT customers is necessary and

no EUT customers have requested the company move to daily balancing. Turning to

RESA, Ms. Curtis disagreed with Mr. Mehling’s proposal that pooling should be adopted,

testifying that his proposal lacks specifics and leaves too many questions unresolved,

and Mr. Mehling has failed to identify the problem he is trying to solve through his pooling

proposal.

Ms. Palkovich presented rebuttal testimony addressing the capital expenditure and

O&M expense disallowances and the IRM and EIRP changes recommended by Ms.

Creisher, Mr. Spence, Ms. Fromm, and Mr. Miller on behalf of Staff, as well as Mr.

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Coppola’s recommended capital expenditure disallowances on behalf of the Attorney

General. She disagreed with Ms. Creisher’s proposed use of the 2017 preliminary actual

O&M amounts for the gas division as a basis for inflating the expenses to the test year.

She also disagreed with Ms. Creisher’s assessment and proposed reductions related to

pipeline integrity O&M expenses, but did agree with Ms. Creisher’s proposed removal of

O&M expenses and capital expenditures related to projects involving the company’s

proposed use of hydrostatic pressure testing on Lines 1070, 1020, and 1600 and

proposed replacement of pipe and fittings for Lines 3070 and the Lahser Lateral. Ms.

Palkovich further disagreed with Ms. Creisher’s removal of pipeline integrity capital

expenditures related to moderate consequence area (MCA) and non-HCA expenditures

due to the incomplete federal rulemaking process incorporating these rule changes.

Turning to material condition no-modeled program capital expenditures, Ms.

Palkovich disagreed with Ms. Creisher’s assessment and proposal that the company rely

on its 2016 actuals, adjusted for inflation, for the program, as opposed to the company’s

2017 actual amounts. She also rejected Ms. Creisher’s determination related to the unit

counts projected by the company for the service renewals program, testifying that the

increases in below-grade leaks support the increased expenditures in the program.

However, Ms. Palkovich agreed to further EIRP reporting requirements related to service

line replacements as proposed by Ms. Creisher, provided the company is able to upgrade

its current reporting system in advance of the April 2019 performance report filing.

Turning to TED-I capital expenditures, Ms. Palkovich agreed with Ms. Creisher’s

recommended disallowance of all but engineering costs for the city gate projects

associated with the Mid-Michigan Pipeline project given the absence of a certification of

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convenience and necessity. However, she rejected her claim that the company had not

presented adequate support for the pressure limiting device (PLD) projects to justify the

cost being borne by ratepayers. Ms. Palkovich testified that she is not opposed to Ms.

Creisher’s proposed inclusion of the vintage service replacement (VSR) program in the

IRM but maintains the company’s position that the program include a projected 10-year

time frame, not a 20-year time frame as recommended by Ms. Creisher.

Turning to Mr. Spence’s recommended removal of expenditures related to two

large new business projects for which the company still lacks executed contracts, Ms.

Palkovich agreed in part as to the large agri-business customer but disagreed as to the

Lansing Board of Water and Light project, testifying that the company expects to have a

contract in place with the LBWL sometime this year. Ms. Palkovich further disagreed with

Ms. Fromm’s recommended disallowances related to projected expenditures for meter

reading handheld devices, testifying that the handhelds produce a benefit to customers.

Regarding Mr. Miller’s concerns related to the pipeline integrity transmission program and

what he determined to be an excessive number of remediations on pipelines in excess of

50 feet, Ms. Palkovich proposes that Staff and the company convene a technical

conference to align on best pipeline integrity practices but she disputed the assertion the

company was using the 50’ capitalization rule to overtly overspend to increase earnings.

She also rejected the notion that the company has not been forthcoming in providing

reports to Staff and she claimed Mr. Miller’s proposed disallowance of historical capital

spending is “extreme and without warrant.” Ms. Palkovich further disagreed with Mr.

Miller’s determination that several of the remediation digs undertaken by the company

should have been maintenance expenses, testifying that “[i]n the interest of public safety,

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it is reasonable to replace at-risk pipe of any length.” Responding to Mr. Miller’s

recommended reduction of the company’s test year pipeline integrity capital expenditures

and increase of the company’s O&M expenses, Ms. Palkovich testified that any changes

by the Commission to the program expenditures should only be made to future periods

because the company could not have reasonably evaluated its practices in 2016 and

2017. She also agreed to Mr. Miller’s recommended reporting requirements but

contended the elements of these requirements should be agreed upon at the proposed

technical conference.

Turning to Mr. Coppola’s recommendations, Ms. Palkovich disagreed with his

analyses and corresponding reductions related to the Mains, Services and Meter Stands

New Business program, Customer Attachment program, MAOP Compliance program,

MC program, Capacity Deliverability program, and the company’s Distribution Regulator

Stations. She also rejected his contention that the company is proposing to expand the

IRM, testifying that the proposed IRM is consistent with the IRM proposed by the company

and approved by the Commission in Case No. U-18124 but with higher amounts to reflect

increased investments for safety, integrity, and reliability.

Mr. Denato’s rebuttal testimony addressed the recommendations of Staff, the

Attorney General, ABATE, and the RCG. Regarding Mr. Megginson’s projected common

equity balance of $6,665,841.999, Mr. Denato testified it was understated as failing to

recognize the company’s planned equity infusion of $100 million in January 2019 and the

impacts of the TCJA. However, Mr. Denato accepted Mr. Megginson’s recommended

cost of long-term debt of 4.57% and use of a 90-basis point spread as being based on

the most recent bond issuance data. Turning to Mr. Coppola’s recommended increase

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in long-term debt by $322 million and decrease in common equity by the same amount,

Mr. Denato testified that these adjustments are “excessive, arbitrary, and lacking any

sound financial reasoning.” He further disagreed with Mr. Coppola’s proposed $21.9

million reduction to working capital to reflect a lower cash balance level, testifying that the

company’s cash balance level is based on the historical average of actual cash balances,

reflects the importance of having adequate liquidity on hand for utility operations that is

comprised of approximately 2% of revenues, and consistent with prior Commission

orders. Mr. Denato also rejected Ms. Laconte’s recommended lower common equity

ratio, testifying that it is lacking in details and analysis to support her determination that

the company would maintain its current credit ratings with a lower equity ratio. For similar

reasons, Mr. Denato rejected Mr. Peloquin’s recommended 50% equity ratio, testifying

that it would have harmful implications on the company’s credit strength, cost of

borrowing, and ultimately the customer. Finally, Mr. Denato explained his disagreement

with Mr. Welke’s observation that the company “has been unwilling to share the benefits

of the achievement of financial measures with ratepayers on a projected basis” and with

Mr. Miller’s observation that the company’s 50-foot capitalization policy allows for the

company to be “incentivized to maximize capital expenses and minimize maintenance

expenses.”

Staff presented the rebuttal testimony of two witnesses, David Isakson and

Heather Cantin. Mr. Isakson’s rebuttal testimony addressed the recommendations made

by ABATE witness Mr. Pollock, RESA witness Mr. Mehling, and the Attorney General’s

witness Mr. Coppola. Addressing Mr. Pollock’s testimony, Mr. Isakson explained the

bases for his disagreement with: ABATE’s proposed methodology for determining peak

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day for use in cost allocation; proposed classification of a portion of distribution mains as

customer-related; the appropriateness of using the “predominant size” classification

method; and ABATE’s general opposition to the company’s allocation of storage costs.

Turning to Mr. Mehling’s testimony, Mr. Isakson disagreed with his assertion that

“[p]ooling should not impact other, non-pooling customers in any way” but further opined

that the rate impact on other customers from pooling is not a basis to deny RESA’s

recommendation that the Commission permit pooling. He explained that, “[a]ll else held

equal, and assuming a competent pool administrator, the total system balance with and

without pooling will remain unchanged.” Mr. Isakson also responded to Mr. Coppola’s

recommendation regarding convening a collaborative to develop a workable daily

balancing program for EUT customers, testifying that such a collaborative presumes that

daily balancing is a necessary and worthwhile endeavor and the company’s study

demonstrates otherwise.

Ms. Cantin presented rebuttal testimony to address the proposals of RESA witness

Mr. White related to the “prominent bill display box” included on the company’s GCC

residential and small commercial bills. Ms. Cantin testified that Staff maintains the same

position it posited in response to RESA’s same proposal in Case No. U-17882, which is

that the information included in the company’s prominent bill display box, comparing the

GCC customer’s contracted rate with their chosen AGS to that month’s GCR factor, is

accurate and neutral, available to customers in other places outside of the display box,

and does not explicitly favor the GCR price. Ms. Cantin nonetheless recommends the

company adopt minor modifications to the language in the display box to provide

additional transparency.

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ABATE presented the rebuttal testimony of Ms. Laconte. In her rebuttal testimony,

Ms. LaConte took issue with Staff’s recommended return on equity as presented by Mr.

Megginson and with the Attorney General’s recommended return on equity as presented

by Mr. Coppola. Ms. LaConte testified that neither Mr. Megginson’s recommended 9.60%

ROE nor Mr. Coppola’s recommended 9.50% ROE is supported by their analyses, which

show estimated, average ROEs of 8.41% and 9.50%, respectively. Consequently, she

maintained, the recommendations of Staff and the Attorney General unnecessarily add

$44 million and $15.6 million, respectively, to the company’s revenue requirement.

As noted above, the parties agreed that Mr. Mehling could present surrebuttal

testimony in response to Ms. Curtis’s rebuttal testimony, and that Ms. Curtis could in turn

present sur-surrebuttal testimony. In his surrebuttal testimony, Mr. Mehling responded to

Ms. Curtis’s criticisms of his proposal that the Commission direct the company to change

its operational tariff rules to allow transportation end-users to be combined into groups or

pools under each supplier’s discretion.

Ms. Curtis presented sur-surrebuttal testimony to respond to Mr. Mehling’s

assertion that the company’s absence of pooling imposes unnecessary burdens and

inefficiencies on gas suppliers, testifying that gas suppliers are not customers of the

company to whom the company has any obligation. She further testified that Mr. Mehling

has failed to indicate how the establishment of pooling would provide efficiencies or other

benefits to the company’s gas transportation customers. She also expressed concern

that his pooling proposal “is not about creating more efficiencies for suppliers, but about

putting storage assets under the control of suppliers who are not subject to Commission

oversight.”

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III.

TEST YEAR

In every general rate case, the initial task is the selection of an appropriate test

year which, as the Commission has observed, is the starting point for establishing just

and reasonable rates for both the regulated utility and its customers.66 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.67

In this proceeding, Consumers Energy proposed using the 12-month period ending

June 30, 2019 as the projected test year and 2016 as the historical year.68

No party has objected to the Company’s proposed test year and historical year.

This PFD therefore recommends that the Commission adopt the 12-month period

ending June 30, 2019 as the projected test year and 2016 as the historical year.

IV.

RATE BASE

The rate base for a gas utility like Consumers Energy consists of total utility plant

(i.e. the capital invested in all plant in service, plant held for future use, and construction

work in progress [CWIP], if any), less the company’s depreciation reserve (consisting of

66 MPSC Case No. U-15986, May 17, 2010 Order, p. 3.67 MPSC Case Nos. U-15768 and U-15751, January 11, 2010 Order, p. 9.68 Consumers Energy’s Application, p. 2; 2 TR 178, 519.

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its accumulated depreciation, amortization, and depletion), plus the utility’s working

capital requirements.69

Here, in its application, Consumers Energy projected a total jurisdictional gas rate

base of $5,468,042,000 for the projected test year, consisting of $4,762,584,000 in net

utility plant, $656,995,000 in working capital, and $51,978,000 in net unamortized

Manufactured Gas Plant (MGP).70 In its initial brief, the Company has reduced the net

utility plant amount by $30,197,000 for a test year utility plant amount of $4,732,387,000

and a revised rate base of $5,437,581,000.71

Staff projects for the Company a rate base of $5,133,487,000 for the test year,

which is approximately $304,094,000 lower than the utility’s above-stated figure.72 This

decrease is derived from Staff’s proposed reductions in the net utility plant and net

unamortized MGP of $279,120,000 and $24,974,000, respectively.73 In contrast, the

Attorney General seeks to reduce the Company’s capital expenditures by $335.2 million

and its working capital by $8.9 million, for a related reduction in the rate base of $231

million for its proposed test year.74

Through both testimony and briefs, the parties have raised several specific

concerns regarding various areas of the Company’s rate base proposal. The components

69 MPSC Case No. U-17735, November 19, 2015 Order, p. 7.70 Consumers Energy’s Initial Brief, Appendix B, p. 1.71 Id.72 Staff’s Initial Brief, Appendix A.73 Staff’s Initial Brief, Appendix B.74 Attorney General’s Initial Brief, pp 58-59; Exhibit AG-40.

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of the rate base projected by the Company, as well as the concerns raised by the parties,

are addressed below in the discussion of net utility plant and working capital.

A. Net Utility Plant

In their respective testimony and briefs, Staff and the Attorney General have

identified concerns regarding the Company’s proposed capital expenditures in the

following areas: (1) gas transmission and distribution; (2) gas compression and storage;

(3) information technology; and (4) gas AMI. And both Staff and the Attorney General

seek an adjustment to remove all contingency costs associated with the Company’s

proposed capital expenditures. Each disputed projection is discussed below in section

IV.A.1. through IV.A.5.

1. Gas Transmission And Distribution Capital Expenditures

Ms. Palkovich testified for the Company regarding its request for rate recognition

of capital expenditures for gas transmission and distribution, with the amounts she

described in her testimony having since been adjusted to $535,654,000, $650,352,000,

and $710,681,000 for the years 2017, 2018, and the six months ending June 30, 2019,

respectively.75 According to Ms. Palkovich, the expenditures proposed are based on the

investment levels necessary to meet customer reliability, safety requirements, and system

deliverability demands and will be invested in six major programs about which she

testified in detail: new business, asset relocation; regulatory compliance, material

condition, capacity/deliverability; and gas operations other.76

75 5 TR 1334; Consumers Energy’s Initial Brief, pp. 7-8.76 5 TR 1334-1335.

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As discussed below, Staff and the Attorney General take issue with the Company’s

test year gas transmission and distribution projections related to the new business,

regulatory compliance, material condition, and capacity/deliverability programs.

a. New Business

The Company has projected capital expenditures of $76,846,000, $81,007,000,

and $92,993,000 for the years 2017, 2018, and the projected test year, respectively, for

the installation of mains, services and meter stands, large new business projects, the

customer attachment program, and new business meters.77 Discussed below are

disallowances proposed by Staff and the Attorney General related to each of these

programs, excluding new business meters.

i. Mains, Services, and Meter Stands

The Attorney General recommends that the Commission exclude $5.9 million and

$1 million from the Company’s forecasted expenditures for 2018 and the projected test

year for mains, services, and meter stands.78 In support of this recommendation, the

Attorney General relies on the testimony of Mr. Coppola that the Company’s projected

rate of escalation in project costs is excessive when compared to a calculation of the unit

costs based on forecasted inflation rates for 2017, 2018, and 2019 in reliance on 2016

historical amounts.79

The Company responds that it disagrees with the Attorney General’s approach,

albeit without explaining the basis for the Company’s disagreement. The Company

77 Exhibit A-55.78 Attorney General’s Initial Brief, p. 62.79 7 TR 2378.

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nonetheless maintains that adoption of the Attorney General’s methodology should utilize

2017 actual information as it is the most recent actual data available – and that doing so

in fact warrants an increased expenditure level, as calculated by Ms. Palkovich.80

However, the Company is not seeking recovery of this increased amount and instead

requests approval of its original projections for this program.

This PFD is persuaded by the Attorney General’s proposed use of historic actuals

to more appropriately calculate the Company’s projections for mains, services, and meter

stands and notes that the Company does not offer a substantive challenge to this

proposal. And although the Company proposes alternatively that the Commission’s

adoption of the Attorney General’s proposal necessarily requires reliance on the most

recent historic actuals – in this case, 2017 – to calculate the projected expenditures, the

Company offers no indication that the 2017 actuals were even made available to Staff

and, indeed, audited as of the March 21, 2018 rebuttal filing date. Accordingly, this PFD

recommends the Commission adopt the Attorney General’s recommended use of historic

actuals, resulting in adoption of the Attorney General’s proposed disallowances of

$5,900,000 and $1,000,000 from the Company’s projected amounts of $36,430,000 and

$38,830,000 for 2018 and the projected test year ending June 30, 2019, respectively.

ii. Large New Business Projects

The Company originally projected expenditures in the amounts of $10,675,000 for

2018 and $20,474,000 for the projected test year ending June 30, 2019 in the sub-

category of large new business projects. Included within these expenditures are costs

80 5 TR 1402; Exhibit A-125.

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associated with two large new business projects, an agriculture services project and a

Lansing Board of Water and Light (LBWL) project, both of which should be disallowed,

according to Staff and the Attorney General, because the Company has yet to execute

legal contracts with these customers to justify the expenditures.81 Specifically, Staff

recommends a $7,875,000 disallowance ($3,172,000 from 2018 and $4,703,000 from the

projected test year expenditures) related to the agricultural services project, and a

$14,099,000 disallowance (from the projected test year expenditures) related to the

LBWL project. Similarly, the Attorney General recommends disallowances of $9 million

and $12.9 million from the Company’s 2018 and 2019 projected expenditures for these

projects.

While the Company has agreed to Staff’s proposed $7,875,000 disallowance

related to the agricultural services project, the Company maintains that the requested

expenditures for the LBWL project should be approved because it “expects to have a

contract in place” sometime this year.82

Because, as noted by Staff, the Company acknowledged as recently as April 2018

that no contract has been finalized and no definitive date has been established for doing

so, this PFD agrees with Staff and the Attorney General that, consistent with the same

rationale that supported the removal of expenditures related to the agricultural services

project, the Company’s projected expenditures of $14,099,000 related to the LBWL

remain speculative and should be disallowed.83

81 Staff’s Initial Brief, pp.17-18; Attorney General’s Initial Brief, pp 63-64.82 5 TR 1387.83 Staff’s Initial Brief, p. 18; 5 TR 1513-1514.

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iii. Customer Attachment Program

The Company has projected expenditures in the amounts of $37,070,000 for 2017;

$27,262,000 for 2018; and $27,078,000 for the projected test year ending June 30, 2019

for the customer attachment program.

The Attorney General recommends that the Commission exclude $4.5 million from

the Company’s forecasted expenditures for 2018.84 In support of this recommendation,

Mr. Coppola testified that the Company’s projected rate of escalation in project costs is

excessive when compared to a calculation of the unit costs based on forecasted inflation

rates for 2017, 2018, and 2019 in reliance on 2016 historical amounts.85

The Company apparently does not disagree with the Attorney General’s proposed

reliance on historic actuals but maintains that adoption of the Attorney General’s

methodology should utilize 2017 actual information as it is the most recent actual data

available – and that doing so in fact warrants an increased expenditure level, as

calculated by Ms. Palkovich.86 However, the Company is not seeking recovery of this

increased amount and instead requests approval of its original projections for this

program.

As concluded in Section IV.A.1.a.i., this PFD is persuaded by the Attorney

General’s proposed use of historic actuals to more appropriately calculate the Company’s

projections for the customer attachment program, and this PFD disagrees with the

Company’s alternative proposal that the most recent historic actuals for 2017 be used as

84 Attorney General’s Initial Brief, p. 65.85 7 TR 2380.86 5 TR 1402; Exhibit A-125.

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it is unclear whether they have been reviewed and audited by Staff. Thus, this PFD

recommends the Commission adopt the Attorney General’s proposed disallowance of

$4.5 million from the Company’s projected amount of $27,262,000 for 2018 for the

customer attachment program.

b. Regulatory Compliance Program

The Company has projected capital expenditures for 2017, 2018, and the projected

test year in the amounts of $80,964,000, $96,257,000, and $94,881,000, respectively, for

this program, which is comprised of the following categories: (i) pipeline integrity –

transmission program; (ii) pipeline integrity – transmission operated by distribution (TOD)

program; (iii) cathodic distribution program; (iv) cathodic compression, storage, and

pipeline program; (v) regulatory base distribution program; and (vi) maximum allowable

operating pressure (MAOP) compliance pipeline program.87 Discussed below are

disallowances proposed by Staff and the Attorney General related to the pipeline integrity

– transmission, pipeline integrity TOD, and MAOP programs.

i. Pipeline Integrity Program

Relying on the testimony of Nathan Miller, Staff has recommended that the

Company’s historic and projected capital expenditures for this program be adjusted

downward from $133,596,000 to $40,797,230. Staff’s total recommended disallowance

of $92,799,770 includes proposed expenditures (of $92,464,040) that Staff recommends

be disallowed due to Staff’s concerns and conclusions regarding the Company’s

87 Exhibit A-57.

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continued capitalization of remediation activities, as well as proposed expenditures (of

$356,812) that Staff maintains were never incurred by the Company as the remediation

digs associated with these costs were postponed or canceled.88

In its Initial Brief, Staff notes that Ms. Creisher had previously expressed concern

with the Company’s prevalence of capitalized remediation digs in her testimony in the

Company’s last gas rate case, Case No. U-18124, and had recommended that the

Commission direct the Company to engage in further review of the 2015 and 2016

remediation dig summaries, as well as on-going review for 2017 and beyond, with regard

to the capitalization of longer-than-50-foot pipe replacements to make sure they were not

intentionally and unnecessarily replacing pipe in increments longer than is appropriate.89

Staff further notes that in the rebuttal testimony of Company witness Sara Bowers in that

case, the Company had attributed the increase in long pipe lengths beyond 50 feet to the

need to minimize the impact of heat-affected zones (HAZs).90 Staff further notes that in

its final order in that case, the Commission recognized Staff’s concerns, concluding:

The Commission is cognizant of the Staff’s concerns regarding Consumers’ PIAP for 2015 through 2019, and the benefit/cost to ratepayers for early assessment and remediation of pipe and the use of longer-than-standard pipe segments. The Commission supports the company’s efforts to continue to assess its pipeline in compliance with federal rules and to keep its pipeline safe and operational. However, the Commission expects that in future rate case filings, Consumers shall provide detailed and sufficient evidence to demonstrate that pipeline assessment and replacement expenditures are being used prudently.91

88 Staff’s Initial Brief, pp. 71-94; Confidential Exhibits S-12.24 and S-12.30.89 Staff’s Initial Brief, p. 76, citing MSPC Case No. U-18124, 7 TR 1778-1779.90 Staff’s Initial Brief, p. 76-77, citing MPSC Case No. U-18124, 7 TR 1164-1165.91 Staff’s Initial Brief, p. 77; MPSC Case No. U-18124, July 31, 2017 Order, p. 10.

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Staff maintains that based on its extensive investigation in this case into the

Company’s practice of remediating minor pipe anomalies discovered through the

pipeline integrity program with pipe segment replacement lengths in excess of 50

feet, Staff has concluded the following, outlined at length in Mr. Miller’s testimony

and supported by his Exhibits S-12.0 through S-12.56:

1. It appears to Staff that Consumers is unnecessarily repairing pipe defectsthat can be as small as one-inch with pipe segments in excess of 50 feet. It is Staff’s belief that this practice is conducted to allow the Company to capitalize these remediation digs.

2. The Company’s assertion that the presence of LF-ERW welds necessitates the replacement of entire pipe segments is untrue. Unless the entire assessed pipeline has all of the LF-ERW welds removed, the Company will still be required to conduct assessments with a technology capable of determining the integrity of these welds. Therefore, any potentialdefects that would still be present in the pipe seam would be continuously monitored for integrity. Additionally, in many instances where the Company has removed entire pipe lengths because of the presence of LF-ERW welds, the assessment tool did not even identify any defects present in the seam; therefore there was not even an integrity concern.

3. Even if the Company were to replace entire pipe segments because of defects, the belief that five feet would need to be added to each end to separate the new welds from existing heat-affected zones is completely false. Since typical pipe segments measure between 40 and 45 feet, it appears that the Company is only adding five feet to each end to expand the total replacement length to a distance in excess of 50 feet for capitalization. This is further evidenced by the Company not typically adding on excessive pipe lengths when the existing pipeline segments being replaced were already over 50 feet. (Exhibit S-12.27.) As Staff has demonstrated by providing examples of the Company’s own laboratory analyses on girth welds, there was not a single instance where a heataffected zone was even wider than one inch.

4. The Company should be applying more consideration to repairinglocalized defects using sleeves or composite repairs rather than defaulting to removing entire pipe segments.

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5. The Company should reconsider the application of replacing pipe coating as a capitalization expense, particularly given since there is existing coating already on the pipeline that is removed to perform an analysis of a defect.

6. The Company has not been forthright in providing Staff documentation, as evidenced by the documents not provided in response to Staff Audit Request CLC-12 (Exhibit S-12.1) and the troublingly late submittal of the 2017 ILI Vendor Reports on the same date that Staff filed its initial testimony.92

As a result of Staff’s determination that the Company has failed to justify the

capitalization of 93% of its remediation digs in 2016 and 83% of its remediation digs in

2017, Staff recommends that the Commission deny capitalization of “all of the remediation

dig costs that Staff has identified in Confidential Exhibit S-12.24 for 2016 and Confidential

Exhibit S-12.30 for 2017 that should have been maintenance expenses.”93 Mr. Miller

explained Staff’s recommendation as follows:

Staff makes this determination based on the evidence presented in this testimony that clearly indicates the Company has been needlessly replacing pipe segments in excess of 50 feet for the sole purpose of being able to capitalize on those expenditures. The Company did not “provide detailed and sufficient evidence to demonstrate that pipeline assessment and replacement expenditures are being used prudently” as directed in Case No. U- 18124. The costs associated with each remediation dig were derived from Confidential Exhibit S-12.58 for Confidential Exhibit S-12.24 and Exhibit S-11.16 for Confidential Exhibit S-12.30. Staff concurrently proposes disallowances in the general capital work orders associated with each pipeline assessment in a proportion equivalent to the monetary expense that each inappropriately capitalized dig contributed to the total amount of the general capital work order. Additionally, there were several remediation digs that the Company reported expenditures for that were either postponed or cancelled. Staff believes it is improper for the Company to collect a return on work that was never performed, and accordingly such digs are also recommended to be excluded as outlined in Confidential Exhibit S-12.30. Lastly, as mentioned in the direct testimony of Staff witness Cindy L. Creisher, all remediation digs

92 Staff’s Initial Brief, pp. 71-93; see also Confidential 6 TR 1658-1688.93 Confidential 6 TR 1684.

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associated with deficiencies in record-keeping to substantiate the maximum allowable operating pressure are also to be excluded for capitalization.94

Should the Commission decline to categorize the remediation digs as operations

and maintenance expenditures and reject Staff’s recommended disallowances of

$22,853,230, $37,293,640, $7,929,950, and $24,722,060 for the years 2016 and 2017,

the remaining bridge year, and the test year, respectively, Staff alternatively recommends

“from this case onward, that the Commission disallow reimbursement of Company capital

expenditures where the Company artificially inflates the length of pipe replacements to

facilitate the capitalization of those expenditures” and “disallow reimbursement of

Company capital expenditures where the Company replaces entire pipe segments when

more cost-effective remediation methods are suitable.”95

Finally, Staff recommends that the Company be required to annually file in this

docket a summary of the prior year’s remediation digs where in-line inspections were

used as an assessment method, and to include in this report specific data intended to

allow Staff to monitor the Company’s adherence to capitalization and maintenance billing

practices.96

The Company responds that it disagrees with Staff’s proposed expenditure

adjustments. Relying on the testimony of Ms. Palkovich, the Company maintains that it

takes a conservative approach in operating its Pipeline Integrity program and believes

that it benefits public safety to remove sections of low-frequency electric resistance welds

94 Confidential 6 TR 1684-1685.95 Confidential 6 TR 1685-1689.96 Confidential 6 TR 1689-1690.

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(LF-ERW) pipe of any length if the pipe has an inherent risk of seam defects.97 The

Company further responds that it is troubled by Staff’s contention that the Company

undertakes pipeline remediation efforts as a means to impact earnings, stating that it

“does not need to undertake Pipeline Integrity projects as a means to earn a return on its

investment.”98

However, Company does not refute the substantive findings made by Mr. Miller as

a result of his investigation and analysis of the data provided by the Company regarding

its remediation digs in 2016 and 2017. Instead, Ms. Palkovich subsequently agreed with

Mr. Miller (in both a discovery response and by striking that portion of her rebuttal

testimony) that the addition of five feet on either side of existing girth welds is unnecessary

to minimize the impact from the associated heat-affected zones.99 The Company also

agreed to continue to review its historical as well as 2018 and 2019 expenditures “to

incorporate new technologies and improved procedures to ensure safety and drive down

costs.”100 And, Ms. Palkovich also agreed to the additional reporting requirements

proposed by Mr. Miller “[i]n an effort to further align with Staff.”101 Describing Mr. Miller’s

testimony as reflecting “a different view on puddlewelds and other technical anomalies

that arise when undertaking pipeline integrity work”, the Company urges that a technical

conference be held as soon as practical with Staff to discuss new industry technology

97 Consumers Energy’s Initial Brief, pp. 18-20; 5 TR 1396-1397.98 Consumers Energy’s Reply Brief, p. 23, referencing Staff’s Initial Brief, p. 70. (Emphasis in original).99 Consumers Energy’s Initial Brief, p. 16; Exhibit S-12.66; 15 TR 1298, 1344. 100 5 TR 1399-1400.101 Consumers Energy’s Initial Brief, p. 19.

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and practices for evaluating and remediating pipeline anomalies, and to ensure that the

information requested by Staff can actually be produced.102 These acknowledgements

notwithstanding, the Company maintains that an expenditure reduction in the amount

proposed by Staff would result in an asset impairment assessment and potential write-off

of the capital asset, including “a write-off of modern replacement pipe segments that are

in-service and clearly providing benefits to customers.”103 The Company also asserts that

Staff’s proposed expenditure reduction is not supported by the Commission’s July 31,

2017 Order in Case No. U-18124, wherein the Commission made known its expectation

that the Company provide, in future rate case filings, “detailed and sufficient evidence to

demonstrate that pipeline assessment and replacement expenditures are being used

prudently.”104 And, even if the Commission’s intention was to advise the Company to

evaluate its pipeline integrity practices, the Company argues that the July 31, 2017

issuance date of the Commission’s Order deprived the Company of a meaningful

opportunity to review and/or modify its 2016 practices for work undertaken in 2017 such

that any changes ordered by the Commission to the Company’s program expenditures

should only be made to future periods.105

Recognizing, as do both Staff and the Company, the continued importance of the

Company’s work related to the Pipeline Integrity Program, this PFD nonetheless finds

troubling the results of Staff’s investigation into the Company’s pipeline remediation dig

102 5 TR 1392, 1399.103 Consumers Energy’s Initial Brief, p. 20.104 Id, at p. 21, citing MPSC Case No. U-18124, July 31, 2017 Order, p. 10.105 Id., p. 21.

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practices based on data provided by the Company and the unflattering portrait that Staff’s

investigation has painted regarding the internal inconsistencies between the Company’s

capitalization practices and subsequent justifications for them under the guise of public

safety. Significantly, the Company has not substantively challenged the aforementioned

six conclusions reached by Staff as a result of this investigation, as outlined at length in

Mr. Miller’s testimony and supported by his Exhibits S-12.0 through S-12.56.106 Instead,

the Company suggests there is site-specific information missing from the documentation

that was provided to Staff “that would be beneficial for the review that was undertaken”

without explaining how such information could have specifically altered Staff’s review and

conclusions.107

The Company also submits that Staff’s conclusions were drawn without providing

citation to the industry data and standards that Staff applied to its review process – but,

again, this general criticism overlooks the fact that the Company has not provided any

sound justification for the specific examples presented by Staff wherein the Company’s

explanations for various remediation digs are inconsistent with their own practices. In the

end, the Company maintains that, because of the 10-month timeframe for rate cases,

“there was no time for the Company to reasonably address each project identified that

the Staff alleged to be improper.” While this PFD appreciates the challenges presented

by this timeframe, the Company’s time-related grievance is unpersuasive given that the

106 Nor has the Company disputed Staff’s proposed exclusion of $356,812 in expenditures for remediation work the Company never performed due to a cancelled or postponed remediation dig.107 Consumers Energy’s Reply Brief, p. 27.

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Company was put on notice as early as December 2016 of Staff’s concerns with the

Company’s practices when Ms. Creisher expressed concern with the Company’s

prevalence of capitalized remediation digs in her testimony in the Company’s last gas rate

case, Case No. U-18124. Further notice was certainly also given when, in its July 31,

2017 Order in that case, the Commission made known its expectation that the Company

provide, in future rate case filings, “detailed and sufficient evidence to demonstrate that

pipeline assessment and replacement expenditures are being used prudently.”108 That

the Company chose to file a new rate case three months later, well aware of the 10-month

timeframe for such cases and of the Commission’s expectations related to the Company’s

pipeline remediation program, renders somewhat disingenuous the Company’s logistical

concerns related to responding to Staff’s direct case, wherein Staff reiterates its concerns

with the Company’s practices.

Although not substantively challenging the results of Staff’s investigation, the

Company does object to the reductions recommended by Staff as a result of Staff’s

investigation, maintaining that the impact of the resulting adjustment to rate base “is

significant.”109 Outlining the importance of the pipeline safety program and its intended

improvements to the utility’s system reliability, the Company maintains that “while Staff

may prefer the Company to operate its Pipeline Integrity Plan in a different manner, this

does not change the fact that customers are benefiting from the newly installed, safer

108 MPSC Case No. U-18124, July 31, 2017 Order, p. 10.109 Consumers Energy’s Reply Brief, p. 17.

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modern pipe.”110 But this assertion is akin to suggesting that an otherwise healthy

individual with one area of coronary artery narrowing or blockage will benefit from

coronary bypass surgery when a significantly less invasive angioplasty and stenting

procedure will adequately address the condition for a fraction of the health care costs,

recovery, and rehabilitation associated with the bypass surgery. In this analogy, it is not

difficult to conclude that, while the individual may achieve the same benefit of improved

cardiac health from either procedure, the health care system realizes a more significant

return in the end from the costs associated with the unnecessary bypass surgery. So too

can it be said that Consumers Energy’s ability to capitalize on its pipeline remediation

program by unnecessarily remediating minor pipe anomalies with pipe segment

replacement lengths in excess of 50 feet, which expenditures in turn result in a rate relief

request that, if approved, increases customers’ rates, amounts to a practice that ultimately

exceeds the fair value or benefit to ratepayers. Doing so is neither prudent nor

reasonable.

Accordingly, this PFD agrees with Staff that: (i) the Company should not include

expenses that it never incurred in rates; and (ii) the Company has not adequately

demonstrated the prudency of 93% of its remediation digs in 2016 and 83% of its

remediation digs in 2017. This PFD therefore recommends the Commission adopt Staff’s

reductions and reduce the Company’s capital expenditures for 2016 and 2017 by

$22,853,120 and $37,293,640, respectively, and applying the 2016 and 2017 numbers to

110 Id. p. 18.

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the Company’s projected expenses, reduce the bridge year and test year expenses by

$7,929,950 and $24,722,060, respectively. Together with the $356,812 exclusion for

canceled work, the total recommended reduction to the program is $92,798,770.

This PFD further recommends the Commission adopt Staff’s recommendation that

the Company use alternative pipeline remediation methods in lieu of total replacement

and Staff’s recommended reporting requirements, the latter to which the Company has

agreed, as well as adopt the Company’s recommended technical conference. Although

Staff has opined that such a technical conference is neither necessary nor beneficial

because the Company’s pipeline integrity practices “are simply wrong and not in

ratepayers’ best interests,”111 this PFD believes such a conference should occur to at a

minimum achieve agreement on what elements should be included in the report to ensure

it is not redundant to the non-EIRP pipe replacement report that was ordered in prior

dockets.

ii. Pipeline Integrity – TOD Program

Relying on the testimony of Ms. Creisher, Staff has recommended that the

Company’s 2017 and projected test year capital expenditures for this program be

adjusted downward by $4,819,000, as such expenditures are related to pipeline

assessments planned by the Company in Moderate Consequence Areas (MCAs) and

pipeline assessments outside of High Consequence Areas (HCAs), both of which are

subject to proposed, but not final, rule changes in the Notice of Proposed Rulemaking

111 Staff’s Initial Brief, p. 91.

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(NPRM), entitled “Pipeline Safety: Safety of Gas Transmission and Gathering

Pipelines.”112

The Company disagrees with Staff’s proposed reduction, maintaining that the

forward looking approach demonstrated by the Company’s proposed expenditures was

contemplated by a news release issued by the Pipeline and Hazardous Materials Safety

Administration (PHMSA), wherein the PHMSA described the proposed rule changes as

“provid[ing] pipeline operators with regulatory certainty that they need when making

decisions and investments to improve gas transmission infrastructure…”.113

However, this PFD shares Staff’s interpretation of the PHMSA’s news release to

mean that the proposed rule changes, once finalized, will provide regulatory certainty, as

opposed to the Company’s interpretation of the same language to mean that the proposed

rule changes, pre-finalization, are intended to provide regulatory certainty. Accordingly,

because the Company’s proposed assessments related to MCAs and areas outside of

HCAs remain subject to an ongoing rulemaking process, this PFD recommends the

Commission adopt Staff’s proposed reduction of expenditures associated with those

proposed assessments, which amounts to a total disallowance of $4,819,000 from the

Company’s projected 2017 and test year levels.

iii. MAOP Program

The Company has projected capital expenditures for 2017, 2018, and the projected

112 Staff’s Initial Brief pp. 20-22,113 Consumers Energy’s Initial Brief, p. 23, citing 5 TR 1377-1378, citing https://www.phmsa.dot.gov/news/1 phmsa-proposes-new-safety regulations-natural-gas-transmission-pipelines.

U-18424Page 90

test year in the amounts of $2,276,000, $24,250,000, and $21,420,000, respectively, for

the Company’s Maximum Allowable Operating Pressure (MAOP) compliance pipeline

program, which involves MAOP verification and remediation of the Company’s

transmission pipeline. Both Staff and the Attorney General recommend the removal of

all expenditures related to the MAOP program.

In support of its recommended disallowance, Staff maintains that the Company

has justified these expenditures as necessary pursuant to the Pipeline Safety, Regulatory

Certainty, Job Creation Act of 2011 (the Act), two advisory bulletins issued by the PHMSA

regarding the MAOP, Advisory Bulletin ADB-11-01 issued on January 10, 2011 and

Advisory Bulletin ADB-2012-06 issued on May 7, 2012, as well as pursuant to a NPRM

published on April 8, 2016, entitled “Pipeline Safety: Safety of Gas Transmission and

Gathering Pipelines, which proposes changes to regulations related to integrity

management and the new requirements for verification of MAOP and pipeline materials.

Staff argues, however, that neither the Act nor the advisory bulletins effectively impose

any new requirements beyond the current regulations and, moreover, the current

rulemaking process to address the Act and advisory bulletins has not yet been

completed.114 Agreeing nonetheless with the Company’s position that the Act requires

assessment of record quality, Staff proposes that the Commission only approve recovery

of capital expenditures related to verification of MAOP and the upgrading of the

Company’s records management system as set forth in the Company’s discovery

114 Staff’s Initial Brief, pp. 23-28.

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response, 18424-ST-CE-564.115 Specifically, Staff recommends approval of capital

expenditures of $296,000 in 2017, $1,776,000 in 2018, and $1,062,000 in the six months

ending June 30, 2019 related to MAOP pipeline compliance, and capital expenditures of

$64,000 in 2017 and $1,624,000 in 2018 related to MAOP compliance measurement &

regulation. This recommendation amounts to a $32,152,000 reduction in the Company’s

proposed expenditures for the MAOP program.

The Attorney General recommends removal of the entire $36.8 million capital

expenditure amount proposed by the Company, or alternatively half of the projected

expenditure amount, arguing that the Company has acknowledged shortcomings in its

recordkeeping pursuant to federal regulations and the need for ongoing costs to identify

the gaps in its records, and therefore “it is not appropriate to burden taxpayers with such

significant costs for something that was within the Company’s control.”116

The Company disagrees with disallowances recommended by Staff and the

Attorney General, arguing that the Company’s MAOP standardization engineering

analysis program has been put in place to meet the direction of the Act. Further, based

on the Company’s assumption that PHMSA will release its Safety of Gas Transmission

and Gathering Lines Notice of Proposed Rulemaking in August 2018, the Company

submits that its capital expenditure amounts are for efforts that are to be undertaken

immediately to meet the timing of the law.117

115 Id., p. 28, citing Exhibit S-12.63.116 Attorney General’s Initial Brief, pp. 68-69, citing 5 TR 1519-1520.117 Consumers Energy’s Initial Brief, pp. 25-26; 5 TR 1376.

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This PFD agrees with Staff that it is not reasonable to burden ratepayers with costs

associated with the Company’s efforts to comply with proposed rules related to MAOP

record verification and management that have yet to be finalized. Although it may be

possible to determine whether the Company’s predicted August 2018 finalization of the

proposed rules at issue has been realized in advance of the Commission’s August 31,

2018 final order deadline in this proceeding, such a determination would still be untimely

as it would nonetheless deprive Staff of the opportunity to evaluate in this proceeding the

Company’s proposed capital expenditures against the backdrop of clear and final

guidance from the Act. Therefore, this PFD recommends adoption of Staff’s proposed

reduction of the Company’s projected MAOP capital expenditures in the amount of

$32,021,000, reflecting Staff’s recommended approval of only those expenditures

associated with MAOP compliance pipeline ($296,000 in 2017, $1,776,000 in 2018, and

$1,062,000 in the six months ending June 30, 2019) and MAOP compliance

measurement and regulation ($64,000 in 2017 and $1,624,000 in 2018).118

c. Material Condition Program

As described by the Company, the Material Condition Program addresses leaks

and deterioration which reduce natural gas emissions to the atmosphere, improve system

integrity, and reduce service interruptions that impact customers.119 The program

consists of the following subprograms: Enhanced Infrastructure Replacement Programs

(EIRP) pipe replacement projects, Vintage Service Replacement (VSR), Material

118 Staff’s Reply Brief, Appendix E.119 Consumers Energy’s Initial Brief, p. 26.

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Condition Non Modeled, Material Condition Renewals, and Field Measurement

Upgrades.120 Both Staff and the Attorney General have expressed concerns with the

Company’s VSR program, while Staff has also proposed adjustments to the material

condition non-modeled and material condition renewals programs.

i. VSR Program

Again relying on the testimony of Ms. Creisher, Staff maintains that the Company’s

VSR program, which proposes to replace all service lines made of copper, bare steel,

and unknown materials over a 10-year period, may be replacing service lines that would

otherwise be impacted over the course of the Enhanced Infrastructure Replacement

Program (EIRP) distribution main replacement projects, which program is a 25-year

program that is expected to be completed in 2036.121 Consequently, to avoid duplicative

service line replacements, Staff recommends that the Company align the length of both

programs such that they conclude simultaneously in 2036, resulting in a reduction of the

Company’s proposed capital expenditures (premised on a 10-year program) by 50%,

which equates to a proposed capital expenditure level of $20,344,000 in 2018 (instead of

$40,688,000) and $24,219,000 in 2019 (instead of $43,810,000) and, ultimately

$8,196,000 in the six months ending June 30, 2018 and $21,905,000 in the test year

period.122 Staff’s proposal would also include an adjustment to the number of service line

replacements for 2018 from 10,500 to 5,250 and for 2018, the number of service line

120 Id. at pp. 26-27; Exhibit A-58. 121 Staff’s Initial Brief, pp. 33-34, citing 6 TR 1877-1879.122 Id., p. 34, citing 6 TR 1879-1880.

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replacements would be reduced from 12,500 to 6,250.123

The Attorney General similarly proposes that the Company’s VSR program be

extended to the 2036 completion timeline, arguing that the Company “has not presented

any technical or engineering analysis showing that such a rapid replacement timeframe

is appropriate or necessary.”124 Additionally, the Attorney General contends that the

Company’s proposed capital expenditures for the program are flawed because, according

to Mr. Coppola, “the Company has projected cost rates that are significantly higher than

what has been experienced with replacement of other service lines in 2015 and 2016.”125

Based on his calculations using the average of the 2015 and 2016 service line cost rates

as a starting point and applying the inflation factors for 2017, 2018, and 2019, Mr. Coppola

determined that the Company’s forecasted expenditures for 2018 and for the six months

ending June 30, 2019 should be decreased by $12.5 million and $5.8 million,

respectively.126

The Company disagrees with the recommendation of Staff and the Attorney

General that the VSR program should be extended to a 20-year program, arguing that

the 10-year period proposed by the Company “provides a significant customer benefit to

safety and reliability”, particularly where the service types targeted under the program

have seen an increasing leak rate.127 The Company contends, however, that should the

123 6 TR 1880.124 Attorney General’s Initial Brief, p. 72.125 7 TR 2383-2385.126 Id., see also Exhibit AG-26.127 Consumers Energy’s Initial Brief, p. 28, citing 5 TR 1406.

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Commission adopt the recommendation of Staff and the Attorney General to extend the

VSR program to 20 years, the funding for the VSR and EIRP programs should be

combined to allow the Company to balance the total funding and maximize the benefit of

its Distribution Integrity Management Program across mains and services concentrating

on the segments with the highest leak rate. The Company further submits that, based on

Staff’s recommended unit count, the VSR program would extend four years beyond the

EIRP program projection and should therefore include unit replacements totals of 7,200

per year, allowing the Company to complete the program by 2036.128 Responding to the

Attorney General’s concern with the projected service line cost rates under the VSR

program, the Company argues that Mr. Coppola’s suggestion that the actual cost

experience of replacing service lines under other programs can be used as a reasonable

benchmark for the VSR program costs is flawed as it overlooks the actual variance in

costs between the VSR program and other programs, as was explained by the Company

in response to an MPSC Staff audit:

Unit costs in the VSR are higher than services in Asset Relocation, Material Condition Non-Modeled, and EIRP programs as the Company is not replacing every service on the street, as is typically done as part of those programs. VSR projects involve replacing one or two services, then skipping a house or two, then replacing a couple more services, etc. This is less efficient than replacing a gas main and every service along the main. Adding to the complexity is the fact that when new main is installed, the new main is usually not under pavement so tying the new services in is easier and with fewer road breaks, which take additional time. Additionally, the service tee is not retired when tying in to new gas main because the old service is retired. Further, copper services, which comprise the majority of vintage services thus far, are more time consuming to expose due to

128 Consumers Energy’s Initial Brief, pp. 28-29, citing 5 TR 1382-1383.

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changes in direction and elevation.129

This PFD agrees with Staff and the Attorney General that the VSR program

timeline should be aligned with that of the EIRP 20-year program. As noted by Staff,

doing so will mitigate any service line replacements in the VSR program that would

otherwise be impacted over the course of the EIRP distribution main replacement

projects, a concern that was not adequately addressed by the Company. This PFD does

not, however, share the Attorney General’s concerns with the projected unit cost per

service line replacement, having found the Company’s explanation for the variance in

costs to be reasonable and noting further that Staff’s own review of the costs provided by

the Company deemed the Company’s justification of the unit cost to be reasonably

supported.130 Consistent with Staff having found the Company’s unit costs to be

reasonably supported, this PFD find persuasive the Company’s alternative proposal that

7,200 service lines per year be approved at a cost of $28,000,000 per year in order that

the Company may complete the program by 2036 without extending four years beyond

the EIRP program projection. Staff did not challenge this estimation or alternative

proposal except to note that the Company did not include this proposed increase in its

original case filing. Consistent with this determination, this PFD recommends that the

Commission adopt the Company’s proposed revised capital expenditure level of

$28,000,000 per year, resulting in an expenditure level of $14,000,000 for the six months

ending June 30, 2018 and $28,000,000 in the test year period.

129 Id., pp. 29-30, citing Exhibit S-11.27.130 Staff’s Initial Brief, p. 35, citing Staff Audit Request #164 (Exhibit S-11.27).

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ii. Material Condition Non-Modeled Program

Staff recommends a disallowance of $3.7 million from the Company’s proposed

material condition non-modeled capital expenditures. Specifically, while not disagreeing

with the Company’s projected expenditures of $16,634,000 for 2017, Staff proposes that

the Company’s 2018 expenditures be reduced from $24,687,000 to $22,217,000 and that

its expenditures for the test year ending June 30, 2019 be reduced from $22,859,000 to

$20,153,000.131 In support of this recommendation, Ms. Creisher testified:

In response to Staff Audit Request #106, which is included in Exhibit S-11.18, the Company indicates that the capital expenditure projections for the Material Condition Non Modeled program for 2018 were expected to be consistent with the 2016 actual capital expenditures for that program with adjustments for inflation with approximately $5,000,000 in known capital expenditure adjustments. The identified capital expenditures of approximately $5,000,000 are related to projects at the Bridgeport Citygate, GM powerhouse in Bay City, and three standard pressure replacement projects. Staff’s review of the 2016 actual capital expenditures of $17,217,000 versus the 2018 projected capital expenditures of $24,687,000 minus approximately $5,000,000 in adjustments for identified projects indicates that the Company forecasts an approximate increase of $2,470,000, or approximately 14% beyond the 2016 actual capital expenditure, related to inflation. The Company did not identify any known adjustments or factors related to the 6 months ending June 30, 2019 projection.132

The Company responds that, without explanation, Staff rejected the Company’s

projected inflation and relied on 2016 actuals despite having been provided with the

Company’s actual 2017 material condition non-modeled program expenditure amount

(showing an annual increase in this program expenditure of $1,700,000) – and, that when

this increase is considered along with the $5,000,000 in specific projects in 2018, the total

131 6 TR 1872-1873.132 6 TR 1872-1873.

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expenditure amount of $25,000,000 is consistent with the Company’s 2018 projection.133

Although generally in favor of reliance on the most recent available yearly data in

determining projected expenditures, this PFD is not in this instance persuaded by the

Company’s rationale to consider the Company’s 2017 overspend in the absence of any

explanation of the basis for the Company’s forecasted inflation of approximately 14% (or

$2,470,000) beyond the 2016 actual capital expenditures. Thus, this PFD finds Staff’s

proposed adjustment to be reasonable and recommends the Commission adopt Staff’s

recommended disallowance of $3.7 million, resulting in revised capital expenditure levels

of $8,950,000 for the six months ending June 30, 2018 and $20,153,000 for the test year

period.

iii. Material Condition Renewals Program

Staff recommends a disallowance of $2,712,000 from the Company’s proposed

material condition renewals capital expenditures. Specifically, while not disagreeing with

the Company’s projected expenditures of $13,027,000 for 2017, Staff proposes that the

Company’s expenditures for 2018 and for the test year ending June 30, 2019 be reduced

from $15,888,000 to $13,955,000.134 In support of this recommendation, Ms. Creisher

testified:

In response to Staff Audit Request #106, which is included in Exhibit S-11.18, the Company indicates the capital expenditure projections for the Material Condition Renewals program for 2018 and 2019 were based on an average service line replacement cost of $5,000, and in response to Staff Audit Request #105, which is included in Exhibit S-11.19, the Company projection for service line replacements under the Material Condition Renewals

133 Consumers Energy’s Initial Brief, p. 31, citing Exhibit S-11.8.134 Staff’s Initial Brief, p. 32, citing 6 TR 1876.

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program is 3,200 services per year for both 2018 and 2019. The Company’s projected service line replacement costs multiplied by the number of service lines replacements projected results in the annual capital expenditure level of $15,888,000 per year for both 2018 and 2019. In response to Staff Audit Request #105 (Exhibit S-11.19), the Company also provided that under the Material Conditional Renewals program, 2,004 service lines were replaced in 2015, 3,031 service lines were replaced in 2016, and 2,551 service lines were projected to be replaced in 2017. Staff finds that when considered in conjunction with the Company’s other initiatives to reduce actionable leaks through completing full service line replacements to remediate active leaks and accelerating the replacement of identified high-risk vintage service lines through the Vintage Service Replacement program, the Company’s projected incoming service line leaks should decrease over time, thus reducing the number of full service line replacements under the Material Condition Renewals program.

Staff recommends that the capital expenditures related to the Material Condition Renewals program be adjusted based on Staff’s projection of the number of service line replacements using the average of 2016 and 2017 service line replacements as provided in Staff Audit Request #105 (ExhibitS-11.20). Using the Company’s projected service line replacement costs of $5,000 multiplied by Staff’s two-year average of the number of service line replacements of 2,791 results in Staff’s recommended annual capital expenditure level of $13,955,000 per year for both 2018 and 2019. As further shown on Staff Exhibit S-11.4, Staff’s proposed adjustment results in a projected capital expenditure of $13,955,000 for the test year ending June 30, 2019.135

Staff further addresses the Company’s rebuttal argument presented by Ms. Palkovich,

contending that her data presentation regarding the number of below grade leaks on

mains and services eliminated between 2012 and 2016 failed to address the Company’s

2017 data, which provides:

The Company’s Annual Report for Calendar Year 2017, Gas Distribution System indicates that the Company eliminated a total of 7,576 leaks on mains and services in 2017. (Ex S-12.72, F# 278 at 303.) This represents a decrease from the 8,194 leaks repaired in 2016 and is nearly at the 2014level of 7,552 leaks repaired. Furthermore, Staff notes that the number of leaks repaired that are directly attributable to corrosion as reported on the annual report is decreasing as well, with 1,113 service line leaks repaired in

135 6 TR 1875-1876; Exhibits S-11.18, S-11.19.

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2017 compared to 1,228 in 2016 and 1,302 in 2015. (Ex S-11.24; F# 278 at 110; Ex S-12.71, F# 278 at 299; Ex S-12.72, F# 278 at 303.) Staff finds that this reduction in the number of leaks repaired, particularly those attributable to corrosion, demonstrates that the Company’s initiatives to mitigate actionable service line leaks through full replacement are beginning to realize the goals set forth by the Company.136

The Company disagrees with Staff’s proposed adjustment, arguing that there is no

dispute that the number of service line leaks on the Company’s system are increasing

and the Company’s projected expenditures are based on remediating a prudent and

obtainable number of leaks and “is more reflective of the work that needs to occur under

this program.”137 The Company further submits that Staff’s recommended extension of

the length of the VSR program to 20 years will not decrease the number of full service

lines replacements needed under this program.

This PFD finds persuasive Staff’s proposed adjustment because it is based on

calculations derived directly from the Company’s responses to Staff Audit Requests #105

and #106 and establishes a two-year average of 2,791 service line replacements based

on 2016 and 2017 actuals, which is 409 less replacements than the 3,200 projected by

the Company for 2018 and 2019. Also persuasive is the 2017 data set forth in the

Company’s 2017 annual report, which demonstrates a decrease in 2017 from the number

of leaks repaired in 2016, including leaks directly attributable to corrosion. Notably, the

Company disputes neither the reasonableness of Staff’s reliance on 2016 and 2017

actuals to calculate a two-year average nor the conclusions Staff has derived from the

136 Staff’s Initial Brief, pp. 32-33.137 Consumers Energy’s Initial Brief, p. 33.

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Company’s 2017 annual report. Consequently, this PFD recommends the Commission

adopt Staff’s proposed disallowance of $2,712,000, and approve recovery of capital

expenditures in the amount of $5,621,000 for the six months ending June 30, 2018 and

$13,955,000 for the test year ending June 30, 2019.

iv. EIRP Reporting

Finally, through Ms. Creisher’s testimony, Staff recommends that the Company be

required to provide additional reporting as part of the annual EIRP performance report

consistent with the matrices set forth in Exhibits S-11.25 and S-11.26.138 The Company

has agreed to Staff’s recommended additional reporting requirements and,

notwithstanding that the information requested in Exhibit S-11.25 will require an upgrade

to the Company’s reporting system, the Company will endeavor to provide this information

with the 2018 EIRP performance report that is due April 2019.139

In light of the Company’s agreement, this PFD recommends the Commission adopt

Staff’s proposed additional EIRP reporting requirements.

d. Capacity/Deliverability Program

The Company originally projected capital expenditures for 2017, 2018, and the

projected test year in the amounts of $180,323,000, $255,942,000, and $302,411,000,

respectively, for this program, which is comprised of the following categories: (i) augment;

(ii) TED-I (iii) TED-I major projects; (iv) regulator stations; (v) citygate program; (vi)

138 6 TR 1882-1883. 139 Consumers Energy’s Initial Brief, p. 34.

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deliverability base field measurement program; and (vii) deliverability base pipeline

expenditures.140 Discussed below are disallowances proposed by Staff and the Attorney

General related to the TED-I, TED-I major projects, and regulator stations – distribution

programs.

i. TED-I Program

Within the TED-I program, Staff expressed concerns regarding the Company’s

Mid-Michigan Citygate Station project expenditures, as well as those associated with the

Company’s installation of pressure-limiting devices (PLDs), while the Attorney General

took issue with the Company’s expenditures related to the South Oakland Macomb

Network project. Each of these disputes is discussed below.

(a) Mid-Michigan Citygate Station

Relying on the testimony of Ms. Creisher, Staff recommended that the Company’s

projected expenditures for the City Station projects associated with the Mid-Michigan

Pipeline be limited only to those related to the design and engineering costs, given that

an application pursuant to Public Act 9 of 1929 for a certificate of public convenience and

necessity to construct and operate the pipeline has not yet been approved.141

The Company has agreed to Staff’s recommendation, thus this PFD recommends

the Commission adopt the parties’ agreed upon reduction of the Company’s projected

test year expenditure amount for six months ending June 30, 2019, by $617,000.142

140 Exhibits A-26, A-59.141 Staff’s Initial Brief, p. 40. 142 Consumers Energy’s Initial Brief, p. 36, citing 5 TR 1384.

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(b) South Oakland Macomb Network

The Company has projected capital expenditures for the South Oakland Macomb

Network project in the amounts of $15,400,000 for 2018 and $45,300,000 for the six

months ending June 30, 2019.143

The Attorney General contends that no capital expenditures should be approved

for this project because the South Oakland Macomb Network program has not yet been

approved by the Company’s Board of Directors, with such approval not occurring until the

second quarter of 2018, and no project work plan or timeline has yet been developed.144

The Company disagrees with the Attorney General’s position, and notes that, as

explained by Ms. Palkovich, the Company does not require approval by its Board of

Directors of the entire South Oakland Macomb Network program but, rather, “of the 16

projects that make up what [the Company needs] to do in order to abandon the Line 3100,

there’s only one of the 16 that meets the criteria where [the Company] would need board

of directors’ approval, the rest [the Company] can do without board of directors’

approval.”145 Regarding the Attorney General’s concern that no detailed work plans have

yet been finalized for this project, Ms. Palkovich testified that the Company has developed

a high-level scope, has begun the design, and is in the process of securing right-of-way,

identifying long lead-time material items, and engineering is under way.146

This PFD agrees with the Company that the Attorney General’s proposed

143 Exhibit A-59.144 Attorney General’s Initial Brief, p. 74, citing 7 TR 2387-2388.145 5 TR 1525.146 5 TR 1526.

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disallowance should be rejected by the Commission. Ms. Palkovich’s testimony has

provided a reasonable explanation for both the project’s procession without specific

approval from the Board of Directors as well as the development of the scope of work

involved and the Attorney General has neither discussed nor challenged her testimony.

Likewise, Ms. Palkovich’s descriptions in her direct testimony, in her response to the

Attorney General’s discovery request 18424-AG-81, and in her rebuttal testimony of the

vital importance of the project to maintaining public safety and improving customer

deliverability are persuasive and have also not been disputed by the Attorney General.

Accordingly, this PFD recommends the Attorney General’s proposed disallowance of the

Company’s projected capital expenditures for the South Oakland Macomb Network

project in the amounts of $15,400,000 for 2018 and $45,300,000 for the six months

ending June 30, 2019 be rejected by the Commission.

(c) Pressure-Limiting Devices

The Company has projected capital expenditures for TED-I transmission PLD

projects in the amounts of $1,090,000 for 2016, $2,033,000 for 2017, $11,568,000 for

2018 and $1,669,000 for the six months ending June 30, 2019.147

Staff recommends that the Commission deny the Company recovery of all PLD

project capital expenditures, for a total disallowance of $16,360,000, $14,467,000 of

147 Staff’s Initial Brief, p. 37, citing Exhibit A-61.

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which is identified by Staff as non-contingency related.148 Staff also recommends a

disallowance of TED-I contingency expenditures in the amount of $1,843,000.149

In support of Staff’s recommended disallowances, Ms. Creisher explained the

current regulatory requirements for projects involving the installation of pressure-limiting

devices to prevent exceedance of the MAOP and concluded that, contrary to the

Company’s assertion, consideration of the pressure gradient under 49 CFR 192.609 in

determining the need for PLDs is inappropriate.150 She testified as follows:

49 CFR 192.609 entitled “Change in class location: Required study” states in part:

Whenever an increase in population density indicates a change in class location for a segment of an existing steel pipeline operating at hoop stress that is more than 40 percent of SMYS, or indicates that the hoop stress corresponding to the established maximum allowable operating pressure for a segment of existing pipeline is not commensurate with the present class location, the operator shall immediately make a study to determine:

What follows are server subsections that specifically give the pipeline operator direction regarding how to deal with changes in class locationsincluding subsection (f), which specifically requires “[t]he maximum actual operating pressure and the corresponding operating hoop stress, taking pressure gradient into account, for the segment of pipeline involved.” This regulation clearly is intended to address the issue of changes in class location and not pressure gradients in general as described in the direct

148 Staff’s Initial Brief, pp. 38-39; Exhibit S-11.6. Although Appendix C to Staff’s Reply Brief includes a larger amount of $14,520,000, Staff fails to include any explanation for the discrepancy.149 Staff’s Initial Brief, p. 8. Staff’s recommended disallowances of all contingency-related expenditures will be discussed in Section IV.A.6.150 As acknowledged by Staff in Staff’s Initial Brief, Ms. Creisher’s direct testimony and supporting Exhibit S-11.6 includes errors related to Staff’s recommended disallowances of PLD project capital expenditures. Unfortunately, Staff’s Initial Brief compounds the errors (referencing on p. 38 “an $11,568,000 downward adjustment for 2017” when in fact it should be for 2018). These errors are not isolated to this case as Ms. Creisher’s prior direct testimony in Case No. U-18124 also included typographical errors which produced mathematical errors that this ALJ was required to solve. Because this ALJ has considerably less time than is allotted to the parties for their direct cases to analyze the record and timely produce a reasoned PFD, the importance of providing accurate and error-free testimony, exhibits, and briefs cannot be overstated.

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testimony of Company Witnesses Mary Palkovich, at page 61. The Company has not provided any information to show that the proposed or completedprojects are related to recently determined changes in class location.151

Ms. Creisher further testified that Staff expressed similar concerns regarding the

Company’s inadequate support for its PLD expenditures in Case No. U-18124, wherein

she testified:

Staff recommends that consideration for recovery of these capital expenditures be deferred until the Company has presented the necessary information to demonstrate the reasonableness and prudence of each of the projects to be included in rate base and to determine the appropriate capital expenditure level to be passed on to the ratepayer. Additionally, Staff recommends that the Commission require the Company to include, in its next general rate case, justification for these projects, including reasons why this work was not completed at the time of the original construction and if the facilities were in compliance with the pipeline safety regulations when built.152

She further noted that the Commission agreed with Staff’s position in Case No. U-18124

in its July 31, 2017 Order:

The Commission finds that Consumers failed to provide specific evidence to support the TED-I capital expenditures on a project-level basis and failed to explain why the cost of the installation of the devices should be borne by ratepayers. In addition, the Commission finds that the company did not specifically identify the expenses for material, labor, contractor, engineering, contingency costs, or a timeline for each PLD installation project and therefore, adopts the ALJ’s recommended $27,444,000 non-contingency-related disallowance.153

Staff contends that, in this proceeding, the Company has again failed to provide

adequate information to demonstrate that the costs of the PLD projects identified by the

Company should be borne by the ratepayers.

The Company disagrees with Staff and submits that it has fully supported the

151 6 TR 1888-1889, (Emphasis added).152 6 TR 1891.153 6 TR 1891, citing MPSC Case No. U-18124, July 31, 2017 Order, p. 18.

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installation of its test year PLDs projects in this proceeding.154 The Company further

contends that it has addressed the Commission’s concerns set forth in its July 31, 2017

Order in Case No. U-18124 because, as described in Ms. Palkovich’s testimony, Exhibit

A-63 includes the cost detail for material, labor, contractor, engineering, and other costs,

and Ms. Palkovich also explained the timing of the 2018 and 2019 projects and the

purpose of the PLDs – to “improve the operation of the system and provide for enhanced

public safety.”155

This PFD agrees with Staff that the Company’s non-contingency related capital

expenditures for PLD projects should be disallowed. To be sure, the Company has

included in its request 2016 capital expenditures related to a project entitled “SAG Line

8100 – Summerton Road Valve Site – 20’ Monitor/Worker Installations East of Valves

8110 and 8112.”156 This, notwithstanding Staff having previously recommended and the

Commission having concluded in Case No. U-18124 that these expenditures should be

disallowed where they were expended to resolve a violation of 49 CFR 192.195 and

absent the Company’s justification that ratepayers should bear the cost of the Company’s

compliance with 49 CFR 192.195. Here, the Company’s filing remains silent as to such

a justification against the backdrop of Staff’s determination of a probable violation at Line

8100 Summerton Road Valve Site. Moreover, in its initial brief, the Company does not

substantively dispute this point regarding these expenditures and instead maintains that

it has “fully supported the installation of its test year PLD projects in this proceeding.”157

154 Consumers Energy’s Initial Brief, p. 39.155 5 TR 1364.156 Exhibit A-63, p. 5, lines 38-45.157 Consumers Energy’s Initial Brief, p. 39. (Emphasis added).

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And, while this PFD agrees with the Company that, through both the testimony of Ms.

Palkovich and her supporting Exhibit A-63 regarding the proposed expenditures for test

year PLD projects, the Company has substantially complied with the Commission’s

project level detail directive in its July 31, 2017 Order in Case No. U-18124 to “specifically

identify the expenses for material, labor, contractor, engineering, contingency costs, [and]

a timeline for each PLD installation project,” this PFD finds that the Company has still not

adequately addressed Staff’s underlying concern regarding whether the projects are

related to recently determined changes in class location, as explained by Ms. Creisher.158

For these reasons, this PFD concludes the Commission should disallow

$14,469,000 in non-contingency related TED-I expenditures, as requested by Staff.

ii. TED-I Major Projects

The Company had originally projected capital expenditures for TED-I major

projects in the amounts of $8,506,000 for 2016 and $291,551,000 in the 30 months

ending June 30, 2019, which includes $129,236,000 in the test year. However, the

Company has since proposed to update these amounts related to the Mid-Michigan

Pipeline and Saginaw Trail Pipeline to address a contingency cost adjustment, actual

2016 and 2017 costs, and updated 2018 cost projections.159 The Company’s revised

expenditures are $7,882,000 in 2016 and $282,892,000 in the 30 months ending June 30,

2019, which includes $130,147,000 in the test year.

Staff recommends that, with respect to the Mid-Michigan Pipeline project, all but

those expenditures related to design and engineering be disallowed because the

158 MPSC Case No. U-18124, July 31, 2017 Order, p. 18; 6 TR 1889.159 Consumers Energy’s Initial Brief, p. 41, Exhibit A-97.

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Company has not yet obtained a certificate of public convenience and necessity pursuant

to Act 9 for the project.160 Staff’s total recommended disallowance is in the amount of

$12,500,000, $10,651,000 of which represents non-contingency related expenditures.161

Similarly, the Attorney General opposes the Company’s recovery of any expenditures

related to this project before an Act 9 application is approved by the Commission, arguing

that such costs “should only be recovered if the project is approved” inasmuch as the

“purpose of going through the Act 9 proceeding is to ensure that the project is necessary

and in the public interest.”162

The Company has offered conflicting rebuttal testimony in response to the

disallowances recommended by Staff and the Attorney General. On the one hand, Ms.

Palkovich agreed with Staff’s recommendation that “without an application for a Public

Act 9 of 1929 certificate of convenience and necessity for the project, Staff does not

support recovery of expenditures other than engineering costs.”163 On the other hand,

Mr. Fultz contends that Act 9 approval is not required before the Commission can

determine whether the projected expenditures are reasonable and prudent. In his

testimony, Mr. Fultz outlined the need for the expenditures and indicated that, except for

expenditures spent in 2016 and 2017 to prepare the construction yard for the project

which he agrees should be removed, all other expenditures are required in order to

comply with the Act 9 filing requirements set forth in the Commission’s March 29, 1995

160 Staff’s Initial Brief, p. 40, citing 6 TR 1882-1885 and Exhibits S-11.6, S-18.4, S-11.30, S-11.31.161 As noted earlier, recommended disallowances of contingency-related expenditures are addressed below in Section IV.A.6.162 Attorney General’s Initial Brief, p. 82. (Emphasis in original).163 5 TR 1384.

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Order in Case No. U-10547 as well as in Commission Rule 460.868.164 Specifically, Mr.

Fultz testified:

The engineering and design required to develop the filing includes real estate and row/easement costs to determine the routing and depth of the pipeline. Similarly, survey and constructability/construction consulting are critical inputs to the line route, design, and estimated construction costs. There are also services, consultants, and contractors required to perform the permitting and environmental assessments required for an Act 9 filing.165

This PFD agrees with Staff, the Attorney General, and Ms. Palkovich that full

recovery of the Company’s projected costs related to the Mid-Michigan Pipeline and

associated gate station work outside of a filed and approved application under Act 9

should be disallowed by the Commission. However, this PFD is persuaded by Staff’s

recommendation that the Company be allowed to recover its engineering and design

costs for this project where the recommendation is based on Staff’s review of the

Company’s responses to Staff Audit Requests #124 and #143, which provided further

detail and identified actual capital expenditures related to these costs for 2016, 2017,

2018 and for the six months ending June 30, 2019.166 Accordingly, this PFD recommends

the Commission adopt Staff’s recommended disallowance of $10,651,000 in non-

contingency related expenditures for this project.

iii. Regulator Stations – Distribution Program

The Company had originally projected capital expenditures for the regulator

stations – distribution program in the amounts of $14,369,000 for 2017, $24,413,000 for

2018, and $23,607,000 for the projected test year. The Company subsequently adjusted

164 Consumers Energy’s Initial Brief, p. 42, citing 2 TR 265.165 2 TR 265.166 6 TR 1884-1885; Exhibits S-11.30 and S-11.31.

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downward by $2,800,000 the total amount projected for 2018 in response to a discovery

request by the Attorney General, wherein the Company agreed to remove the gas

odorizer rebuild projects as they are being funded in other programs.

The Attorney General recommends that the Company’s revised projected 2018

expenditures of $21.6 million, compared with the $15.7 million spent in 2016, should be

further reduced by $3,000,000, arguing that the Company has “simply forecasted some

‘ballpark’ amounts for these projects as placeholders” without providing any work plans

for the list of projects.167

In response, the Company maintains that the Attorney General’s proposed

disallowance should be rejected as the Company’s cost estimates are not “ballparked”

but based on engineering expertise and subject matter expert input and, furthermore, are

justified in the Company’s response to Staff Audit Request #113, wherein the Company

explained the increased expenditures for this program are “in recognition that these

facilities have a limited lifespan and that prior year funding has not kept up with program

needs.”168

This PFD agrees with the Company that the Attorney General’s rationale for the

proposed $3.0 million disallowance is premised on a generalization regarding the nature

of the Company’s cost estimates and fails to recognize the Company’s explanation for

the increase in capital expenditures as set forth in Ms. Palkovich’s rebuttal testimony.

167 Attorney General’s Initial Brief, p. 74-75, citing 7 TR 2388-2389.168 Consumers Energy’s Initial Brief, p. 43-44, citing 5 TR 1407-1408.

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Accordingly, this PFD recommends the Attorney General’s proposed

disallowances of $3,000,000 million from the Company’s forecasted expenditures for

2018 for this program be rejected by the Commission.

e. Gas Operations Other Program

The Company has projected capital expenditures for this program in the amounts

of $5,083,000 for 2017, $17,038,000 for 2018, and $16,017,000 for the projected test

year. No party has opposed the Company’s projected capital expenditures.169 This PFD

therefore recommends the Commission approve the expenditures in the amounts

requested by the Company.

2. Gas Compression And Storage Capital Expenditures

The Company’s witness Danielle Hill testified regarding the Company’s requested

rate recovery of capital expenditures for the gas compression and storage program in the

amounts of $31,700,000 for 2016 (actual), $15,900,000 for the six months ending

June 30, 2018 (projected), $85,000,000 for the 12 months ending June 30, 2018

(projected), and $75,100,000 for the 12 months ending June 30, 2019.170

As discussed below, both Staff and the Attorney General have recommended

reductions to expenditures within this program related to the St. Clair and Freedom

compressor stations, other compressor and storage projects, and well rehabilitation.

169 Exhibit A-60.170 2 TR 456-457; Exhibit A-12, Schedule B-5.2.

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a. St. Clair and Freedom Compressor Stations

i. St. Clair Compressor Station

Staff recommends two adjustments to the Company’s proposed GCS expenditures

assigned to the St. Clair compressor station program, a $450,000 disallowance related to

a fire incident and related costs and a $4,700,000 disallowance related to contingency

expenditures.171

The Company has agreed to and adopted Staff’s proposed reduction of $450,000

related to a fire incident, but opposes Staff’s proposed reduction of $4,700,000, arguing

that the Company has on rebuttal updated its requested capital expenditures for these

station projects to reflect actual costs incurred in 2017 and costs which shifted from 2017

to the first six months of 2018, reflecting that the $4,700,000 was spent as actual project

for the St. Clair compressor station project, which should be approved by the

Commission.172 Specifically, Mr. Fultz testified on rebuttal:

The graph on page 27 of my direct testimony reflected the anticipated spending for remaining project costs at the time of filing, and this remains reflective of the actual project costs since the time of filing. At that time, the costs had not yet occurred, but the risks were known, documented, and quantified, and the associated contingency had been allocated accordingly.173

Staff, however, opposes all capital expenditure adjustments made by the Company

on rebuttal, including the shifting of $4,700,000 in proposed expenditures from

contingency to actual incurred costs, arguing that because the Company has “provided

171 6 TR 2130; Exhibit A-26.172 Consumers Energy’s Initial Brief, pp. 45-46; Exhibit A-97; 2 TR 273.173 2 TR 267.

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no justification, no documentation, and not even a breakdown of the amounts, Staff was

unable to perform a prudency review” of these updated amounts.174

This PFD shares Staff’s concern regarding the inability to review the Company’s

rebuttal updates of capital expenditure adjustments, and therefore recommends the

Commission decline to approve the Company’s reassignment of $4,700,000 in capital

expenditures from contingency to actual incurred costs for this station project. Instead,

for the reasons discussed in detail below in Section IV.A.6., this PFD recommends the

Commission adopt Staff’s recommended disallowance of $4,700,000 in contingency-

related expenditures from the Company’s projected GSC capital expenditures for this

project.

ii. Freedom Compressor Station

The Attorney General recommends the Commission reduce the Company’s

proposed GCS capital expenditures for this project by $54,300,000, contending that the

Company’s Board of Directors has yet to approve Phase 2 of this two-phase project, thus

warranting a disallowance of $20,000,000 from the 2018 expenditures and $34,300,000

from the projected expenditures for the six months ending June 30, 2019.175

The Company disagrees with the Attorney General’s recommendation,

maintaining that Board of Directors approval is not required to support the

reasonableness and prudence of the Company’s cost projections for this project. Mr.

Fultz further explained as follows in his rebuttal testimony:

The criticality of this asset to the Company’s natural gas system, as well as 174 Staff’s Initial Brief, pp. 100-101.175 Attorney General’s Initial Brief, pp. 83-84, citing 7 TR 2398.

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the many benefits of this project to our customers, has been thoroughly detailed in my direct testimony. Not only has the Company’s Board of Directors already approved Phase 1 of the project, but the total projected expenditures for both phases are included in the Company’s infrastructure planning. Board of Directors approval for this project was not approached in two phases to determine whether or not the project would be approved to continue by the time Phase 2 was ready for Board of Directors review. Rather, the approval of Phase 1 by the Board of Directors allowed critical activities to begin that addressed immediate natural gas system reliability, capacity, and safety needs while allowing activities to occur that would significantly increase the accuracy of the projected construction and procurement expenditures by the time Phase 2 Board of Directors approval is requested.176

The Company further notes that, as set forth in the May 9, 2018 affidavit of Mr. Fultz, the

Board of Directors has since met and approved the Phase 2 expenditures on May 4, 2018

and the costs approved by the Board “are consistent with the cost projections provided in

[his] testimony in this proceeding.”177

Because the sole basis for the Attorney General’s objection to the Company’s

proposed Phase 2 expenditures has now been rendered moot by the Board of Directors’

May 4, 2018 approval of the costs, this PFD recommends that the Commission deny the

Attorney General’s proposed disallowance of $54,300,000 for the Freedom Compressor

Station project.

b. Other Compression and Storage Projects

The Attorney General also recommends that the Commission reduce the

Company’s projected GCS capital expenditures related to the Muskegon River and

Overisel compression projects. Specifically, the Attorney General recommends

176 2 TR 266.177 Consumers Energy’s Initial Brief, Attachment A, p. 3.

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disallowances of $2,700,000 from the 2017 expenditures and $1,900,000 from the 2018

projections related to the Muskegon River project. With respect to the Overisel project,

the Attorney General recommends that the Commission “remove the entire $5.5 million

in capital expenditures forecasted for 2018 and the $5.1 million projected for the 6 months

ending June 2019 and instead include $3.2 million of the 2018 capital expenditures that

were planned to be incurred in the first half of that year into the first half of 2019.”178 The

Attorney General’s recommendations are based on Mr. Coppola’s testimony, wherein he

relied on the Company’s response to discovery request AG-CE-359 to conclude that the

amounts projected for the Muskegon River project are lower than what the Company had

forecasted in Exhibit A-12, Schedule B-5.2, and the amounts projected for the Overisel

project are premature because “the Overisel Compression OVC Dehydration System

Replacement project is still under development.”179

The Company responds that the Attorney General’s proposed disallowances are

fundamentally flawed because they are based on a misunderstanding of information

provided by the Company in discovery response AG-CE-359 (Exhibit AG-29), which

contained cost information on a single project related to the Muskegon River project and

a single project related to the Overisel project, against the larger backdrop of the

information contained in Exhibit A-12, Schedule B-6.2, which set forth information on a

total of seven projects related to the Muskegon River project, and 15 projects related to

178 Attorney General’s Initial Brief, pp. 76-77; 7 TR 2391-2392; Exhibit AG-29; Exhibit A-12, Schedule B-5.2.179 Id.

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the Overisel project.180 The Company addressed Mr. Coppola’s “flawed reasoning” with

the rebuttal testimony of Danielle Hill, wherein Ms. Hill addressed and explained the

incorrect assumptions he made based on his misunderstanding of discovery response

AG-CE-359.181

This PFD agrees with the Company that the Attorney General’s recommended

disallowances related to these two projects are based on his misinterpretation of the

underlying discovery response from the Company and the cost information set forth in

Exhibit A-12, Schedule B-5.2, as explained by Ms. Hill, and as revealed by an examination

and comparison of Exhibit AG-29 and Exhibit A-12. Notably, the Attorney General failed

to address or otherwise respond to the Company’s rebuttal testimony regarding Mr.

Coppola’s misinterpretation of these documents in his initial brief. This PFD recommends

that the Commission deny the Attorney General’s recommended disallowances related

to the Muskegon River and Overisel projects.

c. Well Rehabilitation

The Attorney General also recommends that the Commission disallow

$41,200,000 from the Company’s projected GCS capital expenditures related to well

rehabilitation. In support of this recommendation, Mr. Coppola testified in relevant part:

The Company has proposed to undertake a large capital program in excess of $180 million for Well Rehabilitation simply by pointing to federal and industry compliance standards and vague promises of increased gas deliverability. The Company has not provided an engineering study of deliverability problems or baseline assessment of existing compliance problems with federal or industry standards. Furthermore, no financial

180 Consumers Energy’s Initial Brief, pp. 49-53.181 2 TR 472-474.

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analysis was performed to justify the capital program, either in whole or in part, based on the financial benefits to be derived from the purported increase in deliverability of gas from the wells.

Given the lack of evidence and supporting justification for this program, it is not possible to accept the capital expenditures that the Company has proposed for 2017 and future periods in this rate case.182

The Company disagrees with the Attorney General’s proposed disallowance as

being without merit. Relying on the direct and rebuttal testimony of Ms. Hill, the Company

maintains that she described and included great detail in Exhibit A-42 regarding the

Company’s multi-year program in place in response to the safety standards under the

Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2016 and

the American Petroleum Institute Standard (API) Recommended Practice (RP) standard

API RP 1171.183 The Company further disputes as meritless Mr. Coppola’s justification

for his proposed disallowance that the Company has not provided a financial analysis to

support the project because, according to Ms. Hill, “[p]rojects required for regulatory

compliance (such as the Well Rehabilitation Program), are not subject to financial benefit

or economic reviews” and such analyses are performed by the Company for economic

projects.184

This PFD again agrees with the Company that the Attorney General’s

recommended disallowance related to well rehabilitation is without merit. Not only has

the Company adequately supported the capital expenditures for this program through Ms.

182 7 TR 2392-2395.183 Consumers Energy’s Initial Brief, p. 54, citing 2 TR 460-462 and Exhibit A-42.184 2 TR 477.

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Hill’s direct testimony and with supporting Exhibit A-42 detailing the cost elements, none

of which the Attorney General singularly identified as unreasonable or imprudent, but the

Attorney General has neither addressed nor disputed Ms. Hill’s rebuttal testimony,

wherein Ms. Hill testified:

In Case No. U-18124, and in the instant case, the Company has: (i) identified new laws that require regulatory compliance by 2026; (ii) submitted a detailed plan and related expenditures to achieve regulatory compliance; and (iii) provided updates which show schedule and budget adherence.185

This PFD therefore recommends that the Commission deny the Attorney General’s

recommended disallowances related to the well rehabilitation program.

3. Business Services Capital Expenditures

The Company’s witness, Jeffrey Shingler, testified regarding the Company’s

requested rate recovery of capital expenditures for the gas business services program in

the amounts of $6,933,000 for the six months ending June 30, 2017; $30,009,000 for the

12 months ending June 30, 2018; and $30,534,000 for the 12 months ending June 30,

2019.186

As no party has expressed opposition, this PFD recommends the Commission

adopt the Company’s proposed capital expenditures for this program.

4. Information Technology Capital Expenditures

The Company’s witness, Christopher J. Varvatos, testified regarding the

Company’s requested rate recovery of $37,094,000 for actuals in 2016, $27,638,518 for

185 2 TR 475-476.186 2 TR 486-487; Exhibit A-12, Schedule B-5.4.

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actuals in 2017, $42,816,000 projected for 2018, and $38,826,000 projected for the test

year.187 In his testimony, Mr. Varvatos also described the various IT projects within each

of the following seven programs: (i) upgrades and replacements (enterprise); (ii) upgrades

and replacements (business partner); (iii) architecture; (iv) business partner functionality;

(v) enhancements; (vi) IT service delivery; and (vii) security.188

Both Staff and the Attorney General have recommended reductions to these

expenditures, including the removal of contingency costs, the latter of which is addressed

in Section IV.A.6.189 Each party’s proposed non-contingency IT cost reductions are

discussed below.

a. Staff

Staff recommends a $8,635,000 reduction in the Company’s proposed IT capital

expenditures, which reduction includes disallowances of: (i) $2,829,912 related to digital

customer experience (DCE) website and field service solution projects; (ii) $5,570,482

related to cancelled projects; and (iii) and $234,611 related to meter reading hardware

costs.190 Staff further recommends that future IT project submissions by the Company be

subject to additional reporting requirements and include consideration of cloud-based

187 3 TR 737-738, 759; Exhibit A-12.188 3 TR 738-746; Exhibit A-74.189 Like Staff, the Attorney General maintains that the contingency costs in IT and, indeed, in all capital expenditures should be excluded as “[i]t is not fair or reasonable for the Company to recover the depreciation expense and the return on the investment on potential costs that may not be actually incurred but have been added to rate base.” Attorney General’s Initial Brief, p. 60, citing 7 TR 2376. 190 Staff’s Initial Brief erroneously included an IT capital expenditure reduction of $102,960 related to the ITCP Parnall East renovation project and failed to include a reduction of $234,611 for meter reading issues; Staff’s Reply Brief corrects these discrepancies and notes the errors do not affect the numbers in the Appendixes to Staff’s Initial Brief. Staff’s Initial Brief, p. 54; Staff’s Reply Brief, pp. 28-29.

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computing alternatives.

i. DCE Website and Field Service Solution Projects

Staff’s proposed disallowances of $641,355 and $2,188,557 related to digital

customer experience (DCE) website and field service solution projects, respectively, are

supported by the testimony of Mr. Frazier, who testified in relevant part regarding the DCE

website project:

The Company has spent too much on this project. For example, the web presentation layer could be developed by a competent programmer in 6 to 8 weeks. (Exhibit S-14.4) Equipment on which to run the web layer should be less than $250,000. (Exhibit S-14.4) It appears the bulk of the expense is related to modification of backend systems to support the providing and updating of appropriate data, which is a function of backend system complexity. I have been involved with and managed, several similar utility projects, and in my experience, the costs proposed by Consumers Energy are too high given the identified scope of the project. Exhibit S-14.4 shows my estimate of reasonable project costs. This project may have started with reasonable goals but became a runaway cost sinkhole as scope expanded or changed due to a lack of executive change control on scope creep. Ratepayers should not pay for project mismanagement.

***This project, properly managed and maximizing benefits to costs, should have a total cost no higher than approximately $8.5 million, with O&M of no more than approximately $525,000. (Exhibit S-14.4) Staff recognizes that the DCE Website project is difficult to cost justify. Ratepayers expect web functionality even if there is not sufficient offset in utility costs to pay for the project. Given that the Company did not provide an itemized cost breakdown for Staff to evaluate, Staff’s projections are not exactly apples to apples comparisons, and therefore I doubled my cost estimation to give the Company the benefit of any possible price differentials, as shown on Exhibit S-14.4, line 27. Even then, Staff can only justify allowing $2,542,875 capital and $154,125 O&M for the gas portion of the project, as shown in Exhibit S-14.4.191

Regarding the field service project, Mr. Frazier testified in relevant part:

191 6 TR 1914-1915.

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The Company did not provide sufficient information for Staff to make an itemized recommendation. The Company did provide sufficient information for Staff to determine that at least some of the projects grouped together under the “Field Service Solution” were for categories that Staff would typically approve, like replacement of obsolete equipment in the field. But, the Company did not provide Staff with sufficient detail for Staff to determine exactly what portion of costs are attributable to these types of expenses. Staff believes the Commission would be justified if it chose to exclude all expenditures in this category based upon the lack of detailed information about what expenses are included in this large IT project. However, Staff also believes that the Company has shown that some portion of this expense is likely justified but was unable to determine this on a specific sub-project basis. Thus, Staff recommends allowing the Company to recover 100% of all requested material and O&M, as historically the Company’smaterial costs have been reasonable in this category and their O&M has been very low. Based on evaluations of how Consumers Energy utilizes its labor, especially when compared to contract labor, and its treatment of overhead and AFDUC, and given the lack of justifying information, Staff believes it would not be unreasonable for the Commission to approve 67% of the Company’s labor and 50% of its contractor costs, overhead and AFUDC. These disallowances total $2,675,000 of the Field Service projects’ cost for the bridge year and test year, as shown in Exhibit S-14.5 and Exhibit S-14.1, line 22.192

In its Initial Brief, Staff acknowledges that the Company, through Mr. Varvatos’

rebuttal testimony, provided 2017 actual IT expenses, resulting in a reduced disallowance

proposed by Staff related to these projects.193 Staff nonetheless maintains that the

Company has not adequately justified the costs for the DCE website project because,

although the Company provided post project review examples of two projects, it provided

“no information explaining the cost of this project, alternatives explored, or explain any

competitive bidding process.”194 Staff found the Company’s justification for its field

services projects to be similarly deficient because such projects are primarily for the

192 6 TR 1918.193 Staff’s Initial Brief, p. 58; Exhibit S-14.1.194 Staff’s Initial Brief, p. 60.

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benefit of the Company to be more efficient in the field and the Company “did not provide

a cost benefit analysis or detailed information about specific system replacements, even

after Staff asked for additional justification,” to show that the expenditures include

sufficient benefits “to offset the very high cost of field services projects submitted.”195

The Company disagrees that it provided insufficient information to Staff, arguing

that Mr. Varvatos provided significant testimony describing the programs and projects

comprising the utility’s IT capital expenditures.196 The Company contends that Mr.

Varvatos not only described ways in which the IT department controls its costs, but

provided in Exhibit A-74 “[d]escriptions, scope, benefits, cost-benefit ratios, and

implementation dates of the capital projects included in the programs described in his

testimony.”197 The Company maintains that the Commission should reject Staff’s

proposed adjustments related to the DCE website and field services projects and instead

adopt its proposed expenditures as detailed in Exhibit A-12 because, as explained by Mr.

Varvatos in his rebuttal testimony: (1) Mr. Frazier’s proposed disallowance related to the

DCE website was based in part on inaccurate and arbitrary interface estimates without

knowledge of the Company’s specific systems and technology landscape, and grossly

underestimated factors that contributed to a realistic and reasonable project cost

estimate; (2) Mr. Frazier’s testimony that the Company did not provide adequate

information on efficiency improvements to justify the field service project costs overlooks

the information the Company produced in a supplemental discovery response regarding

195 Id., p. 62.196 Consumers Energy’s Initial Brief, p. 58, citing 3 TR 741-746.197 Id., citing 3 TR 739; Exhibit A-74.

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the operational savings and detailed system capabilities provided through these projects;

and (3) Staff’s proposed disallowances reverse the approval the Company received from

the Commission for these projects in Case No. U-18124, based upon the

recommendation of Ms. Fromm.198

This PFD finds that Staff’s adjustment to the Company’s proposed IT capital

expenditures related to the field service project is appropriate and reasonable and should

be adopted, but that Staff’s adjustment related to the DCE website project should be

rejected. As to the former, in response to Mr. Frazier’s testimony that the Company did

not provide adequate information on efficiency improvements to justify the field service

project costs, this PFD disagrees with the Company that the information contained in its

supplemental discovery response (Exhibit A-131) regarding the operational savings and

detailed system capabilities provided through these projects was sufficiently responsive.

To be sure, the discovery request and response state in full:

Question:The gas portion of the Field Service Solution projects is listed at $6.8mil with a split of 30%. Therefore, this project will roughly cost $22.6mil combined gas and electric. This project is primarily to improve the quality and efficiency of CE’s field service functionality. Please explain, in detail, how and why this project costs so much, approximately three times the value to gas, and provides $6.8mil of value to gas.

Response:See the attachment “FSS Release 1-3 Benefits” which supplements the Company’s response to discovery Response No. 18424-ST-CE-316 (Partial). The attachment provides information regarding the benefits of the Company’s FSS Program.199

198 Consumers Energy’s Initial Brief, pp. 59-63; citing 3 TR 741, 751-752 and Exhibits A-130 and A-131.199 Exhibit A-131.

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A review of the attachment “FSS Release 1-3 Benefits” reveals, however, a 13-page

outline of the benefits of the field service projects to operations and customers, but no

detailed explanation for why and how the project costs “three times the value to gas”, as

was requested by Staff.

Regarding the DCE website project, this PFD notes that Mr. Varvatos’ rebuttal

testimony endeavored to address Mr. Frazier’s concerns with additional project detail and,

indeed, Staff has acknowledged that the Company provided Staff with information on the

before and after project results and that “the Company did a nice job of breaking down

how the capital costs were expended.”200 And Staff has also acknowledged that there is

“some merit” in Mr. Frazier having developed his testimony and exhibits and

recommendation regarding the DCE website project without any understanding of the

Company’s specific architecture for its customer systems and enterprise integration

capabilities.201 In fact, Staff doubled its initial estimate related to its recommended

allowance to reflect Mr. Frazier’s lack of familiarity with the Company’s system. Moreover,

neither Staff’s initial brief nor Staff’s reply brief disagreed with the Company’s

characterizations, as explained by Mr. Varvatos, that Mr. Frazier’s cost estimate for the

DCE website project included inaccurate and arbitrary interface estimates and “grossly

underestimated factors that contributed to a realistic and reasonable project cost

estimate.”202 Against this backdrop, this PFD does not agree with Staff’s assertion that

the Company’s projected expenditures for the DCE website are not reasonable.

200 Staff’s Initial Brief, pp. 60, 64.201 Staff’s Initial Brief, p. 62.202 Consumers Energy’s Initial Brief, p. 60, citing 3 TR 752.

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Accordingly, this PFD recommends the Commission adopt Staff’s proposed

adjustment of $641,355 related to the Company’s proposed capital expenditures for its

DCE website project but reject Staff’s proposed adjustment of $2,188,557 related to the

the Company’s proposed capital expenditures for its field service solution project.

ii. Canceled projects

Staff further recommends that the Commission reduce the Company’s projected

IT capital expenditures by 6%, or by $5,570,482, to reflect what Staff believes to be the

Company’s improper inclusion of the cancelled IT projects from its last rate case, Case

No. U-18124. Mr. Frazier explained how the 6% adjustment was determined:

The prior rate case (U-18124) had a total of approximately $99,000,000 for projects of which $6,210,506 was approved but the projects had no capital spend. The 6% was calculated by dividing the total dollar amount of IT projects included in the rate recovery but without capital spend by the total amount of IT projects included in the rate recovery. The resulting number was rounded down to 6%.203

Observing that the Company effectively recovered $6,210,506 in capital expenditures for

projects and functionality that were never implemented, Mr. Frazier described where

these dollars went and the effect of allowing the Company to recover them in this case:

The Company explained that in the process of deciding what projects should proceed, money was expended on other projects not included in the prior rate case, MPSC Case No. U-18124. Although the Company did initiate other projects totaling $8,213,539 not submitted in the prior rate case (U-18124), of that $8,213,539 for other projects, $7,995,275 for those projects was included in the current rate case for recovery. Staff compiled a list of the specific projects the Company claimed as spent but not in rate case U-18124 however these projects are in rate case U-18424. (Exhibit S-14.7.) And Consumers Energy is not merely asking for the difference between the $8,213,539 spent and the $6,210,506 recovered in rates but not spent. Consumers Energy is currently asking for recovery of $7,995,275 (96.5% of $8,213,539), and not offsetting for previous recovery of the unspent

203 6 TR 1920.

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$6,210,506. If Consumers Energy is allowed to recover the $7,995,275 requested in the current rate case (U-18424), then it will have received $6,210,506 from ratepayers without spending any of those dollars for ratepayer benefits.204

Staff therefore recommends that the Company’s proposed IT capital expenditures

be reduced by the percentage of funds that were not spent on the identified projects in

the last rate case. Staff further recommends that the Company provide in the next rate

case “information on the percentage of projects approved in this case that it subsequently

canceled, so that Staff may compare it to the previous case amount and apply a historic

average of cancelled projects to future IT requests.”205

The Company disagrees with Staff’s proposed reduction, arguing that Mr. Frazier’s

recommendation “failed to consider that the Company spent $7,326,895 more on other

projects approved in Case No. U-18124 that required additional funding.”206 In doing so,

the Company relies on the rebuttal testimony of Mr. Varvatos, who further explained that

the funds for approved projects with no capital spend helped offset the collective over-

spend on the other approved projects and the “Company’s customers indeed received

benefits from the use of additional funds to complete the other approved projects.”207 In

its reply brief, the Company further argues that Staff’s reliance on only one historic year’s

percentage to use as a proxy for future behavior, without consideration to how funds were

reallocated, “completely disregard[s] whether higher spend on other approved projects

and incremental spend on unapproved contracts are prudent and requests the across-

204 6 TR 1921.205 Staff’s Initial Brief, p. 57.206 Consumers Energy’s Initial Brief, p. 64, citing 3 TR 756.207 Id., citing 3 TR 757.

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the-board disallowance regardless of prudency or necessity of expenditure.”208 The

Company further contends:

What appears to have been lost by Staff in the IT analysis is the fact that IT is not static -- it is ever-changing. It is well known that IT evolves quickly, setting the stage for emerging needs that could not have previously been anticipated, and for obsolescence in existing technology as new technologies emerge. Sometimes emerging projects cannot wait for approval in a future rate case and require decisions that are more contemporaneous with the need that has arisen. Staff would have this Commission believe that those expenditures are automatically imprudent and worthy of disallowance, but this is simply untrue. Consumers Energy, as a whole, must be responsive to those changes in order to provide safe and reliable service to its customers. This requires the ability to make appropriate management decisions as technologies emerge, causing “business and project conditions change.” This requires flexibility in management decisions – a flexibility that Staff is loathe to give.209

This PFD recommends that the Commission adopt Staff’s recommendation that

the Company’s projected IT capital expenditures be reduced by 6%, or by $5,570,482. In

doing so, this PFD agrees with Staff that the Company “cannot merely forgo an approved

project and offset with higher spends on other projects. IT projects need to be evaluated

on an individual basis to ensure each project represents sufficient value to the Company

and ratepayer to warrant the expense.”210 To do otherwise would effectively amount to

“retroactive ratemaking for expenditures previously approved for recovery” as noted by

Mr. Frazier. Moreover, although the Company takes issue with Staff’s reliance on only

one historic year’s percentage to use as a proxy for future behavior, the Commission

agreed with a similar approach in the Company’s second most recent electric rate case,

Case No. U-17990, wherein the Commission adopted Staff’s recommended reductions

208 Consumers Energy’s Reply Brief, p. 70.209 Id. pp. 70-71.210 Staff’s Initial Brief, p. 55.

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to the Company’s reliability program test year projections based on its historical

underspending after its last rate case and observed:

The Commission finds Consumers' explanations regarding past underspending troubling. The Staff noted that Consumers explained that the underspending was a result of its decision to prioritize reactive programs over the proactive reliability program. However, when Consumers explained its past underspending in its reactive capacity program, the company stated the underspending was due to its decision to prioritize spending in its reliability program. The Commission is concerned with the credibility of Consumers' position when it explains underspending in one program area by pointing to spending in another program area where it also underspent approved amounts. This inconsistency raises questions about the reasonableness and prudence of its projected reliability test year expense in this rate case. 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.211

For these reasons, this PFD recommends the Commission adopt Staff’s recommended

reduction of the Company’s projected IT capital expenditures by $5,570,482.

iii. Meter reading hardware costs

Staff further recommends that the Company’s projected IT capital expenditures be

reduced by $234,611 related to meter reading hardware costs. In its reply brief, Staff

notes that this proposed reduction appeared elsewhere in Staff’s initial brief but should

have been included in the section regarding IT capital expenditures. In support of this

recommendation, Staff maintains that these expenditures relate to work that the Company

has undertaken to address and improve meter reading issues identified by the

Commission in its June 9, 2016 order in Case No. U-18002 and therefore should not be

211 MPSC Case No. U-17990, February 28, 2017 Order, p. 10.

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recovered from ratepayers “because the Company would not have incurred these costs

had it been managing its meter reading staff and reading its meters properly.”212

Specifically, Ms. Fromm testified:

The Company has been found in violation of the Commission’s rules for not having maintained records of efforts made to obtain actual meter reading records and its reasons for failing to do so, which indicates their negligence in the meter reading process itself. The $234,611 in meter reading hardware costs represents an investment made to remedy a problem that the Company should take full responsibility for.213

Ms. Fromm provided an additional basis for Staff’s recommended disallowance of these

costs:

The cost of $234,611 for additional meter reading hardware—due to additional meter reading staff—was incurred in the midst of the Smart Energy Program. The Company’s report indicates that 30 seasonal meter readers were hired throughout January 2016 in anticipation of decreased productivity. (Exhibit S-17.4, p 12.) However, when examining the past meter reading staffing levels, it is unclear why these additional meter readers were needed. Appendix E of the Company’s report shows that in 2015 the Company had 310 meter readers. (Exhibit S-17.4, p 39.) While this was the lowest number of meter reading staff in the past 10 years prior to 2015, it was entirely expected to be at that level due to the Company’s AMI investments. Consumers Energy’s Smart Energy Program has projected the benefit of significantly reduced meter reading staff since the inception of the program. In fact, in 2015 the Company installed 436,692 meters, bringing them to 45.3% complete with their electric service territory. The 310 meter readers in 2015 is only down 17 meters readers from 2012 when the AMI installations began. While the anticipated decrease inproductivity in early 2016 was likely a sound prediction by the Company given that there weren’t any accountability measures in place to ensure accurate meter reads, it is unclear why a meter reading staff at 95% of that seen prior to AMI installations could not read approximately 55% of the meters not yet replaced with AMI meters. Therefore, though the $234,611 investment in additional meter reading hardware is a result of the increase in meter reading staff, ratepayers should not be burdened with this unreasonable cost.214

212 Staff’s Initial Brief, pp. 52-53.213 6 TR 1952-1953.214 6 TR 1953.

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Disagreeing at the outset that that the Company’s proposed meter reading capital

expenditure constitutes an IT capital expenditure, the Company nonetheless disagrees

with Staff’s proposed reduction of this cost as it “essentially prescribes an additional

penalty to what was already ordered by the Commission.”215 The Company further

contends:

In Case No. U-18002, the Commission imposed “a penalty for violation of Rules 13 and 8 of $200 per customer for each of the customers identified by the company as of February 11, 2016 as still awaiting an actual read, for a total penalty of $515,800.” MPSC Case No. U-18002, June 9, 2016 Order,page 22. In imposing that penalty, the Commission did not indicate that the Company could not make investments to improve meter reading; nor did the Commission indicate that any investments made to improve meter reading would not be recoverable. Because these investments were reasonably made and are to the benefit of the Company’s customers, theCompany’s requested capital expenditures for new meter reading equipment should be approved.216

This PFD finds that Staff’s recommended reduction is well supported and without

any substantive challenge from the Company. Although the Company contends that the

reduction would be akin to an additional penalty to that already ordered by the

Commission in Case No. U-18002, the Company does not disagree with Staff’s assertion

that these meter reading hardware costs are borne solely out of the Commission having

found the utility to have disregarded the Commission’s rules through a “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”.217 Nor has the

Company rebutted Staff’s additional basis for this recommended reduction, as articulated

215 Consumers Energy’s Initial Brief, p. 86.216 Consumers Energy’s Reply Brief, p. 68.217 MPSC Case No. U-18002, June 9, 2016 Order, p. 21.

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by Ms. Fromm in her above testimony. Consequently, this PFD recommends the

Commission adopt Staff’s recommended reduction and reduce the Company’s projected

IT capital expenditures by $234,611 related to meter reading hardware costs.

iv. Additional reporting for future IT project submissions

Staff further recommends that the Company’s future IT capital expenditures be

subject to the following additional reporting requirements: (i) future submissions of IT

projects for a rate case should include a breakdown of both the O&M and capital costs

for Staff’s consideration; (ii) for each project greater than $25,000, the Company submit

a project approval document; (iii) when final expenditures exceed the estimated costs by

10% or $50,000 (whichever is greater), then change management documentation should

be provided explaining the reason for the increased cost; (iv) for IT projects over

$100,000, the Company should include as an exhibit a copy of the written, PowerPoint,

or other media presentation that Company technical staff used to present the project for

justification and alternatives considered by Company senior management; and (v) show

how the Company considered cloud computing alternatives in future IT project expense

requests over $100,000 other than cyber security.218

The Company disagrees with all of Staff’s recommendations, arguing in its reply

brief as follows:

While items two and five were addressed by Staff witness Frazier, the remaining three items were not and are, thus, being made for the first time in Staff’s Initial Brief, and are without any evidentiary support; these requests should, therefore, be rejected. As discussed below, the remaining two requests are, similarly, without merit and unnecessary and should be rejected by the Commission. Staff witness Frazier recommended that the Commission, “postpone recovery of future projects until the utility has

218 Staff’s Initial Brief, pp. 63-68.

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evaluated any available cloud-based options to determine whether these might be more cost-effective options.” 6 TR 1926, 1934. In its Initial Brief, Staff expands this recommendation and requests that the Company should show that it considered cloud computing alternatives for future requests over $100,000 (other than cyber security and transmission projects) and, if the Company does not include a cloud solution as part of the alternatives considered, the Commission should defer recovery until the Company evaluates a cloud solution. Staff’s Initial Brief, pages 66-67. As part of this request, although citing no evidentiary basis for the statement, Staff very generally characterizes cloud-based services as “often a less expensive option to a Company-owned IT service.” Staff goes on to direct that between cloud computing and in-house or Company-owned IT service, “[t]he Company should select the lower cost option to the customer (regardless of the best option for the company shareholders).” First, the Company demonstrated that it considers and implements cloud solutions in this case, and it is, thus, not necessary to require the Company to consider cloud-based alternatives. Second, it is important to note that the lowest cost is not always best for customers. Mr. Varvatos explained:

“The Company evaluates and deploys cost-effective IT solutions in the best interest of its customers. The Company is increasingly considering cloud solutions for all projects with new IT capabilities to be delivered. When cloud solutions are available, they are often submitted in Request for Proposal bids and are evaluated alongside on-premise (non cloud) solutions.” 3 TR 762.

* * *“[T]he approach the Company takes in considering cloud for all solutions providing new functionality, it is not appropriate for the Commission to postpone recovery of future projects.Cost-effective options, including both cloud and in-housesolutions, have been and will continue to be evaluated by theCompany.” 3 TR 763-764.219

This PFD finds that Staff’s additional reporting requirements related to the

Company’s IT project expenditures in future rate case filings should be adopted by the

Commission. Contrary to the Company’s assertions, the bases for all five of Staff’s

recommendations were substantively addressed in Mr. Frazier’s direct testimony,

219 Consumers Energy’s Reply Brief, pp. 78-79.

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wherein he described in detail the areas where the Company’s current procedures are

lacking, testifying in relevant part:

It appears that Consumers Energy does not closely follow accounting FASB ASC 350-40, Internal-Use Software rules, which are outlined below. The Company has demonstrated an inability to provide individual project approval documents with date, amount and appropriate expenditure authorization after all preliminary steps had been completed and presented to management.220

Mr. Frazier also explained his concerns with the Company’s IT accounting:

Almost every software project has an O&M component. Some projects have a capital component. The Company has a very low O&M expenditure rate for some big software projects. Given the scope of the projects, it appears that the Company may be understating the portion of project costs that should be treated as O&M, instead reporting project work as capital expenditures, which not only allows recovery but also earns a return on those costs. For example:

Project Name O&M as % of CapitalDCE Web 3%Complex Billing Automation 0%Field Service Solution 5%GCCP projects 14% (reasonable)EPMO project 39% (reasonable)

In my experience managing and accounting for large IT projects similar to the DCE Web, Field Service Solution, and Complex Billing Automation projects, it is unlikely that such low percentages of O&M are accurate if the Company is appropriately categorizing its costs. Staff expects IT project expenditures to follow GAAP guidelines. The Company should be allowed to recover appropriate project expenditures for worthwhile projects from ratepayers but only earn an additional return on the capital portion of theproject. The Company did not keep sufficiently detailed records for Staff to determine the actual nature of the project expenditures to determine whether the Company had correctly categorized them.221

220 6 TR 1924.221 6 TR 1925-1926.

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Having detailed the areas of concern with the Company’s IT expenditure record-keeping,

Mr. Frazier outlined Staff’s recommendations for all future rate cases:

1. Explicitly track and submit project expenditures per Internal-Use Software rules summarized below.

2. Implement a project “approval to proceed” document including date, amount and appropriate expenditure authorization signature, that can be provided to Staff on audit. This document is necessary to correctly categorize initial project expenditures between capital expenditures and O&M and also to see how much the amount submitted for recovery exceeded the original authorization amount due to scope creep or poor estimation.222

Mr. Frazier further described cloud-based IT services, including the associated

benefits of this new approach to providing technology-based solutions, the services

included in this program, and the factors to be considered in determining whether the

services are cost-effective for a utility in comparison to other available options, and the

ability of Staff to perform such an evaluation:

It would be hard or impossible for Commission Staff to determine if cloud-based computing was a better solution if the utility does not include a cloud solution as one of the alternatives considered. Staff will not have access to all of the program and data information necessary to properly evaluate the options. Staff recommends postponing recovery of future projects until theutility has evaluated any available cloud-based options to determine whether these might be more cost effective options.223

Excepted from Staff’s recommendation, however, are cloud-based computing options

related to security applications because, according to Mr. Frazier:

Security applications need to be evaluated differently, one to minimize outside knowledge of security in place, and two, a cyber security service must quickly provide up-to-date information/service for blocking emerging threats. Due to the different evaluation required for security applications, and the fact that these applications often may not be safely postponed, security-related projects are anticipated to be implemented in-house with a

222 6 TR 1926.223 6 TR 1934.

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service providing information and patches for emerging “zero-day” threats. Thus, Staff does not recommend that the Commission require evaluation of cloud-based options in this category.224

In response to Mr. Frazier’s concerns and recommendations of additional

reporting, the Company, through Mr. Varvatos’ rebuttal testimony, described the

processes utilized by the Company for management review and approval of IT projects

and maintains that Staff’s proposed directives are unnecessary as the Company has

“sufficiently demonstrated how it categorizes, tracks, and charges software expenditures

per FASB ASC 350-40 Internal-Use Software rules, and how project sponsors and

Company leadership approve IT projects.”225 Mr. Varvatos also disagreed that the

recovery of future cloud-based computing projects should be postponed because the

Company already “evaluates and deploys cost-effective IT solutions in the best interest

of its customers.”226

Absent from the Company’s response, however, was any substantive refutation of

Mr. Frazier’s determination that the Company has “demonstrated an inability to provide

individual project approval documents with date, amount and appropriate expenditure

authorization after all preliminary steps had been completed and presented to

management.” Moreover, while the Company disagreed with Mr. Frazier’s assertion that

the Company is understating O&M and overstating capital, the Company’s accompanying

explanation also acknowledged an error in the Company’s reporting of its percentage of

O&M costs for one of the projects identified by Mr. Frazier, underscoring the need for

224 6 TR 1934-1935.225 3 TR 762.226 3 TR 762.

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improved tracking of expenditures.227 For these reasons, this PFD finds that the

Company has failed to sufficiently demonstrate that Staff’s additional reporting

recommendations are unnecessary and this PFD recommends that the Commission

adopt Staff’s recommendations.

b. Attorney General

The Attorney General took issue with the Company’s IT capital expenditures,

recommending the following disallowances: (i) $4,500,000 from the Company’s capital

expenditure projection for 2018, and $1,000,000 for the first six months of 2019 for the

Company’s GCCP compliance scheduling project; (ii) $1,000,000 from the Company’s

2017 capital expenditures for the Company’s gas control solutions project; and (iii)

$8,600,000 from the Company’s 2018 capital expenditures and $3,300,000 for the first

six months of 2019 for the Company’s disaster recovery project.228

Noting that the Company has since agreed on rebuttal to remove $5,500,000 from

the Company’s capital expenditures related to its GCCP compliance scheduling project,

the Attorney General argues that the expenditures related to the Company’s gas control

solutions project should be removed in light of the Company’s acknowledgement in

discovery that the project funds initially assigned to this project were allocated to other IT

projects.229 The Attorney General further argues that the expenditures related to the

Company’s disaster recovery project should be removed as the Company has failed to

conduct a cost-benefit analysis or any studies for the new site of the back-up facility and

227 3 TR 762. 228 7 TR 2400-2405.229 Attorney General’s Initial Brief, p. 86, citing 7 TR 2401 and Exhibit AG-36; Consumers Energy’s Initial Brief, p. 67, citing 3 TR 764-765, 772-773.

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has failed to consider any alternative options to the new center.230 The Attorney General

further contends that, in his rebuttal testimony, Mr. Varvatos gave “cursory treatment” to

the Attorney General’s concerns that “[a]dditional research of other alternatives and

opportunities to reduce capital costs needs to occur before the proposed expenditures

can be deemed to be prudent and reasonable.”231

In response, the Company agrees to a partial disallowance related to the gas

control solutions project, contending that only $384,000 of the proposed $1,000,000 is

now necessary because, as Mr. Varvatos testified:

[T]he scope of the Gas Control Solution, along with $125,000, was merged into the broader scope ITCP-Parnall P1-1 renovation project, which is renovating the portion of the Company’s office building that houses the gas control room. This transfer avoided project overlap, simplified project management, and reduced the costs of implementing the technology. Since IT had other important projects that needed incremental funding, the Company transferred portions of the remaining Gas Control Solutions funding to the Gas Nominations project ($11,000) and GIS Integrated Design project ($248,000). The Company is seeking recovery of the $384,000 allocated to the gas business. The Company is not seeking recovery for the remaining $653,000, of which $569,000 was transferred to Electric projects and $84,000 was unallocated.232

Regarding the Attorney General’s proposed disallowance related to the disaster

recovery data center, the Company maintains that the additional research regarding other

major corporations/peers in the Great Lakes region regarding back-up computing facilities

and cost-sharing opportunities was unnecessary where the Company consulted with

230 Attorney General’s Initial Brief, pp. 87-91.231 Attorney General’s Initial Brief, pp. 91-92.232 Consumers Energy’s Initial Brief, p. 67, citing 3 TR 765.

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Gartner, “the leading IT research and advisory firm” regarding disaster recovery

practices.233

This PFD finds that the Company has sufficiently justified its reduced capital

expenditure request amount of $384,000 related to the gas control solutions project with

Mr. Varvatos’ explanation of the merged scope of the project into a broader scope

renovation project to avoid project overlap, simplify project management, and reduce the

costs of implementing the technology. Regarding the Company’s proposed capital

expenditures related to its disaster recovery project, this PFD further finds that Mr.

Varvatos refuted both Mr. Coppola’s description of its current backup recovery center as

only a back-up facility and Mr. Coppola’s suggestion that the Company did not perform

any external research to understand best practices in disaster recovery. Finally, this PFD

notes that the Attorney General offered no additional analysis or response on this issue

in his reply brief. Accordingly, for the reasons set forth above, this PFD recommends the

Commission reject the Attorney General’s recommended disallowances to the

Company’s capital expenditures related to the Company’s gas control solutions and

disaster recovery projects, except that the Company’s reduced recovery amount of

$384,000 for the gas control solutions project should be adopted.

5. Gas AMI/AMR

For the Company’s Gas AMI projects, the Company has presented capital

expenditures of $29,000,000 for 2016 and $16,677,000 for 2017.234 For the Company’s

Gas AMR projects, the Company has presented capital expenditures of $5,865,000 for

233 Consumers Energy’s Initial Brief, p. 68, citing 3 TR 779-780.234 Exhibit A-12.

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2016 and $106,798,000 for the 30 months ending June 30, 2019.235 The Company relied

upon the testimony of Lisa DeLacy to support these expenditure amounts. Ms. DeLacy

testified regarding the Company’s AMI and AMR programs, including the installation

schedule for the gas AMR modules and the benefits that the modules provide to the

Company’s gas only utility customers.236 The Company expects to have the gas module

fully installed in 2019.237

Relying upon the testimony of Lauren Fromm, Staff maintains that the Company’s

projected costs for the AMR program, totaling $112,663,000, should be completely

disallowed.238 In her testimony, Ms. Fromm identified several concerns with the AMR

program:

First is the initiative the Company has taken with the AMR program. In Case No. U-18124, the Company could not provide detail on its purchasing and installation plans for the modules, nor the software and systems development work that was required, and the Commission requested additional information. After the July 31, 2017 order in Case No. U-18124 the Company ramped up its AMR program. While the Company has provided more detail behind their program in this case there are concerns about how the Company vetting their options for metering solutions and the Company's corresponding choice of technology, discussed below.

Staff’s second concern is regarding technology. On page 8 of her direct testimony Ms. DeLacy discusses a solution for 42,329 gas-only accounts. These accounts represent gas meters that are physically located within 2000 feet of two Company electric AMI meters. Because of their proximity the Company has moved these accounts to the SG/AMI program, as they will receive modules that are configured for the Gas AMI solution as opposed to the AMR solution. This means that these particular modules will communicate with nearby AMI electric meters, sending reads daily to the Company, thereby mitigating the need for a drive-by read. While Staff is

235 Exhibit A-12.236 2 TR 44-74.237 2 TR 68-69. 238 6 TR 1943.

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supportive of this new approach for these 42,329 customers, it begs the question whether something similar could be done for the rest of the gas-only customers. Staff believes that there are increased benefits to customers with AMI compared to AMR. The AMI customer has the benefit of receiving hourly reads daily as opposed to monthly with AMR. The Company also benefits from AMI because AMI has better and quicker theft detection capabilities versus AMR. The Company receives AMI reads via a cellular network, meaning it no longer must perform meter reads (whether it be a physical read or a drive-by read). On page 36 of her testimony, Ms. DeLacy attempts to justify AMR as a cheaper alternative to AMI for gas only customers by claiming that the fixed network would cost an additional $23 million in upfront investment for the installation of 3,500 field network devices with ongoing maintenance of $54 million over the 20-year life of the modules. The Company asserts that AMR is the best value to customers given the costs to enhance the program to AMI through a study done internally which was not provided. The alleged unit cost for the 3,500 field network devices equates to over $6,500 per device whereas the 42,329 gas-only accounts communicate with an electric AMI meter that have a unit cost of under $200. (Exhibit S-17.5.) The Company does not explain this large discrepancy between the fixed network devices and electric AMI meters that perform the same function of obtaining reads from a gas module and delivering them to the Company’s back-office system. If the Company were to install AMIelectric meters on utility poles in the rest of its gas-only service territory, thesewould act as the data collection and communication system for their gas modules. Staff has serious concerns that the Company has not considered alternative options for using AMI units in conjunction with gas-only customers that would avoid expensive fixed-network costs. The Company did not provide a study supporting these figures or comparing this approach to the selected AMR approach. There is not enough information for Staff, Intervenors or the Commission to determine if AMR is in fact the best solution due to the lack of supporting evidence regarding comparison to the alternatives.

Staff’s third concern is the limited detail regarding a third potential alternative of the utilization of AMI gas meters. Though the Company claims that AMR was the better value solution with an NPV of $20.0 million as opposed to an NPV of $15.8 million for AMI, this presentation does not convince Staff because there is no cost/benefit analysis supplied.

Staff’s fourth concern is that the Company did not consider the remote disconnect capability of AMI as a safety benefit because a remote disconnect device integrated into these meters is not yet available, though it should be in the near future. Being able to remotely disconnect a gas meter for safety or theft reasons is something Staff believes to be a big benefit of AMI that is entirely lacking in AMR.

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Staff’s fifth concern regarding the AMR technology choice arose due to recent regulatory proceedings with Indiana Michigan Power regarding their AMR program. In 2011, Indiana Michigan Power requested recovery of funds to implement an AMR electric solution, even though AMI was an available option. In its current electric case, Case No. U-18370, it requests to accelerate the depreciation of its AMR meters to transition to AMI meters over the next five years. Staff has taken a position in the I&M case that it is inappropriate to put the cost burden of multiple iterations of advanced metering on ratepayers. The ALJ’s PFD in Case No. U-18370 agreed with Staff’s concerns and denied the Company’s request to shorten the remaining life of its AMR meters. Though this situation involves the migration of electric AMR to AMI as opposed to gas, Staff is still concerned with obsolescence. As Ms. DeLacy states in her direct testimony at page 36, the AMR modules represent approximately 76% of the investment. While this concern does not apply to a potential future situation in which the Company chooses to migrate towards an AMI-module solution (because it would use the same module), it certainly does apply to a situation in which AMI gas meters are deemed more beneficial. The modules, representing 76% of the investment would be a stranded cost. And, as discussed above, given the lack of information regarding the alternatives there is not enough record evidence to prove that AMR is the most prudent technology.

***

Staff is concerned with this investment not only due to the technologyconcerns discussed above, but also regarding the ongoing experience of the AMI project and the benefits the Company has claimed. The Company testifies that the AMR program will realize benefits related to the reduction of meter reading costs, the improvement of billing accuracy and the reduction of energy theft resulting from analysis of meter tamper alerts and energy consumption patterns that the modules will provide. (DeLacy Direct Testimony, p. 37.) These are the same, or nearly the same benefits the Company claims will be realized with the AMI program. But, the AMI program, thus far, has not resulted in the impressive benefits the Company originally claimed. For example, in Case No. U-17735 the Company estimated a total gas and electric O&M benefit from the AMI program at $2.175 billion. (Exhibit S-17.3, p 4, line 85, column o.) In current case U-18322, this benefit is now projected at $1.947 billion as presented in the business case. (Exhibit S-17.3, p. 10, line 85 column o.) Furthermore, the projected benefit of AMI-enabled theft detection has yet to be realized as the program was not planned for implementation until the fourth quarter of 2017. In Case No. U-18322 the Company claimed a benefit of meter reading of $11.558 million for 2017, while their business case represented a 2017 meter-reading benefit of $16.577 million. (Exhibit S-17.3, pp 14, 9.) These changes and discrepancies raise questions regarding the Company’s ability to achieve the alleged

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benefits of AMR in this case, as the AMR business case relies upon the same operational benefits not yet seen at projected levels on the electric side of the business.

***In this case, the Company has requested recovery for the work it has done for the 42,329 gas-only customers whose modules will communicate with another customer’s AMI electric meter. In this situation these customersreceive the same benefits that combination customers do regarding their gas usage and the modules on their meters utilize the same software and systems development as the AMI program. Staff believes that the Company’s creative solution deserves analysis for its entire gas-only territory to identify more customers for whom this solution may work via a fixed collection unit. Both the Company and Staff agree that customers with the AMI solution receive more benefits than those with the AMR solution and it is reasonable to expect the Company to provide the details of how an AMI solution compares to the Company’s proposed AMR solution. While the Company provides a few additional costs that a fixed-network approach would incur, it does not provide the additional operational benefits that would occur with it, and which may offset additional costs associated with AMI. Likewise, Staff also sees an analysis of a gas AMI meter as beneficial. The Company has stated that due to (unidentified) safety concerns with the remote disconnect capabilities of gas AMI meters, it did not consider the benefit of this capability. Regardless of the concerns with the remote shut-off capability of an AMI gas meter, there are operational benefits an AMI solution would provide over an AMR solution. Both the fixed-network gas module approach as well as the gas AMI meter approach would reduce meter reading expenditures more than the proposed AMR solution as well as give the Company further insight into potential incidences of theft.239

Based on Ms. Fromm’s concerns and because the Company did not provide an AMI

cost/benefit analysis, as requested by the Attorney General, allowing for a meaningful

cost comparison between the actual costs to run the AMR program, which is based on

the same operational benefits not yet seen in the AMI program, and the costs to operate

the gas AMI program, Staff contends that all projected AMR program expenditures should

be disallowed at this time.240 Alternatively, should the Commission decide against

239 6 TR 1943-1949.240 Staff’s Initial Brief, pp. 49-50.

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disallowing all such expenditures, Staff recommends that the Commission only allow

recovery of costs that are the net of the levelized cumulative benefits projected for the

program over the 20-year life of the modules.241 According to Staff’s calculations, this

would equate to a yearly benefit of $23,842,000. Finally, Staff maintains that were the

Company permitted any AMR program recovery, it should be prohibited from accelerating

depreciation of its AMR meters before the end of the modules’ 20-year useful life, to allow

for the possibility of the Company’s subsequent decision that the AMI program is the more

prudent approach.242

The Company maintains that the Commission should reject Staff’s proposed

disallowance of all AMR program expenditures, arguing that Staff’s concerns “do not

overcome the Company’s record evidence in support of these expenditures and the

benefits they provide to customers.”243 The Company contends that Ms. Delacy detailed

the benefits of AMR in her direct and rebuttal testimony and further argues in relevant

part:

The Company expects to achieve meter reading cost savings equivalent to approximately 80% of baseline gas-only area manual meter reading expenses. 2 TR 83. Consumers Energy also expects that technological enhancements associated with AMR will generate operating efficiencies in customer service and billing areas of the Company. As an example, improved meter reading accuracy and reduced estimates associated with automatic meter reads reduces the need for gas operations workers to perform special manual reads to resolve billing issues and customer concerns regarding meter reading accuracy. 2 TR 83. Company plans a 70% reduction in special gas reads for gas-only service customers, which would result in a 45.5% reduction in all special gas reads. 2 TR 83.

241 Staff’s Initial Brief, p. 50.242 Id.243 Consumers Energy’s Initial Brief, p. 74.

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The enhanced AMR theft detection process will permit the Company to receive tilt tamper alerts and magnetic tamper alerts from gas modules as part of the drive-by AMR data collection process. 2 TR 84. The data will be analyzed for correlation with service work orders, customer notifications, and daily consumption patterns to identify locations where energy theft has been attempted. 2 TR 84. This is an improvement over the pre-AMR theft detection, which relies on tips to initiate investigations of suspected energy theft. 2 TR 84. Customers will benefit from the incremental gas sales revenue that results from the improved identification of energy theft, and the theft benefit is expected to grow to 0.75% of residential and commercial gas sales revenue. 2 TR 84.

The Company’s implementation of AMR also results in unquantified benefits associated with increasing meter read rates and reducing the frequency of billing estimates for customers. 2 TR 99. The Company has identified AMR as an important opportunity to address high estimated billing frequencies experienced by some customers, and the Company is moving forward with the implementation of gas AMR (as committed to in Case No. U-18002) because it provides immediate benefit to customers through reduced meter reading expense and improved billing accuracy as a result of higher actual read rates. 2 TR 95. As of March 14, 2018, the Company’s initial AMR truck reads have resulted in an actual read rate of 99.9%. 2 TR 105. Meter read rate performance improvement is an unquantified benefit not included in the AMR cost/benefit analysis. 2 TR 99.

When the Company decided to invest in AMR, it represented the most reasonable and prudent alternative to reading meters manually. 2 TR 95. In Case No. U-18124, the Commission disallowed expenditures for the AMR modules and the software and systems development because of a lack of information related to these items. MPSC Case No. U-18124, July 31, 2017, Order, pages 20-21. However, the Commission’s Order determined $13,635,000 of gas AMR capital expenditures to be a reasonable amount to include in rate base. 2 TR 42. Based on the Commission’s Order in Case No. U-18124, the Company continued to invest in gas AMR, and provided the additional information regarding the AMR modules and the associated software and systems in this proceeding. Staff acknowledged that “the Company has provided more detail behind their program in this case” (6 TR 1943), and Staff does not contend that the Company failed to provide the detail found lacking in Case No. U-18124.

Staff now argues that there have been “changes since Case No. U-18124” and the Company’s choice of a “new approach” that warrant its recommendation to disallow all AMR Program costs, including those expenditures previously approved in Case No. U-18124. 6 TR 1948. The only “change” that Staff identified is the Company’s determination that gas

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AMI can be used in certain situations instead of gas AMR, including where a gas meter is physically located within 2,000 feet of two Company electric AMI meters. See Exhibit A-144. The identification of these unique situations does not represent a “change” or “new approach” to the Company’s implantation of its AMI and AMR programs, but instead represents an opportunity the Company recognized to expand AMI within the context of the current AMI and AMR deployment. As discussed, the Company will work with Staff to examine whether using electric AMI meters as data collection devices in the Company’s gas-only service area is worth pursuing. However, because the AMR gas communication modules can be easily reprogrammed to work with AMI, the future consideration of this approach is not a reason to disallow all gas AMR costs, including those that the Commission previously approved and that the Company has already expended based on that approval.244

Having reviewed the record evidence relied upon by both Staff and the Company

in support of their respective positions, this PFD shares Staff’s concerns that there is

insufficient information regarding the costs and benefits of the AMR and inadequate

consideration of and comparison to alternatives in order to justify the Company’s

proposed expenditures and for this PFD to make a determination whether such

expenditures are reasonable and prudent. Although the Company produced a 2014

evaluation that Ms. DeLacy described as having “included cost/benefit analysis of two

AMR alternatives and two AMI alternatives” the Company acknowledged that “the

cost/benefit analysis was only one consideration” as other factors such as technical effort,

integration resources, and business impacts were also considered.245 In fact, a review of

the evaluation indicates that the assessment included a comparison of the

implementation costs, integration effort, schedule, and net present value between the

drive-by AMR and fixed network AMI options offered by two solution providers which was

244 Consumers Energy’s Initial Brief, pp. 74-77.245 2 TR 91.

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used to support the recommendation of the Company’s gas assessment team to select

one provider’s drive-by AMR solution.246 And, while Ms. DeLacy testified that “AMR was

the better value solution for gas-only customers,” the 2014 evaluation determined that,

over a 20-year period, an AMI solution will net $167 million with a net present value of

$15.8 million, whereas an AMR solution with the same provider will net $143 million over

the same period with a net present value of $20 million.247 The 2014 evaluation also

determined that “there are more benefits in choosing an AMI solution over AMR” and

listed all of the same benefits that AMR and AMI share, while noting that AMI includes the

additional benefits of reduced on-site turn-on, turn-off, special reads as well as company

conservation.248 Moreover, in response to Ms. Fromm’s concern that the Company has

failed to explain the “large discrepancy between the fixed network devices and electric

AMI meters that perform the same function of obtaining reads from a gas module and

delivering them to the Company’s back-office system,” Ms. DeLacy acknowledged that

the comparison “needs further assessment of each device’s technical capability and

supporting costs to install and operate.”249 Finally, the Company has not expressly

disagreed with Ms. Fromm’s testimony that Ms. DeLacy’s claimed benefits associated

with the AMR program are “the same, or nearly the same benefits the Company claims

will be realized with the AMI program” and have “not resulted in the impressive benefits

the Company originally claimed.”250

246 Confidential Exhibit A-91.247 2 TR 73; Confidential Exhibit A-91, p. 8.248 Confidential Exhibit A-91, p. 13.249 6 TR 1944-1945; 2 TR 93-94.250 6 TR 1947.

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This PFD therefore agrees with Staff that questions remain regarding the

Company’s ability to achieve the alleged benefits of AMR in this proceeding and

concludes that the Commission should disallow all AMR capital expenditures, as

requested by Staff, totaling $112,663,000, or alternatively, only allow recovery of costs

“that are net of the levelized cumulative benefits the Company projects” will be realized

from the AMR program.251 Doing so, as observed by Staff, will allow the Company to

continue with the program without burdening ratepayers with investment risk.

6. Contingency Costs

Both Staff and the Attorney General recommend that all capital expenditures

related to contingency costs be disallowed from the Company’s capital expenditure

projections.252 Although the Company’s filing included contingency costs of $77,654,000,

Staff recommends a disallowance of $77,601,000 for the reason that Staff has since

accepted the Company’s information technology (IT) actuals for 2017, which includes

acceptance of $53,000 in IT contingency costs that have since been realized.253

In support of Staff’s recommendation, Ms. Fromm testified in relevant part:

Contingency costs are those budgeted for uncertain or unforeseen events occurring and therefore cannot be judged for reasonableness and prudence at the time the Company files their projected test year. Due to the treatment of capital expenditures, if contingency expenditures were allowed the Company could earn a return of and on expenditures that were never incurred. Staff believes this is not an acceptable cost to pass on to ratepayers until these costs do occur and have been determined to have been spent in a reasonable and prudent manner.254

251 Staff’s Initial Brief, p. 50.252 Staff’s Initial Brief, p. 15, citing 6 TR 1950 and Exhibit S-17, and Appendix E to Staff’s Initial Brief; Attorney General’s Initial Brief, p. 59, citing 7 TR 2375-2376 and Exhibit AG-18.253 Staff’s Initial Brief, p. 54, Appendices E and G.254 6 TR 1951.

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Staff further notes that the Commission has previously disallowed such expenditures in

the Company’s most recent gas rate case, as well as in previous general electric rate

cases, Case Nos. U-17990 and U-17735.255

The Attorney General similarly asserts that “[i]t is not fair or reasonable for the

Company to recover the depreciation expense and the return on the investment on

potential costs that may not be actually incurred but have been added to rate base.”256

Through Mr. Fultz, the Company responds that the proposed disallowance of

contingency costs by Staff and the Attorney General should be rejected because the

Company’s use of such costs reflects established and accepted industry practice.257 Mr.

Fultz explained that the Company uses two methods to calculate contingency, a

quantitative method that is “applied to more complex projects and aligned with the

definition of ‘risk-based contingency” and a second method applied to smaller projects

based on guidelines that “simplify the expected value estimated to a percentage of cost,

based on a degree of project planning or engineering that has been completed and the

level of detail available at the time of the estimate.”258

The Company further contends that Staff’s position on contingency is flawed

because Ms. Fromm’s assertion that contingency cannot be judged for reasonableness

and prudence is not correct and that it is a “very real, reasonable, expected, and

255 Id.256 Attorney General’s Initial Brief, pp. 59-60, citing 7 TR 2375-2376.257 Consumers Energy’s Initial Brief, p. 17, citing 7 TR 1176-1177.258 2 TR 254.

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forecastable cost of a project.”259 The Company also maintains that the possibility of

contingency allowing it to earn a return of and on expenditures that were never realized

fails to justify removal of the expenditures.260 Also, according to the Company, its

contingency costs are “directly in line with the expected value of the risks,” so it is

unreasonable to exclude costs the Company fully expects to occur.261 Finally, while

recognizing that the Commission has previously disallowed the recovery of these

expenditures in recent gas and electric rate case orders, the Company nonetheless

maintains “the record evidence in this proceeding demonstrates that contingency

amounts in the Company’s project budgets are not speculative in nature, and are not

dependent upon occurrences outside the Company’s control.”262 In doing so, the

Company points out the Commission’s rulings on this issue, “effectively have established

a Commission policy that no state of facts will ever be sufficient to allow the Company to

recover contingency costs in projected project budgets presented in rate cases” – a

scenario the Company submits is not consistent with MCL 460.6a.263

This PFD is not persuaded by the Company’s position on this issue and finds that

the inclusion of contingency expenditures in rates before establishing a demonstrable

need for them is neither reasonable nor prudent. The Company’s assertion that inclusion

of contingency expenditures in a project’s total projected cost is a well-established project

259 Consumers Energy’s Initial Brief, p. 83, citing 6 TR 1950.260 Id.261 Id.262 Consumers Energy’s Initial Brief, p. 84.263 Id. at p. 84.

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management methodology incorrectly equates project management with rate recovery

and has previously been advanced by the Company and rejected by the Commission.264

And, as Staff has observed, the Commission has consistently rejected a utility’s inclusion

of contingency costs in its test year rate base project cost projections, including in the

Company’s last natural gas rate case, Case No. U-18124, wherein the Commission

reiterated that contingency budgeting “is speculative, and shifts all of the risk associated

with that item onto ratepayers, allowing for a return of and on an investment that may

never be made.”265 The Commission concluded similarly in the Company’s last electric

rate case, Case No. U-18322, wherein the Commission held, “[a]s the Commission has

found repeatedly, although allowing for contingency may be appropriate in project

planning, the inclusion of these costs in customer rates is unjust and unreasonable.”266

More recently, in Case No. U-18370, the Commission again rejected the inclusion of

contingency costs in the expenditures projected by Indiana Michigan Power Company in

its electric rate case. In its April 12, 2018 Order, the Commission held:

The Commission agrees with the ALJ that I&M's projected contingency costs, as calculated by the Staff, should be disallowed. As the Commission has found repeatedly, while allowing for contingency costs may be appropriate in project planning, the inclusion of these costs in customer rates is not reasonable. See, March 29, 2018 order in Case No. U-18322, p. 11; November 19, 2015 order in Case No. U-17735, pp. 7-11; December 11, 2015 order in Case No. U-17767 (December 11 order), pp. 19-20; December 9, 2016 order in Case No. U-17999, pp. 4-6; January 31, 2017

264 MPSC Case No. U-17990, February 28, 2017 Order, p. 8; MPSC Case No. U-18124, July 31, 2017 Order, pp. 37-38.265 MPSC Case No. U-18124, July 31, 2017 Order, p. 37, citing December 11, 2015 Order in Case No. U-17767, pp. 19-20. 266 MPSC Case No. U-18322, March 29, 2018 Order, p. 11, citing November 19, 2015 order in Case No. U-17735, pp. 7-11; December 11, 2015 Order in Case No. U-17767, pp. 19-20; December 9, 2016 Order in Case No. U-17999, pp. 4-6; and January 31, 2017 Order in Case No. U-18014, pp. 12-13.

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order in Case No. U-18014 (January 31 order), p. 12; and February 28, 2017 order in Case No. U-17990 (February 28 order), pp. 11-12. 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.267

Against this backdrop, this PFD agrees with Staff and the Attorney General and

recommends that the Commission disallow the Company’s projected contingency

expenditures of $77,601,000.

7. Capital Expenditure Updates in Rebuttal

In its initial brief, Staff takes issue with the Company’s updated capital

expenditures provided in rebuttal related to the Saginaw Trail and Mid-Michigan Pipeline

projects. Specifically, Staff maintains that the Company’s expenditures for these projects

should be reduced by $1,000 and by $9,282,000, respectively, because “the Company

provided no justification, no documentation, and not even a breakdown of the amounts”,

which prevented Staff from being able to perform a prudency review.268

The Company disagrees with Staff’s proposed rejection of its capital expenditure

adjustments, arguing that Staff had these actual amounts in advance of the filing of its

direct case, and these actual amounts served as a basis for its position with respect to

other Mid-Michigan Pipeline Project costs. The Company argues:

Company witness Fultz explained that, during the audit process, Staff requested a breakdown of expenditures for actual costs through 2017, as well as projected expenditures for 2018 and the six months ending June 30, 2019. 2 TR 269. The cost breakdown provided in response to Staff’s audit

267 MSPC Case No. U-18370, April 12, 2018 Order, p. 5.268 Staff’s Initial Brief, pp. 100-101; Appendix E, lines 21-24.

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request was provided as Exhibit A-96 (CTF-6), Staff Audit Request #143. This audit request was used by Staff witness Creisher to adjust for the removal of all costs for the Mid-Michigan Pipeline Project except for engineering and design costs. 2 TR 269. Subsequent to Staff’s adjustment, in the interest of using the most up-to-date costs in this case, the Company recommended changes to its originally filed capital expenditures to align with the updated TED-I Pipeline, Freedom Compressor Station Upgrade, and St. Clair Compressor Station Upgrade projected capital expenditures provided in Exhibit A-96 (CTF-6). The updates to the originally filed capital expenditures are reflected in Exhibit A-97 (CTF-7), which provides overall decreases in the costs presented, or updates to actual and forecasted expenditures as reflected in the detailed cost breakdowns in Exhibit A-96 (CTF-6) for Line 100A, Line 2800, the St. Clair Compressor Upgrade Project, and the Freedom Compressor Upgrade Project.269

This PFD recommends that the Commission adopt Staff’s recommendation to

exclude the Company’s proposed capital expenditure adjustments of $14,856,000 made

in the Company’s rebuttal filing. In doing so, this PFD notes that, on January 5, 2018

and pursuant to Staff Audit Request #124, the Company provided Staff with a breakdown

of expenditures for actual costs through November 2017 related the TED-I gas

transmission pipeline and Freedom and St. Clair upgrades.270 This PFD further notes

that, on January 29, 2018 and pursuant to Staff Audit Request #143, the Company

subsequently amended its response to Staff Audit Request #124 to include a breakdown

of expenditures related to these projects by year, with 2017 spend broken down by month

and 2017 actuals through December 2017, and projected spend for each project in 2018

and the 6 months ending June 30, 2019.271 However, absent from both Company

responses was any indication that the Company intended to update its rate case filing

269 Consumers Energy’s Reply Brief, pp. 60-61.270 Exhibit S-11.30.271 Exhibit S-11.31.

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based on the actuals and projected spend numbers provided to Staff. In fact, in Staff

Audit Request #124, Staff observed discrepancies between the 2018 Construction

Expected Cost Breakdown provided by the Company in Case No. U-18166 on

December 1, 2017 and the projected expenditures filed in this case in Exhibit A-26 and

Staff asked the Company to “[i]dentify if any projected expenditures for the 12 months

ending 12/31/2018 require updates based on the [Company’s] December 1, 2017 filing”

in Case No. U-18666.272 The Company responded to Staff’s request as follows in

relevant part:

The 2018 Construction Expected Cost Breakdown provided in Case No. U-18166 on December 1, 2017 does pertain only to the Line 2800 – Zilwaukee to Evon Road Valve Site – 18.5 miles of 24” Pipe Installation. The costs shown in the U-18166 filing on December 1, 2017 represent the most recent projection for the 2018 project expenditures. The Company is not updating its rate case projections at this time.273

Therefore, while Ms. Creisher was in possession of a breakdown of the Company’s

actual and projected amounts for the projects in question in advance of the filing of her

February 28, 2018 direct testimony, Ms. Creisher was given no indication at that time that

the Company intended to update its rate case projections with the actual and forecasted

expenditures reflected in the cost breakdowns provided in response to Staff Audit

Requests #124 and #143 – and, indeed the Company expressly indicated it did not plan

to do so as to the Saginaw Trail project. That the Company thereafter introduced revised

expenditure projections through Mr. Fultz’s rebuttal testimony effectively deprived Staff

272 Exhibit S-11.30.273 Id. (Emphasis added).

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and the other parties from investigating and responding to these revised projections

through meaningful discovery and a prudency review in their rebuttal case in a way that

amounts to an unfair ordering of proofs, which is precisely what the rule against improper

rebuttal is aimed at preventing.274

For these reasons, this PFD recommends that the Commission adopt Staff’s

recommendation to exclude the Company’s proposed capital expenditure adjustments of

$14,856,000 made in the Company’s rebuttal filing.

8. Accumulated Provision For Depreciation (Depreciation Reserve)

The depreciation reserve balance (also referred to as the accumulated provision

for depreciation) covering a particular test year is developed by applying the utility’s then-

effective depreciation rates to its average plant-in-service for the test year in question.

The Company initially projected the accumulated provision for depreciation for the

test year at $3,222,237,000 but, with adjustments made to its originally filed case, the

Company’s depreciation reserve has decreased to $3,220,252,000.275

Staff has projected an accumulated provision for depreciation of $3,203,986,00,

based on Staff’s proposed reductions to net plant.276

This PFD recommends that the Company’s revised depreciation reserve amount

274 See, MPSC Case No. U-16034-R, March 8, 2012 Order, pp. 9-10. (“It is true that the Commission may exercise broad latitude in considering evidence that might be rejected in a courtroom. However, that does not mean that, in cases whose outcome will affect customers' bills, the parties may divide their proofs in such a way as to prevent the opposition from being able to adequately review and respond to important evidence. The rule against improper rebuttal ‘is generally aimed at preventing the unfair ordering of proofs.’ [People v] Vasher, 449 Mich [494], at 505 [537 NW2d 168 (1995)].”)275 Exhibit A-12, Schedule B-3, line 21; Exhibit A-82, line 5.276 Staff’s Initial Brief, pp. 9-10; Appendix E.

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be used in this case, with the caveat that any changes to rate base proposed by the ALJ

and adopted by the Commission should be reflected in the level of accumulated

depreciation figures used to set the final rates in this case.

9. Construction Work In Progress

In this proceeding, none of the other parties has challenged the Company’s

proposed level of Construction Work in Progress (CWIP) expenditures, which is

essentially an addition to a utility’s rate base designed to recognize capital investment in

a project, or projects, that have not yet been completed. Accordingly, the ALJ

recommends the Commission adopt the Company’s proposed CWIP amount of

$233,039,000.277

B. Working Capital

Working capital is the amount of funds required to bridge the gap between the time

of payment of a utility’s expenses and the receipt of revenues from its customers. In the

instant case, Consumers Energy and Staff proposed slightly different figures for the

utility’s working capital allowance. Specifically, and as reflected in Exhibit A-12, Schedule

B4, Consumers Energy included $656,995,000 as the working capital figure, whereas the

Staff recommended using a figure of $662,139,000, reflecting an increase of $5,144,000.

The difference between the parties’ figures was based on the following adjustments by

Staff: (i) a reduction of accounts receivable in the amount or $6,488,075 due to an

adjustment for non-current customer attachment program installment receivables gas, as

277 Consumers Energy’s Initial Brief, Appendix B, p. 1.

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proposed by Ms. Harris; (ii) an increase of deferred debits in the amount of $19,990,000,

due to adjustments related to pension and other post-employment benefits (OPEB)

expense, as proposed by Mr. Nichols; and (iii) an increase to other current liabilities in the

amount of $8,358,000, due to adjustments to customer deposits, security deposits, and

gas customer choice (GCC) supplier deposits, as proposed by Mr. Gerken.278

The Attorney General proposes the same adjustments as proposed by Staff

related to pension and OPEB expense and related to customer and security deposits,

however the Attorney General also contends that the Company’s cash holdings should

be reduced by $21,900,000 to a cash balance level of $1,000,000.279 Relying on the

testimony of Mr. Coppola, the Attorney General maintains that “[f]or the Company to earn

a return at the overall cost of capital on this larger cash balance is costly for customers

and is unnecessary.”280

The Company has agreed with Staff’s and the Attorney General’s proposed

adjustments to working capital related to pension and OPEB expense and customer and

security deposits, but argues that the Attorney General’s proposed adjustment related to

cash holdings should be rejected for failing to recognize the importance of having

adequate liquidity on hand for utility operations, including appropriate protection against

volatility or potential inaccessibility of capital markets. The Company outlined Mr.

Denato’s rebuttal testimony, wherein Mr. Denato set forth the bases in support of the level

278 6 TR 2036-2037; Exhibit S-2, Schedule B-4. 279 Attorney General’s Initial Brief, pp. 97-98; citing 7 TR 2410-2412.280 Id. The Attorney General’s Initial Brief on this issue consists entirely of a verbatim recitation of Mr. Coppola’s testimony, unaccompanied by argument or analysis.

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of cash presented by the Company, including his explanation for why reliance exclusively

on short-term debt to meet the Company’s liquidity requirements increases financial

risk.281 Mr. Denato further explained that the Company’s projected cash balance is

necessary due to the seasonality in cash flows, the timing of new bond issuances, and

the need for sufficient liquidity to carry out the Company’s large capital expenditure

program.282

With regard to the Attorney General’s proposed reduction in the Company’s

forecasted cash balance, this PFD finds the Company’s position to be more persuasive.

To be sure, the record reflects that valid reasons exist for the added liquidity provided by

including temporary cash investments as part of the utility’s working capital, such as

smoothing the seasonality of cash flows, providing added flexibility in obtaining long-term

financing on more favorable terms, and providing financial support for the company’s

large and ongoing capital expenditure programs.283 Moreover, the Attorney General

presented no analysis or discussion of this issue beyond a block quote of the testimony

of Mr. Coppola. As noted by the Company, issues insufficiently briefed are deemed

abandoned.284

The Company having agreed to the remaining adjustments proposed by Staff and

the Attorney General, this PFD recommends the Commission adopt the Company’s

281 Consumer’s Initial Brief, p. 89, citing 4 TR 1116-1117, 1152.282 4 TR 1116-1117.283 Id.284 People v Van Tubbergen, 249 Mich App 354, 365; 642 NW2d 368 (2002).

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revised working capital balance of $662,139,000, an amount also accepted by Staff.285

1. Calculation of Cost of Gas Sold and Gas Stored Underground

The Company’s witness, Deborah S. Pelmear, presented the utility’s gas pricing

information used to establish the 13-month average volume and cost of gas stored

underground, as well as the average cost of gas sold.286 Ms. Pelmear described Exhibit

A-64 as reflecting the end of the month underground gas storage volumes and dollars

resulting from the Company’s natural gas purchases for its GCR and GCC customers.287

Through June 2019, the Company projects a 13-month average volume of working gas

in storage of 122,300 MMcf and a 13-month average cost of gas in storage of $367,864,

128 ($3.008 per Mcf).288 In developing Exhibit A-64, the utility used the average New

York Mercantile Exchange (NYMEX) settlement prices for July 2018 – June 2019 as of

the first five business days of June 2017, which averaged $2.934/MMBtu for July 2018 –

June 2019.289

The Company’s projected average cost of gas sold for July 2018 – June 2019 is

$3.094/Mcf ($695,309/224,699). According to Ms. Pelmear, this amount “reflects

locational pricing differences between NYMEX (Henry Hub) and other supply locations

(basis), transportation costs, unused reservation charges, and the GCR accounting

treatment of net system uses.”290

285 Consumers Energy’s Initial Brief, Appendix B, page 1, line 9.286 2 TR 207-208; Exhibit A-64.287 Id.288 2 TR 208.289 Id.290 Id.

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Staff recommends the use of a five-year average of actual Gas-In-Kind (GIK)

volumes forecast, and contends the Company failed to adhere to the forecasting

methodology approved by the Commission in Case No. U-18124, a contention with which

the Company disagrees.291 The Company has nonetheless accepted Staff’s

recommended GIK volumes forecast.292

This PFD finds Staff’s recommended use of a five-year average of actual GIK

volumes, to which the Company has agreed, to be reasonable and appropriate and

should be adopted by the Commission.

C. Unamortized Manufactured Gas Plant Balance

Consumers Energy has 23 sites that formerly housed Manufactured Gas Plants

(MGP).293 On behalf of the Company, Daniel Harry testified that the Commission

previously addressed environmental investigation and remediation expenditures at

former MGP sites in Case No. U-10755 and concluded that such expenditures should be

subject to deferred accounting, with amortization over ten years, beginning the year after

the expenditures are incurred. 294 Mr. Harry elaborated:

The approach adopted by the Commission envisioned that prudence reviews would occur in rate cases and that following a prudence review (i) the amortization expense would be included in rates; and (ii) the deferred balance would be included in rate base and would earn a return at the authorized rate of return. The approach adopted by the Commission also provided for deferred accounting and amortization of third-party recoveries in excess of the costs of recovery over 10 years, the inclusion of the unamortized balance in rate base, and deferred tax accounting. In Case No.

291 6 TR 2046; 2 TR 210-211.292 2 TR 210-211.293 3 TR 593.294 3 TR 553.

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U-13000, the Commission reaffirmed this accounting treatment.295

As set forth in Exhibit A-34, page 2, column (b), the average unamortized MGP

plant balance included in the Company’s initial filing for the test year was $51,978,000.296

However, the Company has since updated these costs on rebuttal with actual 2017

calendar year MGP remediation spending, reflecting a change from $33,758,000 for

projected 2017 costs to $27,748,000 in actual 2017 spending, and an overall lowered net

unamortized MGP plan balance for the test year of $46,570,000.297

Through the testimony of Ms. Edelyn, Staff proposed a $30,382,000 reduction to

the Company’s initial projected unamortized MGP balance, on the basis that such costs

were merely estimated and Staff has not yet audited the Company’s 2017 MGP

remediation expenditures.298 According to Staff, although the Company proposed on

rebuttal to update projected 2017 costs with actuals by making 2017 MCP invoices

available to Staff for review, such a proposal on March 21, 2018, the last day for filing

rebuttal testimony, was unreasonable as the 2017 invoices should have been made

available to Staff prior to the February 28, 2018 deadline for Staff’s direct case.299 Staff

therefore submits that, absent the actual costs for the 2017-2018 period, Staff could not

“evaluate the reasonableness of remedial activities nor the prudence of costs associated

with actions that have not yet occurred.”300

295 Id.296 3 TR 553-555.297 3 TR 566; Exhibit A-98.298 Staff’s Initial Brief, p. 11, citing 6 TR 2090.299 Staff’s Initial Brief, p. 12.300 Id.

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The Company argues in its reply brief that Staff’s assertion that the Company did

not make its 2017 invoices available for review until March 21, 2018 has no record support

and Mr. Harry’s testimony that the Company would make 2017 invoices available should

not be construed to mean this was the first time the Company made the invoices available

for review.301 The Company further posits that it “should not be deprived of recovery of

reasonably and prudently incurred costs simply because Staff did not review 2017 MGP

remediation costs during its January 2018 audit.”302

This PFD finds the Company’s position on this issue to be rather baffling and

circular in nature. On the one hand, and consistent with Commission precedent, Mr.

Harry testified that “only incurred, reviewed, and approved MGP remediation expenses

should be included in the deferred MGP balance and amortized for ratemaking.”303 To

this end, Mr. Harry indicated the Company would make the 2017 MGP invoices available

to Staff for review.304 On the other hand, “if there is insufficient time to conduct a review

during this case,” the Company maintains “that the actual 2017 expenditures [should] be

included in this case.”305 Moreover, the Company points out that there is no record

support for Staff’s assertion that the Company did not make its 2017 invoices available

for review until March 21, 2018 – and, yet, this begs the question of why Mr. Harry found

it necessary in his rebuttal testimony to make the 2017 MGP invoices available to Staff

301 Consumers Energy’s Reply Brief, p. 95.302 Id.303 3 TR 566.304 Id.305 Id.

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for review if the Company had indeed previously provided Staff with such invoices

pursuant to Staff’s January 2018 audit. Indeed, Mr. Harry’s testimony and the record as

a whole are devoid of any indication that the Company had provided Staff with its 2017

MGP invoices pursuant to Staff’s January 2018 audit.

What remains clear and undisputed, however, is the fact that Staff has been unable

to perform a prudency review of the Company’s 2017 actual MGP costs. Consequently,

this PFD recommends that the Commission adopt Staff’s proposed net unamortized MGP

balance of $21,596,000 for the test year.

D. Rate Base Summary

The Company requests that the following rate base be adopted:

Net Plant $ 4,732,387,000Working Capital 662,139,000Manufactured Gas Plant 46,570,000Retainers & Advances (3,515,000)Total Base Rate $ 5,437,581,000306

For the reasons discussed above, this PFD finds that the Company’s net plant

amount should be reduced by $301,409,000, based on the following recommended

adjustments:

1. $14,099,000 – Large New Business Projects2. $92,799,770 – Pipeline Integrity Program3. $4,819,000 – Pipeline Integrity-TOD Program4. $3,700,000 – Material Condition Non-Modeled Program5. $2,712,000 – Material Condition Renewals Program6. $617,000 – TED-I Program – Mid-Michigan Citygate Station7. $14,469,000 – TED-I Program – Pressure-Limiting Devices8. $10,651,000 – TED-I Program Major Projects9. $450,000 – Gas Compression and Storage – St. Clair Compressor Station10.$641,355 – Information Technology – DCE Website

306 Consumers Energy’s Initial Brief, Appendix B, p. 1, line 10, column (d).

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11.$5,570,482 – Information Technology – Canceled Projects12.$234,611 – Information Technology – Meter Reading Hardware Costs13.$384,000 – Information Technology – Gas Control Solutions14.$112,663,000 – Gas AMI/AMR15.$77,654,000 – Contingency Costs16.$14,856,000 – Capital Expenditure Updates in Rebuttal17.$21,596,000 – Unamortized Manufactured Gas Plant Balance

These capital expenditure adjustments, once adjusted for the revised accumulated

depreciation expense, result in a projected rate base of $5,136,172,000, as shown in

Appendix B to this PFD.

V.

CAPITAL STRUCTURE, COST OF CAPITAL, AND RATE OF RETURN

The parties disagree on the long-term debt and common equity components of

Consumers Energy’s capital structure and the appropriate return on equity.

Consequently, the areas of dispute to be addressed are: (1) the correct capital structure

component balance to be adopted in this case, which requires resolution of a dispute

between Staff and the Company regarding Staff’s proposed reductions to the Company’s

test year common equity infusions, and resolution of disputes between the Attorney

General, ABATE, and RCG, and the Company regarding proposed adjustments of the

Company’s common equity and long-term debt balances; and (2) the appropriate return

on common equity, which involves the parties’ significant disagreement, as set forth in

both testimony and argument submitted by the parties.

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A. Test Year Capital Structure

The Company has proposed that the rate of return should be calculated using a

projected Consumers Energy capital structure for the 12- month period ending June 30,

2019.307 Staff agrees with the amounts outstanding to be used in the Company’s

proposed capital structure for long-term debt, short-term debt, preferred stock, deferred

federal income taxes, customer deposits, other interest-bearing accounts, and the job

development investment tax credit (JDITC).308 Staff differs with the Company’s

recommendation for common equity balance and cost rates.

1. Common Equity Balance

The Company projected an average common equity balance of $6.703 billion, and

an equity ratio (as a percent of permanent capital) for the test year ending June 2019 of

52.49% and overall cost of permanent capital of 40.91%.309 In calculating the equity

balance, Mr. Denato began with the common equity balance as of December 31, 2016,

and then made adjustments to reflect retained earnings from August 2017 through June

2019 and an adjustment to reflect the average of equity infusions from August 2017

through June 2019.310 The Company asserts this equity ratio is in line with the Company’s

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

equity ratios and with recently approved rate cases in the low 50% range.311 Mr. Denato

307 4 Tr 1076; Exhibit A-14, Schedule D-1; Exhibit A-94.308 Exhibit A-14, Schedule D-1; Exhibit A-94; Consumers Energy’s Initial Brief, Appendix F; Exhibit S-4, Schedule D-1 (revised). Originally, the Company included customer deposits and other interest-bearing accounts within its proposed capital structure. However, after Staff opposed this inclusion, the Company agreed with Staff’s recommendation to remove customer deposits and other interest-bearing accounts from the projected capital structure. 4 Tr 1101. 309 Exhibit A-14, Schedule D-1a.310 4 Tr 1077; Exhibit A-14, Schedule D-1a. 311 4 Tr 1079.

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argues that it is necessary to maintain an equity ratio higher than 50%, asserting that its

proposed common equity balance and equity ratio enables the Company to “maintain

strong credit ratings and better withstand any shocks in the financial markets”, thereby

ensuring a “smooth implementation” of its “significant” capital expenditure program.312

Also, its proposed equity ratio enables the Company to “prefund its debt maturities to take

advantage of low interest rates without jeopardizing the financial ratios.”313

Moreover, the Company asserts that the proposed equity ratio is justified because

credit rating agencies include securitization debt, power purchase agreements (“PPAs”),

benefit obligations, and leases as “debt” when calculating debt to equity ratios, and, as

such, incorporating the projected equity infusions in 2018 and 2019 in the common equity

balance enables the Company “to maintain reasonable ratios after such adjustments.”314

Indeed, Mr. Denato asserts that, after considering rating agency adjustments, the

Company’s equity ratio is 170 basis points below the average equity ratio for the

Company’s peer group, which supports the need for the Company to maintain a relatively

higher equity ratio before adjustment to be on par with comparable utility companies after

adjustment.315

In his direct testimony, Mr. Denato asserted that the Company’s “goal” was to

return to a balanced capital structure by 2023 in accordance with the Commission’s

directive in its last rate case (U-18124, Order, July 31, 2017):316

312 Id.313 Id.314 4 Tr 1079-1080.315 4 Tr 1080; Exhibit A-25.316 MPSC Case No. U-18124, July 31, 2017 Order, p. 46 (“Consumers shall, in its next rate case, articulateits strategy to return to a balanced capital structure and the steps it intends to take to reach its stated goal.”)

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Over the next five 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. The Company has taken a substantial step in this progression in the current case with a recommended common equity ratio of 52.49%, 61 basis points lower than the equity ratio of 53.1% approved in Case No. U-18124.

The Company plans to reduce the amount of equity infusions into Consumers Energy in order to reduce its common equity ratio over time. The Company plans to reduce equity infusions by approximately $100 million in 2018 and by a similar amount annually until a balanced capital structure is reached. The pace of this reduction aligns well with the decrease in the Company’s PPA obligations over the next five years.317 Staff, the Attorney General, ABATE and RCG have concerns with the common

equity component of the Company’s capital structure, with Staff proposing a reduction to

the Company’s test year common equity infusions, the Attorney General seeking an

adjustment to the Company’s common equity and long-term debt balances to achieve a

50/50 debt-to-equity balance, and ABATE and RCG seeking to have the Company move

closer to a 50/50 debt-to-equity ratio more quickly than proposed by the Company.

a. Staff

Staff recommends a common equity balance of $6.666 billion, which represents

52.36% of the permanent capital structure and overall permanent cost of capital of

40.77%.318 Mr. Megginson explained that the Staff’s common equity balance differs from

the Company’s recommendation primarily due to Staff “not recognizing” an equity infusion

the Company planned in January 2019 as being counter to the Commission’s directive

that the Company “return to a balanced capital structure”:

317 4 Tr 1081.318 6 Tr 1717.

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Staff followed the Company’s methodology with respect to retained earnings, and thus provided for full retained earnings in Staff’s projected equity balance. However, the January 2019 equity infusion is not only counter to the spirit of the Commission’s directive, but was not reasonably explained as a requirement, especially in the last 6-months of the test year. The Company also stated that it planned to reduce its equity infusions by $100 million annually, thus the January 2019 equity infusion did not appear necessary from that standpoint. The Company also stated that the timing of its referenced equity ratio reduction was not set in stone, so Staff’s recommended 52.36% equity ratio is not only reasonable, but more in line with the Commission’s objective of a balanced capital structure and should be adopted.319

In rebuttal, Mr. Denato counters that Staff’s proposed non-recognition of the

January 2019 equity infusion “would leave the Company with one equity infusion of $100

million (in January 2018) over the entire two-year period running July 2017 to June

2019.”320 Moreover, Mr. Denato argues that his projected common equity balance in this

case takes into account equity infusions from CMS Energy “that are planned, needed,

and consistent with the expected capital needs of Consumers Energy through the test

year ending June 2019.”321

In addition, Mr. Denato cites the new federal tax law, The Tax Cuts and Jobs Act

of 2017 (“TCJA”), as supporting the Company’s proposed common equity balance in this

case:

The TCJA, effective beginning in January 1, 2018, reduces the corporate taxrate, and effects current and deferred tax accounting methods used by utilities. In Case No. U-18494, a proceeding initiated on the Commission’s own motion to consider changes in utility rates as a result of the TCJA, the Company estimated a revenue reduction of $120 million for its electric utility business and $52 million for its gas utility business, and a one-time reduction to its total deferred tax balances of $1.5 billion, as a result of the federal tax reduction. While these savings

319 6 Tr 1718-1719 (footnotes omitted).320 4 Tr 1102.321 Id.

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will be passed on directly to our customers, they do create less on-going cash flows to the Company and result in lower rating agency debt coverage ratios.322

The Staff still disagrees with the Company’s position on its proposed equity

infusions, arguing that the 2019 equity infusion “runs counter to the Company’s own

objective of lowering its more expensive common equity balance”.323 Regarding the

TCJA, the Staff asserts that “that because deferred taxes are deducted from rate base,

their elimination will only have a short-term negative impact on utilities, and will present a

long-term benefit.”324

This PFD finds that adoption of the Company’s revised common equity balance is

reasonable and supported by the record. Staff’s recommendation has included no

analysis of the Company’s actual capital needs and no evidence that the equity infusions

were unnecessary or overstated.325 Nor has Staff offered any evidence in contradiction

of Mr. Denato’s assertions that the utility’s projected common equity balance and equity

ratio will enable the Company to maintain strong credit ratings and better withstand any

322 4 Tr 1104. In his rebuttal testimony, Mr. Denato reiterates that the Company believes that its proposed equity ratio of 52.49% is appropriate even with the passage of the TCJA. 4 Tr 1106. However, Mr. Denato adds that the TCJA “will have a significant financial impact to the Company on a long-term basis”, such that the plan to achieve a 50% equity ratio by 2023 is “no longer reasonable” and that maintaining an equity ratio of 52.5% “will be appropriate for the foreseeable future.” Id. Similarly, in its reply brief, the Company makes clear that the TCJA does not support a change to its proposed equity ratio in this case:

the Company has not proposed to deviate from the step-down in its equity ratio originally proposed in this case as a result of the TCJA. Again, the Company’s proposal in this case is simply the continuation of the first step in the plan approved by the Commission just two months ago in Case No. U-18322. The Company included information regarding the impact of the TCJA in its rebuttal testimony in this case simply (i) to caution the Commission about the serious adverse impacts that could result if the Commission moved the Company’s equity ratio in the current case even lower than the step-down already approved in Case No. U-18322 and (ii) to provide the Commission advanced notice that the further step-downs originally planned for future rate cases will likely need to be reconsidered.

Consumers Energy’s Reply Brief, p. 101 (citations and original emphasis omitted). 323 Staff’s Initial Brief, p. 103 (citations omitted).324 Id.325 The Staff did not offer any rebuttal testimony in this case.

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shocks in the financial markets, thereby ensuring a smooth implementation of its capital

expenditure program. Moreover, as the Company asserts, its recommended equity ratio

is lower than its last recommended equity ratio, and thus is in accordance with the

Commission’s directive that the Company return to a balanced capital structure.326 In

addition, the Company agrees that the TCJA does not support an equity balance greater

than the equity ratio proposed by the Company. Accordingly, this PFD recommends the

Commission adopt the Company’s proposed $6.703 billion common equity balance,

representing a common equity ratio of 52.49%, and overall cost of permanent capital of

40.91%, as set forth in Appendix D to this PFD.

b. Attorney General

The Attorney General recommends a capital structure of 50% common equity and

50% debt and preferred stock, which he proposes to achieve by increasing the long-term

debt component by $322 million and reducing the common equity component by the same

amount.327 According to Mr. Coppola, such an adjustment is warranted because of (1) the

Commission’s directive in the Company’s last electric rate case that moving to a 50/50

capital structure is appropriate in the absence of evidence suggesting otherwise; (2) the

Company’s practice of funding a significant part of its equity contributions with funds from

326 Consumers Energy’s Initial Brief, p. 99. Staff takes issue with the Company’s assertion in this case that, because of the TCJA, the Company’s plan to achieve a 50% equity ratio by 2023 is no longer reasonable and that it will need to maintain an equity ratio of 52.5% for the foreseeable future. See, Staff’s Reply Brief, p. 22-23. However, the Company counters that the Commission should “reserve for the Company’s next case any further discussion about the appropriate next steps for the Company’s common equity ratio.”Consumers Energy’s Reply Brief, p. 99. As the TCJA was recently passed and a longer period of market data and updates of analyst forecasts is needed before its effect on the capital structure can be well known, this PFD recommends that any assessment by the Commission on whether the TCJA supports a change in the Commission’s directive to move to a balanced equity ratio by 2023 be made in the Company’s next rate case.327 7 Tr 2412: Exhibit AG-42.

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long term debt issued at the parent company level; and (3) the fact that the common

equity ratio of the peer group, used to assess the cost of common equity in this case,

averages slightly above 50%.328

Regarding the Company’s initial proposal to reduce its common equity ratio each

year until the 50% ratio is achieved in 2023 in order to meet the Commission’s directive,

Mr. Coppola asserts that the Company’s plan is “premised on declining capital

expenditures and reductions in PPAs, which are unlikely to be met.”329 Moreover, Mr.

Coppola asserts that PPAs should not be considered regarding the equity ratio as most

of the Company’s peer utilities buy power under PPAs and PPAs are not relevant to

setting rates for natural gas distribution businesses. Also, he notes that different peer

company groups are used to establish the cost of common equity for each business,

which dictates the exclusion of items that pertain singularly to one business or the other.330

In addition, Mr. Coppola testified that CMS Energy, the Company’s parent, can

make the Company’s common equity ratio “whatever it wants”, as CMS management can

direct at any time how much in capital it wants to inject into the Company and “call it equity

capital.”331 Moreover, Coppola noted that the average common equity ratio of the peer

company group was 50.7%, and that it is critical to synchronize the capital structure of

the Company to the peer group average as closely as possible in order to have

consistency with the cost of equity capital derived from those peer group companies.332

328 7 Tr 2413.329 7 Tr 2414.330 7 Tr 2415.331 7 Tr 2416.332 7 Tr 2419; Exhibit AG-45.

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Thus, he asserts that the Company’s proposed common equity capital ratio of nearly

52.5% is not acceptable and is also more costly to customers.333

Mr. Denato responds that Mr. Coppola’s proposed reduction of the equity ratio to

50% in the current case is “arbitrary”.334 Also, in addition to referencing his prior testimony

regarding why it is necessary for the Company to maintain an equity ratio higher than

50%, Mr. Denato asserts that the Commission’s February 17, 2017 Order in Case No. U-

18424 required the Company to provide a more complete analysis with respect to its

equity ratio, and “not necessarily to take immediate action.”335 Mr. Denato adds that the

federal tax reform legislation “lends further justification to the 52.49% equity ratio

proposed in this case and makes the equity ratio approved in this case critical to the

financial health of the Company.”336

333 Id. The Attorney General also proposes that Customer Deposits and Other Interest-Bearing Accounts be excluded from the authorized capital structure. 7 Tr 2420. As indicated, the Company has agreed to this change. 334 4 Tr 1110.335 Id. Although not dispositive here, this PFD feels compelled to note that, by this testimony, the Company appears to misread the Commission’s prior orders on this issue. In its February 28, 2017 Order in Case No. U-17990 at page 64, the Commission initially offered the Company the option of providing a “more complete analysis” of why not achieving a balanced structure within five years would be reasonable:

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 included to explain why such a result is reasonable and prudent.

In the Company’s next rate case, Case No. U-18124, the Commission noted in its July 31, 2017 Order at pages 45-46 that the Company’s proposed capital structure in that case “represents a departure from its stated objective of a roughly balanced capital structure” and accordingly directed the Company to “return to a balanced capital structure” without offering an option to explain why that would not be reasonable:

The Commission cannot overemphasize the company’s responsibility to rebalance its equity and debt capital. . . 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.

336 Id.

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Regarding PPA’s, Mr. Denato replies that while other utilities utilize PPAs to

purchase power, the relative amount of PPAs assigned as “debt” by credit rating agencies

is much higher for the Company on average.337 Regarding a proxy group comparison, Mr.

Denato testified that Mr. Coppola’s proxy group equity ratio calculation used ratios at the

parent holding company level and thus may be “distorted”, while a comparison at the

regulated subsidiary level shows an average equity ratio that is “comparable to, though

slightly higher than”, the equity ratio recommended by the Company.338

This PFD finds the Attorney General’s proposed adjustment to the common equity

balance is not well supported by the record. The Attorney General has not offered any

rationale for his argument that a 50% equity ratio should be set because of the utility’s

combined capital structure of its gas and electrical divisions. Moreover, as noted by the

Company, the Attorney General’s argument that the Company’s equity balance is at least

in part funded by long term debt from its parent company and should therefore be adjusted

downward has previously been considered and rejected by the Commission.339 Mr.

Coppola has also failed to demonstrate whether adoption of his proposed 50/50 ratio

would actually benefit Consumers Energy’s customers. In contrast, the Company has

demonstrated that, considering its planned investments over the next few years and the

corresponding need to maintain its credit ratings, its proposed equity ratio is necessary.

337 4 Tr 1111.338 4 Tr 1114.339 MPSC November 2, 2009 Order, Case No. U-15645; MPSC May 17, 2010 Order, Case No. U-15986; MPSC June 7, 2012 Order, Case No. U-16794.

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c. ABATE and RCG

ABATE’s Ms. LaConte asserts that Consumers’ common equity ratio is “too high”,

and that the Company can “maintain its strong credit ratings and implement its capital

expenditure program” with a lower equity ratio, while also taking advantage of low interest

rates.340 She adds that a higher common equity ratio will increase costs to ratepayers

because equity is more expensive than debt.341 Thus, Ms. LaConte recommends a

common equity ratio of 51.49% which “moves the Company closer to its goal of a 50/50

debt-to-equity ratio, as required by the Commission”, and which represents a “gradual

change” in the Company’s equity ratio.”342

Similarly, RCG’s William Peloquin also asserts that the Company needs to reduce

its equity component to 50% and that “additional debt” is the method to reduce the equity

percentage.343

The Company responds that Ms. LaConte provides no details or analysis

supporting her conclusion that the Company would maintain its current credit ratings with

a lower equity ratio.344 In addition, Mr. Denato replies that Mr. Peloquin’s assertion also

is unsubstantiated and “far too severe”, and that a 50% equity ratio “would have harmful

implications on the Company’s credit strength, cost of borrowing, and ultimately the

customer.”345

340 7 Tr 2201.341 Id.342 Id.343 7 Tr 2653. 344 4 Tr 1118. 345 4 Tr 1119.

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This PFD finds the proposed adjustments to the common equity balance offered

by ABATE and RCG are not well supported by the record. As Mr. Denato notes, neither

proposal is substantiated with details or analysis. Conversely, as indicated, the Company

has demonstrated that its proposed equity ratio is necessary given its planned

investments and its need to maintain its credit ratings.

2. Long-Term Debt Balance

For the test year, Consumers Energy projects a long-term debt balance of $6.028

billion, a projection with which Staff concurs.346 The Company’s long-term debt balance

projection is therefore adopted.

3. Short-Term Debt Balance

For the test year ending June 30, 2019, Consumers Energy projects a short-term

debt balance of $184 million, a projection with which Staff concurs.347 The Company’s

short-term debt balance projection is therefore adopted.

4. Deferred Federal Income Tax

For the test year ending June 30, 2019, Consumers Energy projects a $3.332

billion deferred tax balance, a projection with which Staff concurs.348 The Company’s

deferred federal income tax balance projection is therefore adopted.

5. Other Capital Structure Balances

Both Consumers Energy and Staff used projected balances for preferred stock and

346 4 Tr 1107-1108; 6 Tr 1717-1718; Exhibit A-94; Exhibit S-4, Schedule D-2.347 4 Tr 1102, 6 Tr 1717-1718; Exhibit A-94; Exhibit S-4, Schedule D-2.348 Consumers Energy’s Initial Brief, p. 100; 6 Tr 1717-1718; Exhibit A-94; Exhibit S-4, Schedule D-2.

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JDITC based on internal projections from the Company’s Tax Department that the

Company expects to record from August 2017 through June 2019, with components for

JDITC based upon the allocation of long-term debt, preferred stock, and common equity.

The adjustments total $11 million on a 13-month average basis for the test year.349

B. Cost Rates

1. Return on Common Equity

A utility’s cost of common equity, generally referred to as the return on equity

(ROE), is the return that investors expect in order to provide the utility with capital for use

in its various operations. The cost of this capital essentially represents an opportunity

cost; in order to induce investors to purchase common stock or bonds, there must be the

prospect of receiving earnings sufficient to make the investment attractive when

compared to other investment opportunities.

The criteria for establishing a fair rate of return for utilities like Consumers Energy

evolved from the decisions issued by the United States Supreme Court in Bluefield Water

Works Co. v Public Service Commission of West Virginia, 262 US 679 (1923) and Federal

Power Comm. v Hope Natural Gas Co., 320 US 591 (1944). With these decisions, the

Court determined that when establishing a fair rate of return for a public utility,

consideration must be given to both customers and investors. As enunciated by the

Commission in previous rate case final orders, the rate of return “should not be so high

as to place an unnecessary burden on ratepayers, yet should be high enough to ensure

349 Exhibit A-14, Schedules D1 and D1a.

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investor confidence in the financial soundness of the enterprise.”350 The Commission

has observed nonetheless that any determination of what is fair and reasonable “is not

subject to mathematical computation with scientific exactitude but [rather] depends upon

a comprehensive examination of all factors involved, having in mind the objective sought

to be attained in its use.”351 Moreover, “[w]hat is reasonable depends upon a

comprehensive examination of all factors involved, having in mind the objective sought to

be attained in its use. In addition, in its recent order in Consumers Energy’s electric rate

case, the Commission noted that “it is not realistic to make a significant change in ROE

absent a radical change in underlying economic conditions.”352

Against the backdrop of these principles, an analysis is conducted of the factors

comprising the appropriate rate of return to be adopted in this case.

As discussed below, four witnesses testified and submitted exhibits regarding the

appropriate ROE to be set in this case. The analysts employed a variety of models using

groups of proxy companies chosen to be comparable to Consumers Energy, resulting in

a range of estimates of the cost of equity capital. The analysts made 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 and the

analysts’ views of the relative risks faced by Consumers Energy in comparison to the

proxy companies.

350 MPSC Case No. U-15244, December 23, 2008 MPSC Order, p. 12.351 Id., citing Meridian Twp. v City of East Lansing, Mich., 342 Mich 734, 749 (1955).352 MPSC Case No. U-18322, March 29, 2018 Order, p. 44.

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Mr. Maddipati presented an analysis for the Company and, in his direct testimony,

recommended a return on equity of 10.50%. However, in his rebuttal testimony, Mr.

Maddipati recommended an increased return on equity of 10.75% due to the recently

enacted tax law.353 Mr. Megginson presented the Staff’s case on this issue,

recommending a return on equity of 9.60%, which is at the upper end of Staff’s ROE

range of 8.70% to 9.70%. Mr. Coppola testified on behalf of the Attorney General and

recommended a return in the range of 9.50%. Ms. LaConte, on behalf of ABATE, did not

make a specific recommendation of an ROE but recommended a return within a range of

8.76% and 10.12%, and used an ROE of 9.72% in calculating her proposed overall rate

of return for the Company. The parties’ respective positions as set forth in their

evidentiary presentations and post-hearing briefs are summarized below, followed by

analysis of the merits of these positions and this PFD’s recommendation.

a. Consumers Energy

As noted above, Consumers Energy originally sought an authorized ROE of

10.50%, which represents a 40-basis point increase from the 10.10% level set in the

Company’s last fully litigated gas rate case, Case No. U-18124. However, as set forth in

its rebuttal testimony, the Company now seeks an authorized ROE of 10.75%, 65 basis

points above its currently authorized ROE.

353 While contending that the ALJ should recommend, and the Commission should find, that an ROE of 10.75% is appropriate, Consumers also asserted that “in any case” the Commission should adopt a ratemaking ROE “no lower than” the 10.50% it originally proposed in this case. Consumers Energy’s Initial Brief, p. 110. Moreover, the Company appears to recognize that the Company’s currently authorized ROE is the ultimate “line” that it argued should not be crossed in setting an appropriate ROE in this case. “Any authorized return lower than the Company’s current authorized rate of 10.10% . . . would not be reasonable.” Consumers Energy Initial Brief, p. 121. “[A]ny reduction below the Company’s current 10.10% ROE would be particularly unreasonable given current economic and financial conditions . . and the need for Consumers to raise substantial amounts of funding for planned investments in Michigan.” Id., p.142.

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In his direct testimony, Mr. Maddipati explains that his original recommendation of

10.50% is the mid-point of his range of 10.00% - 11.00%, and is based upon consideration

of the current state of the economy and capital markets, the need to continue to attract

capital to finance the large capital expenditure program at the Company’s gas business,

the risk profile of the Company’s gas business compared to the proxy group, established

principles for setting a fair ROE, and the results of various economic models used to

calculate the cost of equity.354 He adds that although the Company’s “significant

infrastructure investment” would justify an ROE near the “high end of his range”, he’s

recommending an ROE at the mid-point of 10.50%, which would “balance the needs of

customers as well as provide incentive to invest in necessary infrastructure.”355

Mr. Maddipati also testified that the authorized ROE is one of the most important

parameters used by analysts to determine the attractiveness of investing in utilities, and

that while the analyst and investor community generally view the regulatory environment

in Michigan as constructive, it is important that the Company continues to hold a good

reputation among investors.356

Mr. Maddipati testified that it is appropriate to apply multiple ROE estimating

methods while taking into consideration that the results of the “standard quantitative

models” often make assumptions “that do not fully reflect the returns that investors expect

given current economic and financial conditions”:

The models are based on the assumption that economic conditions are relatively stable and that current market inputs are reflective of their long-term outlook. That assumption is not currently being met. There is

354 4 Tr 809.355 4 Tr 810.356 4 Tr 810-811, 829.

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significant uncertainty, mainly because of the unprecedented amount of intervention by central banks during the last several years. As a result, the models tend to understate the return that investors currently require to compensate them for risk. Furthermore, mechanical application of these models without consideration to the underlying assumptions would not meet the requirements in Hope and Bluefield as indicated in FERC Opinion 551.357

Mr. Maddipati offered that the uncertainty in global markets and the United States

economy “is expected to continue into the near future”.358 Mr. Maddipati also testified

there is no accurate or complete source for ROE trends around the country.359 He adds

that the removal of the 180-day self-implementation option will introduce “new regulatory

lag”, such that the new legislation does not “reduce the risk faced by equity investors in

the utility.”360 Mr. Maddipati further indicated that he applied multiple financial

methodologies using a proxy group of companies that were similarly situated to

Consumers Energy.361 Specifically, to be a part of his proxy group, each entity had to be

classified as a gas utility in the S&P Global database, as well as: (i) have a market

capitalization greater than $1 billion and less than $25 billion; (ii) be headquartered in the

United States; (iii) currently not be a recent merger target or be engaged in significant

restructuring; (iv) be paying current common stock dividends; and (v) have bonds rated

at or above a minimum investment grade of Baa3 by Moody’s and BBB- by Standard &

Poor’s.362 These criteria resulted in a proxy group of 15 companies.363

357 4 Tr 816-817.358 4 Tr 833. 359 4 Tr 822. 360 4 Tr 831.361 4 Tr 837.362 4 Tr 837-838.363 4 Tr 838; Exhibit A-14, Schedule D-5.

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Mr. Maddipati then used this group of proxy companies in performing various

analyses based on the Capital Asset Pricing Model (CAPM), the Empirical CAPM

(ECAPM), the risk premium analysis, the Discounted Cash Flow (DCF) analysis, and the

comparable earnings analysis.364

Applying each of the five above-mentioned analyses performed by Mr. Maddipati

to the proxy group that he selected produced the following average rate of return figures:

the two CAPM analyses (Normalized and Low Interest Rate) resulted in an average of

10.88%, the two ECAPM analyses (Normalized and Low Interest Rate) produced an

average of 11.27%, the two Risk Premium analyses (Normalized and Low Interest Rate)

resulted in an average of 13.17%, the two DCF analyses (Analyst Consensus and

Company Guidance) produced an average of 9.86%, and the Comparable Earnings

analysis resulted in an average of 11.08%.365 Mr. Maddipati concludes that his initial

recommended 10.50% ROE is consistent with both his qualitative and quantitative

analysis, all of which support “an ROE that is higher than the current level.”366

b. Staff

In contrast to Consumers Energy, Staff recommends adopting an ROE of 9.60%,

which is at the upper end of Staff’s ROE range of 8.70% and 9.70% provided by Mr.

Megginson.367 According to Mr. Megginson, his analysis began by using a “modified

version of the Company’s proxy group” and then identifying the following criteria required

to ensure that the proxy group was highly representative of the Company: 1) net plant

364 4 Tr 838-857; Exhibit A-14, Schedule D-5.365 4 Tr 810; 859; Exhibit A-14, Schedule D-5, p.14.366 4 Tr 858, 859.367 6 Tr 1722.

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greater than $2.0 billion but less than $14.0 billion to better compare in size and footprint

to Consumers Energy’s gas division; 2) derive no less than approximately 45% or more

of its revenues from regulated natural gas service; 3) an investment grade rating within

three notches from that of Consumers Energy from the two primary rating agencies, S&P

and Moody’s; 4) currently be paying dividends to shareholders; and 5) not currently

involved in a merger or major corporate buyout.368 This resulted in Staff’s nine gas utilities

proxy group.369

In conducting his analysis, Mr. Megginson employed several models including

three of the same models relied upon by Mr. Maddipati. Specifically, he used the DCF

analysis (which produced an average estimate of 9.02%), a historical CAPM analysis

(which provided average estimates of 9.03% and 8.51%), a projected CAPM analysis

(with an estimate of 8.15%), a historical Risk Premium analysis for A-rated utilities (which

produced an estimate of 7.53%), a historical Risk Premium analysis for Baa/BBB-rated

utilities (which produced an estimate of 7.80%), a low interest rate Risk Premium analysis

(which produced and 7.93% for A-rated utilities and average estimate of 8.19% for BBB-

rated utilities) and a comparison of recent gas ROE determinations from other state

jurisdictions (that produced an average estimate for 2016 of 9.54% and an average

estimate of 9.72% for 2017).370

368 6 Tr 1724.369 Id.; Exhibit S-4, Schedule D-1, p. 2.370 6 Tr 1742. The various methodologies Mr. Megginson utilized are described at 6 Tr 1726-1728, 1730-1733, 1739-1740, 1741. Regarding his DCF calculation, although Mr. Megginson testified that the average DCF estimate of ROE was 9.02% (6 Tr 1727), which assertion was reiterated in Staff’s InitialBrief at p. 108, this PFD notes that the “summary of Staff’s cost of equity model estimates” included in Mr. Megginson’s testimony lists the DCF Model Average as 8.96% and a DCF Model median as 9.02%. 6 Tr 1742.

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Mr. Megginson disagreed with the ROE estimate calculations performed by Mr.

Maddipati. Regarding the Company’s DCF analysis, Mr. Megginson testified that Mr.

Maddipati used just a single source for dividend growth rates, instead of multiple sources

which provide a broader review of estimates.371 Also, Mr. Maddipati used dividend per

share growth metrics instead of the “preferred” earnings per share, which the Company

had relied upon in the past.372 Mr. Megginson also disagrees with the Company’s use of

company’s guidance expectations, which have the potential to produce inflated growth

projections, instead of analyst’s growth rate expectations, which provide more objectivity

and neutrality, and which Mr. Maddipati had used in the past.373 Finally, Mr. Megginson

challenged the Company’s inclusion of flotation costs, which represent costs the

Company has not incurred.374

Regarding the Company’s CAPM analysis, Mr. Megginson offers that Mr.

Maddipati’s use of a historical risk-free rate distorts the accuracy of future borrowing costs

and thus an investor’s reasonable required rate of return to invest in the Company, and

that a forward looking ROE model should rely on bond analyst’s projection of future

Treasury yields as a broad determinant of the Company’s future borrowing costs.375 Mr.

Megginson adds that the Company’s assertion that the Fed’s actions have artificially

suppressed interest rates and created anomalous market conditions is incorrect, such

that the Company’s effort to input unconventional rates or use irregular timelines is

improper. Specifically, he testified:

371 6 Tr 1728.372 Id.373 6 Tr 1729.374 6 Tr 1729-1730.375 6 Tr 1734.

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The Fed raised interest rates in 2016, raised interest rates three times in 2017 and is poised to raise them again in 2018. Thus, the Fed, through its monetary policy, is managing the economy as it sees fit based on market forces. The Company also admitted that the Fed’s policies have been in place for a number of years. Therefore, the Company’s argument that interest rates are currently artificial and market conditions are anomalous fall short.376

Mr. Megginson also expressed concerns with the Company’s ECAPM model,

especially the use of a Value Line adjusted beta instead of a raw beta, and the fact that

the ECAPM adjustment is unnecessary as the Staff’s CAPM analysis already accounts

for the shortcomings recognized by ECAPM.377 Similarly, Mr. Megginson concluded that

the Company’s risk premium analysis has the same flaws as its CAPM analysis; namely,

the use of unconventional, inflated and improper data points and timelines in the model,

which result in “unreasonable, overinflated ROE estimates.”378

Mr. Megginson also noted that Michigan’s regulatory environment is “utility-

positive”, mostly due to Michigan’s legislation passed within the last ten years.379 He

added that the Company’s credit metrics are “solid with relation to its financial ratios”, and

its credit rating has been “stable or rising for the past 5+ years”.380

Mr. Megginson maintains that the Company’s recommended ROE of 10.50%

should be rejected for four reasons. First, the Company’s proposed ROE is 40 basis

points higher than the Company’s currently authorized ROE, which does not coincide with

Consumers Energy’s solid credit rating, supportive regulatory environment and the

376 6 Tr 1734-1735.377 6 Tr 1736-1738. 378 6 Tr 1740-1741.379 6 Tr 1714.380 6 Tr 1717.

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current low interest rate environment.381 Second, the proxy group’s average credit rating

is a notch or more below that of Consumer Energy, with the Company thus being viewed

more favorably than the proxy group and thus which does not support a substantially

higher ROE for the Company than the average authorized ROE of the group.382 Third,

Consumers Energy has exceeded its authorized ROE in earnings the past five years,

which does not lend itself to a higher required ROE.383 And, finally, the Commission has

already allowed risk-mitigating cost recovery mechanisms (RDM and IRM) which

“practically eliminate the Company’s cash flow and liquidity risk associated with

[incremental plant and infrastructure] expenditures.”384

c. Attorney General

The Attorney General recommends an ROE of 9.50% be adopted in this case.385

Mr. Coppola commenced his analysis by using a proxy group made up of the 11 gas utility

companies followed by the Value Line, less 3 companies he eliminated due to a pending

merger, foreign and propane investments, and relatively small size, respectively.386 Using

this revised proxy group, Mr. Coppola then performed his own DCF, CAPM, and Utility

Risk Premium analyses, arriving at ROE estimate figures of 9.21% from the DCF method,

9.03% from the CAPM approach, and 9.01% from the Risk Premium analysis.387

381 6 Tr 1743.382 Id.383 Id.384 6 Tr 1743-1745.385 7 Tr 2427.386 7 Tr 2428.387 7 Tr 2430, 2435, 2436; Exhibits AG-43, AG-44, AG-45, AG-46. 2429-2446. The various methodologies Mr. Megginson utilized are described at 7 Tr 2429-2430, 2433-2435, 2436.

U-18424Page 186

In addition to conducting these analyses, Mr. Coppola reviewed the ROEs that

other regulatory commissions have granted in 2016 and 2017. He noted that, since 1990,

return on equity rates approved by regulatory commissions have been on a steady decline

from over 12.7% in 1990 to approximately 9.5% in 2016 and 9.7% in 2017.388 Mr. Coppola

testified that the evidence shows that “companies in other jurisdictions receiving ROE

decisions in the 9% to 10% range have had ample access to the capital markets”, and

that “there is no evidence equity investors have abandoned utilities that have been

granted ROEs below 10%.”389 Mr. Coppola added that the fact that the Company needs

to raise capital because of a large capital investment program to upgrade its infrastructure

and for other purposes is “not unique to Consumers Energy”, and that other electric and

gas utilities “face the same issues and are able to raise capital with ROEs in the single

digits”.390

Based on all components of his ROE analysis in this case and giving more weight

to the DCF method as a more reliable approach to estimating the cost of equity, Mr.

Coppola developed a weighted average cost of equity of 9.11%.391 However, Mr.

Coppola then increased this number to a recommended ROE of 9.50% as “a gradual

transition to the true cost of equity” because (1) the industry peer group “may not

incorporate the unique risks and circumstances that exist with CECo and how investors

perceive those risks”, (2) while the cost of common equity under the DCF approach is an

accurate assessment of investors’ expectations of higher interest rates, the higher interest

388 7 Tr 2446.389 7 Tr 2452.390 7 Tr 2453.391 7 Tr 2451.

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rates assumed in this case may produce a different result should such higher interest

rates become a reality, and (3) the Commission may be reluctant to set an ROE for the

Company at the true cost of equity in the 9.0% area.392 Mr. Coppola adds that regulatory

commissions in 2017 granted ROE rates which average close to 9.50% in approximately

75% of the cases decided.393

Like Mr. Megginson, Mr. Coppola disagreed with the ROE estimate calculations

performed by Mr. Maddipati. Regarding the Company’s DCF analysis, Mr. Coppola

asserts that Mr. Maddipati includes several combination gas and electric companies

within his proxy group, uses out-of-date information, and includes floatation costs, all of

which inflate the Company’s estimates.394 Regarding the CAPM and utility risk premium

calculations, Mr. Coppola notes that Mr. Maddipati uses historical long-term interest rates

and market risk premium factors which are “unique”, inflated and not reflective of

conditions expected during the projected test period ending June 2019.395 As to the

Company’s ECAPM estimate, Mr. Coppola testified that Mr. Maddipati has not provided

any evidentiary support that the beta adjustment in his ECAPM calculation is

necessary.396 Finally, Mr. Coppola asserts that the Company’s comparable earnings

analysis is not “academically sound”.397

392 Id. 393 7 Tr 2451-2452; Exhibit AG-49.394 7 Tr 2431-2432.395 7 Tr 2437-2441, 2443-2444.396 7 Tr 2441.397 7 Tr 2444-2445.

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d. ABATE

ABATE does not offer a specific recommended ROE but instead indicates that Mr.

Maddipati’s recommended ROE is based on an improper application of the ROE estimate

methodologies, the correction of which would reduce the Company’s initial recommended

ROE by between 38 and 174 basis points, resulting in an average ROE of 9.72% within

the range of 8.76% and 10.12%.398 Ms. LaConte also testified that the national average

authorized ROE for gas utilities in 2017 was 9.72%.399

Ms. LaConte observed that the Company has separate cost recovery clauses

including a revenue decoupling mechanism and an investment recovery mechanism

which promote revenue stability and lead to lower financial risk for the Company.400 In

addition, Ms. LaConte notes that the Company has consistently earned close to or above

its authorized ROE, which was much higher than the national average for these last

years.401 Ms. LaConte adds that the Company improperly includes a flotation cost

adjustment averaging 14 basis points, even though the Commission has not allowed

flotation costs in the past.402

To estimate Consumers Energy’s cost of common equity under the methodologies

used by the Company, Ms. LaConte used the same criteria that the Company used when

it created its proxy group, except that she excluded companies that are not classified as

398 7 Tr 2162, 2167; Exhibit AB-7. Ms. LaConte asserts that Consumer’s CAPM estimate as “corrected” is 8.76%, its corrected Risk Premium calculation is 9.41%, its corrected DCF estimate is 8.84%, and its corrected Comparable Earnings estimate is 10.12%.399 7 Tr 2168; Exhibit AB-6.400 7 Tr 2170-2171.401 7 Tr 2171-2172.402 7 Tr 2173-2174, citing In the Matter of the Application of Consumers Energy Company for Authority to Increase Its Rates, U-14347, Opinion and Order, December 22, 2005, p. 24.

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a natural gas utility by Value Line and do not derive the majority of their operating

revenues from their natural gas operations.403

Ms. LaConte testified that the Company’s ROE analyses were faulty. Specifically,

Consumers Energy’s proxy group includes companies that are riskier than a regulated,

natural gas utility, such as electric utility companies and companies that are involved in

gas and oil exploration.404

In addition, Ms. LaConte asserted that the Company’s ROE analyses rely on

unreliable methods to estimate an ROE for Consumers. According to Ms. LaConte, the

Company’s Normalized CAPM analysis uses a higher, historical risk-free rate of 5.02%

instead of the forecast rate during the test year of 3.96%.405 Similarly, the Low Interest

Rate CAPM relies on too short of a time period (six years) to determine the Market Risk

Premium.406 Ms. LaConte added that the Company’s ECAPM analyses produces over-

stated ROEs by unnecessarily re-adjusting the formula to address that which the adjusted

beta has already corrected.407 She argues that the Normalized Risk Premium method

uses historical long-term government bond yields instead of projected bond yields which

are readily available.408 The Low Interest Rate Risk Premium method relies on a short-

term estimate of the projected long-term government bond yield.409 Ms. LaConte testified

that the DCF analyses use forecast dividend growth rates instead of earnings growth

403 7 Tr 2175.404 7 Tr 2177.405 7 Tr 2183.406 Id.407 7 Tr 2187.408 7 Tr 2189. 409 7 Tr 2190.

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rates.410 The Comparable Earnings method included a few “outliers” which overstated the

ROE by 62 basis points and does not estimate the required cost of equity but only

provides a forecast of return on equity.411

e. Rebuttal

In his rebuttal testimony, Mr. Maddipati changes the Company’s recommended

ROE and challenges the testimony of witnesses for Staff, the Attorney General and

ABATE.

As to the Company’s recommended ROE, Mr. Maddipati testified that the impacts

from the TCJA coupled with the Company’s recommended equity ratio of 52.49% now

supports an ROE of 10.75%, 65 basis points above the Company’s currently authorized

ROE.412 Mr. Maddipati adds that if the Commission were to reduce the Company’s equity

ratio below 52.49%, it would require a higher ROE.413 Mr. Maddipati explained that the

TCJA reduces the corporate tax rate, and effects current and deferred tax accounting

methods used by utilities, such that, as a result of the TCJA, the Company estimates a

revenue reduction of $120 million for its electric utility business and $52 million for its gas

utility business, and a one-time reduction to its total deferred tax balances of $1.5

billion.414 Mr. Maddipati added that, while these savings will benefit both customers and

the state of Michigan, they also lower the amount of ongoing cash flows to the Company,

which ultimately impacts the credit of the Company.415

410 7 Tr 2194-2195.411 7 Tr 2196.412 4 Tr 865.413 Id.414 4 Tr 866.415 Id.

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Mr. Maddipati testified that Moody’s Investor Services revised the outlook of 24

utilities to negative as a result of the tax reform, and that, “while Consumers Energy was

not one of the 24 companies put on immediate negative watch by Moody’s, in part, that

is a result of the constructive regulatory environment in Michigan and the expectation that

the Commission will consider the impacts of tax reform on credit.”416 Mr. Maddipati also

notes that neither Staff, ABATE, nor the Attorney General witnesses even mention the

impact of the TCJA on utility credit or ROE in their direct testimonies.417

In addition to changing the Company’s recommended ROE, Mr. Maddipati rebutted

certain aspects of the direct testimony of the witnesses for Staff, the Attorney General,

and ABATE. As to this opposing testimony generally, Mr. Maddipati testified that he does

not believe that the recommendations of Staff, the Attorney General, and ABATE’s

witnesses meet the standards of Hope and Bluefield, and that, while these witnesses

recommend a reduction from the currently authorized ROE of 10.1% ranging from 38

basis points to 60 basis points, these witnesses did not provide persuasive evidence to

show that their recommended ROEs would assure confidence in the financial integrity of

the Company or support the credit rating of the Company.418 Mr. Maddipati adds that

these witnesses’ analyses include “an over-reliance upon quantitative models whose

assumptions they simply failed to validate”, which failure makes the analyses

unreliable.419 Citing FERC Opinion 551, Mr. Maddipati specifically asserts that Staff, the

416 4 Tr 866-867. (Emphasis in original).417 4 Tr 869.418 4 Tr 869-870.419 4 Tr 871-872.

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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.”420

In rebutting Staff, Mr. Maddipati testified that Staff’s recommendation “would send

a dangerous signal to the investor community at a time when Consumers Energy is

implementing a large infrastructure improvement program.”421 According to Mr. Maddipati,

in its use of its quantitative models, “Staff fails to recognize that current market conditions

are not reflected in the assumptions of the models themselves, which models “assume

market conditions that are different than current conditions and, hence, generate results

that are not appropriate under the conditions.”422 Mr. Maddipati added that Staff “applied

inconsistent or incorrect inputs” with its quantitative models, resulting in a “flawed”

analysis which is “not reasonable” and which fails to “accurately measure the returns of

comparable investments”.423 and, in using Mr. Megginson’s proxy group, Mr. Maddipati

“recalculated” his “correct analysis”, which shows a range of results for Staff’s analysis

from 9.48% to 11.45% and an average of 10.55%.424

In rebutting the Attorney General, Mr. Maddipati asserted that Mr. Coppola’s ROE

recommendation is based on flawed quantitative analysis, is not sufficient to assure

confidence in the financial soundness of the utility, does not support the Company’s ability

to attract capital and, therefore, does not meet the standards set forth in Hope and

Bluefield.”425 Also, like Staff’s recommendation, the Attorney General’s recommendation

420 4 Tr 872. 421 4 Tr 881. 422 4 Tr 885. 423 4 Tr 886-887, 895. 424 4 Tr 886-887, 895; Exhibit A-111. 425 4 Tr 895.

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“would send a dangerous signal to the investor community.”426 According to Mr.

Maddipati, Mr. Coppola has provided no persuasive evidence that lowering the ROE 60

basis points would ensure the Company can continue to adequately attract capital.”427

Mr. Maddipati testified that Mr. Coppola used incorrect inputs for his quantitative

analyses.428

In rebutting ABATE, Mr. Maddipati asserted that Ms. LaConte’s recommendation

is based on flawed quantitative analysis, is not sufficient to 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.429 He added that

Ms. LaConte’s testimony is silent on the impact to the Company’s credit and its ability to

attract capital and provides no justification for why a reduction in ROE by 38 basis points

would continue to meet these requirements from Hope and Bluefield.430 In addition, Ms.

LaConte fails to recognize that regulatory mechanisms such as the proposed RDM and

IRM are reflected in her selection of a proxy group of natural gas companies and that the

current ROE authorized by the Commission of 10.1% already considers these

mechanisms.431 Regarding her quantitative calculations, Mr. Maddipati asserted that, like

Staff and the Attorney General, Ms. LaConte has used incorrect inputs which are

426 Id. 427 4 Tr 898. 428 4 Tr 900, 902-903, 905429 4 Tr 912. 430 Id. 431 4 Tr 914.

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“inconsistent and not reflective of current market conditions”, and does not provide any

“specific academic or regulatory support to refute” Mr. Maddipati’s analyses.432

In its rebuttal, ABATE asserted that both Staff’s and the Attorney General’s

recommended ROEs are too high. Specifically, as to Staff, Ms. LaConte testified that Mr.

Megginson’s proposed ROE range of 8.70% to 9.70% is not supported by his own

analysis, ignores those factors he cites which indicate that the Company is “far from a

risky environment”, including its “solid credit rating and a supportive regulatory

environment”, and fails to identify any extenuating circumstances applicable to the

Company which support a recommended ROE above the midpoint of his recommended

range.433 As to the Attorney General, Ms. LaConte testified that the bases Mr. Coppola

offered in support of recommending an “unsubstantiated premium” over his analytically-

determined ROE are unfounded: with Consumers’ customer operating revenues being

about 58% residential, 21% Gas Customer Choice, 11% commercial, 4% industrial and

6% other, “it is a stretch to contend that the automobile industry somehow increases

Consumers’ risk of doing business; as analysts and investors have incorporated their

estimates for higher interest rates into their forecasts, which are reflected in Mr. Coppola’s

ROE estimates, adding a premium “double-counts” the impact of higher interest rates;

and that Mr. Coppola’s “thorough analysis of Consumers’ cost of equity” should not be

adjusted to accommodate Mr. Coppola’s belief that the Commission “may be reluctant to

authorize an ROE which truly reflects Consumers’ risk.434

432 4 Tr 915-916.433 7 Tr 2213, 2215.434 7 Tr 2217, 2218, 2219.

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f. Recommended ROE

In reviewing the different analyses presented by the witnesses, and mindful of the

Commission’s steadfast reliance on the principles enunciated in Bluefield and Hope,

supra, that there is no precise mathematical formula to determine the appropriate return

on equity, this PFD finds that both the Company’s initial recommended return of 10.50%

and its revised recommended return of 10.75% are excessive and should be rejected for

the following reasons.

First, the Company’s contention that it needs to increase its return by 40 or 65

basis points overlooks the impact of the Company’s solid credit rating and current low

interest rate climate. As Mr. Megginson observed, the Company’s requested ROE of

10.5% “does not coincide with Consumers Energy’s solid credit rating,435 supportive

regulatory environment and the current low interest rate environment.”436 He also testified

that “the Company’s credit metrics are solid with relation to its financial ratios and

Consumers Energy’s credit rating has been stable or rising for the past 5+ years.”437 Mr.

Coppola testified that the Michigan economy has recovered from the most recent

recession and interest rates have been at stable lower levels but are now beginning to

rise, which “have placed the Company in a better position with respect to sales levels,

interest rates and uncollectible sales amounts.”438 He added that the Company’s access

435 Referencing the Company’s Exhibit A-23, Schedule D-6, p. 1, Mr. Megginson notes that “Standard & Poor’s (S&P) rates Consumers Energy’s senior secured debt “A” (raised from “A-” on December 4, 2014), Moody’s rates Consumers senior secured debt “Aa3” (raised from “A1” in April 2017), and Fitch rates Consumers senior secured debt “A+” (raised two notches from “A-” in March 2016)”. 6 Tr 1714.436 6 Tr 1743.437 6 Tr 1717438 7 Tr 2445.

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to the capital markets “is strong as witnessed by its issuance of new 30-year debt”.439

Indeed, Mr. Maddipati acknowledged that the investment community views Michigan’s

regulatory environment as “constructive” even though the Commission authorized an

ROE of 10.10% in its last rate case.440 Also, the record does not indicate that the

Company’s current return of 10.10% has adversely affected its ability to attract capital.

The Company asserts that the newly-passed TCJA will adversely affect the

Company’s credit rating. However, the evidence the Company offers in support of this

argument appears to be incomplete and inconsistent. For example, the Company points

out that Moody’s Investor Services revised the outlook of 24 utilities to negative because

of the TCJA. However, in discussing the changed “outlooks” for those 24 utilities, Moody’s

offered that the change related primarily to those utilities whose credit ratings were

already deteriorating:

The change in outlook to negative from stable for the 24 companies affected in this rating action primarily reflects the incremental cash flow shortfall caused by tax reform on projected financial metrics that were already weak, or were expected to become weak, given the existing rating for those companies.

. . . . . .

The vast majority of US regulated utilities, however, continue to maintain stable rating outlooks. We do not expect the cash flow reduction associated with tax reform to materially impact their credit profiles because sufficient cushion exists within projected financial metrics for their current ratings.441

439 Id.440 4 Tr 963-964.

441 Moody's Changes Outlooks on 25 US Regulated Utilities Primarily Impacted by Tax Reform, Global Credit Research - 19 Jan 2018, New York, January 19, 2018.

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More to the point, Mr. Denato admitted that the TCJA “has not negatively affected

our credit rating at this point” and that the ratings agencies have not revised or modified

their rating or outlook for the Company since the passage of the TCJA.442 Similarly, Mr.

Maddipati agreed that not all utilities would need to increase their ROE and equity ratio in

order to avoid a credit downgrade as a result of the TCJA.443 In addition, Mr. Maddipati

admitted that the Company did not prepare a forecast of the cash-flow changes nor the

credit metrics for 2018, 2019, and the projected test year as a result of the TCJA.444 As

well, the Company points to the effect of the TCJA on a credit metric known as Funds

From Operations (“FFO”) to debt, whereby the ROE and equity ratio are the factors that

determine this ratio, and how Moody’s notes in its credit opinion for Consumers that a

“sharp deterioration” of this ratio falling to the high teens “could lead to a downgrade”.445

However, while Mr. Maddipati asserted that the reduced cash flow attributable to the

TCJA will result in a “lower” ratio, Mr. Maddipati pointedly declined to calculate the

FFO/debt ratio using the ROE and equity ratio proposed by the Attorney General in this

case, and did not use his FFO/debt formula to project the ratio for 2018, 2019, or the

projected test year.446

Second, several of the model-based analyses performed by Mr. Maddipati appear

to be based on flawed assumptions and application of inappropriate inputs. As noted by

Staff, the Attorney General, and ABATE, Mr. Maddipati’s use of a historical risk-free rate

442 4 Tr 1127-1128.443 4 Tr 935. 444 4 Tr 924-925. 445 4 Tr 867-868; Exhibit A-108 (Moody’s Credit Opinion, April 19, 2017 together with Mr. Maddipati’s calculation formula for this ratio and the results of two calculations).446 4 Tr 940-942.

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of 5.07% in his CAPM analysis does not correlate with the forward-looking nature of this

rate case.447 To avoid this distortion, Staff, the Attorney General, and ABATE relied on

the forward-looking Treasury yields that correspond to a forward-looking cost of equity

model in a forward-looking test year.448

In addition, Mr. Megginson, Mr. Coppola, and Ms. LaConte provided persuasive

testimony that Mr. Maddipati’s use of adjusted betas in his ECAPM model instead of raw

betas is improper because doing so effectively double-counts the adjustment to the return

on equity estimate, thus producing a result that is higher than it should be.449

Also, Mr. Maddipati’s use of company-provided long-term guidance growth rates

in his DCF analysis instead of the growth projections of professional analysts as relied

upon by Staff and ABATE in their witnesses’ analyses, is inherently biased and lacking

impartiality, and represents a recent departure from the Company’s use of projections

from the same sources as Staff.450 Moreover, as Staff and ABATE point out, the

Company’s reliance on dividend growth instead of earnings growth renders its DCF

analysis even more unreliable.451

Moreover, Staff, the Attorney General, and ABATE all assert that Mr. Maddipati’s

inclusion of a flotation cost adjustment, which adds approximately 14 basis points to the

results of the company’s modeling, is unnecessary.452 Indeed, the Commission previously

447 6 Tr 1734; 7 Tr 2437-2439; 7 Tr 2183.448 Id.449 6 Tr 1735-1739; 7 Tr 2441; 7 Tr 2187.450 6 Tr 1728-1729; 7 Tr 2194.451 6 Tr 1728; 7 Tr 2194.452 6 Tr 1729-1739; 7 Tr 2431-2432; 7 Tr 2173.

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rejected the application of such an adjustment for this utility.453 This PFD agrees with

Messrs. Megginson and Coppola and Ms. LaConte that Consumers Energy has not

justified a change in the Commission’s prior determination that flotation costs are not

recoverable.454

As a result of these issues, all three of the Company’s analyses based on the

CAPM, ECAPM, and DCF models have likely produced results that were higher than they

should have been.

Mr. Maddipati cautioned that the standard quantitative models are based on the

assumption that economic conditions are relatively stable, that current market inputs are

reflective of their long-term outlook, and that this assumption is not currently being met

due to the recent unprecedented amount of intervention by central banks.455 As a result,

the models tend to understate the return that investors currently require to compensate

them for risk, such that a “mechanical application of these models without consideration

to the underlying assumptions would not meet the requirements in Hope and Bluefield as

indicated in FERC Opinion 551.”456 Accordingly, Mr. Maddipati made “appropriate

adjustments” to the inputs used in various of his methodologies “to mitigate the impacts

of these temporary economic conditions and uncertainty.”457

453 See MPSC Case No. U-14347, December 22, 2005 Order, p. 24. (“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.”)454 6 Tr 2432.455 4 Tr 817.456 Id.457 Consumers Energy’s Initial Brief, p. 126.

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However, the Company’s assertion that the methodologies used and applied by

Staff, the Attorney General and ABATE are unreliable is unpersuasive. Initially, 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.458

In addition, as Mr. Megginson testified, it is questionable whether “anomalous

market conditions” exist today:

The Fed raised interest rates in 2016, raised interest rates three times in 2017 and is poised to raise them again in 2018. Thus, the Fed, through its monetary policy, is managing the economy as it sees fit based on market forces. The Company also admitted that the Fed’s policies have been in place for a number of years. Therefore, the Company’s argument that interest rates are currently artificial and market conditions are anomalous fall short. Therefore, given time, the Fed’s actions stop being anomalous and artificial and start being normal.459

The Company argues that in Consumers Energy’s last electric rate case, Case No.

U-18322, the Commission recognized that “current market conditions are not reflective of

historical conditions” and noted that Staff’s approach to estimating ROE in that case “did

not reasonably reflect market conditions expected during the test year.”460 In that case,

458 In its last rate case, the ALJ questioned Mr. Maddipati’s objectivity in light of his testimony that the Staff’s recommended ROE in that case would “not assure confidence in the financial soundness of the utility”, and the Commission agreed with the ALJ, admonishing the Company in future rate cases to “focus more on objective arguments rather than making sensational statements to bolster its position.” MPSC Case No. U-18322, March 29, 2018 Order, p. 44. This PFD notes that Mr. Maddipati continues to make such statements in this case while discussing the ROE’s utilized and recommended by the Attorney General and ABATE. See 4 Tr 895, 912. 459 6 Tr 1734-1735.460 Consumers Energy’s Initial Brief, p. 113.

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the Commission authorized an ROE of 10.00% instead of the ALJ’s recommended ROE

of 9.80%, reasoning in part, as follows:

The Commission notes that the ALJ based her recommendation to adopt the Staff’s ROE on her finding that “Staff’s analysis is objective and consistent with the analytic framework relied on by the Commission in past cases”, and, “[it] reasonably reflects economic conditions expected in the test year[.]” PFD, p. 219. The Commission agrees with the ALJ as to the first part; however, it differs in its view regarding what economic conditions are “reasonably expected.” The Commission agrees in part with Consumers that factors such as volatility and uncertainty, are currently particularly significant and movements are more extreme in comparison to more stable historical periods.461

However, even with its recognition of the projected “volatility and uncertainty”, the

Commission nonetheless rejected the 10.50% ROE proposed by Consumers in that case:

That said, the Commission disagrees that the 10.50% ROE requested by the company is appropriate. In setting the ROE at 10.00%, the Commission believes there is an opportunity for the company to earn a fair return during this period of atypical market conditions. This decision also reinforces the Commission’s belief that customers do not benefit from a lower ROE if it means the utility has difficulty accessing capital at attractive terms and in a timely manner. The fact that other utilities have been able to access capital despite lower ROEs, as argued by many intervenors, is also a relevant consideration. It is also important to consider how extreme market reactions to singular events, as have occurred in the recent past, may impact how easily capital will be able to be accessed during the future test period should an unforeseen market shock occur. The Commission will continue to monitor a variety of market factors in future rate cases to gauge whether volatility and uncertainty continue to be prevalent issues that merit more consideration in setting the ROE.462

Thus, even if the Commission concludes that the evidence offered by the Company in

this case regarding the effect of market conditions on the reliability of the parties various

quantitative modeling results is deemed to outweigh the countervailing evidence offered

461 MPSC Case No. U-18322, March 29, 2018, p. 42-43.462 Id.

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by the Staff, Attorney General and ABATE, it does not support the Company’s proposed

10.75% ROE.463

Similarly, the Company’s reliance on FERC Opinion 551 in challenging the

propriety of the models as applied by the Staff, the Attorney General, and ABATE in this

case appears to be misplaced. In FERC Opinion 551, FERC reasserted principles first

set forth in FERC Opinion 531 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.464 However, rather than concluding that the

presence of any such anomalies negate the applicability of the various methodologies as

implied by Mr. Maddipati, FERC reiterated the propriety of the DCF model and 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.

“As the Commission found in Opinion No. 531, in considering these other methodologies and the ROEs allowed by state commissions, we do not depart from our use of the DCF methodology; rather, due to the presence of unusual capital market conditions, we find it appropriate to look to other

463 On this same point, Consumers argues that “current market conditions” are not reflective of historical conditions and that in Case No. U-18322 the Commission “recognized this as well”, finding “this to be a ‘period of atypical market conditions’’, which finding the Company noted was rendered “less than two months ago.” Consumers Energy’s Reply Brief, p. 113-114. However, the Company’s suggestion that the market conditions the Commission was referencing in its prior case are the same as the market conditions Consumers points to in this case is misplaced. As Consumers acknowledges, the test year in Case No. U-18322 “extended through September 30, 2018”, while the test year in this case “ends June 30, 2019.” Id., p. 98, fn. 15. Moreover, while the Commission’s Order in U-18322 was issued recently, its findings therein were based on assessments of market conditions presented in that case, which assessments were offered at different times than the assessments offered in this case and which assessments related to different time periods from those at issue in this case.464 FERC Opinion 531, Coakley v. Bangor Hydro-Elec. Co, 147 FERC ¶ 61,234 (June 19, 2014). FERC Opinion 551, Ass'n of Businesses Advocating Tariff Equity, et al., v. Midcontinent Indep. Sys. Operator, Inc., et al., 156 FERC ¶ 61,234 (Sept. 28, 2016).

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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 proxy group] produced by the DCF methodology.”465

Third, although not dispositive, this PFD notes that in the Company’s most recent

gas rate case, the Company sought an ROE of 10.60%, which request was similarly

based on certain qualitative factors which the Company asserts here, including investors’

view of Michigan’s positive regulatory environment, the current state of the economy and

capital markets, and the company’s need to attract capital to finance its capital

expenditure program.466 However, the ALJ recommended that the Commission set the

Company’s ROE at no higher than 10.00%, which the ALJ noted reflected the top of

Staff’s recommended ROE range, which acknowledged “both the volatility in United

States and global markets and the likelihood of rising interest rates”, and which would still

allow the Company to provide “appropriate compensation for risk and assuring

reasonable access to capital on reasonable terms and conditions, while also remaining

cognizant of the burden on ratepayers.”467 Agreeing with the ALJ’s analysis and findings

that the Company’s proposed ROE of 10.60% was “excessive”, and with her observation

“that some of the evidence supports an ROE below 10%”, the Commission concluded

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”, and that it “appropriately balances the interests of the utility with the

465 FERC Opinion 551 at par. 137. Also, it is noted that the precedential value of FERC Opinions 531 and 551 is questionable given that on April 14, 2017, the D.C. Circuit Court of Appeals vacated FERC Opinion 531. See Emera Maine v Federal Energy Regulatory Comm’n, 854 F.3d 9 (2017).466 MPSC Case No. U-18124, 5 Tr 430-433.467 MPSC Case No. U-18124, May 18, 2017 PFD, p. 104-105.

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interests of its ratepayers, and will ensure investor interest and confidence while

protecting customers from unnecessarily burdensome rates.”468

Fourth, the authorized ROEs approved by other Commissions for gas utilities have

generally declined in recent years, with the average authorized returns in the

presentations compiled by the witnesses generally within the range of 9.50% to 9.72%.469

Likewise, since November 2015, in Case Nos. U-17735, U-17999, U-18014, U-17990, U-

18124, and U-18322, the Commission has issued orders for Consumers Energy and DTE

adopting ROEs of 10.30%, 10.10%, 10.10%, 10.10%, 10.10% and 10.00%,

respectively.470 While the Company argues that the Commission has stated its

disinclination “to give significant weight to ROE determinations resulting from evidentiary

records that are not a part of this proceeding and that are exclusively related to

geographically and structurally different utilities”, the Commission nonetheless

acknowledged that it “considers other ROEs.”471 Indeed, in the most recent gas rate case

for the Company, the Commission noted that an ROE of 10.10% “is consistent with its

ROE determinations in recent years”, and that “[n]ationally and in Michigan, ROEs are

trending downward”.472 Therefore, such information, if considered here, further

demonstrates that the Company’s requested ROE of 10.75% is well above these recently

authorized ROEs.

468 MPSC Case No. U-18124, July 31, 2017 Order, pp. 52-53.469 6 Tr 1741, Exhibit S-4, Schedule D-5. p. 12; 7 Tr 2446-2447, Exhibit AG-49; 7 Tr 2168, 2172, Exhibit AB-6.470 MPSC Case No. U-17735, November 19, 2015 Order; MPSC Case No. U-17999, December 9, 2016Order; MPSC Case No. U-18014, January 31, 2017 Order; MPSC Case No. U-17990, February 28, 2017 Order; MPSC Case No. U-18124, July 31, 2017 Order; MPSC Case No. U-18322, March 29, 2018 Order. 471 MPSC Case No. U-17895, Order, September 8, 2016, p. 20.)472 MPSC Case No. 18124, July 31, 2017 Order, p. 52.

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Fifth, the Company’s requested ROE of 10.75% is at odds with the structure for

rate cases established as a result of Public Act 286 of 2008 (Act 286) and the Company’s

progressively improving credit rating. As Mr. Megginson testified:

My assessment is that Michigan’s regulatory environment is utility-positive,based primarily on legislation passed within the last decade. The most important of these legislative acts was Public Act 286 (Act 286). Credit rating agencies emphasize a ‘regulatory framework’ component that focuses on the utility’s ability to effectively manage the regulatory process, recover its costs and earn stable returns. Act 286 addresses this regulatory concern almost exclusively. Amongst other utility friendly provisions, the legislation allows utilities to (1) use projectedcosts, revenues and sales volumes in support of its requested rate increase; (2) to self-implement all or a portion of its requested rate increase 180 days following its approved application if the Commission hasn’t issued an order by that time; (3) requires the Commission to issue a final order 12-months from the time of the approved application, lest the utility’s rate increase request is automatically granted; (4) allows the utility to file a rate increase request 12 months after its previous approved rate case; and (5) limits the amount of retail choice load or competition to 10.0% of a utility’s total sales. The legislation has been deemed utility favorable by security analysts and brokers and is clearly credit supportive of Michigan utilities.473

Mr. Megginson also observed that the recently enacted reforms to Act 286 have further

improved the regulatory landscape for Michigan-based utilities by allowing utilities to more

frequently bring requests to increase rates and obtain those requests expeditiously, and

that the Company has taken advantage of this legislation.474

Moreover, the Company’s requested ROE of 10.75% overlooks the RDM and IRM

previously granted to the Company that have substantially reduced the Company’s

business risk going forward. Specifically, as Mr. Megginson testified, the RDM “reduces

Consumers Energy’s risk in collecting its authorized revenue level and thus reduces the

473 6 Tr 1715-1716.474 6 Tr 1716-1717.

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Company’s risk of not earning its authorized ROE.”475 In addition, Consumers “has in

place IRM surcharge revenues to cover future incremental plant and infrastructure

investments that practically eliminate the Company’s cash flow and liquidity risk

associated with those expenditures.”476

Further, it is important to recall that in its recent order in Consumers Energy’s

electric rate case, the Commission noted that the parties should “consider the degree of

financial adjustment” that they are asking the Commission to make in any case “because

it is not realistic to make a significant change in ROE absent a radical change in

underlying economic conditions.”477 Here, the Company is seeking a significant increase

of 65 basis-points in its authorized ROE without having demonstrated that there is a

“radical change” in the current economic conditions.478

Notwithstanding this PFD’s determination that the Company’s requested ROE of

10.75% is excessive, consideration must be given to the Company’s contention that

setting the rate of return as recommended by Staff, the Attorney General, and ABATE,

would send a significant negative message to investors that would undercut the positive

investor perceptions of Michigan and the Michigan regulatory environment. According to

Mr. Maddipati:

Authorized ROE is one of the most important parameters used by analysts to determine the attractiveness of investing in utilities. The ability of Consumers Energy to earn a reasonable ROE is a critical component of

475 6 Tr 1743.476 6 Tr 1745.477 MPSC Case No. U-18322, March 29, 2018 Order, p. 44. 478 Consumers argued that, with the passage of the TCJA, there “has been” a “radical change in underlying economic conditions”. Consumers Energy Reply Brief, p. 108. However, as discussed supra, Consumers has failed to show that the TCJA should properly be considered a “radical change” in economic conditions which might justify a “significant change” in an authorized ROE in accordance with the Commission’s recent pronouncement.

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their evaluation. The analyst and investor community generally view the regulatory environment in Michigan as constructive. It is important that the Company continues to hold a good reputation among investors . . . Due to the constructive regulatory environment in Michigan and strong internal financial discipline, the Company has developed a good track record of financial performance and delivering excellent customer service. However, investors and credit rating agencies look for a long and consistent track record. It is critical that the Company’s ROE continue to be set at a reasonable level to continue to realize the benefits from the model described above . . . I believe that the Company’s ability to raise capital at attractive prices to invest in the utility, and to accomplish the goals setforth in the report published by the 21st Century Infrastructure Commission,will be jeopardized if the ROE is not set at an attractive level.479

In addition, Staff, the Attorney General, and ABATE are each also proposing

significant changes to the Company’s authorized ROE, ranging between 35 and 60 basis

points. As such (and similarly with the Company’s recommendation to raise its authorized

ROE by 65 basis points), these proposed ROEs are likely to be considered by the

Commission to be “unrealistic” absent a “radical change” in the current economic

conditions, which these parties also have not shown.480 Thus, based on this evidence,

this PFD finds that the ROEs of 9.72%, 9.60%, and 9.50% utilized or recommended by

ABATE, Staff, and the Attorney General, respectively, would be harmful to the Company’s

credit ratings and send an adverse signal to investors, analysts, and credit ratings

agencies and, thus, should not be adopted.

Instead, this PFD finds that the Commission should set the Company’s ROE at

10.00%. This return is above Staff’s ROE range of 8.70% and 9.70%, is based upon an

objectively reasonable analysis which is consistent with past Commission decisions and

the requirements of Bluefield and Hope, and acknowledges the volatility in United States

479 4 Tr 810-812480 MPSC Case No. U-18322, Order, March 29, 2018, p. 44.

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and global markets and the likelihood of rising interest rates. This ROE is also slightly

higher than the average ROE of 9.90% of Staff’s proxy group. This PFD concludes that

such an ROE will still allow the Company to achieve the goals of providing appropriate

compensation for risk and assuring reasonable access to capital on reasonable terms

and conditions, while also remaining cognizant of the burden on ratepayers.

Accordingly, this PFD recommends the Commission authorize an ROE of 10.00%

for the Company.

2. Long-Term Debt Cost Rate

In its Application, Consumers Energy projected a long-term debt cost rate 4.68%

based on a projected 5.50% interest rate for the May 2018 and August 2018 debt

issuances of $325 million and $500 million, respectively, and 6.50% for the May 2019

debt issuance of $300 million.481 However, based on testimony offered by Mr. Megginson,

Staff recommended a long-term debt cost rate of 4.57%.482 Mr. Denato and Mr.

Megginson both testified that the primary difference between the utility and Staff’s

recommended long-term debt cost rate stems from the cost rates attached to the

Company’s projected May 2018 and August 2018 debt issuance and the projected May

2019 debt issuance.483 Through the rebuttal testimony of Mr. Denato, the Company has

elected to adopt Staff’s recommended long-term debt cost rate of 4.57% as it is based on

the most recent issuance data.484

481 Exhibit A-14, Schedule D-2. 482 6 Tr 1720-1721.483 4 Tr 1107; 6 Tr 1720.484 4 Tr 1107-1108.

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3. Short-Term Debt Cost Rate

The Company forecasted a short-term debt cost rate of 2.70% by applying the

projected London Interbank Offered Rate (LIBOR) rate of 2.55% and a spread of 0.15%

to its forecast of the outstanding average short-term borrowing under its commercial

paper facility. 485 In response, Staff recommended a short-term debt cost rate of 3.14%,

using an updated forecast of LIBOR. 486 Through the rebuttal testimony of Mr. Denato,

the Company has elected to adopt Staff’s recommended short-term debt cost rate of

3.14%.487

4. Other Cost Rates

Both the Company and Staff agree to a 4.50% cost rate for preferred stock, and

agree that the cost rates for long-term debt, preferred stock, and common equity

components of JDITC should correspond to the cost rates established for long-term debt,

preferred stock, and common equity, respectively.488 In addition, the Company and Staff

agree that the cost rates for customer deposits and for other interest-bearing accounts

should be zero.489

C. Overall Rate of Return

Based on the foregoing discussion, this PFD recommends that the Commission

adopt the Company’s capital structure and common equity balance, along with a long-

term debt cost of 4.57%, a short-term debt cost of 3.14%, and a return on equity of 10%,

485 4 Tr 1096.486 6 Tr 1722. 487 4 Tr 1102488 Exhibit A-94; Exhibit S-4, Schedule D-1. 489 Id.

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resulting in an estimated overall weighted after-tax cost of capital of 5.86%, as shown in

Appendix D to this PFD.

VI.

THROUGHPUT

Throughput represents the total gas sales and transportation volumes delivered to

end-use customers during the test year. Throughput is used to compute test-year

revenues and is also used in determining rate design issues.

The Company’s witness, Eric J. Keaton, testified that he utilized a weather

normalization process to develop the Company’s forecasted gas delivery and customer

levels used to design test year rates in this case and he explains that such a process had

forecasted weather adjusted deliveries for 2016 that were within 0.3% of the utility’s

anticipated deliveries.490 Mr. Keaton summarized the Company’s gas forecasting process

as follows:

In general, the gas forecasts are based on regression analysis, a mathematical and statistical technique that correlates the relationship between dependent variables (deliveries and customer counts) and independent variables (economics and/or weather). Applying these relationships to expected independent variables allows one to project the corresponding movements in dependent variables. The four major classes of gas deliveries (sales plus transportation) that are forecast are residential, commercial, industrial, and interdepartmental. For each of these classes, monthly forecasts are developed on a cycle billed (billing month) basis and then adjusted to calendar month amounts using the methodology describedlater in my testimony. Moreover, the impact of exogenous factors – e.g., incremental energy efficiency – is applied ex post.491

490 2 Tr 320.491 2 Tr 320-321.

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Based on this process, the Company forecasted total gas deliveries for the test

year to remain near historic weather normal levels of 303 billion cubic feet (Bcf) in 2016

into 2017 based on the continued level of customer attachments.492 The Company asserts

that while total deliveries are projected to increase by 0.04% per annum to 306 Bcf by

2021, the growth or loss in gas deliveries is not symmetric across all classes.493

According to the Company, total customer count levels are projected to increase 1.6%

from 1,749,644 in 2016 to 1,777,539 in the 12 months ended June 2019 test year and,

over the next five years, the customer level is expected to increase 0.5% per annum with

most of this growth occurring within the residential class.494

While Staff has concluded that the Company’s sales forecasts and customer count

projections are reasonable, do not conflict with recent trends, and should be adopted by

the Commission, the Attorney General argues that it is not reasonable to reduce the 2017

gas sales forecast for cumulative energy efficiencies over the 2016-2017 period to the

level calculated by the Company, and that the use of a gas deliveries forecast based on

the most recent weather-normalized actual sales for 12 months ended September 2016

is “a more realistic approach”.495 Mr. Coppola explained his reasoning:

In Exhibit AG-1, I show the average gas usage per customer for the residential and commercial customer classes for the historical years from 2011 to 12 months ended October 2017, and also for the forecasted 2018, 2019 and projected test year periods, as provided by the Company. In the exhibit I have calculated the percent change in average gas usage per customer, year over year, from 2011 to 2019 and the projected test year

492 2 Tr 321-322; Exhibit A-15, Schedule E-1.493 Id.494 2 Tr 322; Exhibit A-15, Schedules E-5 and E-6.495 Staff’s Initial Brief, p. 120; 7 TR 1243.

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along with the average compound rate of decline or increase for the most recent historical five- and six-year period.

The analysis shows that actual weather-normalized average usage for residential and commercial customers has varied little over the past five to six years. Some years show a slight decline and other years an increase, but overall residential gas usage per customer has averaged in a slight decline of 0.2% for the 6-year period and an increase of 0.44% during the latest 5-year period. On the other hand, commercial customers’ gas usage has increased an average of 0.9% to 1.2% in the past five to six years.

However, when analyzing the Company’s gas delivery forecast for 2018 and 2019, it shows a decline in commercial customer usage of 4% in 2018 from the 12 months ended October 2017 level followed by a 1% increase in 2019. When comparing the 12-month ended October 2017 actual weather-normalized usage to the Company’s projected test year gas usage for commercial customers there is an overall decline of 2.9%. Similarly, the Company’s projections of gas usage per residential customers shows a decline of 1.6% in 2018 with a further decline of 0.7% in 2019 for a cumulative decline of 2.0% for the projected test year.

The analysis in Exhibit AG-1 clearly shows that the rate of decline in average customer usage projected by the Company from 2018 to the projected test year is excessive and not supported by historical data or trends.496

Based on his approach, Mr. Coppola concluded that the Company’s forecasted

revenue and operating income for the projected test year are not accurate because its

gas delivery forecast includes losses of sales from energy efficiency and other programs

that are not likely to materialize. He forecasted the Company’s total gas deliveries

forecast to be 308.4 Bcf, an increase of the Company’s forecasted 12 months ended June

2019 by 6.2 Bcf. This increase, when compared to the Company’s forecast for each rate

schedule, would result in incremental revenue of $14.3 million – by which amount the

Attorney General recommends the Commission increase the revenue and operating

496 7 Tr 2333-2334.

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income forecasted by the Company for the future test year and reduce the Company’s

revenue deficiency.497

The Company responded that the Attorney General’s proposal to exclude the

energy efficiency savings adjustment from the forecasted gas deliveries should be

rejected because the annual incremental energy efficiency savings target was prescribed

under Public Act 295 of 2008 and approved by the Commission in the Company’s energy

efficiency plans and reconciliations.498 The Company further responded that the Attorney

General’s test year total gas deliveries forecast is flawed as it is based on the Company’s

historical sales, however forecasted sales “should be based on the regression model

results that have been accepted and approved by the Commission in previous rate

proceedings” and which results “incorporate forecasted economic conditions and energy

efficiency savings and are more than just a historical trend.”499 The Company further

responded that the Attorney General’s proposed forecast “appears to have calculated the

proposed test years twice (see lines 7 and 9 of [Exhibits AG-2 and AG-3] and in two

different ways with two different results.”500 Finally, the Company noted:

Since Mr. Keaton has been performing sales forecasts and acting as an expert witness in general rate cases (with his first sales forecast as an expert witness being conducted in 2016), Mr. Keaton’s forecasts have been within 0.3% and 1.3% accuracy for 2016 and 2017, respectively. This is consistent with the graph set forth in the Attorney General’s Initial Brief at page 20.501

497 7 Tr 2338; Exhibits AG-2 and AG-3.498 Consumers Energy’s Reply Brief, pp. 144-145; 2 Tr 326.499 2 Tr 326.500 Consumers Energy’s Reply Brief, p. 143.501 Id., p. 144.

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This PFD finds that the Attorney General’s calculations and analysis do not warrant

abandonment of the Company’s total gas deliveries forecast for the projected test year

and adoption of a gas deliveries forecast based on the most recent weather-normalized

actual sales for 12 months ended September 2016. As noted by the Company, doing so

not only ignores economic conditions and the fact that regression model results have

been accepted and approved in prior rate cases, but it overlooks the Company’s

unchallenged assertion that “Mr. Keaton’s forecasts have been within 0.3% and 1.3%

accuracy for 2016 and 2017, respectively”.502 Moreover, in the Company’s last natural

gas rate case, Case No. U-18124, the Commission considered and rejected the same

argument that the Attorney General has presented here, concluding that “the Attorney

General’s position overlooks economic conditions and Consumers’ unchallenged

expectation that the calendar year 2016 weather-adjusted actuals will be within 1% of the

originally forecasted deliveries for 2016.”503 Accordingly, the ALJ recommends that the

Commission reject the Attorney General’s proposed adjustments and adopt the

Company’s gas delivery forecast for the test year.

VII.

ADJUSTED NET OPERATING INCOME

Adjusted Net Operating Income (NOI) represents the difference between the

company’s projected test year operating revenues and expenses. As a result, the first

step in computing a company’s NOI is to forecast its overall sales level, and then convert

502 Consumers Energy’s Reply Brief, p. 144; Attorney General’s Initial Brief, p. 20.503 MPSC Case No. U-18124, July 31, 2017 Order, pp. 56-57.

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that figure into the appropriate amount of expected revenue to be received during the test

year through application of the utility’s proposed rates, adjusted for revenue received by

other utility operations. The second step is to determine the expenses that are expected

to be incurred during the test year, and then subtract that amount from overall revenues.

In this case, the Company projects its total jurisdictional operating revenues at

$1.707 billion, and an after-expense net operating income of $265,808,000.504 After

applying the projected $8,260,000 allowance for funds used during construction (AFUDC)

adjustment, the resulting adjusted NOI is $274,068,000.505 However, for the reasons

discussed below, Staff recommends an adjusted NOI of $293,322,000, which represents

an increase of $19,254,000 from the Company’s rebuttal projection in its initial brief.506

A. Operating Revenue Forecast

1. Sales Revenue

The Company has projected revised test year sales revenues of

$1,539,062,000.507

Staff recommends sales revenue of $1,518,572,000, a reduction of $20,490,000

from the Company’s revised projected amount.508 Staff’s recommended reduction is

based on Staff’s revisions to the Company’s originally filed amounts related to the

average cost of gas sold and the average cost of gas in storage. Staff submits that its

projections are based on more recent market data than the Company’s projections and

504 Consumers Energy’s Initial Brief, p. 148; Appendix C, p. 1.505 Id.506 Staff’s Initial Brief, p. 117; Appendix C.507 Consumers’ Initial Brief, Appendix C, p. 1.508 Staff’s Initial Brief, Appendix C, line 3.

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therefore more accurately reflects current market conditions and gas prices. Specifically,

Ms. Quilico testified as to Staff’s updated average cost of gas sold:

The current market price of gas and the national supply/demand situation warrant revision of the Company’s originally filed average cost of gas figure. In addition, in the Company’s 2018-2019 GCR plan case, MPSC Case No. U-18411, the Company supports a lower average cost of gas than the figure it put forth in this case. Therefore, Staff chose to update the Company’s figure.

Staff supports an updated July 2018-June 2019 average cost of gas of $3.001/Mcf, which is a reduction of 9.3 cents from the Company’s filed amount. This updated figure was obtained in the Company’s audit response #131 (see Exhibit S-13.1) and validated by Staff. The updated average cost of gas figure assumes CME (NYMEX) market data from the first five trading days in January 2018. It is the result of dividing $685,347,000, the updated cost of gas sold, by 228,398,524 Mcf, the updated gas sold volume.509

Regarding Staff’s updated average cost of gas in storage, Ms. Quilico testified:

Staff supports an updated combined (GCR/GCC) 13-month average cost of gas in storage of $363,042,801, with a corresponding 13-month average storage volume of 123,858,281 Mcf (or $2.931/Mcf). These figures were received in the Company’s audit response #132, see Staff Exhibit S-13.2. The total 13-month average is a reduction of $4,821,327 from the originally filed figure of $367,864,128 and an increase of 1,557,879 Mcf from the original volume of 122,300,412 Mcf (or $3.008/Mcf) supported by Company witness Pelmear on page 3 of her direct testimony and Exhibit A-64 (DSP-1).510

The Company has not addressed Staff’s revised projections in the Company’s

initial and reply briefs.511 Given that Staff’s projections are based on more recent market

data than the Company’s projections and, as Staff notes, more accurately reflect current

509 6 TR 2111-2112.510 6 TR 2112.511 In its initial brief at page 149, the Company indicates that the development of its calculated average cost of gas sold amount of $3.094/Mcf “as well as a response to Staff’s proposed GIK volumes, is located in Section III.B.2 of this Initial Brief” – however, no such section exists in the Table of Contents or body of the Company’s initial brief.

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market conditions and gas prices, this PFD recommends the Commission adopt Staff’s

updated projections, resulting in a reduction of $20,490,000 from the Company’s revised

projected test year sales revenues of $1,539,062,000, and thus an adjusted sales

revenue of $1,518,572,000.512

2. Transportation Revenue

The Company and Staff agreed that test year transportation revenues should be

projected at $70,980,000.513

3. Miscellaneous Revenue

The Company has agreed to Staff’s $7,678,000 increase to the Company’s

projected test year miscellaneous revenues of $89,978,000, which Staff attributed to the

incorrect removal of asset management agreement revenue and which results in a

revised miscellaneous revenue projection of $97,656,000.514

B. Cost of Gas Sold

The Company has projected a cost of gas sold expense for the test year of

$681,507,000 and recommends that the average cost of gas sold of $3.094/Mcf be used

in this calculation.515

Staff recommends a revised cost of gas sold expense of $661,017,000, which

reflects a $20,490,000 reduction based on an updated average cost of gas, as discussed

512 Staff’s Initial Brief, Appendix C.513 Exhibit A-13, Schedule C-3; Exhibit S-3, Schedule C-1; Staff’s Initial Brief, Appendix C.514 6 TR 2081; 2 TR 204.515 Consumers Energy’s Initial Brief, Appendix C, p. 1.

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in Section VII.A.1.516

As determined in Section VII.A.1., given that Staff’s projection more accurately

reflect current market conditions and gas prices, this PFD recommends the Commission

adopt Staff’s updated projection, resulting in a reduction of $20,490,000 from the

Company’s projected test year cost of gas sold expense of $681,507,000 and an adjusted

sales revenue of $661,017,000.

C. Lost and Unaccounted for Gas and Company Use Gas

The Company has projected lost and unaccounted for (LAUF) gas and company

use gas expenses to be $9,614,000 and $5,453,000, respectively.517 As well, the

Company’s proposed allowance for use and losses percentage, or gas in kind (GIK)

percentage, is 2.24% and proposed five-year average gas loss percentage is 1.49%.518

Staff recommends an adjustment to GIK volumes based on Staff’s inclusion of a

revised June 2017 actual value in the calculation of the Company’s as-filed GIK test year

volume forecast, which methodology is based on a five-year historical average as

approved by the Commission in Case No. U-18124.519 Staff’s GIK volume adjustment

results in a $4,000 increase to LAUF gas to $9,618,000 and a $2,000 increase to

company use gas to $5,455,000.520

The Company does not oppose Staff’s revised amounts and this PFD therefore

516 Staff’s Initial Brief, Appendix C.517 Exhibit A-54.518 Exhibit A-53.519 Staff’s Initial Brief, p. 122; 2 TR 210-211.520 Staff’s Initial Brief, Appendix C.

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recommends the Commission adopt Staff’s adjustment to GIK volumes, resulting in a

$4,000 increase to LAUF gas to $9,618,000 and a $2,000 increase to company use gas

to $5,455,000, for an overall increase of $4,000 to the LAUF and company use expenses.

D. Other Operations and Maintenance Expense

The Company has projected its total Other O&M expenses for the 12-month

June 30, 2019 test year to be $324,467,000.521 Both Staff and the Attorney General have

recommended adjustments to the Company’s projection, with Staff’s recommendations

decreasing the Company’s projection by $8,106,000 for a revised total of $316,360,000,

and the Attorney General’s recommendations decreasing the Company’s projections by

$41,700,000.522 The adjustments by Staff and the Attorney General are discussed below

by relevant program.

1. Gas Transmission & Distribution O&M Expense

The Company projects its gas transmission and distribution O&M expense for the

12-month June 30, 2019 test year to be $167,425,000.523 Ms. Palkovich explained that

the Company’s Gas Division test year O&M expense was derived by taking the 2016

actual O&M expense ($106,592,000) and adjusting for the effects of the voluntary

separation program offered in 2016, and applying respective inflation percentages to the

2016 adjusted actual expenses for each respective time period, which resulted in an O&M

521 Consumers Energy Initial Brief, Appendix C.522 In his Initial Brief, the Attorney General continues to rely upon the Company’s originally filed total projected Other O&M expense for the test year ending June 2019 of $366,100,000, without acknowledging the Company’s revised rebuttal projection of $324,467,000. Attorney General’s Initial Brief, p. 27.523 Exhibit A-49.

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expense of $108,027,000 for 2017, $109,972,000 for 2018, and $111,182,000 for the 12

months ending June 30, 2019.524

Staff contends that the Company’s projected test year O&M expense levels should

be adjusted based on 2017 actual O&M levels, which were unavailable at the time of the

Company’s filing and, with inflation applied, would result in a $5,763,000 reduction for a

revised test year projection of $105,419,000.525 Staff maintains that “the updated

preliminary O&M expense level provided was more appropriate to use in projecting the

test year O&M expense level rather than compounding inaccuracies in the 2017

projection as filed.”526

The Company disagrees with Staff’s proposed adjustment and maintains that its

projected expenses level, based on 2016 levels, “is a more reasonable representation of

the Company’s projected test year Gas Division O&M expense levels.”527 The Company

further argues that, should the Commission find it appropriate to utilize 2017 actual

information, “as it is more recent actual information and arguably more indicative of the

Company’s expense levels,” such a decision should be consistently applied to other cost

categories, including the Company’s actual 2017 capital expenditures.528

This PFD agrees with Staff and recommends that the Commission adopt Staff’s

proposed adjustment based on 2017 actual O&M levels, resulting in a $5,763,000

524 5 TR 1314.525 Staff’s Initial Brief, p. 129-130, citing 5 TR 1321-1322.526 Staff’s Initial Brief, p. 130.527 Consumers Energy’s Initial Brief, p. 152.528 Id.

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reduction for a revised test year projection of $105,419,000. Notwithstanding the

Company’s contention that the 2017 actual information should not be utilized to update

the Company’s projected test year gas division O&M levels, the Company has offered no

rationale for this position. Indeed, while Ms. Creisher recommends reliance on the 2017

actual information, noting that they “were not available at the time of the Company’s

preparation for filing its application, testimony, and projected test year calculations in this

current case,” Ms. Palkovich testified that “[t]he Company believes that using the 2016

historical year actual amount plus inflation should be the basis for the test year projection”,

without offering any basis for the Company’s belief.529 Furthermore, the Company’s

contention that Staff’s reliance on more recent actual costs in this expense category

should be consistently applied to other cost categories is not persuasive as it necessarily

assumes without evidentiary support that Staff has been timely provided with updated

actuals in other cost categories in advance of the filing of Staff’s direct case and thus

afforded a reasonable opportunity to prudently review those actuals. And, more

importantly, such an approach fails to acknowledge the fact that any underspending by

the Company will not afford ratepayers a refund of unspent expenditures as retroactive

ratemaking is prohibited, whereas the Company may seek to recover any overspending

of its capital expenditures in its next rate case.

For these reasons, this PFD recommends the Commission adopt Staff’s

recommended adjustment of the Company’s projected test year O&M expense levels

529 6 TR 1847; 5 TR 1370.

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based on 2017 actual O&M levels, which result in a $5,763,000 reduction for a revised

test year projection of $105,419,000.

a. Pipeline Integrity Expense

The Company projects its pipeline integrity expense for the test year to be

$12,105,000.530 This expense is associated with assessment and remediation of

transmission pipeline segments.531

Staff recommends a pipeline integrity expense amount of $19,510,600 for the

projected test year, which is comprised of: (i) $9,938,000 in projected test year O&M

expenses; (ii) the removal of $2,167,000 related to pipeline integrity assessments using

electro-magnetic acoustic transducer (EMAT) tools; and (iii) the addition of $9,530,350 in

pipeline integrity remediation dig expenses necessitated by Staff’s proposed

disallowance of remediation dig capital expenditures.532

In support of the $9,938,000 projection, Ms. Creisher testified that Staff’s

calculation is “consistent with the Company’s calculation of the test year O&M expense

level, which assumes that 50% of the 2018 O&M expenses and 50% of the 2019 O&M

expenses for the pipeline integrity program are incurred in the test year period.”533

Regarding the proposed reduction related to EMAT, Staff contends it is not reasonable

for the Company to recover expenses for its use of a pipeline assessment method for

which the Company has not yet received the necessary approval to use under federal

530 5 TR 1322.531 Id.532 6 TR 1850-1854; Appendix C to Staff’s Initial Brief.533 6 TR 1854.

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pipeline safety regulations.534 Finally, Staff’s addition of $9,530,350 in remediation dig

expenses is premised on Staff’s proposed disallowance of capital expenditures related to

remediation digs which, based on Staff’s calculations, result in a corresponding amount

of remediation dig O&M expenses for the test year.535

The Company responds that Staff’s proposed disallowance related to the use of

EMAT should be rejected because it fully expects to receive the needed waiver from

PHMSA in 2018 for utilization of the EMAT tool, a belief that “is in part based on the

authorization of other pipeline operators having ability to use EMAT as a means for

baseline assessment under 49 CFR 192.921(a)(4).536 As for Staff’s proposed increase

in O&M expense related to Staff’s corresponding recommended capital expenditure

reductions, the Company contends that, if Staff’s capital expenditure reductions are

adopted, the O&M expense should be $36,935,650 because Staff’s calculation method

“fails to take into account the contractor cost for mobilization, demobilization, and

excavation are essentially the same regardless of the size of pipe removed” and is

therefore insufficient.537 According to the Company, there will “still be the same number

of digs, likely with more segments [t]o remediate, just of shorter lengths” and “[s]taging

and excavation would still be required which are typically the highest portion of the

cost.”538

534 6 TR 1853-1854.535 Staff’s Initial Brief, pp. 124-126; Confidential 6 TR 1690-1691.536 Consumers Energy’s Initial Brief, p. 155. 537 Id., pp. 155-156; 5 TR 1322-1323, 1400.538 Id.

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This PFD recommends that the Commission adopt Staff’s proposed pipeline

integrity expense amount of $19,510,600 for the projected test year. Staff’s

recommended disallowance related to the use of EMAT is well supported by Ms.

Creisher’s testimony, whereas the Company has given no basis to support its belief that

it will receive the requisite approval for use of EMAT in 2018. Nor has the Company

challenged Staff’s characterization of “the long outstanding deficiencies in the Company’s

procedures for the use of EMAT technology” to justify Staff’s proposed disallowance.539

Moreover, the Company’s argument that its average pipeline integrity O&M expenses are

still impacted by verification digs where no pipe is replaced is not easily reconciled with

the Company’s assertion that the highest portion of a dig cost, staging and excavation,

will still be required.540 As noted by Staff, “[s]ince Staff’s methodology already accounts

for the highest costs, which are also incurred on verification digs, then the impact of

verification digs on the capital to maintenance dig cost ration should not be significant.”541

And, the Company’s speculation that there “could be smaller segments, which could allow

for slightly lower material cost, but would be offset by higher labor associated with

contractor welding cost” is insufficient justification for the Company’s proposed

expenditure level against the backdrop of the alternative repair criteria recommended by

Mr. Miller, some of which require no welding at all.542 Finally, in Section IV.A.1.b.i. above,

this PFD has recommended that the Commission adopt Staff’s proposed disallowance of

539 Staff’s Initial Brief, p. 127.540 Consumers Energy’s Reply Brief, pp. 148-149.541 Staff’s Reply Brief, p. 34.542 6 TR 1683.

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the Company’s pipeline integrity capital expenditures, to which this proposed O&M

expense corresponds.

For these reasons, this PFD recommends the Commission adopt Staff’s proposed

pipeline integrity expense amount of $19,510,600 for the projected test year.

b. Leak Repair and Survey Expense

The Company projects a leak repair and survey expense amount of $11,216,000

for the projected test year, to which no party has objected. Accordingly, this PFD

recommends that the expense amount be adopted by the Commission.

c. MAOP Transmission Expense

The Company originally projected a MAOP transmission expense amount of

$5,638,000 for the projected test year, however the Company removed this projected

expense in its rebuttal filing, having concluded that the expense “was not being used for

compliance with the Traceable, Verifiable, and Complete requirements provided in

Advisory Bulletin ADB-2012-06.”543 Except to note its disagreement with the Company’s

position that the Act or advisory bulletins related to MAOP impose new requirements or

enforceable regulations with which the Company must comply, Staff accepts and

recommends that the Commission adopt the Company’s revised position.

Accordingly, this PFD recommends that the Company’s removed expense

adopted by the Commission.

543 Consumers Energy’s Initial Brief, p. 157, citing 5 TR 1377.

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d. Meter Reading Expense

The Company projects a meter reading expense amount of $13,143,000 for the

projected test year, to which both Staff and the Attorney General have objected, with Staff

proposing a $6,357,000 disallowance and the Attorney General proposing a $4,145,000

disallowance.544

i. Staff

In support of its proposed reduction, Staff contends that the Company’s

methodology of projecting the meter reading expense by applying a 2% per year inflation

increase to the 2015 actual expense arbitrarily assumes an inflation rate of 2% that is

unsupported by the historic meter reading expenses between 2016 and 2015.545 Staff

also contends that the Smart Energy benefit “appears to be negligible when comparing

the projected test year cost with actual costs observed before the program was

implemented.”546 Because of this, Ms. Fromm testified:

Staff recommends taking the 2015 actual and adjusting for a cost per meter. As Company witness Lisa DeLacy testifies, 2015 was the year the Company began installing its AMI meters, and in 2017 the Company planned to be complete with those installations. The combination gas/electric customers represent 37% of the gas customers. (DeLacy Direct Testimony, pp 8, 33.) Staff recommends adjusting the 2015 meter reading expense by 37% to reflect the cost to read meters not yet with an AMI or AMR solution, resultingin a test year meter reading expense of $6.786 million. (Exhibit S-17.2.)547

Should the Commission disagree with Staff’s cost per meter analysis, Staff

544 Exhibit A-49; Staff’s Initial Brief, Appendix C; Exhibit AG-17.545 6 TR 1956.546 Id.547 6 TR 1956-1957.

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proposes in the alternative that:

the Commission should still acknowledge the flaw in assuming a 2% yearly inflation to the 2015 meter reading expense. The history of meter reading expenses clearly does not support this trend, nor does the Company in its testimony. Furthermore, Staff would like the benefit included in the AMI business case to be the realized Smart Energy meter reading benefit deducted from the 2015 meter reading actual to derive the test year projected expense. The benefit of $1.795 million shown in Ms. Palkovich’s Exhibit A-51 (MPP-3) does not match the projected test year benefit as supported by Ms. DeLacy. (Exhibit A-21 (LMD-3), p. 3.) The business case benefit for the test year is $2.555 million (.5*2.507+.5*2.602). Should the Commission disagree with Staff’s cost per meter approach, Staff believes the Commission should at a minimum not allow the 2% inflation and also accept the projected benefit as supported by Ms. DeLacy for a test year meter reading expense of $8.236 million, as the benefit she provides is supported in the Smart Grid Program business case, whereas Ms. Palkovich’s figure has no support.548

In response, the Company notes that, per Ms. DeLacy’s testimony, the actual

average annual increase of meter reading expenses from 2006 through 2015 is 2.89%

per year; as such, the utility’s recommended 2% inflation increase is less than the

historical increases for that period.549 Also, the Company submits, Staff’s 37% reduction

of the 2015 actual meter reading expense to reflect the 37% of total gas customers with

automated meter reading oversimplifies the Company’s meter reading operations, which

the Company “has never claimed … would result in a 37% decrease in gas meter reading

costs, but rather has expected a 14% reduction in gas meter reading labor and non-labor

costs.”550 Regarding Staff’s alternative proposal, the Company argues:

The benefit of $1,795,000 in Exhibit A-51 (MPP-3) should not match the $2,555,000 million benefit in the AMI business case. The direct labor and non-labor savings of $1,795,000 reflected in Exhibit A-51 (MPP-3) are a

548 6 TR 1957.549 Consumers Energy’s Initial Brief, p. 157, 2 TR 101.550 Consumers Energy’s Initial Brief, p. 158, citing 2 TR 102.

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subset of the labor, non-labor, employee benefit, and payroll tax savings in the AMI business case in Exhibit A-21 (LMD-3). 2 TR 102. The employee benefit and payroll tax savings benefits are expected to be incorporated as part of those expense items, and it would be double counting those expected savings to also include them as a direct reduction to the meter reading expense. 2 TR 103.

Ms. Fromm also argued that if the Commission does not disallow all AMR Program costs, the Commission should reduce the meter reading expense by an additional $5,674,000 based on the expected benefit in the Company’s AMR business case. 6 TR 1958. Staff’s recommendation does not take into account that the Company already included an adjustment for AMR direct O&M operational savings of $4,556,000 in Exhibit A-20 (LMD-2), and just as with the AMI savings, that expense reduction should notmatch the $5,674,000 savings from the business case because it does not include employee benefit and payroll tax savings benefits. 2 TR 103. As Ms. DeLacy testified, the “Company has included the appropriate meter reading cost adjustments for AMI in Exhibit A-51 (MPP-3) and the appropriate meter reading cost adjustments for AMR in Exhibit A-20 (LMD-2).” 2 TR 103.551

This PFD finds that neither Staff’s nor the Company’s charts as provided in the

testimony of Ms. Fromm and Ms. DeLacy are particularly helpful in determining whether

the Company has assumed an arbitrary inflation rate of 2%, as maintained by Staff.552

Absent this guidance, this PFD finds reasonable Staff’s recommendation that expenses

be calculated based on the 2015 actual adjusted by 37% (to reflect the cost to read meters

not yet with an AMI or AMR solution), for a total test year meter reading expense of

$6,786,000. As noted by Staff, this approach was recommended by Staff, supported by

the ALJ, and adopted by the Commission in Case No. U-18255.553

Accordingly, this PFD recommends that the projected meter reading expense

amount of $6,786,000 be adopted by the Commission.

551 Consumers Energy’s Initial Brief, p. 158.552 6 TR 1957; 2 TR 101.553 MPSC Case No. U-18255, April 18, 2018 Order, p. 45, footnote 9.

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ii. Attorney General

In support of the Attorney General’s recommended reduction of $4,145,000 to the

meter reading expense, he maintains that the Company’s projected test year amount is

inflated as it fails to reflect the decline in meter readers and resulting lower cost.

According to Mr. Coppola, he obtained actual meter reading O&M expenses for the first

10 months of 2017 and used the Company’s projections for the last two months, to

calculate an estimated cost of $11,937,000 for 2017, from which he subtracted 42%,

based on information that the number of meter readers is expected to decrease by that

percent in 2018, for a test year expense of $6,923,000.554

The Company responds that the Attorney General has failed to consider the

Company’s inclusion of an AMR benefit of $4,556,000 in operational savings, of which

$3,980,000 relate to meter reading.555

This PFD recommends that the Commission reject the Attorney General’s

recommended reduction as it appears that Mr. Coppola’s calculation is indeed duplicative

of savings already accounted for by the Company and the Attorney General failed to

respond to or otherwise address Ms. DeLacy’s rebuttal testimony in this regard.556

2. GCS And Gas Management Services O&M

As presented by Ms. Hill, the Company projects its GCS and gas management

services (GMS) O&M expense for the test year to be $27,145,000, which is comprised of

554 Attorney General’s Initial Brief, p. 29, citing 7 TR 2342 and Exhibit A-51.555 Consumers Energy’s Initial Brief, p. 159, citing 2 TR 104 and Exhibit A-20.556 2 TR 104.

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a base O&M amount of $23,095,000 and an adjusted O&M expense of $4,050,000.557

Finding that the Company’s forecast of the 2017 base O&M expenses “varied

substantially from the actual expenses through November 2017 and the forecasted

expenses for December 2017,” Staff initially recommended that the Company’s GCS and

GMS O&M expense level for the test year be reduced by $301,000 to $26,844,000,

arguing that the level “should be adjusted based on 2017 actual Base O&M expense

levels that were not available at the time of the Company’s preparation for filing of this

application, testimony, and projected test year calculations in this current case.”558 Ms.

Creisher explained the calculation of Staff’s proposed test year base O&M expense level:

Staff’s proposed test year Base O&M expense level is derived by applying Staff’s forecasted inflation factors, which are supported by Staff Witness Kirk Megginson, of 2.01% for 2018 and 2.25% for 2019 to the actual Base O&M expenses through November 2017 and projected O&M expense levels for December 2017. By applying an inflation factor of 2.01% for 2018 and a prorated inflation factor of 1.13% for the 6 months ending June 30, 2019, Staff calculated a Base O&M expense level for the test year ending June 30, 2019 of $22,457,000 as shown in Exhibit S-11.2.559

However, Staff further acknowledges and accepts the Company’s rebuttal position that

included updated 2017 actual expenses of $22,096,000 but still recommends that the test

year expense level be projected using this amount with inflation factors applied, producing

an expense level of $22,794,000.560

In response, recognizing there “is not a wide disparity between the parties on this

557 2 TR 447; Exhibit A-41.558 Staff’s Initial Brief, pp. 139-140, citing 6 TR 1867-1868 and Exhibit S-11.8.559 6 TR 1867-1868.560 Staff’s Initial Brief, pp. 140-141; see also Exhibit A-100.

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issue,” the Company contends that the total variance of $799,000, or approximately 3%

is not substantial and that the Commission should approve the Company’s test year base

O&M expense, “which was based on the Company’s projected needs, rather than relying

on Staff’s unsupported inflation factor.”561

This PFD recommends that the Commission adopt Staff’s recommended expense

level of $22,794,000, the calculation of which is well supported by Ms. Creisher’s

testimony and, as noted in Section VII.D.1. above, the Company has offered no

persuasive argument against the utilization of 2017 actual information to update the

Company’s projected test year O&M levels, except to contend that Staff’s applied inflation

factor is unsupported. However, Ms. Creisher relied upon inflation factors developed by

Mr. Megginson, who testified:

Staff recommended an average inflation rate of 2.01% for 2018 and 2.25% for 2019 using December 2017 estimates from Value Line, Global Insight and the Energy Information Administration. Staff’s inflation rate forecasts are outlined on Exhibit S-4, Schedule D-3, page 2 of 2.562

Thus, it cannot be said that Staff’s inflation factor is unsupported. Moreover, the

methodology by which Staff calculated and projected this inflation factor is the same as

that which was recently presented by Staff in DTE Electric’s last rate case, Case No. U-

18255, and found by the Commission to be “the most reasonable.”563

For these reasons, this PFD recommends that Staff’s recommended GCS and

GMS O&M expense level for the test year of $22,794,000 be adopted by the Commission.

561 Consumers Energy’s Initial Brief, p. 162; Consumers Energy’s Reply Brief, pp. 152-153.562 6 TR 1867-1868, 1722.563 MPSC Case No. U-18255, April 18, 2018 Order, p. 38.

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3. Business Services O&M

The Company projects its gas business services O&M expenses for the test year

12 months ending June 20, 2019 to be $9,874,000.564 No party has opposed this

projected expense. This PFD therefore recommends that the projected gas business

services expense amount of $9,874,000 be adopted by the Commission.

4. Corporate Services O&M Expense

The Company projects that the corporate services O&M expense for test year for

the gas utility portion to be $31,509,000.565 No party has opposed this projected expense.

This PFD therefore recommends that the projected corporate services expense amount

of $31,509,000 be adopted by the Commission.

5. Information Technology O&M Expense

The Company’s witness Christopher J. Varvatos testified regarding the utility’s

projected test year information technology (IT) O&M expenses for 2017 and 2018, which

are $28,110,000 and $31,002,000, respectively.566 No party having opposed these

projected amounts, this PFD recommends that the projected IT expense amounts for

2017 and 2018 of $9,874,000 be adopted by the Commission.

6. Pension And Benefits Expense

The Company initially projected its employee benefits O&M expense for the 2017

test year to be $23,310,000, but the Company agreed in its rebuttal testimony to accept

564 Exhibit A-70.565 5 TR 569; Exhibit A-46.566 Exhibit A-73.

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Staff’s proposal, also recommended by the Attorney General, to reduce the total test year

expense by $21,203,000 based on the December 31, 2017 pension and OPEB plan

actuarial measurements.567 Thus, the revised total gas O&M expense level for employee

benefits is $2,107,000, which amount is comprised of: (i) a pension plan expense of

$17,301,000; (ii) a defined company contribution expense of $5,300,000; (iii) a 401k

employees’ savings plan (ESP) expense of $4,933,000; (iv) an active employee health

care, life insurance, and long-term disability (LTD) insurance expense of $16,289,000;

and (v) a retiree health care and life insurance expense, also known as Other Post-

Employment Benefits (OPEB) expense, of ($41,716,000).568

The Attorney General recommends an adjustment of $1,600,000 in pension and

OPEB expenses, to reflect a projected rate of return on plan assets of 7.25% instead of

the Company’s projected rate of return of 7.00%, as well as an adjustment of $3,100,000

to the pension plan expense to reflect the Attorney General’s suggestion that cash

contributions to the pension plan of $100,000,000 should be made in both 2018 and

2019.569 These recommended adjustments are addressed below.

The Attorney General’s first proposed adjustment, regarding the projected rate of

return, takes issue with Mr. Kops’ explanation of the decreased return rate, as provided

in a discovery response to the Attorney General. According to Mr. Coppola, Mr. Kops’

reference to the Company’s historical reductions every two years as being consistent with

567 6 TR 2102; 2 TR 153; 7 TR 2366.568 Exhibit A-105.569 Attorney General’s Initial Brief, pp. 46-57.

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current market trends no longer makes sense given the “booming stock market in recent

years.”570 Mr. Coppola also took issue with the survey data relied upon by the Company,

contending it does not justify the reductions for 2018 and 2019 because it “shows the

median return rate actually increased in 2016 by 28 basis points to 7.33%.571

He also opined that Mr. Kops’ reliance on the article, “Diminishing Returns: Why Investors

May Need To Lower Their Expectations,” has “no direct relevance to the Company’s

situation given the adjustments made over the past 7 years.”572

Relying on the rebuttal testimony of Mr. Kops, the Company responds that Mr.

Coppola’s recommendation should be rejected for three reasons:

The Company has updated Plan information that requires it to update its expected return assumption. The Company incorporates future expected capital market assumptions, asset allocation information, and other resources provided by its consultants. It is important to note that the expected return assumption is based on long-term expectations and not short-term returns. For example, Mr. Coppola contends that the Company should update its expected return based on “the booming stock market in recent years.” This contention disregards the market swings that already have taken place in 2018 or potential future market expectations.

Secondly, the Edison Electric Institute Pension Survey for 2017, attached as Exhibit A-106 (HBK-5), demonstrates that the Company’s long term assumption decline from 7.25% to 7.00% is consistent with what other utility peers are expecting for 2018. The average expected pension plan fund return for 2018 is 7.05%. Consumers Energy’s historical 10-year return for its Pension Plan is 6.3%, which is more in line with the 2018 return assumption of 7.00% versus the 7.25% recommended by Mr. Coppola.

Also, the Company’s investment advisory consultant, New England Pension Consultants, prepared a memo which fully supports the 7.00% return on assets assumption rate used to calculate 2018 and 2019 expense for the

570 2 TR 2368.571 Id.572 Id.

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Company’s pension and OPEB plans. The memo is provided as Exhibit A-107 (HBK-6).573

Against the backdrop of Mr. Kops’ detailed explanation and supporting exhibits

regarding how the Company determined the 7.00% return on assets assumption rate, this

PFD is not persuaded that the Attorney General’s recommended reduction is reasonable

and appropriate. Although the Attorney General has attempted to discredit Mr. Kops’

testimony by pointing out that the Company could not have relied upon a December 18,

2017 memo from its investment advisory consultant to establish the 7.00% return on

assets assumption rate presented in the Company’s original filing, on October 31, 2017,

this attempt mischaracterizes Mr. Kops’ testimony. Specifically, Mr. Kops testified in his

direct testimony in relevant part that the rate of return assumption for 2018 and 2019 “is

intended to be a long-term assumption based upon the best estimate of long-term

expected investment earnings of the plan assets.”574 He further testified that, pursuant to

the Company’s required annual review of these assumptions in accordance with GAAP

and ASC 715 requirements, the Company “remeasured both [the pension and OPEM]

plans” at the end of 2017 and, relying in part on the December 18, 2017 memo from its

investment advisory consultant, established the 7.00% assumption rate for 2018 and

2019 on December 31, 2017.575 In short, there is no substantive discrepancy in Mr. Kops’

testimony, as maintained by the Attorney General.

In support of the Attorney General’s second proposed adjustment, Mr. Coppola

573 2 TR 154-155.574 2 TR 143.575 2 TR 165-166. (Emphasis added).

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testified as to the Company’s previous cash contributions to the pension plan in 2015 and

2016 and how the restructuring of its pension plan in December 2017 have changed the

requirements for cash contributions and PBGC flat rate premiums such that “the

Company now shows cash contributions beginning in 2020 and later years, but still no

cash contributions in 2018 and 2019.”576

The Company responds that no legal basis exists for the Attorney General’s

proposed adjustment, noting that at times the Company has contributed in excess of the

Employee Retirement Income Security Act (“ERISA”) Minimum Funding Standards “to

ensure its employees and retirees have a secure pension” after consideration of

Company-wide priorities, but continually making such contributions would put at risk

Company spending in other areas for the benefit of customers.”577

This PFD also disagrees with the Attorney General’s second proposed adjustment.

Mr. Kops provided a detailed explanation for why the Company should not be required to

contribute $100 million in annual pension contributions in 2018 and 2019 and the Attorney

General has failed to present a legitimate basis to dispute Mr. Kops’ explanation.

This PFD therefore recommends that the Attorney General’s requested

adjustments be rejected, and that the Commission adopt the Company’s revised test year

revised total O&M expense level for employee benefits of $2,107,000.

576 7 TR 2371-2372.577 2 TR 155.

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7. Incentive Compensation Expense

The Company seeks to recover the test year costs of its employee incentive

compensation plan (EICP) in the amount of $1,752,550, which consists of the EICP linked

to operating performance metrics, totaling $590,000, and the remaining amount of

$1,162,550 for the portion of the EICP linked to financial performance metrics.578 In her

testimony, Ms. Conrad provided a general overview of the Company’s compensation

philosophy and structure, as well as the components of the overall compensation for non-

officer employees and officers of the Company.579

In 2017, the EICP had 14 specific performance measures for non-officer

employees encompassing continuous improvement, safety, quality, cost, delivery,

morale, and being financially healthy.580 Ms. Conrad indicated that these same plan goals

will be in effect for 2018, with 50% of the non-officer incentive compensation based on

the safety, reliability, and customer value measures, and the remaining 50% based on

the financial measures.581 The goals for the officer EICPs are the same as those for the

non-officer EICPs, but they are weighted differently.582

Staff seeks the exclusion of that portion of the Company’s incentive compensation

expense that is timed to financial metrics, or $1,162,550, while the Attorney General

recommends that the entire amount of $1,752,550 be disallowed.583

578 Exhibit A-18.579 2 TR 396.580 2 TR 419; Exhibit A-17.581 2 TR 419.582 2 TR 396.583 Staff’s position in its Initial Brief is somewhat confusing as Staff first argues on pages 143-147 for a $1,162,550 reduction, but then argues on page 148 that Staff agrees with the Attorney General’s recommended exclusion of the entire $1,752,550. Because the testimony of Staff witness, Brian Welke,

U-18424Page 238

Mr. Welke testified that the Commission has long held that incentive plans that are

tied to financial metrics, such as earnings, benefit shareholders and that, to shift such

costs to ratepayers, the Company must quantify the benefits to ratepayers that are tied

to non-financial metrics and demonstrate that the benefits to customers of the plans

outweigh the costs.584 He testified that Staff is further unable to support the Company’s

request to include financial based performance measures of EICP expense in rates

because “the Company has been unwilling to share the benefits of the achievement of

financial measures with ratepayers on a projected basis.”585 Yet, Mr. Welke maintains that

projected O&M savings “could assist in the achievement of both an earnings per share

and cash flow financial performance measures.”586 As a result, Staff recommends

inclusion of only that portion of the Company’s incentive plan costs related to the

achievement of non-financial goals.587

The Attorney General recommends excluding the Company’s incentive

compensation costs in entirety.588 In support of this recommendation, Mr. Coppola’s

assessment concluded that Company’s short-term incentive plans are too heavily

weighted toward financial measures that benefit mostly shareholders, but not

ratepayers.589 This, he noted, is evidenced by the fact that only $590,000 (or 34%) of

the projected $1.8 million in short-term incentive compensation would be paid out if no

and the calculations reflected in Staff’s Appendix C recommend and incorporate a $1,162,550 reduction,this ALJ will analyze Staff’s first position.584 6 TR 2136.585 Id.586 6 TR 2137.587 6 TR 2137; see also Appendix C to Staff’s Initial Brief.588 7 TR 2363.589 7 TR 2355.

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financial measures were achieved and all non-financial measures were achieved.590 Mr.

Coppola further found that the purported ratepayer benefits claimed by the Company are

“highly inflated and often stale”.591 He further noted that the Company offered no exhibits

to support Mr. Stuart’s stated cost savings regarding the EICP cost, and that most of the

cost savings relate to the entire Company and only in some cases exclusively to the gas

business.592 Mr. Coppola also challenged portions of Mr. Stuart’s presentation, including

the assertion that the Company has kept O&M expenses below the rate of inflation since

2006, with potential annual savings of $160 million:

These are not real savings but simply a “what-if” exercise. The claim of keeping O&M costs below the rate of inflation rings hollow when in this rate case filing the Company is requesting that customer rates include O&M cost increases reflecting payroll increases of more than 3%. In fact, O&M expenses, excluding Lost and Unaccounted for gas and Company use gas which are generally out of the control of the Company, are projected to increase by $18.3 million or 5.5% from 2016 to the end of June 2019 projected test year. Clearly, customers are not benefiting from any O&M cost decreases, real or otherwise.593

Recognizing the Commission’s order in Case No. U-18124 allowed Consumers Energy

to recover a portion of its projected short-term incentive compensation expense related

to only achieving operating goals, Mr. Coppola testified that “the Company did not make

a case sufficient enough to justify recovery of the proposed incentive compensation costs

in Case No. U-18124. This is also true in this rate case.594 In addition, Mr. Coppola

testified that if the Commission wished to include some of the projected expenditures in

590 7 TR 2355; Exhibit AG-12.591 7 TR 2359.592 Id.593 7 TR 2361. (Footnote omitted).594 7 TR 2364.

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rates it should not be more than the $590,000 shown by the Company to be related only

to the operating performance measures.595

The Company maintains that the exclusions recommended by Staff and the

Attorney General should be rejected. Specifically, the Company responds that the

assertions by Staff and the Attorney General that the EICP financial metrics mostly benefit

investors and not customers are refuted by Ms. Conrad’s testimony that “[t]he financial

measures provide appreciable benefits to customers by allowing Consumers Energy to

maintain an attractive cost of capital, among other benefits, in addition to any benefits

provided to shareholders.”596 The Company further refutes these assertions with Mr.

Maddipati’s testimony that “[t]he two financial measures used to determine EICP are

critical to attracting capital and maintaining credit, both of which benefit customers by

enabling necessary investments and lowering interest costs.”597

The Company also disagrees with Staff’s assertion that the Company’s financial

measures are undefined, noting that the information regarding the earnings per share and

operating cash flow guidance is available to the public on the Company’s website.598 The

Company further contends that it shares the benefits of financial metrics achievements

with ratepayers because, “[a]s the Company reduces operating costs in an effort to

achieve its financial-based performance targets, the savings are passed on to customers

in the form of lower rates.599 Finally, the Company submits that because it is only seeking

595 Id., citing Exhibit AG-12.596 Consumers Energy’s Initial Brief, p. 179; 2 TR 430.597 Consumers Energy’s Initial Brief, p. 180; 4 TR 912.598 2 TR 434.599 4 TR 1120.

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funding for its incentive compensation plan up to the approved target payout level of

100%, customers are not impacted in terms of rates if the payout in a particular year is

above 100%.600

The Commission has disallowed incentive compensation expenses in every rate

case issued in the decade preceding 2015 for two reasons: (1) “incentive compensation

plans that were tied to Company earnings and cash flow were financial considerations

that largely benefit shareholders and should not be paid for by ratepayers;” and (2)

“utilities must quantify the benefits to ratepayers of employee incentive compensation

plans that are tied to non-financial metrics and demonstrate that the benefits to customers

of such plans outweigh the costs.”601

However, in 2015, in Case No. U-17735, the Commission approved the

Company’s short-term incentive compensation plan, having concluded that the Company

had provided convincing evidence that its proposed costs for its short-term EICP afforded

appreciable benefits to customers and met the standard enunciated in the Commission’s

Order in Case No U-15233.602 The Commission again revisited this issue in Case No.

U-17990 and determined “it is reasonable for the company to recover amounts

undisputedly linked to utility operating performance metrics meant to benefit customer

service.”603 The Commission thus approved the Company’s proposed costs of its short-

600 2 TR 432-433.601 MPSC Case No. U-15233, December 23, 2008 Order, p. 38. 602 MPSC Case No. U-17735, November 19, 2015 Order, p. 77.603 MPSC Case No. U-17990, February 28, 2017 Order, p. 106.

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term EICP for the projected payout for non-financial measures, “[a]ssuming that target

performance in all non-financial measures is met.”604

The Commission concluded similarly in the Company’s last natural gas rate case,

finding that the Company “provided convincing evidence that the non-financial measures

of the short-term EICP provide appreciable benefits to ratepayers, and the company

quantified the benefits associated with the metrics of safety, reliability, and customer

value.”605 Likewise, in DTE Electric’s most recent rate case, Case No. U-18255, the

Commission again disallowed incentive compensation tied to achieving financial

measures, concluding:

This is consistent with prior Commission decisions and is reasonable and prudent given that these measures do not benefit ratepayers. As noted in the last rate case, “[t]he Commission agrees that the company failed to support its request for incentive compensation related to financial metrics, specifically noting that the purported benefits to ratepayers that DTE Electric cites are attenuated at best, and in some cases, specious.” The 2017 order, p. 85. However, regarding the additional 50% disallowance proposed by the Attorney General, the Commission declines to adopt the ALJ’s recommendation. The Commission notes that DTE Electric provided evidence showing that the company has achieved performance targets for AIP at an average of 96.3%, and for REP at an average of 82.8%, from 2012 through 2016. 7 Tr 837. When looking at historical performance over a longer period, the Attorney General’s recommendation that 50% should be disallowed is simply not supported.606

Against the backdrop of this recent Commission precedent, and based on the

record in this case, this PFD finds that the Company has established there are

appreciable benefits afforded to ratepayers by the non-financial measures of the

Company’s EICP. To be sure, this PFD notes that the Company’s EICP equally weighs

604 Id.605 MPSC Case No. U-18124, July 31, 2017 Order, p. 87.606 MPSC Case No. U-18255, April 18, 2018 Order, pp. 48-49.

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the operational and performance measures of safety, reliability, and customer value with

the financial measures.607 Ms. Conrad explained that 50.0% of the non-officer incentive

compensation is based on the safety, reliability, and customer value measures, and the

remaining 50.0% is based on the financial measures.608 Through the testimony of Mr.

Shirkey, the Company quantified the customer benefits associated with five key metrics:

employee safety, distribution reliability, generation reliability, first time quality

improvement, and productivity improvement.609 Mr. Shirkey concluded that, utilizing an

allocation of 37% for gas customers, Mr. Stuart concluded that his quantification “equates

to annual savings for gas customers of more than $61.478 million, significantly more than

the annual costs of the EICP allocated to gas customers.”610 Accordingly, this PFD

recommends the Commission reject the total disallowance of short-term EICP

recommended by the Attorney General and instead adopt Staff’s recommendation to

allow that portion of the Company’s proposed costs of its short-term EICP for the

projected payout for non-financial measures, or $590,000.611

8. Gas AMR Expense

Supported by the testimony of Ms. DeLacy, Company has projected a test year

gas AMR expense of $649,000 associated with the installation of gas AMR modules and

related activities in the test year, which the Company maintains is offset by direct O&M

operational savings of $4.556 million related to AMR.612

607 2 TR 395.608 Id.609 2 TR 496.610 2 TR 498.611 Exhibit S-3; see also Appendix C to Staff’s Initial Brief.612 2 TR 40; Exhibit A-20.

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As set forth above in Section IV.A.5., Staff recommends disallowing all AMR

program costs, including both projected test year O&M costs and operational savings

related to AMR.

Consistent with this PFD’s recommendation in Section IV.A.5 that the Commission

should adopt Staff’s recommended disallowance all AMR expenditures in light of

outstanding questions regarding the Company’s ability to achieve the alleged benefits of

AMR in this proceeding, this PFD recommends that the Company’s corresponding

projected O&M costs and savings related to the AMR program be disallowed.

9. Customer Experience O&M Expense

The Company projects a test year expense amount of $12,499,000 for customer

experience, which amount is comprised of: (i) a customer services expense of

$1,373,000; (ii) a digital customer experience (DCE) expense of $5,137,900; and (iii) a

marketing and strategy expense of $5,988,200.613

Both Staff and the Attorney General have proposed reductions to this expense,

with Staff recommending a $3,900,000 reduction to the projected marketing and strategy

portion of the expense, and the Attorney General recommending a $5,858,700 reduction

to the total projected expense amount.614

In support of Staff’s proposed reduction, Staff contends that despite attempting to

ascertain through several discovery requests the work output that has resulted from the

613 Exhibit A-48.614 Staff’s Initial Brief, p. 136; Attorney General’s Initial Brief, p. 30.

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Company’s funding of its customer services and marketing and strategy departments, the

Company could not demonstrate any such work output. Staff argues that, “[w]ithout any

evidence on the record for what the Company actually does as a result of these two

departments, Staff believes the Commission should disallow any increases in funding and

require the Company to provide evidence of work output in any future requests including

funding of these departments.”615

The Attorney General likewise recommends that this expense be set at a level no

higher than the forecasted level for 2017 of $6,640,300. Relying on Mr. Coppola’s

testimony, the Attorney General contends the Company has not provided sufficient detail

or adequately justified its projected test year level for this expense.616

The Company argues that both proposed reductions should be rejected.

Regarding Staff’s assertions, the Company agrees that it has no identifiable capital

projects in the marketing and strategy department and this is so because of the nature of

the work – but the Company maintains that the inability to break out the work by program

or project should not undermine its importance. Relying on the testimony of Ms.

Youngdahl, the Company contends that the proposed increase in spending is to improve

customer experiences and to improve its current position in the JD Power residential gas

survey, and to increase its ranking in the JD Power business gas survey, which currently

ranks the Company in the low second quartile.617 The Company further disputes the

615 Staff’s Initial Brief, p. 137-139.616 Attorney General’s Initial Brief, pp. 31-32, citing 7 TR 2344-2346.617 Consumers Energy’s Reply Brief, p. 167, citing 5 TR 1187.

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Attorney General’s assertion that the Company failed to adequately justify the cost

differences for this expense based on historical spending levels, pointing to the

Company’s discovery responses wherein the Company maintains it “extensively

explain[ed] the work being done by Marketing and Strategy but it also explained the

results of that work.”618

This PFD agrees with both Staff and the Attorney General that the Company’s

support for this projected test year level expense for customer experience is deficient.

Although the Company has relied at length on its responses to Staff’s discovery as set

forth in Exhibit S-17.3 to maintain that it has extensively supported its projected expense

level, Question 28 specifically asked:

Regarding Exhibit A-48, please explain the significant projected increases in test year O&M expenses from 2016 for each of the three Customer Experience programs. Please provide a detailed explanation for each increase: Customer Services (Labor and Business Expense), Digital Customer Experience (Contractor, Labor, and Business Expense), and Marketing & Strategy (Contractor, Labor, and Business Expense). Within each explanation, please provide the benefit the customers will realize as a result of the spending increase.619

Missing from the response provided by the Company to Staff’s request was any specific,

concrete description of the benefits to be realized by customers as a result of the

projected increases. Instead, the only information from the Company that is arguably

responsive to this request is as follows:

This [Customer Services] group also supports customers by helping them understand Company policies, strategic direction, company announcements, regulatory and legislative policies, costs implications

618 Id., citing S-17.3, pp. 18-21.619 Exhibit S-17.3, p. 18. (Emphasis added).

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including rate design and tariffs, energy efficiency, and energy management.

***Marketing & Strategy provides data-driven insights and the strategy on how to communicate with customers in the ways they prefer. Third party data is also being utilized to assist with customer segmentation … [which] will allow us to deliver a unique customer experience based on how the customer wants to interact with the Company. All of this information is used as inputs to modify policies, adjust processes, develop better communication efforts, and inform product and service development, with the ultimate goal of improving customer satisfaction.620

Without more than generalities regarding the manner in which customers will

benefit from the Company’s projected spending increase, this PFD is unable to determine

whether such an increase is reasonable and prudent and should be borne by ratepayers.

Consequently, this PFD recommends that the Commission adopt the Attorney General’s

recommended reduction of $5,858,700, resulting in a spending level no higher than the

forecasted level for 2017 of $6,640,300.

10. Customer Payment Program O&M Expense

The Company projects a test year O&M expense amount of $7,497,000 for its

customer payment program.621

The Attorney General recommends the Commission set this expense at the same

level as in 2016, resulting in a reduction of $4,614,000 in the amount projected by the

Company. Specifically, the Attorney General argues that this expense is the result of the

Company’s elimination of a processing fee charged to customers for using its “Easy Pay”

credit card option, and the Company’s subsequent effort to recover those fees. The

620 Id., pp. 18-19.621 5 TR 1179.

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Attorney General argues that because the Company’s recovery of these fees will be offset

by a reduced uncollectible accounts expense, allowing the Company to do so without

considering this reduced uncollectible expense would create a financial windfall for the

Company. 622 Mr. Coppola testified:

Beginning in early 2016, the Company decided to waive the fee charged to customers for use of credit cards when paying electric and gas bills. The Company expanded the program to all residential and small commercial customers, and has since seen an explosive increase in the use of credit cards to pay current and past due bills. In 2015, the Company processed about 1.3 million credit card transactions and that number is expected to increase to nearly 4.4 million transactions by the end of 2019.

According to Mr. Morales’s direct testimony in the Company’s 2017 electric rate Case No. U-18322, the Company decided to make this payment program a no-cost option as a convenience to customers, particularly the” most vulnerable customers”, which it defines as low income customers who have difficulty paying their electric and gas bills. The issue in this case is whether the Company should be allowed to recover incremental fees for credit card transactions when the credit card company now assumes the risk of uncollectible customer bills. This in turn eliminates the Company’s risk of outstanding and past due bill collection and reduces its uncollectible costs.

In other words, there is a significant benefit to the Company from having customers pay their current and past due bills with a credit card and that benefit likely offsets the cost of paying the fee for credit card transactions. To allow the Company to recover the credit card fees and not consider the reduced uncollectible expense would create a financial windfall for the Company and should not be allowed.623

The Company responds that Mr. Coppola has provided no analysis or evidence to

support his position but instead relies upon broad assumptions about credit card

companies assuming the risk of bad debt, as well as about vulnerable customers being

622 7 TR 2348-50.623 7 TR 2347-2378. (Footnotes omitted).

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twice as likely to default on bill payments.624 Ms. Youngdahl further testified that Mr.

Coppola’s recommendation “fails to recognize that low income customers are less likely

to have credit cards and therefore assuming a rate of non-payment that is twice the

average default rate, is not supported.”625 Ms. Youngdahl also disagreed with Mr.

Coppola’s assertion that there is a direct correlation between credit card fees and bad

debt expense, stating that the decline in bad debt expense in recent years “is most likely

a result of several factors including benefits from more consistent turn-on processes, an

improved economy, and smart meter remote disconnect.”626 Finally, the Company noted

that the Attorney General presented an identical recommendation in the Company’s

electric rate case, Case No. U-18322, and the Commission rejected it, concluding that

“the Attorney General did not provide compelling evidence to support his contention that

recovery of credit card transaction fees should result in an adjustment of Consumers’

uncollectible expense.”627

This PFD agrees with the Company that Mr. Coppola’s analysis is deficient as

identified in Ms. Youngdahl’s rebuttal testimony and, in light of these errors, which the

Attorney General has not adequately explained or otherwise rebutted, the ALJ remains

unconvinced by Mr. Coppola’s conclusion that costs related to the Company’s elimination

of a processing fee charged to customers will be offset by a reduced uncollectible

624 5 TR 1188.625 5 TR 1189. 626 Id.627 Consumers Energy’s Reply Brief, p. 172, citing MPSC Case No. U-18322, March 29, 2018 Order, pp. 70-71.

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accounts expense. And, as noted by the Company, the Commission recently rejected

the Attorney General’s same argument presented in Case No. U-18322. Consequently,

this PFD recommends the Commission reject the Attorney General’s proposed

disallowance and approve the Company’s projected test year O&M expense amount of

$7,497,000 for its customer payment program.

11. ASP O&M Expense

The Company’s appliance service program (ASP) margin is a non-regulated

service offering to customers who choose to protect themselves from the cost of

appliance repairs on their enrolled appliances. The Company’s projected test year ASP

margin is $30,867,000.628

The Attorney General has proposed an increase to the Company’s projected ASP

margin by $1,286,000 to $31,153,000. In support of this proposal, Mr. Coppola testified:

The Company has understated the amount of ASP revenue and gross margin included in the rate case filing. The latest projections provided by the Company show a significant increase in ASP revenue for the projected test year. In fact, a review of historical ASP revenue from 2012 to 2016 shows a steady increase in revenue from $46.9 million in 2012 to $67.9 million in 2016.629

The Company disagrees with the Attorney General’s recommendation as it is

“improperly based exclusively on ASP revenue and gross margin forecasts and failed to

consider actual margins and ASP expenses which continue to increase.”630 The

Company points to Ms. Youngdahl’s rebuttal testimony wherein she explained the

628 Exhibit A-47.629 7 TR 2340; Exhibit AG-6.630 Consumers Energy’s Initial Brief, p. 190, citing 5 TR 1191 (Confidential).

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Company’s actual ASP margin results for 2017 and the reasons for those results, as well

as the changed ASP margin forecast for 2018, which is a lower projection than was

originally filed in the Company’s case.631

Staff also disagrees with the Attorney General’s recommendation, arguing that

while the Attorney General sought and obtained from the Company an updated projection

of ASP revenues and expenses, the Attorney General has rejected the expense revision

and accepted the revenue revision without a valid reason. Staff submits that the Attorney

General’s proposal is therefore arbitrary and should be rejected:

The Company’s initial projection is a better projection of the margins it will experience in the test year than the AG’s projection. As the margin relies on both expenses and revenues, to take a margin relying on previous revenues and expenses and apply it to updated revenues without examining the other piece used to calculate margins is unreasonable.632

This PFD agrees with Staff and the Company and recommends that the Attorney

General’s recommendation be rejected. Although the Attorney General characterized

Ms. Youngdahl’s rebuttal testimony as being “light on details” and maintains that it “does

not provide sufficient guidance for the Commission to agree with the Company’s

forecasted gross-margin for ASP in this case,” Ms. Youngdahl provided a reasonable

explanation for the Company’s projected increase in ASP expenses and, except to

criticize the lack of specific detail Ms. Youngdahl was able to provide on cross-

examination regarding the repair costs of certain appliances, the Attorney General does

not substantively refute her explanation.633 And, as noted by Staff, the Attorney General’s

631 5 TR 1191 (Confidential).632 Staff’s Reply Brief, pp. 27-28.633 Attorney General’s Initial Brief, pp. 22-23.

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criticism of the Company’s projected increase in ASP expenses whilst nonetheless

acknowledging and accepting the Company’s expected increase in ASP revenues for the

projected test year overlooks the relationship between the expenses and revenues in

determining a reasonable ASP margin.

This PFD therefore recommends that the Commission reject the Attorney

General’s recommended increase to the Company’s projected ASP margin and instead

adopt the Company’s projected test year ASP margin of $30,867,000.

12. Manufactured Gas Plant Direct Project Management Costs

The Company originally projected a test year manufactured gas plant (MGP) direct

project management expense of $996,000, however the Company has since agreed to

Staff’s proposed reduction of $215,104, for a revised expense of $781,078.634

With this expense no longer disputed, this PFD recommends that the Commission

adopt the Company’s revised MGP direct project management expense of $781,078.635

13.Gas Uncollectible Expense

The Company has projected a test year gas uncollectible expense of

$18,500,000.636 The Company’s witness, Mr. Harry, testified that in calculating this

amount, he utilized a three-year average bad debt loss ratio (BDLR) of uncollectible

accounts expense to gas service revenue for the years 2014-2016.637

634 Consumers Energy’s Initial Brief, p. 192, citing 6 TR 1904; Staff’s Initial Brief, p. 142, Appendix C.635 As noted on page 28 of Staff’s Reply Brief, although the Company accepted Staff’s adjustment, the Company failed to update its appendices, which still indicate a higher revenue deficiency.636 Consumers Energy’s Initial Brief, p. 148; citing 5 TR 571-572; Exhibit A-47.637 3 TR 550551; Exhibit A-32.

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No party has opposed the Company’s use of the three-year average approach or

the Company’s projected uncollectible expense amount of $18,500,000. This PFD

therefore recommends this amount be approved by the Commission.

14.Injuries and Damages Expense

The Company has projected a test year gas injuries and damages expense of

$1,618,000.638 The Company’s witness, Mr. Harry, testified that in calculating this

amount, he utilized a three-year average bad debt loss ratio (BDLR) of uncollectible

accounts expense to gas service revenue for the years 2014-2016.639

Staff recommends a $1,645,000 reduction to the Company’s projected expense.

In support of this recommendation, Mr. Welke described the costs included within the

“Injuries and Damages” expense under the Federal Energy Regulatory Commission

Uniform System of Accounts, which the state of Michigan has adopted, and Mr. Welke

noted that account 925 is the account used by the state of Michigan and in which this

expense is booked.640 He further testified that the Company’s projection incorrectly used

the calendar year 2016 sum of three expense elements and then used inflation to escalate

them through the projected test year, whereas Staff’s projection is based on the use of a

five-year average of account 925, a methodology endorsed by the Commission in Case

No. U-16794.641

The Company disagrees with Staff’s position and contends that Mr. Welke

638 Consumers Energy’s Initial Brief, p. 194; citing 3 TR 552; Exhibit A-33.639 3 TR 550551; Exhibit A-32.640 6 TR 2138.641 Id.

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misunderstood how the Company determined these costs and his calculations reflect

clear error. The Company notes that Exhibit A-33, footnote 1, expressly states that the

“Test Year Ended 6/30/2019 used a 5-year average (2012-2016)” and this was reiterated

by Mr. Harry in his rebuttal testimony.642 The Company further maintains that Mr. Welke’s

proposed calculation has resulted in an illogical negative expense because it relied on

inputs unrelated to the corporate projection of injuries and damages in this case:

Account 925 includes amounts far in excess of amounts included in Exhibit A-33 (DLH-4). For example, Account 925 contains MGP amortization expense which has a specific recovery method defined by Commissionorder. In addition, Account 925 contains insurance premiums covered in other areas of the case. Staff’s five-year average (2012-2016) exceeds the Company five-year average projection by $12.745 million ($14.372 million -$1.618 million). As a result, Staff’s method is inappropriate because it uses data unrelated to the Company’s Injuries and Damages exhibit to produce a negative expense. The Company did not have negative Injuries and Damages expenses. The Company has consistently used the approach in Exhibit A-33 (DLH-4) in all of its recent electric and gas rate case filings and has consistently received full Commission approval of its Injuries and Damages cost.643

This PFD agrees with the Company and finds that Mr. Harry’s rebuttal testimony

adequately illustrated that the Company’s projected test year injuries and damages

expense was indeed based on the five-year average approach previously endorsed by

the Commission, without application of an inflation factor. Staff neither addressed nor

refuted this portion of Mr. Harry’s rebuttal testimony. Nor has Staff addressed or

acknowledged Mr. Harry’s rebuttal testimony that Mr. Welke erroneously relied upon all

expenses in account 925, including non-injuries and damages expenses, rather than only

642 Consumers Energy’s Initial Brief, p. 194, citing Exhibit A-33 and 3 TR 567.643 3 TR 568.

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the subset of account 925 that included injuries and damages expenses. For these

reasons, this PFD recommends that the Commission reject Staff’s proposed adjustment

and adopt the Company’s projected test year gas injuries and damages expense of

$1,618,000.

E. Depreciation And Amortization – Non MGP

The Company has calculated a test year non-MGP depreciation expense of

$260,723,000, to which Staff proposes a $15,972,000 reduction, based on Staff’s

proposed adjustments to various components of the Company’s capital expenditures.644

This PFD adopts the Company’s depreciation expense, with adjustments based on this

adjustments recommended in this PFD.

F. Manufactured Gas Plant Amortization Expense

The Company projects a test year MGP amortization expense of $8,044,000, to

which Staff proposes a $3,376,000 reduction, based on differences in recommendations

regarding other rate elements.645 In addition to recommending that this expense be set

at $4,669,000, Staff recommends that the Commission approve the Company’s continued

deferred accounting for MGP expenditures as approved in Case No. U-10755 using a 10-

year amortization in rates following a Commission review for prudence.646

This PFD recommends adoption of Staff’s recommended MGP amortization

expense of $4,669,000.

644 Consumers Energy’s Reply Brief, Appendix C; Staff’s Reply Brief, Appendix C. 645 Exhibit A-13, Schedule C6; Exhibit S-3, Schedule C1.1.646 Staff’s Initial Brief, p. 151.

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G. Taxes

The Company’s adjusted rebuttal projection of its property tax expense for the test

year is $98,698,000, with the Company’s witness, Brian J. VanBlarcum, providing the

methodology used to arrive at that amount.647 Staff has calculated an estimated property

tax expense for the test year of $95,006,000, with the differences due not to any

differences in methodology but rather to Staff’s proposed adjustments to the Company’s

projected capital expenditures.648

The Company’s adjusted rebuttal projections for federal income tax (FIT), Michigan

corporate income tax (MCIT), and local income tax (LIT) expenses for the test year are

$28,7000,000, $15,222,000, and $492,000, respectively.649 Staff has calculated

estimated FIT, MCIT, and LIT expenses for the test year at $35,281,000, $17,168,000,

and $545,000, respectively, again with the differences due to Staff’s proposed

adjustments to the Company’s projected revenue and expenses, and not to any

differences in methodology.650

Finally, the Company projects its other general taxes expense for the test year at

$16,944,000, an amount also calculated and recommended by Staff.651

1. Tax Cut and Jobs Act of 2017

On December 22, 2017, after the filing of the Company’s instant rate case, the Tax

Cuts and Jobs Act of 2017, Pub. L. No. 115-97, 131 Stat. 2054 (TCJA), was signed into

647 Consumers Energy’s Initial Brief, Appendix C, p. 1.648 Staff’s Initial Brief, Appendix C.649 Consumers Energy’s Initial Brief, Appendix C, p. 1, lines 10, 11, 12.650 Staff’s Initial Brief, Appendix C, line 24, columns (m), (n), and (o).651 Consumers Energy’s Initial Brief, Appendix C, p. 1, column (d), line 9; Staff’s Initial Brief, Appendix C, line 24, column (l).

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law. The TCJA contains provisions reducing the corporate tax rate and revising the

federal tax structure. These new federal requirements affect the current tax expense and

deferred tax accounting methods used by corporations, including utilities. Most of the

provisions of the TCJA went into effect on January 1, 2018.

On December 27, 2017, the Commission initiated proceedings (Case No. U-

18494) intended “[t]o ensure that all utilities account for these changes in a similar

manner” and directed utilities, beginning January 1, 2018, to institute regulatory

accounting treatment for any impacts of the new law including current and deferred tax

impacts, and to file information detailing the calculation of the change in revenue

requirements with and without the TCJA, and outlining the preferred method to flow the

benefits of those impacts to ratepayers.652

In this proceeding, the RCG maintains that “[a]ll parties appear to agree that the

impact of the federal Tax Cut and Jobs Act (TCJA) should be fully recognized for purposes

of setting customer rates in this case.”653 The RCG further maintains that “there should

be some reconciliation to ensure that the correct TCJA impacts determined in this rate

case are reflected in either Credit A or Credit B described in the Commission’s Order in

U-18494.”654 The RCG thus recommends that “the full impact of TCJA be reflected in this

case and that determinations in the Credit A and Credit B cases be coordinated to ensure

proper alignment with the Commission’s Order in this case.”655

652 MPSC Case No. U-18494, December 27, 2017 Order.653 RCG’s Initial Brief, p. 13.654 Id., p. 14.655 Id.

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The Attorney General similarly contends that the Commission “could reflect the

lower federal income tax rate currently in effect in this rate case”, noting that doing so “will

help to ensure that customers see the benefit of the lower tax rate as soon as possible.”656

However, the Attorney General further “recognizes that this issue is being separately

[addressed] in the Credit A case, but wants to present this alternative, in case the

Commission wants to return the money to ratepayers as quickly as possible.”657

Both the Company and Staff disagree with the RCG’s position and submit that the

Commission should not make any determination with respect to the impact of deferred

taxes and other TJCA issues in this proceeding, which are currently being addressed in

Case No. U-18484, as well as the Tax Reform Credit A proceeding, Case No. U-20103.658

Staff’s recommendation is supported by the testimony of Mr. Nichols, who indicated that,

because of the timing of the new law, Staff was unable to receive updated information in

time to review and include the impacts of the law on deferred taxes.659

This PFD agrees with Staff and the Company that the more appropriate venue to

resolve the TCJA issues is in the separate proceedings initiated by the Commission

following the enactment of the TCJA. Doing so is not only prudent and necessary in light

of Staff’s uncontested inability to receive and review updated information in this case to

include the impacts of the TCJA on deferred taxes, but it is also consistent with the

Commission’s recent decision to do the same in DTE Electric’s last electric rate case,

Case No. U-18255, wherein the Commission concluded:

656 Attorney General’s Initial Brief, p. 139, and Exhibit AG-53.657 Id.658 Staff’s Initial Brief, p. 154; Staff’s Reply Brief, p. 29; Consumers Energy’s Reply Brief, p. 179.659 6 TR 2098-2100.

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In exceptions, the Staff opposes the ALJ’s inclusion of the new FIT rate, arguing that the Commission has commenced a proceeding in Case No. U-18494 for dealing with these issues. The Staff points out that inclusion of the new FIT rate in rates for 2018 may cause the imposition of penalty interest on DTE Electric in its self-implementation reconciliation proceeding. The Staff recommends that the Commission not rush the evaluation of this issue and look at the effects of the TCJA in a separate case. Finally, the Staff argues that if the Commission includes the new FIT rate in this matter, then it should not agree to any associated changes in the capital structure.

…The Commission agrees with the Staff and DTE Electric that, given the timing of this rate case, the most prudent method for dealing with the tax issue is in Case No. U-18494. On February 22, 2018, the Commission issued an order in that docket providing a comprehensive plan for all regulated utilities, including DTE Electric, to address the impacts of the TCJA. That plan includes the filing of three contested cases to address the effect of the new FIT in rates (1) going forward, (2) looking backward to January 1, 2018, and (3) with respect to deferred tax balances, bonus depreciation, and all other impacts. The first two case-types will be expedited. These cases will provide the opportunity for all interested persons to participate in contested proceedings with a meaningful record regarding these important calculations, while safeguarding the right of ratepayers to be made whole as a result of the changed federal law.660

This PFD therefore recommends that the Commission heed the recommendations

of Staff and the Company and not make any determination with respect to the impact of

deferred taxes and other TJCA issues in this proceeding.

H. Allowance For Funds Used During Construction

The Company has projected for the test year an allowance for funds used during

construction (AFUDC) amount of $8,260,000, to which Staff has made no adjustment and

recommends that the amount be adopted.661

660 MSPC Case No. U-18255, April 18, 2018 Order, pp. 56-57.661 Consumers Energy’s Initial Brief, Appendix C; Staff’s Initial Brief, Appendix C.

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I. Calculation of Adjusted Net Operating Income (Approximated)

Based on the foregoing discussion regarding test year operating revenue and

expenses, this PFD finds that the Company’s total projected net operating income for the

test year should be set at $293,250,000 as shown in Appendix C to this PFD.

VIII.

OTHER REVENUE RELATED ISSUES

A. Revenue Decoupling Mechanism

Consumers Energy witness Heather Rayl presented the Company’s proposed

revenue decoupling mechanism (RDM) and indicated that the proposed RDM uses the

same methodology as the RDM that was included in and approved by the Commission in

the utility’s last gas rate case, Case No. U-18124.662 Ms. Rayl described the previously

approved RDM:

The calculation of the RDM approved by the Commission compares the weather-normalized actual revenue realized by the Company to the approved qualifying rate case revenue by rate schedule and subject to the following conditions: (i) for full service customers, revenues reflected in the calculation will be equal to the total rate schedule revenue less monthly customer charges and Excess Peak revenues, GCR revenue, and other surcharge revenue; (ii) for gas choice customers, revenues reflected in the calculation will be equal to the total rate schedule revenue less monthly customer charge revenue and other surcharge revenue; (iii) all months associated with the projected test-year will be excluded from true-up; thus, (iv) the first annual reconciliation period commences with the first month following the end of the general rate case projected test-year (i.e. commencing July 1, 2019); (v) operation of the mechanism will terminate upon utility implementation of new rates and must be re-approved in the next general rate case order; (vi) allocation of the qualifying revenue shortfall will be by rate schedule, consistent with the calculation; (vii) the actual revenue used in the calculation will be weather-normalized in a

662 2 TR 301.

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manner consistent with the weather-normalization method proposed by Consumers Energy in this case; and (viii) rate schedule GS-3 and all Transportation rate schedules (ST, LT, XLT, and XXLT pilot) will be exempt from the calculation. The Company proposes no changes to this RDM methodology in this case.663

According to Ms. Rayl, the reconciliation process would be filed three months after the

end of the 12-month period following the projected test-year or three months following the

implementation of new rates, whichever comes first.664

No party has challenged the reasonableness or prudence of the Company’s

proposed RDM. Accordingly, this PFD recommends that the Commission adopt the

Company’s proposed RDM.

B. Investment Recovery Mechanism

In its application, Company has sought authorization to implement an investment

recovery mechanism (IRM) that would allow for the recovery of the incremental

investment amounts of eight specific transmission and distribution programs: TED-I-

distribution; TED-I-transmission; EIPR-distribution; EIRP-transmission; VSR; pipeline

integrity-transmission; pipeline integrity transmission operated by distribution; and asset

relocation – decision analysis mains and services.665 Recovery for the investments would

be through a surcharge effective from January 1, 2019 until rates are reset in a

subsequent general rate case, with a reconciliation process at the end of June 30,

2020.666 Following the Commission’s approval of the 2019 reconciliation filing, the

663 Id.664 6 TR 835.665 2 TR 371.666 Id.

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surcharge would be adjusted to reflect actual capital expenditures and, thereafter, the

Company would annually submit a reconciliation filing to adjust the surcharge to reflect

the depreciated value of the capital expenditures.667

Staff and the Attorney General object to varying degrees to the Company’s

proposed IRM. These concerns are discussed below, followed by this PFD’s

recommendation.

1. Staff

Although Staff continues to support the general concept of the proposed IRM for

high-risk pipelines as described by Mr. Laruwe in Case No. U-18124, Staff recommends

that the Commission reject the IRM proposed by the Company in this case because the

Company’s previously approved IRM in Case No. U-18124 “has not resulted in the

realized benefit of reduced frequency of general rate cases or any reduction in the

resources associated with regulatory proceedings.”668 Specifically, Ms. Creisher testified:

If the Company continues to plan on yearly rate case filings, there are no real benefits to be realized by allowing the IRM, because the parties could have as easily reviewed the yearly proposed expenditures associated with the rate case, rather than having another separate proceeding for a reconciliation. With annual rate cases, all the IRM does is add another case to the Commission’s docket every year.669

As an alternative, Staff proposed a revised IRM that excludes the TED-I distribution

and TED-I transmission programs, includes a spending flexibility cap of 3.2%, and

667 6 TR 900.668 6 TR 1894.669 6 TR 1894.

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maintains the EIRP spending level of at least $75 million.670 Staff further recommends

that this alternative IRM proposal include adjustments to the projected test year

expenditure levels as follows:

Staff recommends that, if an IRM is approved, the IRM expenditures be adjusted to be in line with Staff’s recommendations for the projected test year expenditure levels of $4,374,000 for Pipeline Integrity – TOD program and $21,905,000 for the VSR program. … As shown in Exhibit S-11.7, Staff recommends recovery of incremental spending for the years ending June 30, 2020, and June 30, 2021, with annual capital expenditures totaling $186,420,000.671

In response, and “[i]n an effort to minimize the differences with Staff,” the Company

has largely accepted Staff’s alternative IRM proposal but notes that Staff has reduced the

VSR program expenditure levels to reflect a 20-year program, as opposed to a 10-year

program as proposed by the Company.672 On this point, the Company submits that if the

Commission adopts Staff’s recommended extension of the program, the funding for the

VSR Program “should be $28,000,000” and “should be combined with the EIRP Program

funding and the Company should be allowed to balance the total funding between the

programs so that it can maximize the benefit of its Distribution Integrity Management

Program across mains and services to reduce risk.”673 Further, the Company disagrees

with Staff’s recommended projected test year expenditure levels but submits that the IRM

should ultimately reflect the test year spending levels in the amounts approved by the

Commission for the programs included in the IRM.

670 6 TR 1896.671 6 TR 1895-1896.672 Consumers Energy’s Initial Brief, p. 204.673 Consumers Energy’s Initial Brief, p. 204.

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2. Attorney General

The Attorney General, through Mr. Coppola, contends that the Commission should

reject the Company’s proposal to expand the IRM, arguing that “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.”674 Mr. Coppola testified:

This is a perverse approach to ratemaking that may be appealing to the Company but is fraught with negative consequences for customers who will pay higher rates. It is more difficult to disallow costs that have already been incurred. The rate case review of proposed costs offers all parties to the proceeding the opportunity to weigh in on the reasonableness of projected costs before significant capital expenditures are incurred. This is one of the benefits of a rate case proceeding that includes projected costs. The IRM basically takes a level of capital expenditures identified in prior years and allows the Company to recover the associated costs through bill surcharges. There is no specific list of projects or breakdown of components of the program expenditures to challenge upfront, only years later after the summary program amounts have been spent.675

The Attorney General identifies eight additional reasons for his recommended

rejection of the Company’s proposed IRMs but fails to provide any record support for

these assertions.676 The Attorney General also does not address Staff’s proposed

alternative IRM, to which the Company has agreed.

The Company disputes the Attorney General’s claim that the proposed IRM

permits automatic recovery of costs, noting that the Commission and participating parties

will have two opportunities for prudence and reasonableness reviews of the costs

associated with the IRM.677 The Company further notes that the eight additional reasons

674 7 TR 2406. 675 7 TR 2407.676 Attorney General’s Initial Brief, pp. 94-95.677 Consumers Energy’s Reply Brief, pp. 182-183, citing 2 TR 377-378.

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listed by the Attorney General for rejection of the proposed IRM “were largely evaluated

in U-18124 and rejected.”

3. Recommendation

This PFD recognizes and appreciates Staff’s concerns that a justification asserted

by the Company for the IRM approved by the Commission in the Company’s last natural

gas rate case, a reduced frequency of general rate cases and the reduction in resources

associated with regulatory proceedings, has not in fact been realized.678 Indeed, as noted

by Ms. Creisher, “[w]ith annual rate cases, all the IRM does is add another case to the

Commission’s docket every year.”679 However, this PFD disagrees with Staff’s

representation that “[o]ne of the main reasons the Commission gave for approving the

IRM [in Case No. U-18124] was the premise that IRMs would help to stretch out the

amount of time between rate cases.”680 Nowhere in the Commission’s discussion of this

issue in its July 31, 2017 Order does the Commission provide such a reason as a basis

for its approval. Equally misleading is Staff’s assertion that, in that same order, “the

Commission quoted Staff witness Ryan Laruwe’s testimony that IRMs the Commission

approved for DTE Gas and SEMCO have allowed those utilities to improve the safety of

their systems, while also allowing them to ‘file significantly less general rate cases since

their inception.’”681 A more accurate recitation of the Commission’s order in this regard is

that, in discussing the ALJ’s proposal for decision on this issue, the Commission noted

that, in support of her recommendation, the ALJ cited Staff’s testimony discussing the

678 Staff’s Initial Brief, p. 90, citing MPSC Case No. U-18124, 4 TR 163.679 6 TR 1894.680 Staff’s Initial Brief, p. 19, citing MPSC Case No. U-18124, July 31, 2017 Order, pp. 102-103.681 Staff’s Initial Brief, p. 189.

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reasonableness of the IRM, including Staff’s testimony that the IRMs approved for DTE

Gas and SEMCO have allowed the utilities to “increase the safety of their systems,

minimize the number of active leaks on the system, and file significantly less general rate

cases since their inception.”682 Moreover, although the Commission “substantially

adopt[ed] the findings and recommendations of the ALJ” and “agree[d] with the ALJ that

it is reasonable, prudent, and lawful to adopt a modified IRM in this case”, the Commission

did not expressly indicate that it did so with the expectation that the modified IRM would

result in a reduced frequency of rate case filings by the Company.683

Regarding the Attorney General’s concern that the proposed IRM would turn a rate

case proceeding into an automatic cost recovery program by taking a level of capital

expenditures identified in prior years and allowing the Company to recover the associated

costs through bill surcharges, this PFD agrees with the Company that such a

characterization of the IRM is inaccurate where the filing and reconciliation timelines for

the proposed IRM provide the necessary opportunity to review proposed expenditures for

prudency prior to their inclusion in the calculation of the IRM surcharge. As for the

Attorney General’s remaining concerns, this PFD finds that they are too generalized in

nature and without sufficient evidentiary support. Put another way, whether an IRM will

reduce the Company’s risk exposure and increase it for ratepayers, reduce regulatory lag

in the recovery of capital costs, or result in a confusing IRM surcharge or rider to

customers are purely speculative concerns as the record is devoid of any evidence

682 MPSC Case No. U-18124, July 31, 2017 Order, pp. 98-99, citing PFD, p. 85, citing 7 TR 1831.683 MPSC Case No. U-18124, pp. 102-103.

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quantifying risk exposure reductions and increases, much less any data supporting

customer confusion.

Against this backdrop, this PFD finds that the revised IRM incorporating the

modifications recommended by Staff, and to which the Company has agreed, is

reasonable and should be adopted by the Commission. Specifically, this PFD

recommends that the revised IRM: (i) exclude the TED-I distribution and TED-I

transmission programs; (ii) include a spending flexibility cap of 3.2%; and (iii) maintain the

EIRP spending level of at least $75 million.684 This PFD further finds reasonable Staff’s

20-year VSR program expenditure level, as opposed to the 10-year program proposed

by the Company. And, because this PFD has recommended adoption of Staff’s

recommendations for the projected test year expenditure levels of $4,374,000 for Pipeline

Integrity – TOD program and $21,905,000 for the VSR program, this PFD recommends

that the Commission also include such adjustments in this revised IRM, consistent with

Exhibit S-11.7, wherein Staff recommends recovery of incremental spending for the years

ending June 30, 2020, and June 30, 2021, with annual capital expenditures totaling

$186,420,000.

C. MGP Remediation-Related Expenditures

The Company’s witness, Mr. Harry, identified 23 sites that formerly housed

Manufactured Gas Plants (MGP) and in which Consumes Energy has a present or former

ownership interest as well as required environmental response activities (under Part 201

of the Michigan Natural Resources and Environmental Protection Act, MCL 324.20102 et

684 6 TR 1896.

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seq.), and associated expenditures that the utility is seeking approval to recover in its

application.685 As discussed in Section IV.C. above, the Company has updated its filed

test year net amortized MGP remediation costs with actual 2017 costs, lowering the test

year costs from $8,044,000 to $7,443,000.686 However, because Staff’s audit did not

include a review of 2017 costs, Staff recommended that the Company’s projection of

deferred MGP amortization expense be reduced to $4,669,000.687 As set forth in Section

IV.C, this PFD agrees with Staff’s recommendation and recommends that the

Commission adopt Staff’s proposed net unamortized MGP balance of $4,669,000 for the

test year.

RCG maintains that the Commission “should revisit and revise its ratemaking

approach and methodology dealing with the inclusion of remediation costs” for MGP sites

and exclude such costs from customers’ rates because “said costs arose from

management actions, do not represent used and useful plant, and do not provide for any

balancing of the interests of shareholders and ratepayers.”688 In support of RCG’s

position, RCG presents Exhibit 5 and 6, which RCG contends “establish that many of the

sites are only partially owned by CECo, while some are owned entirely by third parties,

including municipalities.”689 RCG thus argues:

In order to balance the interests of both shareholders and ratepayers, it would be appropriate at most to share the MPB costs related to MGP on a 50/50 basis – with 50% of the costs being assigned to shareholders and

685 Exhibit A-34.686 Exhibit A-98.687 Staff’s Initial Brief, p. 151; Exhibit S-9.0; 6 TR 1903. 688 RCG’s Initial Brief, p. 14.689 Id., p. 15.

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50% of the costs to ratepayers. In addition, none of the MGP costs should be included in rate base, as none of the costs relate to “used and useful plan” providing gas service to ratepayers.

The assignment of only 50% of the amortization of these costs in rates (with no rate base treatment of same) would establish a much fairer regulatory policy in dealing with these costs. It would more reasonable [sic] balance the interests of ratepayers and shareholders. After all, the ratepayers had no role in creating the pollution, and had no role in the decision-making process that created the sites or which led to CECo acquiring other gas companies that created the sites. Moreover, a sharing of the costs (without rate base treatment) would also address the serious concern relating to the open-endedness of these costs and the need to provide incentives to CECo to minimize these costs.690

The Company contends that RCG’s arguments are meritless and should be

rejected by the Commission. Noting that the Commission has allowed the Company to

recover its MTGP remediation costs in numerous cases since its March 11, 1996 Order

in Case No. U-10755 and including in the Company’s last gas rate case, Case No. U-

18124, the Company argues that RCG’s proposed disallowances are not only contrary to

these prior Commission orders, but they are refuted by the evidentiary record.691

Specifically, Ms. Prentice provided testimony establishing that the Company is

responsible for the environmental remediation costs at the 23 former MGP sites, the costs

are required by law, they are necessary and ongoing costs of doing business, and they

were reasonably and prudently incurred.692 She further testified that, contrary to RCG’s

argument that others should be contributing to the cleanup of the sites, the Company has

not been able to identify any former MCP owners or predecessor or successor companies

690 Id., p. 16.691 Consumers Energy’s Reply Brief, p. 184.692 Id., pp. 186-187, citing 3 TR 595-598.

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of such owners at the 23 MGP sites.693 The Company submits that RCG “has not

identified a single MGP remediation expenditure that was unreasonable or imprudent, nor

has it provided any basis for the Commission to depart from its numerous prior orders

allowing the Company recovery of MGP remediation costs.”694

This PFD agrees with the Company that RCG’s proposed disallowance of the

Company’s MGP remediation costs is without record support and inconsistent with

Commission precedent. The Company’s liability for such costs as a responsible party

under Part 201 of Michigan’s Natural Resources and Environmental Protection Act, MCL

324.20101, is well established and RCG has not challenged Ms. Prentice’s testimony in

this regard or demonstrated that any of the Company’s remediation costs are

unreasonable. Nor has RCG presented any factual or legal basis for the Commission

abandon its precedent in thus far allowing the Company’s recovery of these costs.

Accordingly, as set forth in Section IV.C. above, this PFD finds that the Commission

should adopt Staff’s recommended MGP amortization expense of $4,669,000 and

continue to allow the Company’s deferred accounting of MGP expenditures as approved

in Case No. U-10755 using a 10-year amortization in rates following a Commission review

for prudence.

D. End-User Transportation Customer Pooling Program

RESA recommends that the Commission issue an order directing the Company to

adopt a pooling program for the Company’s end user transportation (EUT) program. In

support of this recommendation, RESA relies on the testimony of RESA’s expert, John

693 3 TR 598.694 Consumers Energy’s Reply Brief, p.189.

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Mehling, who provided the following reasons and explanations as to why such a program

should be adopted: (i) pooling is a common industry practice that should be available to

the Company’s EUT customers; (ii) pooling would benefit EUT customers through

reduced costs, expanded flexibility, and increased options; (iii) pooling does not increase

costs to other customers or adversely affect system reliability; (iv) pooling provides

benefits to the Company; (v) any incremental costs to implement pooling should be borne

by pooling suppliers; (vi) pooling should be a voluntary program for EUT customers; and

(vii) the Company’s criticisms of RESA’s pooling proposal are without merit.695 Mr.

Mehling specifically recommends that the Commission direct the Company to:

1. Accept pooled nominations from suppliers;2. Calculate and assess any load balancing charges based upon the net

imbalance of a supplier’s pool;3. Calculate and assess any authorized and unauthorized gas usage

charges based upon the net imbalance of a supplier’s pool;4. Calculate and assess excess pipeline costs surcharge based upon the

net imbalance of a supplier’s pool;5. Establish the Pool Authorized Tolerance Level (“PATL”) as the sum of

all of the individual pool member Annual Contract Quantity (“ACQ”) times 8.5% or, when appropriate, the percentage of ACQ Tolerance Level as selected by the pool member; and

6. Establish the pool monthly injection rights as the corresponding sum of the rights of the individual pool members under existing tariff limits.696

Mr. Mehling further recommends that the Company’s tariff be revised with certain

definitions and statements added, as well as the transportation service rate and load

balancing charge be amended, to reflect incorporation of the pooling program.697

695 5 TR 1568-1575.696 5 TR 1576.697 5 TR 1576-1577.

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The Company opposes RESA’s pooling program proposal, maintaining through

the testimony of Ms. Curtis that the proposal could have detrimental effects on

transportation customers, would cause an administrative burden to the Company, and is

lacking in sufficient detail.698 In her testimony, Ms. Curtis provided an overview of the

Company’s current EUT program and identified specific concerns with the pooling

proposal. She indicated that start-up costs would be about $60,000 and take

approximately six months to complete. Ms. Curtis also responded to Mr. Mehling’s

assertion that the company’s absence of pooling imposes unnecessary burdens and

inefficiencies on gas suppliers, testifying that gas suppliers are not customers of the

company to whom the company has any obligation.699 She further testified that Mr.

Mehling has failed to indicate how the establishment of pooling would provide efficiencies

or other benefits to the company’s gas transportation customers.700 Ms. Curtis explained

further:

Mr. Mehling continues to provide no proof that cost savings achieved from pooling by suppliers would be passed on to transportation customers. The benefits of his pooling proposal are achieved by the supplier. But the Company’s transportation customers are paying for the storage being utilized by the supplier under Mr. Mehling’s proposal. To date, no transportation customer has requested the Company to implement a pooling program.701

She also expressed concern that RESA’s pooling proposal is not about creating

more efficiencies for suppliers, but about putting storage assets under the control of

698 5 TR 1255.699 5 TR 1258.700 5 TR 1258-1259.701 5 TR 1260.

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suppliers who are not subject to Commission oversight.702 Of further concern to the

Company is that the pooling proposal, if approved, would require a thorough review of the

Company’s existing tariff, the drafting of form contracts between the pool administrator

and the Company, and the establishment of the pool administrator’s credit obligations.703

Responding to the Company’s concerns, RESA contends that the interests of EUT

customers and their suppliers are not mutually exclusive, and that improving the EUT

program would benefit both groups. RESA also dismisses the Company’s assertion that

the proposal could be detrimental to EUT customers inasmuch as the proposal is merely

an option for EUT customers, and not a mandate, and such customers are “capable of

making an informed decision about whether the benefits of pooling exceed any detriments

and whether to join a supplier’s pool.704 RESA also submits that the Company’s concern

with suppliers being able to gain access to the Company’s storage assets without any

third-party oversight is overblown and vague. Finally, RESA argues that any

administrative burden associated with the implementation of a pooling program is small

and not unexpected with a new program, and will include benefits to the Company:

The utility should see reduced administrative costs from pooling. Rather than monitor each customer account individually, the utility would be able to monitor fewer accounts that contain one or more individual pooled customer accounts. Consumers would need to verify fewer nominations and storage banks even though the total volumes remain the same under pooling. Pooling would also simply the tracking of imbalance nominations. After the initial start-up costs to implement pooling, the utility should experience reduced manpower costs and lower invoicing costs.705

702 5 TR 1261.703 5 TR 1262.704 RESA’s Reply Brief, p. 3.705 5 TR 1571.

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Staff has taken no position on RESA’s proposal, except to maintain that the

Commission should not reject the proposal on the basis that there would be a reduction

in revenue because “pooled customers avoiding the financial penalty that they would have

paid without pooling is not a detriment to other customers.”706

This PFD finds that the record lacks sufficient evidence demonstrating the

reasonableness of RESA’s proposal such that adoption of it by the Commission is

warranted at this time. Although Mr. Mehling has described pooling as “a proven market

enhancement which has led to greater efficiency elsewhere, contributing to more robust

competitive markets with a greater number of suppliers and offers to end-use

transportation customers,” absent from this record is a clear illustration that the

anticipated cost savings achieved from pooling by suppliers would be passed on to

transportation customers, despite those customers paying for the storage that would

utilized by the supplier.707 Instead, Mr. Mehling has explained that pooling reduces costs

for the supplier and ultimately the customers through a “trickle down” effect.708 And,

although Staff has taken no position regarding whether the Company should implement

RESA’s pooling proposal,709 it is worth noting that in the last natural gas rate case in which

a pooling proposal was recommended by an intervenor, Case No. U-15986, Staff argued

the following:

Although Constellation’s proposed pooling changes would undoubtedly benefit the marketers on Consumers’ system, it is not apparent how these

706 Staff’s Initial Brief, pp. 174-176.707 5 TR 1583.708 5 TR 1568.709 As noted by the Company, Staff’s observation regarding revenue is perplexing as no party has actually argued alleged harm due to a reduction in the Company’s revenues.

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changes would truly enhance the current system in place for Consumer’s transportation customers. Consumers’ transportation tariffs are, by definition, for its transportation customers, but Constellation’s proposed tariff changes would be for the greater benefit of the marketers serving these transportation customers and to the detriment of the transportation customers themselves. Under Constellation’s proposed tariffs, marketers on Consumers’ system would benefit from pooling nominations and imbalances, and it would be simpler administratively for them to maintain storage inventories, withdrawals, and injections in aggregrate rather than by the individual transportation customer. On the other hand, Constellation’s proposed tariffs would restrict transportation customers’ flexibility to manage their gas supply within a given month because customers would have to designate a specific marketer. A transportation customer currently can have any number of different marketers within a given month supplying the customer gas at the best price available, but Constellation’s proposed tariffs would restrict customers to one marketer and its pricing in a given year.710

The Commission agreed with Staff and the Company, concluding:

[T]he weight of the evidence shows that marketers on Consumers' system would likely benefit from CNE's proposed pooling program because it would make it easier for marketers to manage their inventories on an aggregate basis. However, CNE's proposal could harm Consumers' transportation customers by limiting their flexibility in selecting marketers within a particular month because each of them would have to designate a single marketer to provide that month's supply. In addition, the Commission has serious concerns about the potential effects on Consumers' GCR customers if nominations by marketers vary with gas prices on a day-to-day basis, creating surpluses and deficiencies. As Consumers and the Staff point out, this could force the company to replace missing gas supply for its transportation customers by taking from its GCR customer supply or by purchasing gas on the spot market, which could be very expensive on a peak winter day. The Commission therefore rejects CNE's proposal.711

Acknowledging that, as noted by RESA, RESA’s pooling proposal recommends a pooling

option for EUT rather than a mandate that EUT customers be pooled, as was

recommended by CNE in Case No. U-15986, it remains equally unclear in this case how

710 MPSC Case No. U-15986, Staff’s Initial Brief, pp. 42-43.711 MPSC Case No. U-15986, May 17, 2010 Order, pp. 56-57.

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a pooling program would truly enhance the current system in place for the Company’s

transportation customers. Moreover, as noted by the Company, no transportation

customer has thus far requested the Company to implement a pooling program. For

these reasons, this PFD finds that RESA’s pooling proposal is not reasonably justifiable

and should not be approved by the Commission.

E. Gas Customer Choice Billing

RESA further maintains that the gas customer choice (GCC) bill text box or

prominent bill display that is included on the Company’s utility consolidated bills for GCC

customers is “anticompetitive”, and “false, deceptive and misleading.” Relying on the

testimony of RESA expert witness, Matthew White, RESA recommends that the

Commission require the following of the Company: (i) the bill message should be the

same for both GCC and gas cost recovery (GCR) customers; (ii) the bill message should

not single out GCC customers for price comparisons, but simply direct both GCC and

GCR customers to the Commission gas price comparison website; (iii) the bill message

should not include a link to the Company’s webpage for both GCC and CGR customers;

and (iv) the bill message should include information to contact their existing supplier for

information on their current contract.712 RESA further recommends that the Commission

amend the Company’s GCC tariff to prohibit the utility from making false, deceptive, or

misleading statements to customers.

The Company disagrees with RESA’s recommendation, with Ms. Miles offering the

712 RESA’s Initial Brief, pp. 17-18.

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following rebuttal testimony:

[T]he Company provides a GCC customer’s factual information on its bill, which includes the amount the customer is paying for gas commodity and the current Company GCR factor. …

The Company does not make a profit on the sale of the gas commodity and has no economic incentive to dissuade customers from selecting an AGS. …

Customers have multiple sources from which they can obtain GCC pricing and program information, and those interested in participating in the GCC program are free to obtain from any source they choose …

[T]he Company’s website address and the MPSC’s website appear on GCC customer bills; thus, the Company already provides information to assist customers in locating a variety of information, including GCC pricing and programs. …

[J]ust as a customer is at liberty to pursue information regarding GCC programs, an AGS is free, within legal limits, to market their products and services to GCR customers.713

The Company further contends that Mr. White’s suggestion that GCR information

on GCC bills causes GCC customers to “lose the benefits that promoted them to choose

an AGS,” is without merit where he fails to explain how the information contained in the

bill would cause this benefit loss, nor does he address that potential GCC customers are

free to make informed decisions based on information from an AGS’s marketing efforts

and other data available on the MPSC’s GCC website and the Company’s website.714

Staff has posited on this issue and, through the testimony of Ms. Cantin, does not

agree with RESA that the information in the prominent bill display box is anti-competitive

but does recommend the following changes:

Staff recommends that the Commission direct Consumers Energy to

713 3 TR 697.714 Consumers Energy’s Initial Brief, p. 214.

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change the prominent bill display box rate comparison language to reflect the actual month in which the rate is being compared, insert “Mcf” after “GCR rate,” and provide the relevant AGS phone number in the “Questions” section of the box. Staff also recommends that the Commission recommend that Consumers Energy include the Commission’s gas choice website inside the box as opposed to elsewhere in the fine print. Staff believes these changes will promote increased transparency and clarity for all customers. While Staff maintains that the rate comparison information inside the box is not anti-competitive, Staff is generally supportive of the promotion of the Commission’s gas choice website to all customers. However, because the Commission concluded in the September 11, 2014 Order in In re Creation of a Gas Choice Comparison Website, MPSC Case No. U-17580, 9/11/2014 Order, p. 9, that any reference or promotion of the website by the utilities or the AGSs must be discretionary, Staff maintains the inclusion of the website must be voluntary.715

The Company accepts the changes proposed by Staff, however RESA continues

to maintain that the Company should be directed to remove the GCR price comparison,

which RESA contends is purposeful and intentional.716 RESA further contends that its

proposed tariff amendment prohibiting false, deceptive, and misleading statements by the

Company, should be approved by the Commission to ensure that the Company cannot

make false, deceptive or misleading statements in its bill messages going forward.717

This PFD, like the Company and Staff, does not agree with RESA that the

information in the prominent bill display box is anti-competitive, but does find that Staff’s

proposed changes to the box are reasonable and will promote increased transparency

and clarity for all customers. And because RESA has failed to establish that the

information in the prominent bill display box constitutes false, deceptive, or misleading

statements, a tariff amendment prohibiting such conduct by the Company is unnecessary.

715 Staff’s Initial Brief, pp. 187-188, citing 5 TR 1600.716 Consumers Energy’s Reply Brief, pp. 195-196.717 RESA’s Reply Brief, pp. 7-8.

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This PFD therefore recommends that the Commission reject RESA’s recommendations

in this regard and adopt Staff’s proposed changes to the prominent bill display box, to

which the Company has agreed.

F. Daily Balancing Study

The Company has included in its rate case filing the presentation of a daily

balancing study pursuant to the agreed upon terms of a settlement agreement in Case

No. U-17900.718 The Company notes that, in presenting this study, the Company is not

requesting approval of a daily balancing program and is not seeking recovery of any of

the costs necessary to offer a daily balancing program.719 In presenting this study, Ms.

Curtis further testified that the Company is not in agreement that a problem with monthly

balancing exists.720

The Attorney General submits that the Company has not made a good-faith effort

to present a study in this case. Specifically, he argues:

It failed to adequately incorporate the specific details of Consumers as a company into the study, and instead simply adopted the MGUC model without considering the differences between the two companies. MGUC did not have any storage capacity dedicated to EUT when it moved to daily balancing. Therefore, unless EUT customers were willing to purchase new storage capacity, MGUC had no choice but to set its daily balancing tariffs so that all imbalances had a cost to them.

In contrast, Consumers has allocated 7 Bcf of storage capacity to EUT customers. That storage capacity has been used to cushion monthly imbalances and can also be used to cushion daily imbalances. There is no reason why the same concept currently used for monthly balancing cannot be applied to daily balancing, including using the existing tolerance levels. The volumes would be proportionally smaller, but the tolerance percentages

718 5 TR 1232-1242.719 Consumers Energy’s Reply Brief, p. 197.720 5 TR 1245.

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are still relatively reasonable. The only difference in the reconciliation procedure would be to determine the variance between gas receipts from suppliers and deliveries to customers on a daily basis and apply any fees for being outside the permitted tolerance levels. Those fees for the month would then be accumulated for settlement at month-end.

The Company’s study also presented inflated time and cost estimates for converting to daily balancing. The Company has estimated $6.7 million to install approximately 3,500 meters. After reviewing the cost components per installation, it appears that this cost estimate is inflated. For example, the Company has estimated that it will cost $675.49 to perform the installation of the meter reading module that will electronically transmit the daily reads. Assuming that a field service employee’s wage with overheads is in the $67 per hour range, it appears that the Company allotted 10 hours to install each module. Such an amount of time is clearly excessive. A reasonable timeframe, including travel time, would be in the 2-4 hour range. The addition of 9 employees to “handle exceptions and perform daily balancing” at a cost of $540,000 also seems excessive, after computer system changes are completed to allow daily balancing. These and other inflated costs in the Company’s study serve to make the move to daily balancing look less attractive than it actually is.721

Based on his concerns, the Attorney General recommends that the Commission

“instruct Staff to organize a collaborative effort with all stakeholders for the purposes of

developing a workable daily balancing program for EUT customers.”722

The Company disagrees with the Attorney General and argues that his

recommended daily balancing collaborative should be rejected. In doing so, the

Company denies that it failed to make a good faith effort in presenting the study, noting

that the additional means of daily balancing that the Attorney General may have wanted

to be studied were not required by the settlement agreement and Mr. Coppola did not

offer his own study for review.723 The Company further contends that the Attorney

721 Attorney General’s Initial Brief, pp. 142-144.722 Attorney General’s Initial Brief, p. 134. 723 Consumes Energy’s Reply Brief, p. 198.

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General’s rationale for how the Company’s installation of smart meters could impact daily

balancing is unsupported where the Attorney General references electric smart meters

and “over 50% of the meters associated with EUT are located in the AMR area, not the

AMI area.”724 In summary, the Company argues:

The Company in this case is not offering a proposal for Daily Balancing; nor did the Attorney General. While the Attorney General’s Initial Brief alleges some of the benefits daily balancing could provide, these claims are not based on record evidence. Neither is the contention that transportation customers are being “subsidized” in this case. What is in the record is the fact that moving toward daily balancing will shift $33,000,000 in revenue requirements from the Transportation rate classes to the Residential and General Service rate classes. As such, the Attorney General’s recommended daily balancing collaborative should be rejected.725

Relying on the testimony of Mr. Isakson, Staff does not support a daily balancing

collaborative as proposed by the Attorney General. Specifically, Mr. Isakson testified

that, “[i]n its application, the Company provided a study of the costs and benefits of

moving to daily balancing and found that such a shift in metering would cost more than

the benefits it would provide to transportation customers. Therefore, Staff does not

recommend daily balancing for transportation customers at this time.”726

This PFD agrees with Staff and the Company and finds that the Attorney General’s

proposed daily balancing collaborative is not supported by the record in this case. The

Attorney General has failed to demonstrate that the study presented by the Company is

not a good faith effort or otherwise is inconsistent with the settlement agreement terms,

724 Consumers Energy’s Reply Brief, p. 200, citing 5 TR 1250.725 Consumers Energy’s Reply Brief, p. 201. (Citations omitted).726 6 TR 2051.

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pursuant to which the Company agreed to analyze “the benefits and costs associated

with daily balancing of EUT customers’ supplies and deliveries in the company’s next

general gas rate case filed after the conclusion of the currently pending rate case, Case

No. U-18124.”727 Nor has the Attorney General established through the record in this

case that a problem exists with monthly balancing so as to warrant a move to daily

balancing as recommended by the Attorney General. Moreover, as noted by the

Company, neither the Company nor the Attorney General is proposing in this case a daily

balancing program.

For these reasons, this PFD recommends that the Commission reject the Attorney

General’s proposed daily balancing collaborative.

IX.

REVENUE DEFICIENCY SUMMARY

Based on the rate base, cost of capital, and adjusted net operating income as

presented above, Consumers Energy’s revenue deficiency for the projected test year is

estimated to be $10,617,000 as shown in Appendix A to this PFD.

X.

COST OF SERVICE, RATE DESIGN AND TARIFF ISSUES

A. Cost of Service

The Company’s witness, Mr. Saenz, presented the Company’s cost of service

study (COSS) by rate class, describing it as “a systematic classification, functionalization,

727 MPSC Case No. U-17900, November 7, 2016 Order.

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and allocation of a utility’s fixed and variable costs to serve each rate class or gas rate

schedule.”728 Mr. Saenz prepared two test year COSSs in this case:

The Test Year Gas COSS – Version 1 (“COSS Version 1”) is at Exhibit A-16 (LFS-1), Schedule F-1. The COSS Version 1 develops customer costs by rate class using the methodology previously approved by the Commission. The Test Year Gas COSS – Version 2 (“COSS Version 2”) is at Exhibit A-16 (LFS-3), Schedule F-1a. The COSS Version 2 differs from the COSS Version 1 in that COSS Version 2 incorporates a new pilot transportation rate schedule XXLT for transportation customers with a volumetric usage of 4 Bcf or higher on an annual basis, excluding contiguous accounts. The costs to serve XXLT customers were developed by setting the ATL for the pilot Rate XXLT at 4% because XXLT customers would not require the same storage capacity as other transportation customers. Based on the Company’s originally filed revenue requirement, the proposed Rate XXLT shifts $323,000 from the Transportation class to the Residential class ($229,000) and General Service class ($94,000) when comparing values from page 1, line 22, of both versions of the COSS.729

Maintaining that the COSS – Version 2 provides additional options to transportation

customers, the Company proposes that the Commission approve COSS Version 2 in this

proceeding.730

Staff does not oppose the Company’s proposed peak design day (PDD) to develop

the average and peak allocation factors, however Staff recommends that the Commission

“require the Company to determine the feasibility of a gas load study to determine if peak

month remains a reasonable stand-in for peak day, or if calculated peak day serves as a

better alternative.”731 The Company has agreed to examine whether such a load study is

feasible and discuss the progress with Staff. Accordingly, this PFD recommends the

728 3 TR 641.729 Consumers Energy’s Initial Brief, p. 222, citing 3 TR 625, 643-645.730 Id, p. 222.731 Staff’s Initial Brief, p. 157.

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Commission adopt the Company’s PDD as well as Staff’s recommendation to require the

Company to pursue such a feasibility determination.

ABATE, Lansing Board of Water and Light, and RCG have additional

recommendations, with which Staff has varying concerns, and each is discussed

below.732

1. ABATE

ABATE recommends that the Company use the PDD rather than the peak month

in the A&P allocator and in the calculation of storage allocation, and further contends that

the Commission should require the Company to conduct a study to determine how

transportation customers utilize storage.733 In support of ABATE’s latter proposal, ABATE

argues:

[T]he Company’s own tariff provisions expressly limit the use of storage by end-use transportation (“EUT”) customers during the critical injection and withdrawal periods. In general, no such limitations apply to gas sales customers. The only conclusion is that EUT customers are not using storage in the same manner as gas sales customers. However, the Company does not have the data necessary to quantify how EUT customers actually utilize storage. Therefore, the Commission should require the Company to conduct an in-depth study of its end-use transportation EUT customers to determine how they utilize storage.734

Additionally, ABATE argues that a portion of distribution mains should be recognized as

customer-related cost. In support of this proposal, ABATE argues:

732 Although Mr. Coppola suggested on behalf of the Attorney General that there was a contradiction in the amount of costs that would be shifted away from the transportation class if all storage costs are removed from transportation customers identified by Ms. Curtis and the amount of storage allocated to transportation customers in the COSS, the Attorney General did not include any argument or analysis of Mr. Coppola’s concern in his briefs, thus the issue is deemed waived. 7 TR 2460.733 ABATE’s Initial Brief, pp. 1-4, 7-8.734 ABATE’s Initial Brief, p. 8. (Citations omitted).

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Mr. Pollock presented a revised class cost-of-service study in Exhibit AB-4. In it, he replaced peak month throughput with Peak Day Design demand in allocating a portion of transmission, distribution, and storage plant and related costs. Mr. Pollock also allocated 25% of distribution mains as a customer-related cost based in part on the results of the Predominant Size method to more closely reflect cost-causation while providing only a modest recognition of the physical realities of the Company’s gas delivery system. 7 Tr 2291. The Commission should use the results of Mr. Pollock’s revised class cost-of-service study to determine an appropriate allocation of any base revenue increase taking into account the allocation of the Residential Income Assistance and Low Income Assistance credits and applying rate stability adjustments (e.g., gradualism), as may be appropriate. Specifically, the rates charged to the gas sales and transportation rate groups should be adjusted to reflect each group's allocated costs.735

The Company agrees with ABATE’s recommendation to use the PDD in

allocations rather than the peak month but disagrees that a storage usage study should

be required in its next rate case, maintaining that a more detailed storage study will be

presented if the Company proposes to modify the storage allocator from the current

allocator based 50% on storage capacity and 50% on peak month sales in a future rate

case.736 The Company further notes it is not opposed to ABATE’s proposed classification

of distribution mains but submits it should not be adopted at this time as more time is

needed to evaluate the available data and to explore the appropriate classification.737

Staff proposes to use the currently approved method of allocating storage costs

based 50% on storage utilization and 50% on deliverability. However, Staff only supports

ABATE’s recommended storage study for inclusion in the next rate case if the Company

proposes a change to the 50-50 storage cost allocation method. Further, Staff opposes

735 Id., pp. 8-9.736 Consumers Energy’s Reply Brief, p. 202.737 Id., p. 203.

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ABATE’s proposal to classify 58% of distribution mains as customer related, arguing that

the Commission should reject the proposal because: (i) it is contrary to Commission

guidance on the allocation of demand-related and customer-related costs in customer

charges; (ii) it is not supported by the NARUC manual over other methods; and (iii)

ABATE’s reliance on other states’ utility commission decisions is misplaced and does not

support its proposal to classify distribution-main costs as customer related.738

This PFD finds that the Commission should adopt ABATE’s recommendation to

use the PDD in allocations rather than the peak month, a recommendation to which the

Company has agreed and no other party has substantively opposed. This PFD further

finds that ABATE’s proposal to require the Company to conduct a study to determine how

transportation customers utilize storage is premature and should be rejected by the

Commission inasmuch as the Company is not in this case proposing to modify the storage

allocator from the current allocator based 50% on storage capacity and 50% on peak.

Lastly, this PFD recommends that the Commission reject ABATE’s proposal to classify

58% of distribution mains as customer related. As noted by Mr. Isakson on behalf of

Staff, upholding the current practice satisfies the condition of fairly charging customers

for how the gas system is both designed and used, and is supported by cost-causative

principles, the NARUC Gas Distribution Rate Design Manual, and previous Commission

decisions.739

738 Staff’s Initial Brief, pp. 159-167.739 6 TR 2062-2067.

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2. Lansing Board of Water and Light

LBWL maintains that the Commission should approve the Company’s proposal for

a new pilot transportation rate classification called the “extra extremely large

transportation service rate schedule XXLT” (XXLT) and submits that it is both reasonable

and consistent with cost of service concepts.740 In doing so, LBWL notes that Mr. Saenz

has agreed that his cost of service analysis showing a lower cost to serve XXLT rate

customers than XLT rate customers should be adjusted to remove the allocation of non-

high pressure distribution facilities costs to the XXLT rate class.741

The Company agrees that, since the customers who would qualify for the pilot rate

XXLT would not use the Company’s non-high pressure distribution facilities, the costs of

these facilities should be removed from the pilot rate XXLT cost of service.742

Staff, however, maintains that the Commission should reject LBWL’s proposal,

arguing:

BWL entered into evidence Exhibit LBWL-1 during the cross examinationphase of the instant rate case. This exhibit shows the Company’s proposal to remove non-high-pressure costs from Rate XXLT’s cost allocation butdoes not actually identify those costs. As Staff argues in its initial brief, entering new evidence and proposals as late as the rebuttal filing does not afford Staff, the Company, and intervenors sufficient time to properly audit and analyze any party’s position. (Staff Initial Brief, pages 5-7, F# 302 at 18.) Exhibit LBWL-1 is a discovery response produced by the Company and dated March 27, 2018, which was merely two days before cross examination began and nearly a week after rebuttal filing. BWL proposed removing non-high-pressure distribution facility costs first in its initial brief and that proposal is based on evidence not made available to Staff early enough in the case for proper consideration.743

740 LBWL’s Initial Brief, pp. 1-2.741 LBWL’s Initial Brief, pp. 2-3, citing Exhibit LBWL-1.742 Consumers Energy’s Reply Brief, p. 202.743 Staff’s Reply Brief, pp. 36-37.

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This PFD is not persuaded by Staff’s opposition to LBWL’s proposal. Staff’s

objection is premised solely on Staff’s claim that it had insufficient time to analyze the

information contained in Exhibit LBWL-1. However, Staff had the opportunity to conduct

cross-examination of Mr. Saez based on information contained in Exhibit LBWL-1 and

could have certainly sought additional time during the evidentiary hearing to review

Exhibit LBWL-1 with relevant Staff witnesses before conducting such a cross-

examination. That Staff chose to forego this inquiry is not an adequate basis to oppose

LBWL’s proposal. Thus, this PFD recommends the Commission adopt the LBWL’s

proposed removal of the costs of these facilities from the pilot rate XXLT cost of service.

3. RCG

RCG contends that the Company’s agreement with ABATE’s proposal to use the

PDD rather than the peak month for the peak demand metric of the A&P allocator is

contrary to the Commission’s July 31, 2017 Order in Case No. U-18124.744 Doing so,

according to RCG, “would change the existing cost allocation methodology for gas

storage, but without any confirmed gas storage study or verification that CECO has the

necessary meters, facilities, or technology for altering the current gas storage cost

allocation methodology.”745

The Company responds that RCG’s suggestion is incorrect, noting that “[s]ince

744 RCG’s Initial Brief, p. pp 17-18.745 Id., p. 18.

U-18424Page 289

ABATE’s proposal does not involve changing the 50/50 storage allocation, the storage

system study discussed in Case No. U-18124 is not required.”746

This PFD agrees with the Company that RCG has mischaracterized ABATE’s

proposal inasmuch as ABATE is not recommending that the Commission reject the A&P

allocator.

B. Rate Design

Ms. Rayl presented the Company’s rate design proposals, testifying that the rates

are designed so that the revenue recovered from each customer class reflects the costs

for that class as provided in the Company’s test year COSS.747 Ms. Rayl indicated that

the Company’s proposed delivery revenues and associated rate increases for each class

include: (1) delivery revenues for Residential Rates A and A-1 which are designed to

produce an increase in nonfuel revenues in the amount of 19%; (2) delivery revenues for

the General Service Rate Class, consisting of rate schedules GS-1, GS-2, and GS-3,

which have been designed to result in an increase in annual nonfuel revenues of 18%;

and (3) an increase to the Transportation Rate Class revenues, which consists of rate

schedules Small Transportation (ST), Large Transportation (LT), and Extra Large

Transportation (XLT), of 21%.748 The Company is also proposing a decrease to the

proposed revenue for GL of 20%, as well as a pilot rate schedule XXLT.

746 Consumers Energy’s Reply Brief, p. 203.747 Consumers Energy’s Initial Brief, p. 225, citing 2 TR 289.748 Id., citing 2 TR 292.

U-18424Page 290

Contending that its rate design maintains appropriate balance between interests

while also striving to move the customer classes closer to cost-based rates, Staff

maintains that the Company’s proposed rate design “strays too far from the cost of service

rate design targets, using rate design adjustments to shift significantly more costs to other

rate classes than Staff’s proposed rate design.749 Staff recommends the following

adjustments or requirements: (i) an unchanged residential customer monthly charge; (ii)

relocation of the excess peak demand charge from the customer charge to the distribution

charge section of the tariff book; and (iii) the addition of a 4% ATL option to the current

XLT rate, as well as for the new XXLT rate.750

The Attorney General also recommends that the residential customer monthly

charge remain unchanged, or alternatively be increased by only $1.00 (from $11.75 to

$12.75), maintaining that an increase larger than this could cause rate shock to customers

in smaller households who use less gas than the average customer.751

And, like Staff, both ABATE and RESA expressed concerns with the Company’s

proposed 4% ATL option.

Each of these recommendations is addressed below.

1. Residential Customer Charge – Residential Rates A and A-1

Staff maintains that because the ASP expenses were not directly related to the

attachment of customers to the Company’s system, they should be removed from the

Company’s revenue requirement, resulting in a proposed customer charge of $10.48 for

749 Staff’s Initial Brief, p. 179.750 Staff’s Initial Brief, pp. 109-114; see also 7 TR 1632 and 7 TR 1751-1753.751 Attorney General’s Initial Brief, p. 147.

U-18424Page 291

residential customers.752 Mr. Isakson nonetheless recommends retaining the current

residential customer charge of $11.75 to avoid rate volatility in what is a relatively stable

charge on customer bills.753

Likewise, the Attorney General recommends that the residential customer monthly

charge remain unchanged, or alternatively be increased by only $1.00 (from $11.75 to

$12.75).

The Company agrees with Staff that the ASP expenses should not be included in

the residential customer charge calculation but notes that the Staff’s recommended

charge differs from the Company as it is based on Staff’s revenue requirement. Thus, if

the final Commission-approved revenue requirement supports a residential customer

charge greater than $11.75, then the Company requests that the residential customer

charge be designed to reflect that higher cost.

Based on a comparison of the parties’ cost of service studies, and because Staff’s

methodology appears to closely adhere to the Commission’s guidance in Case Nos. U-

4771 and U-4331, which the Commission again endorsed in Case Nos. U-17999, U-

17990, and U-18124, this PFD finds it reasonable and appropriate for the Commission to

leave this charge at the $11.75 per month rate currently embodied in the Company’s

rates, and as recommended by Staff and the Attorney General.754 In doing so, however,

752 6 TR 2044-2045.753 6 TR 2045-2046.754 MPSC Case No. U-17999, December 9, 2016 Order, p. 66; MPSC Case No. U-17990, February 28, 2017 Order, p. 137 (“The Commission does not find its precedent outdated, and at this time, continues to support a customer charge based on marginal costs that are directly related to supplying service to customers.”); MPSC Case No. U-18124, July 31, 2017 Order, p. 115.

U-18424Page 292

this PFD acknowledges the Company’s highlight of the fact that Staff’s proposed rates

are designed to collect Staff’s proposed rate design and revenue based on Staff’s cost

allocation, and that the final rates approved by the Commission should be designed such

that the revenue recovered from each customer class reflects the costs for that class as

provided in the test year COSS approved by the Commission and maintains the crossing

points established in the current tariffs as closely as possible.755

2. Excess Peak Demand Charge – Residential Rate A-1

Although agreeing that the Company’s proposed excess peak demand charge

should increase by the same percentage as the residential customer charge increase,

Staff witness Daniel Gottschalk recommends that the Company’s proposed excess peak

demand charge for residential rate A-1 customers be moved from the customer charge

to the distribution charge in the tariff book because it is “assessed on a per-Mcf-of-excess-

peak-demand basis and is therefore “demand-related, not customer-related.”756

The Company has agreed with Staff’s recommendation and has agreed to move

the excess peak demand charge from the “customer charge” section to the “distribution

charge” section of the tariff sheet.757

3. 4% ATL for Rate XLT and Rate XXLT

Staff takes issue with the Company’s proposed 4% ATL for the proposed XXLT

rate, with Mr. Gottschalk maintaining that “rather than applying the same percentage

755 Consumers Energy’s Initial Brief, p. 229, citing 2 TR 306-307.756 6 TR 2032.757 Consumers Energy’s Reply Brief, p. 205, citing 3 TR 698.

U-18424Page 293

increase to XXLT customers as it did to XLT customers, [the Company] artificially locked

the percentage increase to XXLT customers at zero.758 Mr. Gottschalk concluded that

such an artificial cost gap is inappropriate and unreflective of the cost to serve these

customers. He further testified as to Staff’s ambivalence towards the creation of a new

XXLT rate:

In Staff’s opinion, this could be affected by either creating a new XXLT rate with the same customer charges and distribution charges as the XLT, but with only the 4% ATL as an option, or adding the 4% ATL option to the current XLT rate. Staff supports the 4% ATL option and finds that either method would be reasonable to put in place.759

760

ABATE also took issue with the Company’s proposed XXLT rate, arguing that the

rate XXLT customers are no different from the XLT customers and that the 4% ATL should

be available to all transportation customers, not just those eligible for rate XXLT.761

RESA recommends that the 4% ATL be rejected altogether, with Mr. Mehling

testifying that:

[t]here is no evidence that the existing ATLs are ineffective at ensuring that sufficient quantities of gas are delivered to meet customer usage. The existing ATL elections are tied to specific quantities of gas storage. If the available ATLs were reduced, then transportation customers should not be allocated the same storage costs. Consumers, however, has not studied the necessary change in storage costs that would be required due to a change in the ATL.762

The Company, on rebuttal, has agreed with the proposals of Staff and ABATE to

offer the 4% ATL level, which rewards customers who can more closely manage their

758 6 TR 2025.759 6 TR 2026.760 7 TR 1753.761 7 TR 2295.762 5 TR 1580.

U-18424Page 294

monthly gas supply.763 However, responding to RESA’s recommendation that the 4%

ATL level be rejected, Ms. Rayl testified:

The Company does not believe that this proposal is harmful and provides customers with a potential option that can assist them in lowering their energy costs. Furthermore, the Company did not change its ATL assumptions in the COSS offer the 4% ATL discount. The Company’s COSS filed in this case assumes all Transportation customers use an ATL of 8.5%.764

This PFD finds that RESA’s basis for proposing that the 4% ATL level be rejected

– namely, the absence of evidence that existing ATLs are ineffective at ensuring that

sufficient quantities of gas are delivered to meet customer usage – is insufficient on its

own to prohibit the Company from introducing this proposed pilot. This PFD thus

recommends that the Commission adopt the proposal offered by Staff and ABATE, and

agreed to by the Company, to offer the 4% ATL level.

C. Tariff Issues

The Company’s witness Karen Miles identified and supported the proposed

changes to be made to the gas tariff book, which changes are summarized in Exhibit A-

47, and set forth in the proposed gas tariff sheets contained in Exhibit A-16, Schedule F-

5.765 On cross-examination, Ms. Miles corrected Exhibit A-16, Schedule F-5, page 10 of

21 (tariff sheet D-1.10).766

Relying on the testimony of Mr. Gottschalk, Staff supports the Company’s proposal

to change the selection of its customers for the Low Income Assistant Credit (LIAC) from

763 2 TR 310-311.764 2 TR 310-311.765 Company’s Initial Brief, p, 208, citing 3 TR 689-693 and Exhibit A-46 and Exhibit A-16, Schedule F-5.766 3 TR 685.

U-18424Page 295

randomly selected to company selected. However, Mr. Gottschalk recommends inclusion

of the criteria used to select customers for the LIAC on tariff sheet No. D-8.00.767 Mr.

Gottschalk testified:

According to the Company’s response in Exhibit S-15.7 (DJG-14), theCompany will select customers for the LIAC based on the following criteria:

Customers with an approved critical care certification where the total household income does not exceed 150% of the Federal Poverty level within the last 12 months, as verified by an authorized State or Federal agency.

Customers who have received a Home Heating Credit in the previous 12 months.

Enrollment based on customers with highest arrears balance.

Customers whose total household income does not exceed 150% of the Federal Poverty level and have a past due balance.

Enrollment based on customers with the highest arrears balance.768

According to Staff, “retaining this language will help ensure that the Company follows and

is held to this important selection criteria.”769

The Company responds that, “[a]lthough there were no witnesses sponsored by

Staff opposing the language, in its Initial Brief, Staff opposes removing the selection

criteria from tariff sheet No. D-8.00.”770 The Company further contends that “[t]his change

in position is new in Staff’s Initial Brief and should be denied as without record support.”771

767 6 TR 2029-2030.768 Id.769 Staff’s Initial Brief, p. 185.770 Consumers Energy’s Reply Brief, p. 208.771 Id.

U-18424Page 296

This PFD finds that the Company is mistaken in asserting that Staff’s position is

“new in Staff’s Initial Brief and should be denied as without record support.”772 Mr.

Gottschalk clearly testified in support of Staff’s position, as set forth above. This PFD

further finds that Staff’s proposed inclusion of the selection criteria for its low-income

program is reasonable and, without persuasive opposition, should be approved by the

Commission.

XI.

ACCOUNTING TREATMENT

A. RDM Accounting Request

Relying on the testimony of Mr. Harry, the Company maintains that, because its

proposed gas RDM would result in deferred debits or credits until any under-recovery or

over-recovery is fully collected or refunded, the Company requires approval to recognize

regulatory assets or liabilities as needed to record these deferred amounts.773 The

Company notes that the Commission approved a similar request in the Company’s last

gas rate case, Case No. U-18124, in connection with its gas RDM, and furthermore, no

witness has opposed the Company’s RDM accounting request.774

Accordingly, this PFD recommends that the Commission approve the Company’s

request for accounting approval for use of its regulatory assets or regulatory liabilities, as

needed, for its gas RDM in this case.

772 Consumers Energy’s Reply Brief, p. 208.773 3 TR 555.774 Consumers Energy’s Initial Brief, p. 237, citing MPSC Case No. U-18124, July 31, 2017 Order, p. 94.

U-18424Page 297

B. Regulatory Accounting for Investments in Cloud-Based Technologies Accounting

The Company also seeks the Commission’s approval of deferred regulatory

treatment for cloud-based IT solutions. Mr. Harry also provided testimony in support of

this request, including a summary of the proposed accounting impacts of such

transactions, a summary of typical cloud-based solutions, and an explanation for the

necessity of this accounting treatment.775 Staff supports the Company’s request, with Mr.

Welke testifying as follows:

Staff believes that project implementation costs will provide economic benefits in periods beyond the calendar year in which they were incurred. Further, Staff believes that streamlined accounting is both efficient and promotes the enablement to realize a substantial benefit that a cloud-based solution may offer in the future. Therefore, Staff supports the Company’s regulatory accounting request to capitalize project implementation costs related to cloud-based technologies.776

Given Staff’s support for the Company’s deferred regulatory treatment for cloud-

based IT solutions, this PFD recommends that the Commission approve the Company’s

request.

775 3 TR556-558.776 6 TR 2140-2141.

U-18424Page 298

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 $10,617,000 with an authorized return on equity of 10.0% and an overall

cost of capital of 5.86%, as well as recommendations regarding ratemaking mechanisms,

cost of service allocations, rate design, and tariff modifications.

MICHIGAN ADMINISTRATIVE HEARING SYSTEMFor the Michigan Public Service Commission

________________________________ Suzanne D. Sonneborn

Administrative Law Judge

July 2, 2018Lansing, Michigan

Suzanne D. Sonneborn

Digitally signed by Suzanne D. Sonneborn DN: cn=Suzanne D. Sonneborn, o=MAHS, ou=MAHS PSC, [email protected], c=US Date: 2018.07.02 14:47:31 -04'00'

MICHIGAN PUBLIC SERVICE COMMISSION

Consumers Energy Company Ca

Revenue Deficiency (Sufficiency) for the

Projected 12-Month Period Ending June 30, 2019

($000)

(a) (b) (c) (d)

Line No. Description Source

Applicant Projection

(Reply Brief) PFD Adjustmentt PFD Projection

1 Rate Base Appendix B 5,437,581$ (301,409)$

2 Adjusted Net Operating Income Appendix C 274,228 19,023

3 Overall Rate of Return Line 2 / Line 1 5.04% 0.67%

4 Required Rate of Return Appendix D 6.07% -0.21%

5 Income Requirements Line 1 * Line 4 330,039 (28,909)

6 Income Deficiency / (Sufficiency) Line 5 - Line 2 55,811 (47,931)

7 Revenue Conversion Factor Exhibit No.: A-13 (JRC-12) 1.3475 -

8 Revenue Deficiency / (Sufficiency) Line 6 * Line 7 75,203$ (64,586)$ 10,617$

CECo @ 10.5% ROE P

9 Incremental Rev. Def. for CECo 25 basis point ROE increase request 7,357 (7,357)

10 Revenue Deficiency / (Sufficiency) 82,560$ (71,943)$ 10,617$

CECo @ 10.75% ROE P

Appendix A


Consumers Energy Company

Projected Rate Base for the


($000)

(a) (b) (c) (d)

Line No. DDescription Source

Applicant Projection (Reply

Brief)PFD

AdjustmenttsPFD

Projection

1 Plant in Service Appendix E 7,719,392 (292,1

2 Plant Held for Future Use 209 -

3 Construction Work in Progress 233,039 -

4 Total Projected Utility Plant Sum Lines 1 - 3 7,952,640 (292,1

5 Less: Depreciation Reserve Appendix E (3,220,252) 15,68

6 Net Utility Plant Line 4+ Line 5 4,732,388 (276,43

7 Retainers and Customer Advances (3,515) -

8 Adjusted Net Utility Plant Sum Lines 6 - 7 4,728,872 (276,43

9 Working Capital 662,139

10 Net Unamortized MGP Appendix E 46,570 (24,97

11 Total Projected Rate Base Sum Lines 8 - 10 5,437,581$ (301,40$

Appendix B


Consumers Energy CompanyProjected Net Operating Incomefor the Test Year Ended June 30, 2019($000)

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (

LineNo. Description (Witness)

Company Filed1 Operating Income (Initial Filing) 1,539,062 70,980 89,978 1,700,020 681,507 9,614 5,453 351,015 263,142 99,100 16,944 427 12,848 422 Federal Income Tax Reform (213 Other Gas Revenue AMA 7,678 7,678 12 452 14 Impact of Capital Spending Adj. - (1,818) (402) 4 1315 Pension & OPEB Adj. - (21,203) 34 1,249 46 Interest Income on Security Deposits - 293 (0) (17)7 MAOP O&M - (5,638) 9 332 18 MGP Amortization - (601) 1 359 MGP - Direct Management Costs (Edelyn) (215) 0 13

10 Proforma Interest - 5 19311 Interest Synchronization - - - - - - - - - - - 0 -12 Operating Income (Reply Brief) 1,539,062 70,980 97,656 1,707,698 681,507 9,614 5,453 324,252 260,723 98,698 16,944 492 15,235 28

PFD Adjustments13 Sales Revenue (Gottschalk) (20,490) (20,490) (20,490) - -14 Pipeline Integrity Inspections and Remediation (Miller) - 9,530 (15) (562) (115 Gas DCO Division Expenses (Creisher) (5,763) 9 340 116 Pipeline Integrity Inspections and Remediation (Creisher) (2,167) 3 12817 Meter Reading Fromm) (6,357) 10 375 118 LAUF (Isakson) 4 (0) (0)19 Company Use Gas (Isakson) 2 (0) (0)20 Customer Experience (Fromm) - -21 Gas Compression, Storage, and Asset Management (Creisher) (301) 0 1822 Injuries & Damages (Welke) - - -23 Incentive Compensation (Welke) (1,163) 2 6924 Gas AMR 3,907 (6) (230)25 Customer Experience (AG) (5,859) 9 346 126 Capital Expenditure Adj. Impact on Depr. & Prop. Tax (Gerken) (13,245) (3,818) 27 1,006 327 Cap Ex Addback for Concession not adopted 332 166 (1) (29)28 MGP Amortization Expense (Edelyn) (3,376) 5 19929 MGP Amortization Addback for Concession not adopted 601 (1) (35)30 Proforma Interest (Nichols) - 9 315 131 Interest Synchronization (Nichols) - - - - - - - - - - - 0 232 Total Adjustments (20,490) - - (20,490) (20,490) 4 2 (8,172) (15,688) (3,651) - 53 1,940 6

33 PFD NOI - Test Year 1,518,572 70,980 97,656 1,687,208 661,017 9,618 5,455 316,080 245,036 95,047 16,944 545 17,174 35

Company Use LAUF

R&PP Tax

Appendix C

Other General Taxes

Other (or Local) Taxes

State Income

Tax F

Revenue Expenses

Sales Revenue

Transport Revenue

Other Gas Revenue Total

Cost of Gas Sold

Other O&M

Depreciation & Amort.


Consumers Energy Company

Overall Rate of Return Summary

Projected Capital Structure & Cost Rates


13-Month % of % of We

Average Permanent Total Cost Permanent Tot

Line Description Source ($000) Capital Capital Rate Capital Cap

(a) (b) (c) (d) (e) (f) (g) (h

1 Long-Term Debt Exhibit No.: A-14 (AJD-1) 6,028,845$ 47.21% 36.79% 4.57% 2.16% 1.68

2 Preferred Stock Exhibit No.: A-14 (AJD-1) 37,315 0.29% 0.23% 4.50% 0.01% 0.0

3 Common Equity Exhibit No.: A-14 (AJD-1) 6,702,778 52.49% 40.91% 10.00% 5.25% 4.09

4 Permanent Capital 12,768,938$ 100.00% 7.42%

5 Total Short Term Debt Exhibit No.: A-14 (AJD-1) 184,300 1.13% 3.14% 0.04

6 Customer Deposits Exhibit No.: A-14 (AJD-1) - 0.00% 7.00% 0.00

7 Other Interest Bearing Accounts Exhibit No.: A-14 (AJD-1) - 0.00% 4.00% 0.00

8 Deferred FIT Exhibit No.: A-14 (AJD-1) 3,332,545 20.34% 0.00% 0.00

Deferred JDITC/ITC

9 Long-Term Debt Exhibit No.: A-14 (AJD-1) 47,501 0.29% 4.57% 0.0

10 Preferred Stock Exhibit No.: A-14 (AJD-1) 294 0.00% 4.50% 0.00

11 Common Equity Exhibit No.: A-14 (AJD-1) 52,520 0.32% 10.00% 0.03

12 Total Capitalization 16,386,098$ 100.00% 5.86

Appendix D

MICHIGAN PUBLIC SERVICE COMMISSION PFDConsumers Energy Company Case No.: U-18424Summary of Rate Base Adjustments Appendix EProjected 12-Month Period Ending June 30, 2019($000)

(a) (b) (c ) (d) (e ) (f) (g) (h)

Cap Ex Adj. Plant Adj. Accum Depr. Rate Base Depreciation Prop. Tax

Line Witness Adjustment DescriptionIncrease / (Decrease)

Increase / (Decrease)





1 AG Trans. & Dist. - New Business - Mains, Services, Meters (6,825) (4,600) (86) (4,514) (136) (57)2 Staff/AG Trans. & Dist. - New Business - Large New Projects (14,099) (7,050) (104) (6,945) (209) (88)3 AG Trans. & Dist. - New Business - Customer Attachment (4,455) (3,119) (59) (3,059) (92) (39)4 Staff Trans. & Dist. - Regulatory Compliance Pipeline Integrity (4,819) (2,566) (47) (2,518) (76) (32)5 Staff Trans. & Dist. - Regulatory Compliance MAOP (32,021) (20,994) (361) (20,633) (525) (262)6 Staff Trans. & Dist. - Material Condition Non Modeled/Renewals (6,413) (4,094) (74) (4,020) (121) (51)7 Company Trans. & Dist. - Material Condition VSR (18,201) (10,296) (170) (10,126) (305) (129)8 Staff Trans. & Dist. - Capacity/Deliverability (14,469) (11,431) (281) (11,150) (286) (143)9 Staff Trans. & Dist. -Line 100A (10,651) (7,196) (182) (7,014) (180) (90)

10 TOTAL TRANS. & DIST. NON-CONTINGENCY (111,953) (71,344) (1,365) (69,979) (1,930) (892)

11 Staff AMR (112,663) (92,376) (9,301) (83,075) (7,232) (1,155)12 Staff IT (6,446) (5,024) (880) (4,144) (588) (63)13 Staff Pipeline Integrity (92,799) (80,438) (3,130) (77,308) (2,011) (1,005)14 TOTAL OTHER NON-CONTINGENCY (211,908) (177,838) (13,311) (164,527) (9,830) (2,223)

15 TOTAL NON-CONTINGENCY (323,861) (249,181) (14,675) (234,506) (11,760) (3,115)

16 Staff/AG Trans. & Dist. - Line 100A Contingency (1,838) (1,094) (16) (1,078) (27) (14)17 Staff/AG Trans. & Dist. - St. Clair Upgrade Contingency (4,741) (4,741) (176) (4,565) (117) (59)18 Staff/AG IT Contingency (1,646) (911) (63) (848) (107) (11)19 Staff/AG Trans. & Dist. - All Other Contingency (38,913) (25,335) (434) (24,901) (633) (317)20 Staff/AG Gas Comp. Storage - All Other Contingency (30,516) (24,147) (604) (23,542) (601) (302)

21 TOTAL CONTINGENCY (77,654) (56,228) (1,292) (54,935) (1,485) (703)

22 TOTAL (401,514) (305,409) (15,968) (289,441) (13,245) (3,818)

23 Staff Adjustment to Consumers MGP Projection24 Staff MGP (30,382) (3,376)

25 Consumers Update in Rebuttal not Adopted by Staff26 Staff MGP Addback Company Update - - 5,408 601 -27 TOTAL MGP DIFFERENCE WITH CONSUMERS - - (24,974) (2,775) -

28 Staff Trans & Dist. - MAOP (Palkovich) 5,573 3,556 54 3,502 89 4429 Staff Trans & Dist. - TED-I Saginaw 1 3,869 112 3,757 97 4830 Staff Trans & Dist. - TED-I Mid-Michigan 9,282 5,870 122 5,748 147 7331 TOTAL PLANT UPDATE NOT ADOPTED 14,856 13,294 288 13,006 332 166

32 TOTAL (292,115) (15,680) (301,409) (15,688) (3,651)

App B, ln 1 App B, ln 5 App A, ln 1 App C, ln 32 App C, ln 32

Test Year Impacts on Historic and Projected Capital Spend

Appendix E

Documents

STATE OF MICHIGAN BEFORE THE MICHIGAN … › documents › mpsc › U18424.comppfd...STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * * PROPOSAL FOR DECISION