DANA NESSEL ATTORNEY GENERAL

STATE OF MICHIGAN DEPARTMENT OF ATTORNEY GENERAL

P.O. BOX 30755 LANSING, MICHIGAN 48909

DANA NESSEL ATTORNEY GENERAL

September 27, 2019

Executive Secretary Michigan Public Service Commission 7109 West Saginaw Highway Lansing, MI 48917 Dear Ms. Kunkel: Re: MPSC Case No. U-20479

Enclosed find the Attorney General’s Direct Testimony and Exhibits and related Proof of Service.

Sincerely, Michael E. Moody Assistant Attorney General

c All Parties

1

PROOF OF SERVICE - U-20479 The undersigned certifies that a copy of the Attorney General’s Direct Testimony and Exhibits, was served upon the parties listed below by e-mailing the same to them at their respective email addresses on the 27th of September 2019. Michael E. Moody MPSC: Monica Stephens Michael Orris Daniel Sonneveldt Lori Mayabb [email protected] [email protected] [email protected] [email protected] Attorney General Special Litigation Division: Michael Moody [email protected] [email protected] Sebastian Coppola [email protected] SEMCO Energy Company: Sherri Wellman Paul Collins Matthew Carstens [email protected] [email protected] [email protected] Citizens Utility Board of Michigan: John R. Liskey Constance D. Groh [email protected] [email protected]

Retail Energy Supply Association: Jennifer U. Heston [email protected]

mailto:[email protected]











STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

MPSC Case No. U-20479In the matter of the application of ) SEMCO ENERGY GAS COMPANY ) for authority to increase its rates for the ) distribution and transportation of natural gas ) and other relief ) __________________________________________

Direct Testimony

And Exhibits

of

Sebastian Coppola

On behalf of

Attorney General Dana Nessel

September 27, 2019

U-20479 S. Coppola – Direct – 2 9/27/19

TABLE OF CONTENTS

I. Introduction ............................................................................................................................ 3 II. Summary Conclusions and Recommendations .................................................................. 8 III. Rate Base & Capital Expenditures ... .............................................................................. 11 A. Contingent Capital Expenditures ................................................................................ 12 B. MCP Observations ........................................................................................................ 13 C. Purchase of Harborside Office Building ..................................................................... 14 D. MRP Capital Expenditures .......................................................................................... 17 E. IRIP Capital Expenditures ........................................................................................... 22 F. Valve Replacement Program ........................................................................................ 24 IV. Working Capital Adjustment ........................................................................................... 27 V. Cost of Capital ..................................................................................................................... 30

VI. Gas Sales & Transportation Revenue .............................................................................. 55

VII. O&M Expense Adjustments ........................................................................................... 63 A. Credit Cards – Payment Processing Fees ................................................................... 64 B. O&M Expense Inflation Adjustment .......................................................................... 67 C. Appliance Repair Program .......................................................................................... 68 D. Uncollectible Accounts Expense .................................................................................. 70 E. SERP ............................................................................................................................... 71 F. Incentive Compensation ................................................................................................ 72 G. AltaGas Corporate Expenses ........................................................................................ 78 VIII. Company Use and LAUF Gas ....................................................................................... 83

IX. Revenue Decoupling Mechanism ..................................................................................... 85

X. Rate Design .......................................................................................................................... 86

XI. MRP and IRIP Surcharges ............................................................................................... 87

XII. Facilities Improvement Demand Surcharge .................................................................. 92

XIII. Adjustments to Revenue Deficiency ............................................................................. 93


I. Introduction 1

Q. PLEASE STATE YOUR NAME, OCCUPATION, AND ADDRESS. 2

A. My name is Sebastian Coppola. I am an independent business consultant. My office is 3

at 5928 Southgate Rd., Rochester, Michigan 48306. 4

Q. PLEASE SUMMARIZE YOUR PROFESSIONAL QUALIFICATIONS. 5

A. I am a business consultant specializing in financial and strategic business issues in the 6

fields of energy and utility regulation. I have more than thirty years of experience in public 7

utility and related energy work, both as a consultant and utility company executive. I have 8

testified in several regulatory proceedings before the Michigan Public Service 9

Commission (MPSC or Commission) and other regulatory jurisdictions. I have prepared 10

and/or filed testimony in rate case proceedings, revenue decoupling reconciliations, gas 11

conservation programs, Gas Cost Recovery (GCR) cases and Power Supply Cost Recovery 12

(PSCR) cases. As accounting manager and later financial executive for two regulated gas 13

utilities with operations in Michigan and Alaska, I have been intricately involved in 14

regulatory proceedings related to gas cost recovery cases, gas purchase strategies, rate case 15

filings and power plant cost analysis. I have also supported other witnesses in testimony 16

before the MPSC in various rate setting and other regulatory proceedings. 17

Q. PLEASE LIST SOME OF THE MORE RECENT CASES YOU HAVE 18

PARTICIPATED IN BEFORE THE MPSC AND OTHER REGULATORY 19

AGENCIES. 20


A. Here is a partial list of the most recent regulatory cases in which I have participated: 1

o Filed testimony on behalf of the Michigan Attorney General in SEMCO Energy 2 Gas Company (SEMCO) 2019-2020 GCR Plan case U-20479. 3

o Filed testimony on behalf of the Michigan Attorney General in Consumers 4 Energy Company (CECo) 2019-2020 GCR Plan case U-20233. 5

o Filed testimony on behalf of the Michigan Attorney General in DTE Electric 6 Company (DTEE) 2019 PSCR Plan case U-20221. 7

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 8 Company (DTE Gas) 2019-2020 GCR Plan case U-20235. 9

o Filed testimony on behalf of the Michigan Attorney General in Michigan Gas 10 Utilities Corporation (MGUC) 2019-2020 GCR plan case U-20239. 11

o Filed direct testimony on behalf of the Illinois Attorney General in Nicor Gas 12 2018 rate case on capital expenditures and rate base additions in Docket 18-1775. 13

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 14 Company (DTE Gas) Tax Credit C Calculation in case U-20298. 15

o Filed testimony on behalf of the Michigan Attorney General in Consumers 16 Energy Company (CECo) Tax Credit C Calculation for the Gas and Electric 17 Divisions in case U-20309. 18

o Filed testimony on behalf of the Michigan Attorney General in Upper Peninsula 19 Power Company 2018 electric rate Case U-20276 on several issues, including 20 excess deferred taxes, cost of capital, rate design and other items. 21

o Filed testimony on behalf of the Michigan Attorney General in DTE Electric 2018 22 electric rate Case U-20162 on several issues, including O&M expenses, capital 23 expenditures, cost of capital, rate design and other items. 24

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 Tax 25 Credit B refund for the Electric Division in case U-20286. 26

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 27 Integrated Resource Plan in case U-20165. 28

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 Tax 29 Credit B refund for the Gas Division in case U-20287. 30

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2018 31 Tax Credit B refund case U-20189. 32

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 33 electric rate Case U-20134 on several issues, including capital expenditures, cost 34 of capital, rate design and other items. 35


o Filed direct testimony on behalf of the Illinois Attorney General for the 1 reconciliation of the rate surcharge for the Qualified Infrastructure Program 2 (Rider QIP) of the Peoples Gas and Coke Company’s (Peoples Gas) in Docket 3 16-0197. 4

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2016-5 2017 GCR reconciliation case U-17941-R. 6

o Filed testimony on behalf of the Michigan Attorney General in SEMCO 2018-7 2019 GCR Plan case U-18417. 8

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 Tax 9 Credit A refund case U-20102. 10

o Filed testimony on behalf of the Michigan Attorney General in Indiana Michigan 11 Power Company (I&M) 2018 PSCR Plan case U-18404. 12

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2018-13 2019 GCR Plan case U-18412. 14

o Filed testimony on behalf of the Michigan Attorney General in Upper Peninsula 15 Power Company (UPPCO) 2018 Tax Credit A refund case U-20111. 16

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2018 17 Tax Credit A refund case U-20106. 18

o Filed testimony on behalf of the Michigan Attorney General in DTE Electric 19 Company (DTEE) 2018 PSCR Plan case U-18403. 20

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 PSCR 21 Plan case U-18402. 22

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2017 23 gas rate Case U-18999 on several issues, including revenue, operations and 24 maintenance costs, capital expenditures, cost of capital, rate design and other 25 items. 26

o Filed testimony on behalf of the Michigan Attorney General in CECo 2017 gas 27 rate Case U-18424 on a several issues, including revenue, operations and 28 maintenance costs, capital expenditures, cost of capital, rate design and other 29 items. 30

Appendix A elaborates further on my qualifications in the regulated energy field. 31


Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 1

A. I have been asked by the Michigan Department of Attorney General to perform an 2

independent analysis of SEMCO Energy Gas Company’s (“SEMCO Gas” or the 3

“Company”) Gas Rate Case filing U-20479. This testimony presents a report of that 4

analysis with related recommendations. 5

Q. WHAT TOPICS ARE YOU ADDRESSING IN YOUR TESTIMONY? 6

A. I am addressing the following major topics in this case: 7

1. The level of proposed capital expenditures and rate base 8 2. The Company’s working capital requirements 9 3. The Company’s cost of capital 10 4. The level of forecasted gas sales and transportation sales & revenue 11 5. The level of operations and maintenance expenses 12 6. The amortization of costs for the Service Valve Replacement Program 13 7. The expansion of the Main Replacement Program (“MRP”) 14 8. The proposed Infrastructure Reliability Improvement Program (“IRIP”) 15 9. The calculation of surcharges for the MRP, IRIP and Facilities Improvement 16

Demand (“FID”) charge. 17 10. Rate design issues 18

The absence of a discussion of other matters in my testimony should not be taken as an 19

indication that I agree with those aspects of SEMCO’s rate case filing. The narrow focus 20

of my testimony is, instead, a consequence of focusing on priority issues within the 21

available resources. 22

Q. IS YOUR TESTIMONY ON THESE TOPICS ACCOMPANIED BY EXHIBITS? 23


A. Yes. I am sponsoring the following exhibits, which were either prepared by me or under 1

my direct supervision: 2

1. Exhibit AG-1 SEMCO Response – Contingency Costs 3 2. Exhibit AG-2 SEMCO Response – Harborside Office Building Incremental Costs 4 3. Exhibit AG-3 SEMCO Response – Non-MRP Projects 5 4. Exhibit AG-4 SEMCO Response – Gas Leak Data 6 5. Exhibit AG-5 SEMCO Response – Service Valve Replacement Costs 7 6. Exhibit AG-6 SEMCO Response – Update Gas Costs and Gas Inventory 8 7. Exhibit AG-7 Overall Cost of Capital 9

8. Exhibit AG-8 Cost of Common Equity 10 9. Exhibit AG-9 Cost of Common Equity-DCF 11 10. Exhibit AG-10 Cost of Common Equity-CAPM 12 11. Exhibit AG-11 Cost of Common Equity-Risk Premium 13 12. Exhibit AG-12 Peer Group Utility and Non-Utility Business Mix 14 13. Exhibit AG-13 Market to Book Ratios of Peer Group 15 14. Exhibit AG-14 ROE Decisions by Regulatory Commissions 16 15. Exhibit AG-15 Average Gas Usage by Customers 2014-2020 17 16. Exhibit AG-16 Incremental Gas Sales and Transportation Revenue by Rate Schedule 18 17. Exhibit AG-17 Summary of Incremental Gas Sales and Transportation Revenue 19 18. Exhibit AG-18 Revised Billing Determinants 20 19. Exhibit AG-19 O&M Adjustments - Summary 21 20. Exhibit AG-20 SEMCO Response – Value Added Services 22 21. Exhibit AG-21 Revised Uncollectible Gas Accounts Expense 23 22. Exhibit AG-22 SEMCO Response – Incentive Compensation Plan Performance 24 23. Exhibit AG-23 SEMCO Response – Incentive Compensation STIP Measures 25 24. Exhibit AG-24 SEMCO Response – Incentive Compensation Financial Measure 26 25. Exhibit AG-25 SEMCO Response – Incentive Compensation LTIP Measures 27 26. Exhibit AG-26 SEMCO Response – SEMCO Inc and AltaGas Corporate Costs 2020 28 27. Exhibit AG-27 SEMCO Response – AltaGas Corporate Cost Allocations 2013-2019 29


28. Exhibit AG-28 SEMCO Response – Description of AltaGas Corporate Functions 1 29. Exhibit AG-29 Calculation of Disallowance of AltaGas Duplicate Corporate Costs 2 30. Exhibit AG-30 SEMCO Response – Alta Gas Incentive Compensation STIP Goals 3 31. Exhibit AG-31 SEMCO Response – LAUF Reduction Initiatives 4 32. Exhibit AG-32 Revised LAUF and Company Use Gas Costs 5 33. Exhibit AG-33 Revised MRP Surcharges 6 34. Exhibit AG-34 Revised IRIP Surcharges 7 35. Exhibit AG-35 Revised FID Surcharges 8 36. Exhibit AG-36 Calculation of Revised Revenue Deficiency 9

II. SUMMARY CONCLUSIONS & RECOMMENDATIONS 10

Q. PLEASE PROVIDE A SUMMARY OF YOUR CONCLUSIONS AND ANY 11

ADJUSTMENTS TO THE COMPANY’S REVENUE DEFICIENCY 12

CALCULATION BEFORE YOU ADDRESS EACH TOPIC IN DETAIL. 13

A. The Company filed for a rate increase of $38.1 million. The rate increase represents an 14

overall increase in base gas distribution rates of 30% with a similar increase to residential 15

customers. Including the cost of gas, the Company’s proposed rate increase would raise 16

the total bill for the average residential customer by 14%. As a result of the rate case 17

adjustments I propose in my testimony, the average residential customer should see a much 18

smaller increase in their total bill of approximately 3%. 19

It is worth noting that during the 2018 historical test year, the Company reported a revenue 20

sufficiency of $10.6 million.1 However, SEMCO Gas calculated this revenue sufficiency 21

based on a required rate of return using an inflated equity ratio of 61%. By recalculating 22

1 Exhibit A-1 (BHF-1), Schedule A1.


the required rate of return using the equity ratio of approximately 55% underlying the rate 1

settlement in the Company’s last rate case, Case No. U-16169, the true revenue sufficiency 2

during 2018 was $11.8 million. 3

Similarly, the Company reported an earned ROE of 9.81% for 2018 on a regulatory basis, 4

while also reporting a ROE of 12.52% on a financial basis. The ROE of 9.81% is not 5

reflective of the true ROE earned by the Company on a regulatory basis. To arrive at this 6

lower number the Company used an estimated rate base amount for 2018 which is almost 7

$100 million higher than the rate base amount reported for the historical 2018 test year in 8

Exhibit A-1, Schedule A1. The Company also did not reflect the lower federal tax rate of 9

21% and instead appears to have used a 35% federal tax rate in the various calculations to 10

arrive at net income on a regulatory basis. The result of reflecting the proper rate base and 11

other factors is a corrected earned ROE for 2018 of 12.86%. In comparison, to the 12

Company’s current authorized ROE of 10.35%, which was approved by the Commission 13

in January 2011, SEMCO over-earned its authorized return in 2018 by approximately 250 14

basis points. 15

Based on the foregoing analysis, I have identified several cost disallowances to the 16

Company’s proposed revenues, cost levels and capital projects, which I recommend that 17

the Commission approve. As a result of these adjustments, I have determined that the 18

Company has a revenue deficiency of $8.4 million. This result also should not be 19

surprising given the fact that the Company earned a ROE of 12.86% in 2018, and I now 20

propose that the ROE in this rate case be set at 9.50%. 21


My conclusions and related adjustments are summarized below: 1

1. I recommend a small reduction in capital expenditures to remove contingency 2

costs and adjustments to working capital for a total adjustment to rate base of 3

$5.6 million. This reduces the Company’s revenue deficiency by $0.4 4

million. 5

2. I recommend that the Commission adopt a lower cost of capital rate of 5.66%, 6

a capital structure with 50% equity capital and a return on common equity of 7

9.50%. These recommendations reduce the Company’s revenue deficiency 8

by $13.5 million. 9

3. I recommend an increase in forecasted gas sales and transportation volumes 10

for the projected test year. These adjustments increase forecasted revenue by 11

$4.8 million and reduce the revenue deficiency by the same amount. 12

4. I recommend a lower level of Operations and Maintenance expenses for the 13

test year. This reduces the Company’s revenue deficiency by $8.9 million. 14

5. I recommend adjustments to LAUF and Company Use gas, the amortization 15

of the Valve Replacement Program costs and the revenue requirement impact 16

for the purchase of the Harborside Office building. In total, these adjustments 17

reduce the revenue deficiency by $2.1 million. 18

6. I recommend that the Commission limit the MRP to only MRP-qualified 19

capital projects and not shifting base and routine main replacement funding 20

to other capital programs. 21

7. I recommend that the Commission reject the IRIP at this time and encourage 22

the Company to coordinate development of any IRIP projects with the 23

collaborative initiatives ordered by the Commission in Case No. U-20631. 24

The Commission should also encourage the Company to proactively seek 25

input from interested parties through a collaborative forum before 26

resubmitting its proposed IRIP. 27


8. I recommend that the Commission reject the Company’s proposed alternative 1

RDM. 2

9. I recommend that the Commission retain the monthly customer charge for 3

residential customers and the commercial GS-1 rate at $11.50, or at most 4

increase it to $12.50. 5

10. I recommend that the Commission reject the Company’s MRP and IRIP five-6

year average surcharges, and instead approve annual surcharges if the 7

Commission approves those programs. 8

11. I recommend that the Commission modify the Company’s proposed FID 9

surcharge to include additional pipeline interconnection costs proposed by 10

the Company in Case No. U-20245. The Commission should also approve a 11

process to periodically update the FID surcharge, when new pipeline 12

interconnection costs are approved in future years. 13

The remainder of my testimony provides further details and support to these summary 14

conclusions and recommendations. 15

III. RATE BASE 16 CAPITAL EXPENDITURES 17

Q. PLEASE DISCUSS THE LEVEL OF CAPITAL EXPENDITURES PROPOSED BY 18

THE COMPANY AND THE RESULTING INCREASE IN RATE BASE. 19

A. In this general rate case, SEMCO Gas has projected capital expenditures of $243 million 20

for the two years ending 2020.2 In comparison the Company had $65.1 million in capital 21

spending in 2018 and has spent similar amounts in recent prior years. The majority of the 22

2 Exhibit A-12, Schedule B-5.


increase in spending in 2019 and 2020 is due to the construction of the Marquette 1

Connector Pipeline (“MCP”). The proposed capital expenditures for 2019 and 2020 are 2

the main contributors to the increase in rate base from $517.1 million in 2018 to the 3

forecasted amount of $724.5 million for the 2020 projected test year. 4

A. Contingency Capital Expenditures 5

Q. IN YOUR ANALYSIS, HAVE YOU DETERMINED ANY SPECIFIC 6

ADJUSTMENTS TO THE PROPOSED CAPITAL EXPENDITURES FOR 2019 7

AND 2020? 8

A. Yes. In my review of the capital expenditures, I discovered that the Company included 9

$466,000 in contingency capital expenditures for the construction of the MCP in 2019. 10

Exhibit AG-1 includes a schedule provided by SEMCO Gas in response to a Staff Audit 11

Request (KPS-1MCPP-EAC) which shows the contingency capital cost of $466,000 12

included in the total cost of $159,020,000 for the MCP project. This amount matches the 13

total capital expenditures for the MCP included on line 8 of Exhibit A-12 (KLS-1), 14

Schedule B-5, page 1, for the period 2018 through 2020. 15

In other recent general rate cases, the Commission has consistently rejected the inclusion 16

of contingent capital expenditures in the projected rate base.3 The $466,000 is similar to 17

3 MPSC Case Nos. U-17735, U-17990, U-18124, U-18999 and U- 20162.


contingency costs previously rejected by the Commission, and I recommend that those 1

costs be removed from the Company’s projected rate base in this case. 2

B. MCP Observations 3

Q. ARE THERE OTHER OBSERVATIONS YOU WANT TO MAKE ABOUT THE 4

PROJECTED COST TO BUILD THE MCP? 5

A. Yes. The cost to build the pipeline and related facilities has increased significantly since 6

the Company made its Act 9 filing in December 2016 requesting approval to build the 7

pipeline. In the Act 9 filing, in Case No. U-18202, the Company projected that the total 8

construction cost would be $140.4 million. The current estimate of $159 million is $18.6 9

million, or 13% higher. From the comparative schedule provided in response to a 10

discovery question and included in Exhibit AG-1, it appears that the Company 11

significantly underestimated the cost of contractor labor and expenses. Based on the 12

contractor bid accepted by the Company, which was the lowest bid received, the cost for 13

contractor labor and expenses was $44.4 million above the original estimate. This is an 14

increase of 55%. Land related costs also were above the original estimate by 70%. These 15

higher costs were partially offset by a large contingency cost reserve of $21.7 million built-16

in the original cost estimate. 17

Although the Company points to the escalation in contractor costs from 2016 to 2019 due 18

to cost inflation and an increase in utility construction projects in the U.S., it is difficult to 19

understand the large percentage variances and significant cost increases. The logical 20


conclusion from the available information is that costs were poorly estimated in the 1

original Act 9 filing. It may be instructive for the Commission to learn from this case and 2

in the future perhaps establish a maximum approved cost level in Act 9 filings with the 3

provision that any cost increases would be the responsibility of the utility. 4

C. Purchase of Harborside Office Building 5

Q. ARE THERE OTHER CAPITAL COSTS IN THE PROJECTED RATE BASE FOR 6

2020 THAT SHOULD BE REMOVED? 7

A. Yes. In April 2018, SEMCO Energy Inc. (“SEMCO Inc.”) purchased the Harborside 8

Office building for the price of $11.5 million. The office location serves as its corporate 9

headquarters. The Company decided to include this cost in rate base for 2018 as a utility 10

asset. Prior to the purchase of the building, SEMCO Inc. was leasing 65,000 square feet 11

of space and charging the Michigan utility operations (SEMCO Gas) for a proportional 12

share of the lease and related expenses, with the remaining portion allocated to non-utility 13

businesses. In discovery, the Company was asked to justify the purchase of the building 14

and the inclusion of the cost in rate base along with the related operating expenses and 15

property taxes. In response, the Company provided a comparative analysis showing the 16

revenue requirement assuming the lease arrangement had continued into 2020 versus the 17

revenue requirement paid by customers in 2020 with SEMCO Gas owning the building 18

and including the applicable costs in base rates. 19


The analysis shows that the projected 2020 revenue requirement of owning the building is 1

$344,676 higher than if the Company had continued to lease space in the building with 2

annual inflation escalation of the rent and related expenses. Exhibit AG-2 included the 3

analysis provided by the Company. Clearly, the purchase of the building creates added 4

cost for utility customers, which is not desirable. The Company points to the risk of 5

business disruption if an acceptable lease arrangement could not have been reached with 6

a different owner at the expiration of the current lease arrangement in 2020. However, 7

with SEMCO Inc occupying about two-thirds of the space in the building, it is unlikely 8

that any new owner would have been uncooperative in agreeing to a market-based lease 9

arrangement to keep such an anchor tenant. From any of the information provided by the 10

Company in testimony and discovery, it does not appear that the Company shopped for 11

alternative office space in the Port Huron area in order to use that information as 12

negotiating leverage. 13

More importantly, it is not clear why SEMCO Inc. decided to include the cost of the 14

building in rate base as a utility asset, other than to obtain assured recovery of costs, when 15

a portion of the lease is assignable to non-regulated businesses, and the remaining third of 16

the space in the building is leased to third-parties. This is an asset that should have been 17

owned by SEMCO Energy Inc. as a parent company asset, and an appropriate share of the 18

cost assigned to the Michigan utility operations and other businesses. Like other affiliated 19

transactions, those costs should have been charged to utility operations at the lower of 20

actual cost or market-based costs, which in the case of office space are usually easily 21


available. Any risk for loss of rents from third-party tenants would then have fallen on 1

SEMCO Inc. and not on SEMCO Gas as is the case under the current rate base 2

arrangement. Rate basing the purchase of the Harborside Office building is not in the best 3

interest of utility customers. 4

Q. WHAT IS YOUR CONCLUSION AND RECOMMENDATION WITH REGARD 5

TO THE HIGHER COSTS OF INCLUDING THE HARBORSIDE OFFICE 6

BUILDING IN RATE BASE AND THE INCREASE IN REVENUE 7

REQUIREMENT? 8

A. From the evidence presented by the Company, the purchase of the Harborside Office 9

building is not in the best interest of utility customers. I recommend that the Commission 10

remove the capitalized amount of $11,255,962 from the 2020 projected rate base along 11

with O&M costs of $1,105,941, net of third-party revenue, and replace those costs with 12

the projected rent and related costs of $1,708,882, as shown in the revenue requirement 13

schedule in Exhibit AG-2. Alternatively, the Commission could impute a revenue credit 14

of $344,676 in calculating the revenue deficiency in this rate case to compensate for the 15

higher costs that will be incurred by utility customers. For simplicity, in calculating the 16

cost disallowances and revenue deficiency in my testimony and exhibits, I have used this 17

revenue credit approach. 18


D. MRP Capital Expenditures 1

Q. PLEASE DISCUSS THE EXTENDED MAIN REPLACEMENT PROGRAM 2

PROPOSED BY THE COMPANY. 3

A. Beginning on page 5 of her direct testimony, Company witness Katie Singer discusses the 4

Company’s Main Renewal Program (“MRP”), its history, current pace of replacement and 5

future plans. The MRP began in 2011 with a five-year term ending in 2015 and with an 6

initial objective to replace cast iron, ductile iron, and unprotected steel mains and services 7

at a replacement rate of 13 miles annually and at cost of $4.4 million.4 Combined with the 8

Company routine main replacement program, SEMCO would then replace approximately 9

21 to 22 miles of targeted mains and related facilities annually over that five-year period. 10

In 2013, the MRP was expanded to include replacement of vintage plastic pipe installed 11

prior to 1978 due to its poor material condition. In conjunction with this change, the 12

Company committed to replace 40.6 miles of metallic and vintage plastic main annually 13

both through the MRP and its routine main replacement activities. The MRP annual capital 14

spending budget was set at $8.7 million.5 15

In 2015, the MRP was extended for an additional five years from 2016 to 2020 with the 16

same target to replace 40.6 miles of mains, consisting of 14.6 miles in base routine 17

4 MPSC order in Case No. U-16191, page 3. 5 MPSC order in Case No. U-17169.


replacements and an additional 26 miles through the MRP at average annual capital 1

expenditures of $10.1 million.6 2

In this rate case, the Company is proposing to continue the MRP for an additional five 3

years by replacing 26 miles of targeted mains annually between 2021 to 2025 with a total 4

capital spending of $59.6 million over the five-year period. Exhibit A-23 (KLS-5) details 5

this information. In addition, the Company has requested approval beginning in 2021 to 6

shift funds previously dedicated to MRP-qualified mains and services in its base and 7

routine main replacement program for use to replace also non-MRP mains. The non-MRP 8

funds would go toward retiring, derating and relocating high-pressure and transmission 9

mains and other reliability projects, which the Company determines are high risk.7 10

Q. WHAT IS YOUR ASSESSMENT OF THE COMPANY’S PROPOSED EXTENDED 11

MAIN REPLACEMENT PROGRAM FOR 2021 TO 2025 AND THE INCLUSION 12

OF NON-MRP PROJECTS? 13

A. In discovery the Company was asked to provide a list of the non-MRP projects with 14

description of the projects, the related cost and risk score by year for the 2021 to 2025 15

period. In response, the Company provided a list of 184 pipeline segments with a total 16

estimated cost of $29.1 million. The range of annual replacement projects spans from 22 17

6 MPSC order in Case No. U-17824. 7 SEMCO Gas witness Singer direct testimony at page 9.


to 57 pipeline segments with capital spending ranging from $5.5 million to $6.7 million. 1

Exhibit AG-3 includes the information provided by the Company. 2

From the information provided it is not clear why these pipeline segments need to be 3

replaced and why they do not qualify as MRP projects. As stated earlier, the MRP 4

currently targets replacement of risky unprotected steel and vintage plastic mains, and 5

services. The remaining pipe in the Company’s distribution and transmission system 6

consists of coated steel and post-1977 plastic mains, and services. The Company has not 7

specifically identified any widespread problems with these mains and services. It is 8

difficult from the risk score provided in the list of projects what serious risk these pipeline 9

segments present and why. With the exception of the top 10 projects targeted for 2021, 10

which have a higher score number, the risk score for the rest of the projects is relatively 11

low. 12

Given current plans with the MRP projects, the Company will have 213 miles of eligible 13

vintage mains to replace at the end of 2020. The Company’s proposed replacement rate 14

of 26 miles per year will replace the remaining 213 miles in 8 years, assuming zero miles 15

get replaced under the base routine replacement program. This high pace of replacement 16

seems unnecessary given that the number of gas leaks in 2018 from corrosion problems 17

has declined by two-thirds from the number of leaks prior to the start of the MRP. 18

Similarly, the number of gas leaks for vintage pre-1978 plastic pipe has dropped from 59 19

in 2013 to 18 in 2018. In other words, the worst mains and services have been replaced as 20


reflected by the significant decline in the number of leaks from the eligible mains and 1

services. Exhibit AG-4 provides a detailed report of gas leaks provided by the Company 2

in response to discovery. 3

The urgency to continue the MRP at an accelerated pace has diminished in light of the 4

significant decline of gas leaks from corrosion and plastic material condition. 5

Additionally, there is no other compelling evidence or engineering studies presented by 6

the Company that the remaining mains and services are degrading at a rate alarming 7

enough to require an accelerated pace of replacement. This favorable situation offers an 8

opportunity to throttle back the level of capital spending on the MRP and continue using 9

the base program routine funding in base rates to replace eligible MRP mains and services 10

instead of dedicating that funding to non-MRP projects. 11


TO THE COMPANY’S PROPOSED SPENDING LEVEL FOR THE MRP AND 13

THE BASE MAIN AND SERVICES REPLACEMENT PROGRAM? 14

A. The Company has not made a convincing case that funding for the base and routine main 15

replacement program should be redirected to non-MRP eligible projects. The capital 16

spending of $5.5 million proposed annually for non-MRP project, if not redirected to these 17

projects, will permit the replacement of approximately 10 miles of MRP-eligible mains 18

and related facilities.8 This in turn should permit scaling down the MRP to half the pace 19

8 $5.5 million divided by $450,000 per mile of main replacement from Exhibit A-23.


of replacement proposed by the Company from 26 miles to 13 miles per year. This plan 1

would reduce the total capital requirements for the MRP over the 2021 to 2025 period from 2

$59.6 million to $29.8 million, and still permit the replacement of at least 23 miles of 3

MRP-eligible mains. The result should be full replacement of all remaining uncoated steel 4

and pre-1978 plastic mains and services in 9 years or less. 5

For any high-risk non-MRP pipeline and facilities, SEMCO Gas needs to present more 6

evidence in the next rate case of the need to replace these facilities, and provide a more 7

thorough and clearer definition of the projects, any performance problems of the facilities 8

and the risks presented by their continued operation. 9

Therefore, I recommend that the Commission reject the Company’s proposal to redirect 10

funding in the base and routine main and services replacement program to non-MRP 11

projects. I also recommend that the Commission reduce the amount of approved funding 12

for the MRP program presented in Exhibit A-23 by half to $29.8 million over the 2021 to 13

2025 period. I will discuss later in my testimony the appropriate method for developing 14

annual surcharges for the MRP over the 5-year period. 15


E. IRIP Capital Expenditures 1

Q. PLEASE DISCUSS THE INFRASTRUCTURE RELIABILITY IMPROVEMENT 2

PROGRAM PROPOSED BY THE COMPANY. 3

A. Beginning on page 15 of her direct testimony Ms. Singer discusses SEMCO Gas’s 4

proposal to initiate an Infrastructure Reliability Improvement Program (IRIP) to address 5

what the Company’s perceives as reliability risks in its gas distribution and transmission 6

system. Apparently, subsequent to the January 2019 Consumers Energy’s Ray 7

Compression Station fire and Governor Whitmer’s request to the Commission for an 8

assessment of the Michigan energy infrastructure, SEMCO Gas decided to undertake a 9

review of its own gas delivery system. 10

With the IRIP, the Company proposes five construction projects between 2021 and 2025 11

to build pipeline by-passes and regulation stations in various sections of its distribution 12

and transmission system. The projected cost for these projects is $54.5 million. 13

Q. WHAT IS YOUR ASSESSMENT OF THE COMPANY’S PROPOSED IRIP? 14

A. Ms. Singer’s testimony and Exhibit A-27 provide very few details as to how the projects 15

would solve potential gas delivery issues. In discovery, the Company was asked to provide 16

additional information about the proposed projects and how the redundant facilities would 17

achieve the desired effect of protecting against pipeline failures and gas flow interruptions. 18

Unfortunately, the responses raised even more unanswered questions about the Company’s 19


strategy to achieve redundancy at these locations. The premise put forth to justify these 1

projects could easily lead to the requirement that nearly all the single-feed elevated 2

pressure distribution lines and transmission pipelines should have a redundant by-pass to 3

protect against gas interruptions on the existing lines. 4

Although the Company should be commended for taking the initiative on this matter and 5

putting forth the proposed program, the projects outlined in the program need to be more 6

thoroughly explained and vetted against the Commission’s directives under the Michigan 7

Statewide Energy Assessment (“SEA”). On September 11, 2019, the Commission issued 8

several orders directing the Commission Staff to organize various collaborative 9

workgroups with the objective to make recommendations on required initiatives to 10

improve contingency planning and energy infrastructure resilience and reliability. 11

Specifically, in Case No. U-20631, the Commission directed Staff to commence a 12

collaborative meeting to consider issues related to mutual aid agreements and transmission 13

contingency planning. 14

Before proceeding with the Company’s proposed IRIP at a capital cost of $54.5 million, it 15

would make sense to first assess the outcome of Case No. U-20631. Subsequent to this 16

proceeding, it would also make sense for the Company to request a collaborative meeting 17

with Staff, the AG and other interested parties to review the proposed projects with more 18

in-depth analysis about the necessity of each project and the specific solution 19

recommended. Such a forum would provide the opportunity to all interest parties to fully 20


understand and hopefully support the proposed projects for the benefit of all Michigan 1

energy consumers. 2


TO THE PROPOSED IRIP? 4

A. The Company’s IRIP proposal is premature and should be integrated within the 5

Commission’s other initiatives to strengthen the resiliency and reliability of Michigan’s 6

energy infrastructure. 7

I recommend that the Commission not approve the IRIP at this time. Instead, the 8

Commission should encourage the Company to participate in the collaborative proceeding 9

in Case No. U-20631, and incorporate into its plans for the IRIP any directives from the 10

Commission subsequent to that collaborative proceeding. In addition, the Commission 11

should encourage the Company to initiate a separate collaborative meeting with Staff, the 12

AG and other interested parties subsequent to a Commission order in U-20631 to provide 13

a better understanding and obtain support for the proposed IRIP projects. 14

Later in my testimony, I will discuss required changes to the IRIP surcharge if the 15

Commission decides to approved the proposed IRIP. 16

F. Valve Replacement Program 17

Q. PLEASE DISCUSS THE COMPANY’S PROPOSAL TO AMORTIZE THE COSTS 18

FOR THE SERVICE VALVE REPLACEMENT PROGRAM. 19


A. On page 11 and 12 of her direct testimony, Ms. Singer describes the work performed by 1

the Company to replace more than 50,000 defective service valves over the past 12 years. 2

In response to discovery, the Company provided additional information showing that it 3

began incurring costs for this program in 2007 with the bulk of the expenditures occurring 4

after 2010 and continuing into 2018. In total the Company has spent $4,881,117 to replace 5

the defective valves and deferred those costs for recovery beginning with this rate case. 6

Included in the $4.9 million is approximately $225,000 pertaining to litigation and 7

investigative services. Exhibit AG-5 includes the Company’s discovery responses 8

showing this information. 9

On page 2 and 3 of her testimony, Company witness Tracy Vincent proposes to amortize 10

these costs over a three-year period beginning with the projected test year at an amount of 11

$1,627,039. In her brief testimony on this matter, Ms. Vincent does not explain why the 12

Company has chosen a three-year amortization period. In discovery, the Company was 13

asked to explain why an amortization period of three years is appropriate for the replaced 14

valves. In its response to discovery request 2-AG-SEMCO-113, which is included in 15

Exhibit AG-5, the Company stated that a 3-year amortization is justified because it has 16

incurred these costs over a 12-year period with no compensation. In addition, the response 17

states that the Company would have expensed those costs instead of capitalizing them as 18

plant-in-service if the cost would not have been deferred from later recovery. 19

The response does not adequately justify the future amortization of these costs. Although 20

the costs were incurred over the past 12 years and were deferred for future recovery, it 21


does not mean that a 3-year future recovery period is justified. The fact that the Company 1

would have expensed those costs as O&M expense is also not pertinent here, because the 2

costs have been deferred and will need to be amortized over future years akin to 3

depreciation expense. 4

To properly justify an appropriate recovery period, we need to assess the remaining 5

depreciable life of the assets. Shut-off valves are installed as part of the meter riser when 6

the service line is installed at the customer service location. According to Exhibit A-29 7

(TLV-1), line 26, the depreciation rate for plastic service lines is 2.83%. This equates to 8

a depreciable life of 35 years. The replacement shut-off valves have a similar depreciable 9

life. Given that the Company installed the replacement valves over an average period of 10

6 years (12 years/2), the average remaining depreciable life of the newly installed 11

replacement valves is 29 years (35-6). Therefore, the annual amortization amount to be 12

included in the projected test year is $168,314 and not $1,627,039.9 The difference of 13

$1,458,725 should be removed from the Company’s projected amortization expense in test 14

year. 15

Q. WHAT IS YOUR RECOMMENDATION? 16

A. I recommend that the Commission reject the Company’s proposed amortization period of 17

3 years for the Valve Replacement Program deferred costs and instead adopt a 29-year 18

amortization period based on the depreciable life of these assets. I recommend that the 19

9 $4,881,117 divided by 29 years = $168,314.


Commission reduce the Company’s forecast amortization expense for this item by 1

$1,458,725 for the projected test year. 2

IV. Working Capital Adjustments 3

Q. PLEASE IDENTIFY THE ADJUSTMENTS YOU PROPOSE TO MAKE TO THE 4

WORKING CAPITAL BALANCE PROPOSED BY THE COMPANY FOR THE 5

PROJECTED TEST YEAR. 6

A. The Company has forecasted a working capital balance of $49,960,181 for the projected 7

test year. I propose to make two adjustments to this balance. The first adjustment is to 8

reduce the value of gas inventory for gas in storage during the 13 months ending December 9

2020, and the second adjustment is to reduce the deferred account balance for the 10

amortization expense in the test year pertaining to the deferred costs for the valve 11

replacement program. 12

Q. PLEASE DISCUSS THE GAS INVENTORY ADJUSTMENT. 13

A. In Exhibit A-12 (BHF-28), Schedule B-4, column (d), the Company shows an adjustment 14

to increase Gas Stored Underground and total working capital between 2018 and 2020 by 15

$4,449,240. The Company provides the calculation of this adjustment in Exhibit A-41 16

(WEF-11)10. The adjustment consists of an increase in the volume of gas inventory stored 17

underground from 2018, and also from the change in value from 2018 to the projected test 18

10 Exhibit A-12, B-4, line 8, references Exhibit A-40. It should be Exhibit A-41.


year. In its analysis, the Company calculated the value of the inventory gas based on the 1

forecasted price of gas for the projected 13 months as of the first week of March 2019. 2

In discovery, the Company was asked to update the forecasted cost of gas and value of the 3

gas stored underground as of a more recent date during the first week of August 2019. In 4

response to this request, the Company provided a revised forecasted value for the inventory 5

gas of $24,448,030. Exhibit AG-6 includes the information provided by the Company 6

supporting the revised amount. This updated value is $5,004,342 lower than the amount 7

of $29,452,373 calculated in Exhibit A-41. 8

The $24,448,030 represents a more recent cost estimate that reflects NYMEX future prices 9

during August 1-7, 2019 for the December 2019 to December 2020 period. NYMEX 10

future prices typically reflect a price premium that take into consideration the uncertainty 11

and volatility of future prices. That premium typically declines as future prices get closer 12

to current prices. It is also noteworthy to point out that the Commission Staff similarly 13

requested updates to the forecasted cost of gas rate and the value of inventory gas on two 14

separate occasions. The first request was for a cost update with NYMEX future prices as 15

of the first week of June 2019. That request produced an inventory value of approximately 16

$25.6 million.11 The second request was for a cost update with NYMEX future prices as 17

July 22-26, 2019. That request resulted in a forecasted gas inventory value of $25.1 18

11 SEMCO response to Staff Audit request NBO-01.


million. This latest value is approximately $700,000 different than the updated cost the 1

Company provided in response to the AG’s request.12 2

My conclusion is that the $24,448,030 gas inventory value for the project test year is 3

reasonable. Therefore, I recommend that the Company’s project working capital balance 4

should be reduced by $5,004,342. 5

Q. PLEASE DISCUSS THE WORKING CAPITAL ADJUSTMENT FOR THE 6

AMORTIZATION OF DEFERRED COSTS FOR THE VALVE REPLACEMENT 7

PROGRAM. 8

A. After reviewing Exhibit A-12 (BHF-28), Schedule B-4, it is apparent that the Company 9

did not reduce the projected balance for Other Deferred Charges on line 17 for the 2020 10

projected test year for the proposed amortization of $1,627,039 for the valve replacement 11

program discussed earlier. The balance should have been reduced down to $74,356,153. 12

However, as a result of my proposal to amortize the deferred balance of $4,881,117 over 13

29 years, the amortization amount for the projected test year is only $168,314. I propose 14

that this amount be reflected as a reduction in the working capital balance for the projected 15

2020 test year. 16

12 SEMCO response to Staff Audit request NBO-05.


Therefore, in total, I recommend that the Commission reduce the Company’s projected 1

working capital balance for the 2020 test year by $5,172,656. 2

V. Cost of Capital 3

Q. WHAT IS THE CAPITAL STRUCTURE YOU RECOMMEND FOR USE IN THE 4

OVERALL RATE OF RETURN CALCULATION? 5

A. I am recommending that the capital structure shown on page 1 of Exhibit AG-7 be used in 6

this case. Lines 1 and 3 show the projected long-term debt and common equity permanent 7

capital of the Company for the test period ending December 2020. The permanent capital 8

balances in this exhibit reflect 50% common equity and 50% long-term debt. 9

It is worth noting that the Company’s presentation of its permanent capital structure on 10

Exhibit A-14, Schedule D1, includes 61% common equity and 39% long-term debt. The 11

common equity component of this capital structure presented by the Company is excessive 12

and too costly to customers. Also, the Company’s presentation includes no short-term 13

debt typically used to fund seasonal working capital. These items will be discussed further 14

later in this section of my testimony. 15

Q. WHY DID YOU INCREASE LONG TERM DEBT AND REDUCE THE COMMON 16

EQUITY BALANCE ADVOCATED BY THE COMPANY? 17

A. A capital structure with 61% common equity and no short-term debt is unnecessarily 18

expensive for the Company’s gas customers. My analysis of the peer group of companies 19


shown in Exhibit AG-12 has determined that the percentage of common equity to 1

permanent capitalization averages approximately 51%. 2

It is worth pointing out that the peer group average common equity ratio of 51% reflects a 3

combined capital structure of the peer companies’ utility operations, as well as their non-4

utility operations which tend to be somewhat riskier. The percentage of non-utility 5

operations for the peer companies is shown in column (e) of Exhibit AG-12. The riskier 6

non-utility operations require a higher common equity cushion to maintain similar credit 7

ratings. Therefore, if we adjusted for the higher equity capital required by the non-utility 8

businesses, the equity capital for the utility portion of the peer group’s capital structure 9

would be lower than 50%. 10

Furthermore, the Commission has made it clear that moving toward a 50%/50% balanced 11

capital structure is appropriate for Michigan utility companies in the absence of compelling 12

evidence to the contrary. 13

In search of a compelling reason, in discovery, the Company was asked if the rating 14

agencies had notified the Company of the need to maintain a certain capitalization level or 15

financial metrics in order to keep an investment grade rating for its debt securities. In 16

response. the Company stated that it had received no such notifications.13 17

13 SEMCO response to discovery request 1-AG-SEMCO-19.


It is also important to point out that SEMCO Gas is a division within SEMCO Inc, which 1

is captive subsidiary of AltaGas. AltaGas can make the Company’s common equity ratio 2

whatever it wants. The same executive management that runs AltaGas controls the 3

Company’s major decisions. Management can direct the Company to retain earnings and 4

not pay large dividends in order to increase the common equity balance. Management can 5

also control how much equity capital it wants to inject into the Company from the parent 6

company by issuing debt and call it equity capital. 7

In fact, page 3 of Exhibit A-1, Schedule A-2, shows that common equity ratios of the 8

Company increased from the low 50% range in 2014 to nearly 60% in 2017, and then 9

dropped to 55% at year-end 2018. Additionally, I will point out that the parent company, 10

AltaGas, is far more leveraged than SEMCO Gas. AltaGas’ average common equity over 11

the four quarters ended June 2019 is approximates 36% reflecting its aggressive use of 12

debt capital. 13

Q. YOU STATED THAT THE COMMON EQUITY RATIO OF THE PEER GROUP 14

USED TO ASSESS THE COST OF COMMON EQUITY IS SLIGHTLY ABOVE 15

51%. PLEASE EXPLAIN WHY THIS IS RELEVANT IN DETERMINING THE 16

COMMON EQUITY RATIO FOR THE COMPANY IN THIS CASE. 17

A. As shown in Exhibit AG-10, the average common equity ratio of the peer company group 18

over the 12 months ending June 2019 was 51.2%. The cost of equity for those companies 19

in the peer group is highly dependent on the financial risk reflected in their capital 20


structure. Thus, it is critical to synchronize the capital structure of the Company to the 1

peer group average as closely as possible in order to have consistency with the cost of 2

equity capital derived from those peer group companies. The Company’s proposed 3

common equity capital ratio of 61.0% creates a significant disconnect that is not acceptable 4

and is also more costly to customers. 5

Q. HOW DOES THE COMPANY ATTEMPT TO SUPPORT THE 61% COMMON 6

EQUITY LEVEL PROPOSED IN ITS RATE CASE? 7

A. There is no direct support for the 61.03% proposed equity ratio in the testimony and 8

exhibits of the Company’s witness. Company witness Robert Hevert presented an analysis 9

of common equity ratios of his peer group over the eight quarters ending December 2018 10

in Exhibit A-61 (RBH-9). This exhibit shows an average common equity ratio of 54.82% 11

not 61%. A more in-depth analysis shows that the average common equity ratio has been 12

progressively declining quarter by quarter from 57.75% in the first quarter of 2017 to 13

52.46% by the end of the fourth quarter of December 2018. The results are also skewed 14

by the inclusion of an extremely small utility with a common equity ratio of up to 75.61% 15

over this same time frame. 16

Q. DID YOU CALCULATE THE DIFFERENCE IN REVENUE REQUIREMENT OF 17

INCREASING THE COMMON EQUITY RATIO FROM 50% TO 61%? 18

A. Yes. If the Commission were to adopt a 61% common equity level in this case, revenue 19

requirements would be higher by approximately $6.2 million. This reflects the Company’s 20


rate base of approximately $725 million and the difference between its pretax cost of 1

common equity of 14% versus the pretax cost of long-term debt of approximately 4.9%. 2

The $6.2 million represents approximately 16% of the $38.1 million the Company has 3

requested in total rate increase in this rate case. 4

Q. DID YOU MAKE ANY OTHER ADJUSTMENTS TO OTHER ITEMS INCLUDED 5

IN THE COMPANY’S PROPOSED CAPITAL STRUCTURE? 6

A. Yes. I have included $18.4 million of seasonal short-term debt which represents 7

approximately 2.5% of the total capital structure. This is consistent with many of the peer 8

group companies who use short-term debt to finance working capital. Financing short 9

term working capital needs with short term debt is a common practice in the gas utility 10

industry. The calculations to arrive at the $18.4 million of short-term debt are shown on 11

page 3 of Exhibit AG-7. 12

Q. WHAT RETURN ON EQUITY AND OVERALL RETURN ON CAPITAL ARE 13

YOU RECOMMENDING IN THIS CASE? 14

A. I am recommending an overall return on capital of 5.66% which includes a return on 15

common equity of 9.50%, as shown in Exhibit AG-7. 16

Q. WHAT COST RATE DID YOU USE FOR LONG TERM DEBT? 17

A. I used a 4.02% cost rate. This rate is determined on page 2 of Exhibit AG-7 and is based 18

upon not only the Company’s currently outstanding debt, but also on the new long-term 19


debt needed to replace debt maturing in April 2020, and other debt that would be included 1

to properly balance the capital structure. 2

Q. WHAT RATE DID YOU USE FOR THE FINANCING OF NEW LONG-TERM 3

DEBT? 4

A. I have utilized a 4.25% interest rate assuming the issuance of new 30-year debt. This rate 5

assumes a 3.1% rate on 30-year U.S. Treasury bonds in 2020 which is based on the 6

projection from the June 1, 2019 Blue Chip Financial Forecast supplied by the Company.14 7

To this rate, I added 110 basis points which reflects the historical spread from 2016 to 8

2018 of new A-rated bond issues plus 5 basis points for financing expenses. 9

Q. WHY HAVE YOU UTILIZED A SPREAD FOR “A” RATED BOND ISSUES 10

INSTEAD OF RELYING ON THE CURRENT CREDIT RATING OF THE 11

COMPANY? 12

A. In December 2018, S&P downgraded SEMCO Energy’s Senior Secured debt from A- to 13

BBB+. According to S&P this action was taken in tandem with its downgrade of 14

SEMCO’s parent AltaGas which is restructuring to pay down debt taken on to purchase 15

WGL Holdings (parent of Washington Gas Light). 16

14 SEMCO Gas discovery response 1-AG-1-SEMCO-14.


Moody’s affirmed SEMCO Energy’s ratings in January 2019 assigning an issuer rating of 1

Baa1 but assigning an A2 rating to the Senior Secured debt of SEMCO. 2

Although SEMCO Energy Gas may experience higher debt costs than I have included due 3

to events at AltaGas, Michigan customers should not pay such higher costs due to the 4

financial issues faced by its parent company. 5

Q. WHAT COST RATE DID YOU UTILIZE FOR SHORT TERM DEBT AND THE 6

OTHER COMPONENTS OF THE CAPITAL STRUCTURE? 7

A. For Short Term Debt, I have used a 4.0%% rate which is the average rate paid by the 8

Company in the November and December 2018 period. For Deferred Taxes, I have 9

utilized the balances recommended by Company witness Fairchild at zero cost. 10

Q. PLEASE EXPLAIN THE DEVELOPMENT OF THE OVERALL COST OF 11

CAPITAL ON PAGE 1 OF EXHIBIT AG-7. 12

A. To develop the overall cost of capital on line 12, column (f), I have first developed the 13

percentage weighting of each capital component in column (d) by dividing the individual 14

capital balances in column (b) by the total of all capital components in that column. Next, 15

I have multiplied the weightings in column (d) by the cost rates in column (e) to arrive at 16

the values in column (f). The total of the individual values in column (f) is the total cost 17

of capital of 5.66%. 18


Regarding the pretax weighted cost of capital on line 12, column (h), I have multiplied 1

each cost component in column (f) by the conversion factors in column (g). These 2

conversion factors are included to reflect the impact of income and other taxes paid by the 3

Company for calculation of the pretax weighted cost of 7.01% in column (h). 4

Q. WHAT GENERAL PRINCIPALS HAVE YOU CONSIDERED IN DETERMINING 5

THE COST OF COMMON EQUITY FOR THE COMPANY? 6

A. A utility company is entitled to a fair return that will allow it to attract capital and be 7

sufficient to assure investors of its financial soundness. In its opinion in Bluefield Water 8

Works and Improvement Company v Public Service Commission of West Virginia (the 9

“Bluefield Case”) 262 U.S. 679 (1923), the United States Supreme Court indicated that: 10

”A public utility is entitled to such rates as will permit it to earn a return on the value 11 of the property which it employs for the convenience of the public equal to that being 12 made at the same time…on investments in other business undertakings which are 13 attended by corresponding risks and uncertainties; but it has no constitutional right 14 to profits such as are realized or anticipated in highly profitable enterprises or 15 speculative ventures. The return should be reasonably sufficient to assure 16 confidence in the financial soundness of the utility and should be adequate, under 17 efficient and economical management, to maintain and support its credit and enable 18 it to raise the money necessary for the proper discharge of its public duties…” 19

The principals of the Bluefield Case were re-affirmed by the U.S. Supreme Court in 1944 20

in the case FPC v Hope Natural Gas Company, 320 U.S. 591. 21

Q. PLEASE EXPLAIN THE DEVELOPMENT OF THE COST OF COMMON 22

EQUITY IN EXHIBIT AG-8. 23


A. Determining the cost of common equity for an enterprise or an industry group is inexact 1

since investors can only estimate what the future cash flows from any enterprise may be 2

over time. Because of this uncertainty, most financial experts will not rely solely on any 3

one particular method. To determine the cost of common equity, I have utilized three 4

approaches to determine this cost. These are the Discounted Cash Flow (DCF) Method, 5

the Capital Asset Pricing Model (CAPM) and a Utility Risk Premium approach. These 6

methodologies have previously been accepted by the Commission and have been generally 7

accepted by regulatory commissions in other jurisdictions in the United States. Also, I 8

have considered the current circumstances in the Capital Markets and any potential 9

changes in the risk profile of SEMCO Gas and the state of the Michigan economy. While 10

Exhibit AG-8 shows a calculated cost of common equity of 8.64%, from the three 11

approaches, I recommend an allowed rate of return on equity of 9.50% for the reasons 12

explained later in this section of my testimony. In connection with these methods for 13

determining the cost of common equity, I have considered the cost of common equity for 14

a proxy group of peer companies. 15

Q. PLEASE EXPLAIN THE DEVELOPMENT OF YOUR PROXY GROUP OF PEER 16

COMPANIES? 17

A. To develop my peer group, I started with the gas utility companies followed by the Value 18

Line Investment Survey in its “Natural Gas Utility Industry” section. I eliminated two 19

companies for of the following reasons. The companies that I eliminated are (1) UGI 20

Corporation due to its foreign investments and propane investments, which is 50% of its 21


business; and (2) Chesapeake Utilities which has revenues of approximately $700 million 1

in 2018 and because of its concentration in non-regulated businesses, which according to 2

Value Line is 55% of their business. Moreover, it has approximately 158,000 gas 3

customers and is far smaller than SEMCO Gas. Chesapeake also has more than doubled 4

its non-regulated business over the 2016 to 2018 period. 5

These two companies clearly are not comparable utilities for inclusion in a peer group. 6

After eliminating these two companies, the result is the group of eight companies shown 7

in Exhibit AG-9, all of which have growing earnings and dividends. 8

Q. HOW DOES YOUR PEER GROUP OF EIGHT COMPANIES COMPARE TO 9

THE COMPANY’S PEER GROUP? 10

A. The Company’s peer group presented by witness Robert Hevert also consists of a group 11

of 8 companies. 12

Q. DO YOU BELIEVE THAT THE COMPANY’S PEER GROUP IS 13

APPROPRIATE? 14

A. No. Witness Hevert set a standard that all companies in the peer group have ratings from 15

S&P. Then he includes Chesapeake Utilities in violation of this standard. Also, as stated 16

earlier according to Value Line, 55% of the company’s business is non-regulated. The 17

relatively small size of the company’s utility operations and its significant non-utility 18

operations make it a poor fit. 19


Q. WHAT IS YOUR RECOMMENDATION TO THE COMMISSION REGARDING 1

THE COMPANY’S PEER GROUP? 2

A. The Commission should reject the Company’s peer group for the reasons noted above. 3

Discounted Cash Flow (DCF) Approach 4

Q. PLEASE DESCRIBE THE DISCOUNTED CASH FLOW (“DCF”) APPROACH. 5

A. The DCF approach is based on the proposition that the price of any security reflects the 6

present value of all future cash flows (dividend flows) from the security discounted at a 7

single discount rate, which in the case of common stocks, is the required return of equity. 8

Expressed mathematically, the resulting equation can be reconfigured to solve for the 9

required rate of return and this equation is: 10

R = D/P + g 11

where “R” = the Required Equity Return 12

“D/P” = the Dividend Yield on the Security 13

and “g” = the expected growth rate in dividends 14

Generally, the “D” or dividend is known, and the “P” or stock price is also known as the 15

stock trades each day. Also, recent growth in the dividend is known or estimates of growth 16

furnished by stock analysts can be relied upon with some degree of certainty. With this 17

information, one can solve for “R” which is the required rate of return. 18

Q. PLEASE EXPLAIN THE RESULTS OF YOUR DCF ANALYSIS. 19


A. The results of my DCF analysis are summarized in Exhibit AG-9. The stock price 1

information in column (c) on this exhibit reflects the average of the high and low prices 2

for each of these equity securities on each of the 30 trading days from July 24, 2019 to 3

September 4, 2019. The annual dividend in column (d) is the projected dividend level for 4

2020 as projected by the Value Line Investment Survey. Column (h) shows the average 5

long-term earnings growth rate based on Value Line projections of earnings per share 6

through the year 2023 and Yahoo Finance analysts’ projected growth in earnings per share 7

over the next five years. The resulting calculation of the DCF Method indicates an average 8

required return on common equity of 9.29% for the proxy group. 9

Company witness Hevert shows his DCF results in Exhibit A-53 pages 1, 2 and 3, which 10

utilize average stock prices over 30 days, 90 days and 180 days. Using the stock prices 11

three months and 6 months prior has increased the DCF ROE results due to lower stock 12

prices during those prior periods. His 30-day results show a ROE range of 7.3% to 13.3% 13

with an average ROE of 9.64%, which is 35 basis points higher than my results. 14

Witness Hevert’s analysis was completed earlier in 2019 and some of the growth estimates 15

are slightly different than what I used. Moreover, since his results were completed earlier 16

in 2019, the stock prices and some of his other data are now stale. 17

Q. PLEASE ASSESS THE RESULTS OF THE DCF ANALYSIS YOU PERFORMED. 18

A. The DCF analysis relies upon financial market information for the dividend yield portion 19

of the equation. However, it also relies upon judgments of growth prospects of security 20


analysts which may or may not be consistent with the beliefs of investors. I will point out 1

that the forecasted growth rates for the proxy group include some very high growth rates 2

which in some cases are as high as 9.73%. These high growth rates appear to be the result 3

of a temporary rebound in earnings from a low point in recent years and the higher growth 4

and risk of non-utility businesses. While these earnings may materialize in the short term, 5

such high rates are not sustainable long-term growth rates for gas utilities given that 6

customer and revenue growth continue to be barely in low single digits. As such, the results 7

of the DCF analysis in some cases reflect a return on equity rate that is somewhat higher 8

than what investors currently expect in the long term. Nevertheless, I place a fairly high 9

degree of reliability in the DCF results when considered in conjunction with the results of 10

other approaches to determining the cost of common equity. 11

Capital Asset Pricing Model Approach 12

Q. PLEASE EXPLAIN THE CAPITAL ASSET PRICING MODEL APPROACH TO 13

DETERMINING THE COST OF COMMON EQUITY CAPITAL. 14

A. The Capital Asset Pricing Model (“CAPM”) is based on the proposition that the expected 15

return on a common equity security is a function of risk as measured by the “Beta” of that 16

security. In equation form, CAPM is as follows: 17

ke = Rf+ (B x Rp) where 18

ke = The market cost of common equity for a specific security 19

Rf = the “risk free” rate of return 20


Rp = the overall return of the market less the risk free rate (over several years) 1

B = the systematic risk of a particular common equity security vs. the market 2

Q. PLEASE EXPLAIN THE BETA OR “B” COMPONENT OF THE EQUATION. 3

A. This measure of risk reflects the extent to which the price of a particular security varies in 4

relationship to the movement of the overall market. Some securities vary less in price over 5

time than the overall market. In these cases, the Beta will be less than 1.00. Securities 6

that vary over time more than the overall market will have a Beta that is greater than 1.00. 7

Q. PLEASE EXPLAIN EXHIBIT AG-10 SHOWING THE RESULTS OF THE CAPM 8

APPROACH. 9

A. Exhibit AG-10 shows the results of the CAPM method based upon (1) a projected 3.10% 10

risk free rate as explained below; (2) Beta information available from Value Line; and (3) 11

Historical Market Risk Premium (Rp) information of 6.91% based on the Ibbotson Classic 12

Yearbook. 13

Normally, I would use a historical risk-free rate (the current yield on 30-year treasury 14

bonds) which as of early September 2019 ranged from 2.0% to 2.25% due to fears of an 15

upcoming economic downturn. However, sentiment in the market is that U. S. Treasury 16

rates will strengthen in future years. In this regard, interest rate projections from the Blue 17

Chip Financial Forecast dated June 1, 2019 show that the U. S. Treasury Bond rate will 18

increase to 3.1% in 2020. 19


As shown in Exhibit AG-10, I have added the Beta-adjusted peer group risk premium of 1

4.53% to the 3.10% risk-free rate to arrive at the 7.63% ROE rate under the CAPM 2

approach. The peer group risk premium is the result of multiplying the average beta for 3

the peer group of 0.66 times the historic risk premium of the market which is 6.91%. 4

Q. PLEASE COMMENT ON WITNESS HEVERT’S CALCULATIONS OF CAPM 5

COMMON EQUITY COST RATES RANGING FROM 9.2% TO 12.6%. 6

A. Witness Hevert summarizes his CAPM and ECAPM analysis on his Exhibit A-57 (RBH-7

5) and derives his results from the use of market risk premiums of 10.61% and 13.72% 8

(nearly twice the historic risk premium of 6.91%). These higher risk premiums are derived 9

by using an unconventional approach of the DCF analysis of the S&P 500 based on 10

projected data available from Bloomberg and Value Line which looks at earnings over a 11

five-year period and based upon this data he develops his risk premium information. 12

Analysts typically make short term projections based upon a limited number of years and 13

assume continued economic expansion as a driver of earnings and value. They don’t make 14

long-term projections that include a complete cycle of economic expansion and 15

contraction, which is what occurs over the long-term. 16

This would be akin to only selecting the positive return years in the Ibbotson series over 17

the 90-year period and not the losses in the downturn years. Expectedly and incorrectly, 18

we would derive a far higher overall return for the market and a far higher market risk 19

premium, similarly to what Mr. Hevert has proposed. 20


Utilizing a long-term historic period with several up and down economic cycles to 1

determine the market risk premium (“MRP”) is far more appropriate than utilizing a short-2

term projection of MRP. 3

Q. IS THERE ANY ACADEMIC SUPPORT FOR THE USE OF LONGER PERIODS 4

FOR THE DEVELOPMENT OF MRP RATES? 5

A. Yes. Dr. Roger Morin, in his book “New Regulatory Finance”, favors the use of the 6

longest possible period for calculation a risk premium. On page 114 of his book, Dr. Morin 7

makes the following point. 8

“Therefore, an historical risk premium study should consider the longest possible period 9 for which data are available. Short-run periods during which investors earn a lower risk 10 premium than they expect are offset by short-run periods during which investors earn a 11 higher risk premium that they expect. Only over long time periods will investor return 12 expectations and realizations converge. Clearly, the accuracy of the realized risk 13 premium as an estimator of the prospective risk premium is enhanced by increasing the 14 number of years used to estimate in….” 15

Accordingly, the use of data over a short time period, whether historical or projected, is to 16

be avoided in the development of a risk premium estimate. 17

Q. PLEASE COMMENT ON WITNESS HEVERT’S ECAPM ESTIMATES? 18

A. Witness Hevert’s ECAPM estimates build off his CAPM estimates. Therefore, his results 19

are corrupted by the same MRP development problems outlined above. The basic 20

justification for the ECAPM is the theory that Value Line betas tend to under-predict stock 21


market returns for lower beta stocks (such as utilities) as explained on page 24 (lines 16-1

21) of witness Hevert’s testimony. 2

Accordingly, witness Hevert recommends that a further upward adjustment to the CAPM 3

results should be considered by the Commission under the ECAPM method. He proposes 4

adding an additional 1.1% to his CAPM results and produces a range of results of 10.26% 5

to 13.75% under his ECAPM. This adjustment is subjective, unconventional, and not 6

supported. The approach relies upon the same future estimate of S&P 500 results over the 7

short term discussed earlier. 8

There is not wide acceptability of the ECAPM among state regulatory commission that 9

regulate gas and electric utilities in the United States. One of the few regulatory 10

commissions that has spoken to the subject of ECAPM is the Alberta Utilities Commission 11

of Canada and its order of October 7, 2016. That regulatory commission noted on page 12

45, paragraph 199 of the order that the ECAPM “…appears to be a model that could 13

contribute to the Commission’s determination of a fair allowed ROE…” However, later 14

in the same paragraph, the commission noted the high degree of judgment required by the 15

ECAPM methodology and the Alberta Commission added this statement: “Consequently, 16

the Commission will not rely heavily on the ECAPM results in this proceeding…” 17

(Emphasis added). 18

While witness Hevert’s various methods used to calculate the cost of equity capital are 19

inventive, they are highly unconventional and not generally accepted. The Commission 20


should reject these alternative approaches for the reasons previously discussed, which are 1

clearly an attempt to inflate the Company’s true cost of common equity. 2

Q. PLEASE ASSESS THE CAPM APPROACH. 3

A. I believe that CAPM has value in assessing the relative risk of different stocks or portfolios 4

of stocks. As such, it can be useful. However, the key issue with CAPM is that is assumes 5

that the entire risk of a stock can be measured by the “Beta” component and as such the 6

only risk an investor faces is created by fluctuations in the overall market. In actuality, 7

investors take into consideration company-specific factors in assessing the risk of each 8

particular security. As such, I give the CAPM approach less weight than the DCF approach 9

in determining the cost of common equity. 10

Utility Risk Premium Approach 11

Q. PLEASE EXPLAIN THE UTILITY RISK PREMIUM APPROACH OF 12

ESTIMATING THE COST OF COMMON EQUITY. 13

A. In general, one can estimate the cost of common equity by estimating three components 14

and adding them together. The three components are (1) the risk-free rate of return on 30-15

year U. S. Treasury Bonds; (2) the historical differential between yields of the rated utility 16

bonds of the Company and the 30-year U.S. Treasury Bonds (risk-free rate); and (3) the 17

average return differential of utility common stocks over utility bonds. 18

Q. PLEASE EXPLAIN YOUR UTILITY RISK PREMIUM ANALYSIS RESULTS. 19


A. Exhibit AG-11 shows the three components required to estimate the cost of common equity 1

under this approach. The results for this approach reflect a return on common equity of 2

8.35%. To arrive at this result, I have used a 4.00% historical spread of gas utility common 3

stock returns relative to utility bonds. This spread is the average of utility common equity 4

returns from the period 1955 through 2018 over the rates that could be earned on utility 5

bonds. Also, I have used a 1.25% (A-rated/BBB-rated) average spread for utility bonds 6

over the U.S. Government bond risk-free rate. The use of the 1.25% spread plus the risk-7

free rate approximates the average bond rates for new issues today assuming bonds rated 8

A/BBB. For the risk-free rate, I used the projected 30-year Treasury rate of 3.10% 9

discussed under the CAPM section of my testimony. 10

Q. DOES THE COMPANY PRESENT A UTILITY RISK PREMIUM ANALYSIS? 11

A. No, not on a traditional basis of looking at utility returns compared to utility bonds. 12

Q. WHAT IS THE BOND YIELD PLUS RISK PREMIUM APPROACH PRESENTED 13

BY WITNESS HEVERT ON PAGE 25 OF HIS TESTIMONY WHICH IS 14

SUPPORTED BY HIS EXHIBIT A-58? 15

A. In Exhibit A-58, Mr. Hevert compares the ROE rates assigned by regulators to 30-year 16

U.S. Bond rates. He provides just ten lines of testimony on page 25 discussing his Bond 17

Yield Plus Risk Premium approach. He provides no details in these ten lines of testimony 18

regarding how he conducted his analysis in Exhibit A-58 and then provides his summary 19

results from his exhibit at the bottom of the table on page 26 of his testimony. A review 20


of this Exhibit A-58 shows that Mr. Hevert is simply comparing (a) ROEs assigned in rate 1

cases in the 40-year period from 1980 to 2019 to (b) 30 Year U.S. Treasury rates in effect 2

during the six months immediately prior to each rate case ROE being assigned, and (c) the 3

difference between these two rates becomes his so-called risk premium. The data shown 4

on pages 2 through 23 of the exhibit shows U.S. Treasury bond yields falling by over 600 5

basis points during this 40 year period, but ROEs falling far less and the results of this data 6

are included in a regression analysis with the results shown on page 1 of 23 of the exhibit. 7

What is troubling about this analysis is that it lacks any comparison to actual utility returns 8

achieved (dividends plus price appreciation) and suggests that the 30-year U.S. Treasury 9

bond yield is the primary driver in ROE decisions by regulators. This analysis has no 10

validity as a tool to determine the ROE to be established in rate proceedings. Regulators 11

approach the serious business of establishing a ROE based on many factors and often 12

exercise “gradualism” in the process as well. The Commission should give this analysis 13

no weight in this case. 14

Q. HOW HAS THE ECONOMIC AND INTEREST RATE ENVIRONMENT 15

CHANGED IN RECENT YEARS FOR THE COMPANY? 16

A. The Michigan economy has substantially recovered from the most recent recession and 17

interest rates are stable at lower levels thanks in part to the monetary policy of the Federal 18

Reserve Bank. These factors have placed the Company in a better position with respect to 19

sales levels, interest rates and uncollectible sales amounts. The Company’s debt ratings 20


are dependent in part on the success of its parent AltaGas. However, the Company is an 1

investment rated company and access to the capital markets should be adequate based on 2

the current economic and business environment. 3

Accordingly, the Company’s recommendation that the authorized rate of return on 4

common equity should be increased to 10.50% is unsupportable. It is largely based on 5

unconventional methodologies applied to the CAPM cost of equity calculation and the 6

Utility Risk Premium analysis. They both produce ROE rates that are not valid. On the 7

other hand, my approach to calculating the true cost of common equity uses conventional 8

and widely accepted methodologies. My approach results in a cost of equity for SEMCO 9

Gas of approximately 8.6%. As discussed later in my testimony, I have increased this true 10

cost of equity by 90 basis points to arrive at a recommended ROE rate of 9.5% for this rate 11

case. 12

Q. COMPANY WITNESS HEVERT ON PAGES 27 AND 28 OF HIS DIRECT 13

TESTIMONY DISCUSSES SMALLER SIZE FIRMS AS RISKIER AND THAT 14

SEMCO GAS, BECAUSE OF ITS SMALLER SIZE, FACES HIGHER RISK. DO 15

YOU AGREE WITH HIS COMMENTS? 16

A. In general, smaller non-utility companies are likely to face higher business and financial 17

risks as witness Hevert explains. However, SEMCO’s circumstances largely mitigate 18

these higher risks noted by Mr. Hevert of “…(i) liquidity risk (i.e. the risk of not being 19


able to sell one’s shares in a timely manner due to the relatively thin market for the 1

securities; and (ii) fundamental business risk…” 2

In discovery, Mr. Hevert was asked if he agreed that liquidity risk was a non-factor for 3

SEMCO Gas due to its ownership by AltaGas, which is a far larger company. In his 4

response, he stated that his comments regarding liquidity were “…related to smaller 5

companies in general and…not necessarily specific to SEMCO Gas…”15 6

With regard to “fundamental business risk”, I am sure that the Commission recognizes the 7

fact that utilities, such as SEMCO Gas, which are subject to regulation are in a different 8

risk category than small non-utility companies. Because of their monopolistic position 9

and the opportunity to request rate increases within a short period of time when business 10

circumstances change, regulated utilities can largely mitigate their “business risk”. 11

Therefore, Mr. Hevert’s premise that smaller utilities should receive above average 12

authorized returns on equity and a common equity ratio in excess of 61% of the permanent 13

capital structure in misplaced and unsupported. 14

Q. PLEASE DISCUSS WHAT RETURN ON EQUITY RATES OTHER 15

REGULATORY COMMISSIONS HAVE GRANTED IN RECENT YEARS? 16

15 SEMCO Gas discovery response 1-AG-SEMCO-12.


A. Since 1990, return on gas utility ROE rates, granted by regulatory commissions in the U.S., 1

have been in a steady decline from over 12.7% in 1990 to approximately 9.7% in 2017, 2

and 9.6% in both 2018 and through June 2019. 3

Pages 1, 2 and 3 of Exhibit AG-14 shows the more recent ROE rates granted by state 4

regulatory commissions for gas utilities during 2018 and 2019, and published by 5

Regulatory Research Associates, a respected and independent regulatory research firm. 6

More than 80% of the gas decisions rendered involved ROE rates averaging approximately 7

9.5% during this eighteen-month timeframe. 8

Page 1 of Exhibit AG-14 shows that there were five ROE decisions for gas companies in 9

2018 and 2019 with ROE rates at 10% or higher. In contrast, there were 41 gas ROE 10

decisions with authorized rates below the 10% level. The 41 decisions are shown on pages 11

two and three of the exhibit, which also include information regarding debt financing 12

subsequent to the rate orders. It is clear from this information that the capital markets 13

have continued to provide debt capital at competitive interest rates to gas utilities with 14

authorized ROEs well below 10%. 15

Q. PLEASE EXPLAIN YOUR CONCLUSION CONCERNING THE APPROPRIATE 16

RETURN ON EQUITY RATE THE COMMISSION SHOULD USE IN THIS CASE. 17

A. In Exhibit AG-8, I have summarized the cost of equity rates from the three methods I used. 18

The range of returns for the industry peer group is from 7.63% at the low end, using the 19

CAPM approach and 9.29% at the high end using the DCF approach. 20


As explained earlier in my testimony, I give more weight to the DCF method as a more 1

reliable approach to estimating the cost of equity, which in my analysis is 9.29%. In this 2

regard, on line 4 of Exhibit AG-8, I have calculated a weighted return on equity of the 3

three methodologies using a 50% weight for DCF and 25% for each of the other two 4

methods. The result is a weighted return on equity of 8.64% for the average of the industry 5

peer group. However, I am recommending a higher ROE rate of 9.50% for SEMCO 6

Energy Gas Company for the reasons explained below. 7

First, long-term interest rates are currently at a low level, and although they certainly 8

justify ROEs well below 10%, they could negatively impact the long-term cost of common 9

equity if they were to increase significantly in the coming years. As such, while the cost 10

of common equity I have calculated is an accurate assessment of expectations for the 11

forecasted test year, significantly higher U.S. Treasury interest rates above the 3.1% level 12

assumed in this rate case analysis may very well produce a different result should such 13

higher interest rates become a reality. In this regard, a potential 10% correction in utility 14

stock prices due to higher interest rates would produce a 0.40% increase in the cost of 15

capital under the DCF approach. 16

Second, I understand that the Commission may be reluctant to set a ROE for the Company 17

at the true cost of equity of 8.64%. As shown in Exhibit AG-14, regulatory commissions 18

around the country have granted an average ROE of 9.60% to gas utilities during 2018 and 19

slightly above this number during 2019. In fact, approximately 90% of the reported ROE 20

decisions in gas utility rate cases reported by “Regulatory Focus” during this timeframe 21


are well below 10%. Therefore, my recommended ROE rate of 9.50% in this case is 1

reasonable and fair, if not generous, as a gradual transition to the true cost of equity. 2

Q. SHOULD THE COMMISSION BE CONCERNED THAT ESTABLISHING AN 3

AUTHORIZED ROE OF 9.50% IN THIS CASE WILL LEAD TO IMPAIRMENT 4

OF THE COMPANY’S ABILITY TO ACCESS THE CAPITAL MARKETS? 5

A. No. In recent general rate case proceedings, the Commission seems to have been 6

persuaded by the applicants’ arguments that they should receive a ROE of 10% or higher 7

to ensure the financial soundness of the business and to maintain its strong ability to attract 8

capital in addition to being compensated for risk. Pages 2 and 3 of Exhibit AG-14 show 9

several utilities that have accessed the capital markets at competitive interest rates since 10

receiving a ROE substantially below 10%. 11

Similarly, there is no evidence equity investors have abandoned utilities that have been 12

granted ROEs below 10%. On the contrary, stock investors continue to migrate to utility 13

stocks recognizing that authorized ROEs are still above the true cost of equity. Exhibit 14

AG-13 shows the market to book ratios for each of the peer group companies, and many 15

of these companies have received rate orders during the past few years reflecting ROEs 16

ranging from 9.25% to 9.85%. Yet this group of companies has an average Market to 17

Book common equity value ratio of 2.2 times. 18

This information is provided to dispel the myth that the Company must receive a ROE at 19

or above 10%, or it will face dire consequences in the financial markets. 20


The fact that the Company needs to raise capital because of a large capital investment 1

program to upgrade its infrastructure and for other purposes is not unique to SEMCO Gas. 2

Other gas and electric utilities face the same issues and are able to raise capital with ROEs 3

in the single digits. Therefore, this issue is another “red herring”. 4

Q. IF THE COMMISSION APPROVES A 10.0% COST OF COMMON EQUITY IN 5

THIS CASE (AS IT DID IN THE 2018 DECISIONS OF DTE GAS AND 6

CONSUMERS ENERGY GAS), WHAT IS THE COST TO CUSTOMERS 7

COMPARED TO AN ROE OF 9.50%. 8

A. Assuming the Commission grants a 10.00% ROE in this case versus a 9.50% ROE, the 9

additional cost to customers is approximately $2.0 million annually. There is absolutely 10

no need to burden customers with this additional cost, when historically the Company has 11

been earning well above its authorized ROE. 12

I recommend that the Commission take note of the evidence and arguments I have 13

presented in my testimony and grant the Company a ROE of no more than 9.50%. 14

VI. Gas Sales & Transportation Revenue 15

Q. WHAT ARE YOUR FINDINGS FROM ANALYZING THE COMPANY’S 16

PROJECTED LEVEL OF GAS SALES AND TRANSPORTATION DELIVERIES? 17


A. In Exhibit A-15 (PAR-4), Schedules E-1, Company witness Paul Raab presents the 1

Company’s forecast of gas sales and transportation deliveries for the projected test year of 2

2020 along with 2019 and subsequent years. It should be pointed out that the forecasted 3

volumes in this schedule exclude the Energy Optimization Losses which are shown in the 4

subsequent column. In Exhibit A-15 (PAR-6), Schedule E-3, the Company has reflected 5

the Energy Optimization Losses and other adjustments to arrive at the next forecasted gas 6

volumes in column (F). This exhibit shows that the Company has forecasted total gas sales 7

of 42,937,173 Dth and end-user transportation deliveries of 22,297,791 Dth for total gas 8

deliveries of 65,234,963 Dth for the projected test year. This level of sales and 9

transportation volumes represents a decrease of 897,978 Dth, or approximately 1.4%, from 10

the actual weather-normalized gas delivery in 2018. 11

According to Mr. Raab’s direct testimony, he has calculated the forecasted sales based on 12

regression models applied to customers’ historical gas consumption during the January 13

2014 to December 2018 timeframe.16 The models also make use of other historical and 14

projected data, including weather degree days and number of customers. 15

After reviewing the Company’s sales and transportation forecast, I have determined that 16

the Company has appropriately captured the increasing trend in gas deliveries for 17

transportation customers in rate schedules GS-1, GS-2, GS-3, TR-1, TR-3 and Special 18

Contract customer, and I do not dispute those forecasts. However, I believe that the 19



Company has underestimated gas sales to residential and commercial customers in rate 1

schedules GS-1, GS-2, GS-3, as well as to customers in transportation rate schedule TR-2 2

for the projected test year by a significant amount. 3

Q. WHAT IS THE BASIS FOR YOUR CONCLUSION THAT RESIDENTIAL AND 4

COMMERCIAL GAS SALES AND TRANSPORTATION GAS DELIVERIES TO 5

RATE SCHEDULE TR-2 ARE UNDERSTATED? 6

A. In discovery, the Company was asked to provide the weather-normalized actual gas 7

deliveries and the average number of customers for each year from 2014 to 2018 for each 8

customer rate schedule. Based on the information provided by the Company, I calculated 9

the average gas usage per customer for the applicable residential and commercial rate 10

schedules. 11

In Exhibit AG-15, I show the average gas usage per customer for the residential, GS-1, 12

GS-2, GS-3 and TR-2 customers for the historical years from 2014 to 2018, and also for 13

the forecasted 2019 and 2020 test year period. These calculations are based on information 14

provided by the Company for both the historical and projected years. In the exhibit, I also 15

calculated the percent change in average gas usage per customer, year over year, from 16

2014 to 2020 along with the average compound rate of change in average customer gas 17

usage for the most recent historical four- and five-year period. 18

The analysis shows that actual weather-normalized average gas usage for residential 19

customers has been relatively flat from 2014 to 2017 with a health increase of 1.4% in 20


2018. Overall, over the five-year period sales have increased at a compound average 1

annual rate of 0.47%, or about half a percentage point. During the more recent four-year 2

period, the rate of growth has been somewhat higher at 0.76%. In contrast, the Company’s 3

forecast of residential gas usage per customer for 2019 and 2020 declines by 2.6% and 4

1.0%, respectively, from the prior year for a cumulative decline of 3.6% from the weather-5

normalized level in 2018. 6

Similarly, as shown in Exhibit AG-15, average customer gas usage for rate schedules GS-7

1, GS-2, GS-3 and TR-2 projected by the Company for 2019 and 2020 show a decline or 8

in some cases show an increase significantly less than the 4 or 5-year average growth rate. 9

This dichotomy in the Company’s gas sales and transportation forecast is perplexing given 10

the fact the Company’s regression model uses the same weather-normalized volumes and 11

customer numbers from 2014 to 2018 to forecast sales and transportation volumes for 12

future years. 13

The analysis in Exhibit AG-15 clearly shows that the rate of decline in average customer 14

usage projected by the Company from 2018 to the projected test year is excessive and not 15

supported by historical data or trends. 16

The following charts demonstrate the growth in residential and commercial sales from 17

2014 to 2018 and the unusual decline projected by the Company for 2019 and 2020 even 18

with a growing customer base. 19


Q. TO WHAT DO YOU ATTRIBUTE THE SIGNIFICANT DECLINE IN AVERAGE 1

CUSTOMER USAGE FORECASTED BY THE COMPANY FOR THE 2

PROJECTED TEST YEAR FOR RESIDENTIAL AND COMMERCIAL RATE 3

SCHEDULES? 4

A. Although Mr. Raab does not address it in his direct testimony, one significant factor is the 5

assumption of additional energy optimization losses during 2019 and 2020. On page 1 of 6

Exhibit A-15, Schedule E-3, column (D), Mr. Raab shows the reductions due to energy 7

optimization losses applied to 2018 volumes with other adjustments resulting from the 8

regression forecast model in order to arrive at the net forecasted sales and transportation 9

volumes for 2020. In response to discovery, the Company disclosed that it assumed a 1% 10

declined in gas sales and applicable transportation volumes for 2019, and a 2% decline for 11

2020 for anticipated energy optimization gas losses. Stated differently, the volumes in 12

column (d) of Exhibit A-15, E-3, represent the assumed gas sales and transportation 13

volume attrition due to energy efficiency programs. 14

Q. DOES THE HISTORICAL TREND IN AVERAGE RESIDENTIAL AND 15

COMMERCIAL GAS USAGE PER CUSTOMER JUSTIFY THE DECLINE 16

PROJECTED BY THE COMPANY FOR THE PROJECTED TEST YEAR DUE TO 17

ENERGY EFFICIENCY PROGRAMS? 18

A. No. As discussed earlier the actual experience in average gas usage per residential 19

customer has been a slight increase over the past four to five years, and certainly not a 20


decrease in usage. Similarly, the gas usage for commercial customers has been trending 1

up in the past four to five years. If the assumed energy efficiency reductions or other 2

external events were actually occurring to the extent projected by the Company, then we 3

should see steady declines in average usage per customer year over year. The actual data 4

shows that this is not happening. The Company’s energy efficiency program began nearly 5

a decade ago with the enactment of 2008 PA 295. 6

Therefore, either customers are not achieving the energy efficiency savings projected by 7

the Company, or other underlying energy consumption factors are occurring which more 8

than offset the energy efficiency sales reductions. In either case, the Company’s 9

projections of a rate of decline of 1% to 2.0% in average gas usage for residential 10

customers are not realistic. 11

Therefore, the residential and commercial rate schedule GS-1, GS-2, GS-3 and TR-2 gas 12

deliveries projected by the Company for the test year are also unrealistic and understated. 13

Q. DID YOU DETERMINE A MORE REALISTIC FORECAST OF RESIDENTIAL 14

AND COMMERCIAL GAS DELIVERIES FOR THE PROJECTED TEST YEAR? 15

A. Yes. In Exhibit AG-16, I calculated revised sales forecasts for residential customers and 16

commercial customers in rate schedules GS-1, GS-2, GS-3 and transportation customers 17

in rate schedule TR-2. The common approach I used was to start with the weather-18

normalized usage per customer from 2018 and apply the lower of the two annual growth 19

rates for the applicable rate schedule from Exhibit AG-15 to arrive at the 2019 and 2020 20


average usage per customer. For all rate schedules other than TR-2, the lowest growth rate 1

was the 5-year compound annual growth rate. For rate schedule TR-2, the lowest growth 2

rate was the 4-year rate. 3

The resulting 2020 average usage per customer was multiplied by the forecasted number 4

of customers for each rate schedule provided by the Company. The result was the revised 5

forecasted sales or transportation volume for the applicable rate schedule. The variance 6

of this volume from the Company’s volume forecast for 2020 was multiplied by the current 7

distribution rate to determine the expected increase in revenue above the Company’s 8

forecast. 9

Exhibit AG-17 summarizes the incremental revenue for the five rate schedules for a total 10

incremental revenue of $4,827,551. 11

In addition in Exhibit AG-18 I provide the revised Billing Determinants both for volumes 12

and number of customers reflecting the adjusted volumes from Exhibit AG-16. 13

Q. WHAT IS YOUR CONCLUSION AND RECOMMENDATION? 14

A. The Company’s forecasted revenue and operating income for the projected test year are 15

not accurate because gas deliveries for the projected period are understated. The 16

Company’s gas delivery forecast includes losses of sales from energy efficiency and other 17

factors that are not likely to materialize. The Commission should reject the Company’s 18

residential and commercial gas delivery forecast for rate schedules GS-1, GS-2, GS-3 and 19


TR-2 for the projected test year and instead adopt my forecast as presented in Exhibit AG-1

16 through AG-18. 2

Therefore, I recommend that the Commission increase the revenue and operating income 3

forecasted by the Company for the future test year by $4,827,551. 4

VII. Operations and Maintenance Expenses 5

Q. WHAT ARE YOUR FINDINGS IN ANALYZING THE COMPANY’S LEVEL OF 6

O&M EXPENSES INCLUDED IN THIS RATE CASE? 7

A. My review of Exhibit A-13 (MAM-1), Schedule C-5, shows that Other O&M expenses, 8

excluding Company Use and Lost & Unaccounted For (“LAUF”) gas, are projected to be 9

approximately $59.7 million for the future test year, an increase of $7.9 million or 15% 10

from 2018. In my analysis below, I will recommend that Other O&M expense should be 11

reduced by $8.9 million to a level of $50.8 million. 12

Additionally, I will recommend that the forecasted cost of Gas Used by the Company and 13

LAUF gas should be reduced by $262,919 to a reasonable level of $272,486. 14

Exhibit AG-19 shows a summary of my proposed O&M expense adjustments. 15

Q. HOW DID THE COMPANY DEVELOP ITS PROJECTED O&M EXPENSES 16

INCLUDED IN THIS RATE CASE FOR THE PROJECTED TEST YEAR 2020? 17


A. As shown in Exhibit A-13 (MAM-1), Schedule C-5, the Company started by using the 1

2019 budget of O&M expenses approved by its Board of Directors. To this level of 2

expenses, it made certain known and measurable changes totaling to $8.4 million to arrive 3

at the forecasted 2020 expense of $59.7 million. The largest increases involve: (1) $2.7 4

million for credit card and payment processing fees; (2) higher pension and OPEB costs 5

of $2.3 million; and (3) $1.2 million for inflation cost adjustments to O&M costs. These 6

items total $6.2 million. The remainder of the O&M cost increases of $2.2 million involve 7

the removal of $0.6 million of appliance repair revenues from O&M; $0.8 million in 8

expenses associated with the Marquette Connector Pipeline, and cross boring & inspection 9

costs; with the balance consisting primarily of higher Information Technology costs, and 10

higher rate case expenses. 11

Q. IN YOUR ANALYSIS, HAVE YOU DETERMINED SPECIFIC AREAS WHERE 12

O&M COSTS COULD BE REDUCED? 13

A. Yes. I have analyzed O&M costs by major department or area and I have identified more 14

appropriate and reasonable expense levels that the Commission should consider. 15

A. Credit Cards – Payment Processing Fees 16

Q. DO YOU AGREE WITH THE COMPANY’S PROPOSAL TO PAY FOR CREDIT 17

CARD AND OTHER PAYMENT PROCESSING FEES FOR A PROJECTED 18

COST OF $2.7 MILLION INSTEAD OF CHARGING CUSTOMERS FOR THESE 19

FEES? 20


A. No. The Company presents no compelling business case to support the shift of these fees 1

from those customers using those services to the Company and ultimately all ratepayers. 2

Beginning on page 4 of her direct testimony, Company witness Laurie Owens discusses 3

the proposal to stop charging customers the current fee of $3.50 when paying their gas bill 4

by credit card or electronic check. Ms. Owens points to the following benefits to justify 5

this change: (1) improved customer satisfaction; (2) providing another affordable payment 6

option; and (3) alignment with DTE and Consumers Energy who provide this cost-free 7

service to customers. 8

With regard to improving customer satisfaction, the Company has reported that it is 9

achieving a 4.7 rating on a scale of 1 to 5 in its surveys of customer satisfaction. Therefore, 10

it seems that the Company’s customers are very satisfied for the most part, and this is not 11

a compelling reason to justify removing credit card fees.17 12

As to providing an “affordable payment option”, a $3.50 convenience fee to pay by credit 13

card does not pose a problem of affordability, especially when the gas bill can be paid by 14

check, money order or with cash at a Company business office to avoid paying the credit 15

card fee. 16

A key factor contributing to the $2.7 million cost is the Company’s projection that 17

participation in the credit card payment program will increase from the current level of 18

approximately 15% of eligible residential and small commercial customers to 37% with 19



the convenience fee eliminated. According to the Company, the projection is based on the 1

experience of SEMCO Gas’s utility affiliate in Alaska. Although over time, that level of 2

participation may be reached. The projection that it can be reach in 2020 is at best 3

speculative and most likely unrealistic. With the Company receiving an order in this case 4

in the first quarter of 2020, it is unlikely that participation would escalate from 15% to 5

37% in the 2020 test year. 6

It would have been more reasonable for the Company to use the current participation rate 7

of approximately 15% to estimate the cost of waiving the credit card fee for the projected 8

test year. Using that assumption, the Company would have forecasted a cost of 9

approximate $1.1 million. 10

Another important fact that the Commission should consider is the positive impact on 11

uncollectible accounts expense. When customers pay their gas bills by credit card, the risk 12

of the gas bill becoming uncollectible is removed from SEMCO Gas and shift to the credit 13

card company. This in turn will reduce the amount of uncollectible gas bills for the 14

Company. Given the expected 150% increase in credit card payments in future years, the 15

savings in uncollectible gas expenses will most likely offset any payments SEMCO Gas 16

needs to make to the credit card company. 17

Therefore, my recommendation is that the Commission remove the entire $2.7 million of 18

expense from the projected test year. However, if the Commission believes that some 19


consistency among utilities is appropriate on this matter, it should only approve the lower 1

amount of $1.1 million. 2

B. O&M Expense Inflation Adjustment 3

Q. DO YOU AGREE WITH THE COMPANY’S $1.2 MILLION ADJUSTMENT FOR 4

EXPECTED FUTURE INFLATION? 5

A. No. The Company has presented no evidence that it will face inflationary cost pressure in 6

the projected test year, and that an adjustment to future O&M expenses is warranted. On 7

the contrary, in his direct testimony Company witness Mark Moses has stated that from 8

2009 to 2018, the Company’s O&M costs have increased at an average annual rate of 9

0.23%, well below the rate of inflation.18 This result is indicative of the Company’s ability 10

to manage its O&M costs below the rate of inflation of 1.74%. To approve an inflationary 11

cost increase of 2.28% for 2019 and 2020 would be unfair and unreasonable to ratepayers, 12

and likely result in a large cost over-recovery. 13

Therefore, I recommend that the Commission deny recovery of the inflation cost 14

adjustment of $1.2 million. 15

18 Direct testimony of Mark Moses at page 12.


C. Appliance Repair Program 1

Q. PLEASE EXPLAIN YOUR REASONS FOR REJECTING THE COMPANY’S 2

PROPOSAL TO INCREASE ITS O&M EXPENSE BY $0.6 MILLION 3

PERTAINING TO THE APPLIANCE REPAIR PROGRAM. 4

A. In Exhibit A-13, Schedule B-5, the Company increased the projected 2020 O&M expense 5

by $605,000 to remove the net revenue earned from the Company’s home appliance 6

service and repair program, which is operated by an outside third party. The Company has 7

concluded that this is a value-added service and therefore any revenues net of expenses 8

incurred by the utility business should be retained by the Company and not reflected in the 9

utility revenue requirement in this rate case. 10

The premise by the Company is that the $10,000 in expenses it has identified against the 11

fee it earns from the appliance repair program is an adequate amount to compensate 12

SEMCO Gas for costs incurred in marketing and administratively supporting the program. 13

Unfortunately, this premise is faulty. The $10,000 only barely covers a portion of the 14

incremental costs incurred by the utility business to support the appliance repair program 15

and certainly does include other direct and indirect costs of marketing and administering 16

the program. 17

In response to discovery, the Company stated that approximately 29 utility employees may 18

be involved with this program in customer accounting and customers service. The 19

discovery response is included in Exhibit AG-20. From the discovery response, it appears 20


that an appropriate allocation of labor costs was not made in the 2019 budget to the 1

appliance value added program (VAP). Given that the utility’s customer service 2

employees are involved in marketing the program and also answer customer service calls, 3

any reasonable estimate of the cost of the time dedicated to the program will certainly 4

exceed $10,000 in labor cost during the year. The $10,000 in expense estimated by the 5

Company also does not include employee benefit costs, management time, and indirect 6

costs for office space and other overheads. Also, SEMCO Energy Gas should be 7

compensated for the use of its assets including the association of its name and logo with 8

the program. There is considerable value to the program when marketed under the 9

SEMCO Gas name. Customers using the program certainly feel more at ease with, and 10

are more likely to sign up for, an appliance service and repair program marketed by the 11

local gas utility than an unknown company. This value is not reflected in the cost of the 12

program to be retained by the utility. 13

Section 8 of MCL 460.12ee provides the guiding legislation on VAP services and the 14

revenues that should be retained by the utility to offset both direct and indirect costs, as 15

shown below. 16

(8) All utility costs directly attributable to a value-added program or service allowed 17 under this section shall be allocated to the program or service as required by this 18 section. The direct and indirect costs of all utility assets used in the operation of the 19 program or service shall be allocated to the program or service based on the 20 proportional use by the program or service as compared to the total use of those assets 21 by the utility. The cost of the program or service includes administrative and general 22 expense loading to be determined in the same manner as the utility determines 23 administrative and general expenses loading for all of the utility’s regulated and 24 unregulated activities. 25


The law is very clear about the requirement to allocate administrative and general 1

expenses, and for the utility to be compensated for the use of its assets which would include 2

the utility’s name and logo. The O&M costs of $10,000 identified by the Company in this 3

case for the 2020 test year fall significantly short of the total costs that should be assigned 4

to the appliance repair program and the revenue that should be retained by the utility. 5

Therefore, the $605,000 in revenue removed from O&M is inaccurate and not adequately 6

supported. I recommend that the Commission remove this adjustment and accordingly 7

reduce the 2020 O&M expense by $605,000. 8

D. Uncollectible Accounts Expense 9

Q. DO YOU AGREE WITH THE COMPANY’S ESTIMATE OF 10

UNCOLLECTIBLE ACCOUNTS EXPENSE OF $987,759? 11

A. No. According to the direct testimony of Company witness Moses, the Company used a 12

five-year average of uncollectible expense to revenue to develop a loss ratio.19 There are 13

two problems with this approach. First, the use of uncollectible expense instead of net 14

uncollectible charge-offs is an inferior approach to developing the loss ratio. Booked 15

uncollectible expense is a subjective estimate of future losses related to current sales, 16

whereas net charge-offs are an actual measure of losses. Second, as gas prices have 17

declined over the five-year period, natural gas has become more affordable to consumers. 18

19 Mark Moses direct testimony at page 15.


Accordingly, it is not surprising that the loss ratio has fallen from 0.43% in 2014, and 1

0.46% in 2015 to an average of 0.23% in the three-year period ending in 2018. This 2

analysis is shown in Exhibit AG-21 3

Because of this dramatic reduction by nearly 50% in the loss ratio in the most recent three 4

years, I have calculated the uncollectible accounts expense based on the ratio of the 5

Company’s actual net charge-offs to the related revenues for the years 2016 through 2018. 6

The average loss ratio for this three-year period is 0.23%. Multiplying this percentage by 7

the Company’s projected revenues of $289.2 million results in the projected uncollectible 8

accounts expense of $665,700. This amount is $240,000 less than the Company’s 9

estimated uncollectible account expense. 10

Therefore, I recommend that the Commission should reduce the Company’s uncollectible 11

accounts expense by $322,100 for the 2020 test year. 12

E. Supplemental Executive Retirement Plan 13

Q. DO YOU AGREE WITH THE INCLUSION OF EXPENSE FOR THE 14

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN IN THE COMPANY’S 15

FORECASTED EMPLOYEE BENEFITS? 16

A. No. In the 2020 test year, the Company has included an expense amount of $68,105 17

pertaining to the Supplemental Executive Retirement Plan (“SERP”) for certain former 18


highly-paid executive employees.20 In other rate cases, the Commission has consistently 1

removed SERP costs from projected test year expenses. The costs in this case are no 2

different than in other rate cases, such as Case No. U-17767 and U-17735. I recommend 3

that the Commission remove the expense amount of $68,105 from the 2020 test year in 4

this rate case. 5

F. Incentive Compensation 6

Q. PLEASE PROVIDE A BRIEF SUMMARY OF THE COMPANY’S INCENTIVE 7

PAY PLANS AND THE AMOUNT OF EXPENSE THE COMPANY SEEKS TO 8

RECOVER IN THIS RATE CASE. 9

A. For the projected test year, the Company seeks to recover $1.9 million of employee 10

incentive expense. In response to discovery, the Company disclosed that approximately 11

$1.2 million of this amount pertains to the Short-Term Incentive Plan (“STIP”) and $0.7 12

million pertains to the Long-Term Incentive Plan (“LTIP”). Exhibit AG-22 includes this 13

information provided by the Company. 14

Short-Term Incentive Plan – the STIP is an annual bonus program covering 133 15

management and professional employees focused on the following major categories and 16

specific measures: 17

1. 33% on Financial Performance (Adjusted Operating Income, CAPX, O&M and 18

Customer Additions). 19

20 SEMCO response to discovery request 1-AG-SEMCO-29d.


2. 33% on Customer Service (Customer Satisfaction Call Survey, Average Answer 1

Time, Leak Response Time, Minimize number and duration of preventable 2

customer outages, year over year reduction in non-compliances). 3

3. 33% on Employee/Workplace Factors (Recordable Injuries, Dart Severity Rate, 4

Reduce Vehicle Accidents and Year End Active Leaks). 5

Long-Term Incentive Plan – the LTIP is a plan for the 2018 to 2020 period focused on 6

achieving multi-year goals for 19 executives and focuses on the following measures: 7

1. Regulatory – No disallowances (Gas Supply Plan) and successful outcome on the 8

current rate case. 9

2. System Integrity and Compliance – MCP Project timeliness; no significant audit 10

or MPSC non-compliance issues; cybersecurity enhancement; and optimizing 11

utility operations. 12

3. Customer Care – Bad debts (less than 0.6% of sales); low income programs; 13

customer satisfaction of 4.3 or greater on a scale of 1-5; workforce development 14

and succession planning. 15

The testimony and exhibits of Company witness Ann Forester provide more details on the 16

STIP and LTIP. 17

Q. WHAT IS YOUR ASSESSMENT OF EACH OF THESE INCENTIVE PAY 18

PLANS? 19

A. Regarding the STIP, 33% is related to financial objectives which benefit shareholders and 20

not customers. 21


Another 33% is related to customer service, leak response time and preventing customer 1

outages. These goals are certainly important. However, in discovery the Company was 2

asked to explain how the target performance measures shown in Exhibit A-42 (ALF-1) 3

were determined and why no target performance level was set for one of the measures. 4

The Company’s response provided only general explanations with few of the specific 5

details requested. Furthermore, the Company was asked to provide the actual performance 6

levels achieved against the target performance. The information provided shows that the 7

goals were easily achieved in most of the past five years with little improvement in 8

performance in the most recent three years. In fact, as shown in Exhibit AG-22, during 9

the six-year period from 2013 to 2018, actual performance has surpassed target 10

performance at 150% to 200% of target. This consistently high level of actual performance 11

above target is a clear indication that the target measures are easily achievable. 12

With regard to the other 33%, the performance measures here are directed more at 13

employee safety. Again, these are worthy goals, but not directly related to customer 14

benefits that have been quantified. In discovery, similar questions were posed to the 15

Company about explaining how the performance target measures were determined. The 16

responses were again general statements, and therefore difficult to assess the 17

reasonableness of the incentive measures. Exhibit AG-23 includes the Company’s 18

discovery responses with regard to the determination of the target performance measures 19

and historical achieved performance. 20


Most importantly, in response to a Staff audit request, the Company disclosed that in order 1

to achieve any payout under the STIP, a minimum level of financial performance is 2

necessary. If that minimal level of financial performance is not achieved, no payout will 3

be made. The Company did not specify the minimal level of financial performance. 4

However, it is clear that short-term incentive payments are driven by financial performance 5

first and foremost, and not solely by achieving operating performance measures. SAR 6

TMS-3.10 providing this information is included in Exhibit AG-24. 7

As for the Long-Term Incentive Plan, the performance metrics outlined in Exhibit A-43 8

(ALF-2) are very general and subjective performance objectives not conducive to clear 9

quantitative measurement. These are not performance metrics in the true sense. Most of 10

the objectives are basic management responsibilities that should be carried out in the 11

course of running the utility business. There are no apparent stretch goals here that will 12

result in management achieving superior performance. Also, some of the goals, such as 13

customer satisfaction, are duplicative of the performance measures included in the STIP. 14

In discovery, the Company was asked to explain in more details what the goals entail and 15

how successful performance will be measured. The Company was also asked to provide 16

evidence of historical performance achieved. In response, the Company provided only 17

general explanations of little value, and could not provide any specific evidence of the 18

goals achieve historically and specifically at what level. Exhibit AG-25 includes the 19

Company discovery responses on the LTIP. 20


Given the subjective and general nature of the performance objectives of the LTIP, the 1

lack of information about specific performance achieved in historical period and the fact 2

that this plan applies only to a limited number of senior level management employees, the 3

conclusion I reach is that there is very little value accruing to customers from this incentive 4

plan. 5

Q. DID THE COMPANY PROVIDE ANY QUANTIFICATION OF BENEFITS 6

BEING ACHIEVED AS A RESULT OF THESE INCENTIVE PLANS? 7

A. On page 7 of her testimony, Ms. Forester stated that the Company had difficulty in 8

quantifying benefits pertaining to the metrics of each plan. The only item to which she 9

pointed as a benefit was the Company’s O&M level from 2009 to 2018. The Company’s 10

O&M expense level increased at an average annual rate of 0.23% rate versus the CPI 11

average annual increase of 1.76%, thus potentially saving customers $750,000 annually. 12

These are not real cost savings, but a what-if scenario, particularly since the Company did 13

not file a rate case from 2011 to 2018 and retained those benefits for shareholders. 14

Ms. Forster also did not explain which incentive performance measures helped achieve the 15

lower O&M costs and how. Therefore, there is a significant lack of justification that the 16

incentive plans have provided benefits to customers in excess of the cost of the incentive 17

pay the Company seeks to recover in rates. 18

Q. DO YOU HAVE OTHER CONCERNS WITH THE COMPANY’S INCENTIVE 19

COMPENSATION PLANS? 20


A. Yes. The incentive plans are structured to provide significant incentives to higher level 1

management employees at the Director level and above with far lesser incentives to other 2

employees. The table below shows the skewed nature of the incentive plans.21 3

4

5

The Commission should be mindful of the fact that the incentive plans are not broad-based, 6

and the majority of incentive payments are provided to highly-paid employees. In fact, 7

approximately 50% of the Company’s non-union employees do not participate in any 8

incentive payment plan, and the LTIP applies to only 19 senior level management 9

employees. 10



Incentive Compensation Table—SEMCO Energy Gas

Incentive Comp. Percentage of Pay Incentive Comp. At Target STIP LTIP Total President 35% 40% 75% Vice President 25% 35% 60% Director 20% 18% 38% Others 3 – 8% 3 – 8% 2018 at 174% & 155% of Target President 61% 62% 123% Vice President 43% 54% 97% Director 35% 28% 63% Others 5 – 14% 5 – 14%


A. I recommend that the Commission reject the Company’s proposal to include $1.9 million 1

of incentive pay in customer rates and remove this amount from O&M expense for the 2

2020 projected test year. 3

G. AltaGas Corporate Expenses 4

Q. PLEASE DISCUSS THE CORPORATE COSTS ALLOCATED BY ALTAGAS 5

AND SEMCO ENERGY, INC. TO SEMCO ENERGY GAS IN THE PROJECTED 6

2020 TEST YEAR. 7

A. Beginning on page 3 of his direct testimony, Company witness Moses discusses the shared 8

services provided by the SEMCO Inc. corporate functions and the allocation of the costs 9

pertaining to those functions to SEMCO Gas. For 2018, Mr. Moses identified $9,650,038 10

of costs allocated to the Company, including the amount pertaining to corporate costs 11

allocated to SEMCO Inc. from the ultimate parent, AltaGas. Ltd. (AltaGas). The Company 12

has increased the 2018 allocated costs by an inflation rate of 2.28%, applied to both 2019 13

and 2020, to arrive at the forecasted amount of $9,369,711 included in O&M expense for 14

the projected 2020 test year. Exhibit AG-26 includes the information provided by the 15

Company to support the 2020 forecasted amount. 16

On pages 4 through 7 of his direct testimony, Mr. Moses describes in detail the various 17

functions performed by the corporate group at SEMCO Inc. The functions include: 18

Accounting/Tax, Corporate Compliance, Communication and Record Maintenance, 19


Finance/Treasury, Information Technology, Human Resources, Risk Management, and 1

Facilities. 2

Similarly, Jillian Fan, Director of Regulatory Policy at AltaGas, in her direct testimony 3

describes the functions performed by the AltaGas corporate group based primarily at the 4

corporate office in Calgary, Canada. Although, she does not describe the AltaGas 5

corporate functions in detail, she states that they are not duplicative of the corporate 6

functions performed by SEMCO Inc. 7

Q. WHAT IS YOUR ASSESSMENT OF THE CORPORATE FUNCTIONS 8

PERFORMED BY SEMCO INC. AND ALTAGAS? 9

A. In discovery, the Company was asked to provide additional details on the components of 10

the costs billed by AltaGas to SEMCO Inc. and the corporate functions to which they 11

pertain. In response, the Company provided a schedule showing that for 2019, the AltaGas 12

corporate group forecasted total costs of $42.6 million, of which $6.3 million would be 13

allocated to SEMCO Inc. SEMCO Inc would subsequently allocate approximately 57% 14

of these costs to SEMCO Gas. 15

The schedule also shows the costs incurred during each year from 2013 to 2018 and the 16

portion allocated to SEMCO Inc. during those years The reduction in allocated costs to 17

SEMCO Inc. from 2017 to 2019 reflects primarily AltaGas’ acquisition of Washington 18

Gas Holding Company in mid-2018 and the resulting shift of a portion of the corporate 19


costs to that company. Exhibit AG-27 includes the discovery response with the schedule 1

of corporate costs from AltaGas. 2

The corporate functions billed to SEMCO Inc. include costs for Board of Directors, 3

Executive Management, Finance, Accounting and Tax, Legal & Compliance, Information 4

Technology (IT), Procurement, Corporate Resources and Corporate Depreciation. In 5

discovery, the Company was asked to explain what specific services are provided by the 6

AltaGas corporate functions to SEMCO Gas and why some of these functions are not 7

duplicative of the functions performed by the SEMCO Inc. corporate group. The response, 8

prepared by Ms. Fan, discusses high level strategic direction and coordination of policy in 9

the various functions provided by the AltaGas corporate group and acknowledges that day 10

to day corporate functions are performed by the SEMCO Inc. corporate group. Similar 11

questions posed to SEMCO Inc. and answered by Mr. Moses, Chief Financial Officer of 12

SEMCO Inc., confirm that SEMCO Inc. is rather self-sufficient and does not rely much if 13

at all from the AltaGas corporate office, particularly in the area of IT resources and 14

management, corporate planning, treasury/finance, and accounting. Exhibit AG-28 15

includes the discovery responses prepared by Ms. Fan and Mr. Moses. 16


A. The amount of costs allocated to SEMCO Gas from the AltaGas corporate functions for 18

the 2020 test year is $3.7 million. In comparison, the amount of SEMCO Inc. corporate 19

costs charged to SEMCO Gas is $5.7 million. The AltaGas corporate costs represent an 20


additional 65% corporate overhead burden on top of the corporate costs allocated by 1

SEMCO Inc. to SEMCO Gas, for basically corporate strategic direction and coordination 2

of policy. 3

The allocation of corporate costs from AltaGas is excessive and mostly duplicative. In 4

Exhibit AG-29, I have identified the duplicate functions and related costs to be disallowed. 5

I find the Finance function costs to be duplicative. SEMCO Gas has a Financial Officer 6

in Mr. Moses and three other employees who perform corporate planning and treasury 7

functions.22 SEMCO Gas has also been self-reliant with its capital needs with no injection 8

of equity capital or financing assistance from AltaGas for either long-term and short-term 9

capital. 10

I also find the Accounting and Tax function to be mostly duplicative. SEMCO Gas has its 11

own accounting and tax staff and an Accounting Controller in Ms. Vincent. However, I 12

have only disallowed 50% of the AltaGas corporate accounting and tax costs to allow for 13

internal and external reporting by AltaGas that may eventually benefit SEMCO Gas. 14

I have removed the entire IT, Procurement and Corporates Resources costs from AltaGas 15

corporate cost allocation. SEMCO Gas does not share any computer systems with AltaGas 16

and therefore does rely on AltaGas’ IT staff and services, other than perhaps occasional 17

coordination of policies and planning.23 With regard to Procurement of goods and 18

22 See SEMCO discovery response 3-AG-SEMCO-127 in Exhibit AG-28. 23 Id.


services, this appears to be a functional mainly performed for the midstream and power 1

businesses, and only some occasional strategic assistance for SEMCO Inc. Corporate 2

Resources appears to involve human resources and facilities management. SEMCO Gas 3

has its own well-staffed human resources function and facilities management function. 4

Any assistance from Calgary seems remote and infrequent to justify the allocation of 5

millions of dollars in costs. 6

Based on the above analysis, I have identified $23.2 million of duplicate costs out of $43.6 7

million at the AltaGas level. Exhibit AG-OM5 shows the specific amounts along with the 8

portion that should not be allocated to SEMCO Inc. I have calculated the portion of the 9

duplicate costs allocable to SEMCO Inc. at 14.7%, which is the same allocation percentage 10

used by AltaGas in 2019. The resulting amount is $3.4 million. To this amount I have 11

added the removal of AltaGas incentive compensation billed to SEMCO Inc. in 2019, 12

which I have adjusted to 2020 levels, but only for the portion pertaining to corporate costs 13

not disallowed. This adjustment will have the effect of removing all the incentive bonus 14

from the 2020 O&M costs pertaining to AltaGas corporate functions. 15

Similar to SEMCO’s incentive plans, I found the AltaGas incentive goals to be very 16

subjective and the performance results not adequately supported to justify inclusion of the 17

incentive compensation expense as beneficial to the customers of SEMCO Gas.24 18

24 Exhibit AG-30 includes discovery response 1-AG-SEMCO-43 and 152.


Exhibit AG-29 shows also the allocation of the portion of the disallowed duplicated costs 1

to SEMCO Gas at $2.1 million. I recommend that the Commission remove this amount 2

from the Company’s forecasted O&M expense for the projected test year. 3

VIII. Company Use & LAUF Gas Costs 4

Q. DO YOU AGREE WITH THE COMPANY’S ESTIMATED COST FOR 5

COMPANY USE AND LOST & UNACCOUNTED FOR GAS (LAUF)? 6

A. No. In Exhibit A-13, Schedule C 4.1, the Company calculated an expense amount of 7

$535,434 for LAUF and Company Use gas. In determining this amount, SEMCO utilized 8

five years of historical volumes of LAUF and Company Use gas. Also, in the calculation 9

of the forecasted expense amount the Company used a gas price of $3.6089 per Dth which 10

was determined based on forecasted gas prices as of early March 2019. 11

In discovery, the Company was asked to update the 2020 forecasted gas price as of early 12

August 2019. In the discovery response included in Exhibit AG-6, the Company provide 13

an updated gas cost rate of $3.2032 per Dth, which is approximately 11% lower. This 14

more recent gas price forecast is more appropriate to calculate the cost for Company Use 15

& LAUF gas. 16

As stated earlier, to determine the forecasted volumes of LAUF and Company Use gas, 17

the Company used a five-year historical average. However, the actual data on page 2 of 18

Exhibit A-13 (SQM-2), Schedule C-4.1, shows that LAUF volumes were 197,157 Dth in 19


2014, 34,497 Dth in 2015, followed by three consecutive years of negative gas losses, or 1

“found” gas volumes, ranging from (31,077) Dth in 2016 to (132,307) in 2018. The 2

progressively higher volumes of negative lost gas from 2016 to 2018, following a declining 3

trend from 2014 to 2015 shows that a significant change in the level of LAUF gas has 4

occurred in the most recent three years. In its response to discovery, the Company outlined 5

several steps that it has undertaken in the past five years, or in some case even longer, to 6

replace leaky pipes, improve gas metering, and implement other procedures to reduce 7

LAUF gas. These actions include the replacement of more than 350 miles of unprotected 8

metallic and vintage plastic pipe, replace temperature and pressure correction devises, and 9

monthly audits of large customers gas usage and related meters. Exhibit AG-31 includes 10

the Company’s discovery response. 11

All of these factors have had a significant beneficial impact on LAUF gas and suggest a 12

permanent improvement in the Company’s gas system that supports the use of an average 13

LAUF ratio over a period shorter than five years. As such, I have used the most recent 14

three-year average to calculate the Company Use and LAUF gas volumes for the projected 15

test year. 16

Exhibit AG-32 shows the calculation of Company Use and LAUF gas using the three-year 17

average and the more recent price per Dth discussed above. The result is a forecasted 18

expense amount of $272,486. Therefore, I recommend that the Company’s forecasted 19

expense amount for LAUF and Company Use gas for the projected test year should be 20

reduced by $262,919. 21


IX. Revenue Decoupling Mechanism 1

Q. PLEASE SUMMARIZE THE REVENUE DECOUPLING MECHANISM 2

PROPOSED BY THE COMPANY. 3

A. Beginning on page 6 of her direct testimony, Company witness Jennifer Dennis discussed 4

an alternative Revenue Decoupling Mechanism (“RDM”) which would not reconcile 5

actual sales for residential and small commercial customers to the levels set in rates, but 6

instead would include a fixed charge within the monthly customer service charge to 7

recover the expected loss of revenue from Energy Waste Reduction (“EWR”) or energy 8

efficiency programs. The Company shows the calculations to arrive at the monthly charge 9

in Exhibit A-16 (JLG-5), Schedule F-3.1. 10

Aside from the fact that RDM charges for each rate schedule in Exhibit A-15, F-3.1, were 11

calculated incorrectly (the calculation skips the step of dividing the annual RDM fixed 12

amount by 12 to get to a monthly charge), the proposed RDM suffers from other 13

deficiencies. The purpose of an RDM is to compensate gas utilities for actual lost load 14

from energy efficiency programs. The proposed RDM charge that would be included in 15

the monthly service charge removes that link to actual results and assumes that projected 16

energy efficiency gas losses will occur. In fact, from the analysis I have performed in the 17

Gas Sales section of my testimony, it is clear that actual gas sales in the past four years 18

have not shown such a decline in sales from energy efficiency programs. 19


Therefore, the Company’s proposed RDM would charge customers for costs that would 1

not likely occur. This is not a fair and reasonable proposal. I recommend that the 2

Commission reject the Company’s proposed RDM. 3

X. Rate Design 4

Q. WHAT INCREASE IN THE MONTHLY SERVICE CHARGE FOR 5

RESIDENTIAL AND SMALL COMMERCIAL CUSTOMERS IN RATE 6

SCHEDULE GS-1 HAS THE COMPANY PROPOSED? 7

A. In her direct testimony, Company witness Jennifer Dennis proposes to increase the 8

monthly service charge from $11.50 to $17.40 per month for both residential and small 9

commercial customer in rate schedule GS-1. A portion of the increase pertains to the 10

incorrect calculation of the alternative RDM charge. The remainder reflects the 11

Company’s desire, based on assumptions made in rate design, to shift more costs to the 12

monthly charge for more assured recovery of costs through a fixed charge. 13

Q. DO YOU AGREE WITH THE COMPANY’S PROPOSAL? 14

A. No. The proposed change from $11.50 to $17.40 per month represents an increase of 51%. 15

Such a large increase could cause rate shock to customers in smaller households who use 16

less gas than the average customer. They would see their monthly gas bill increase 17

drastically without using any more gas. Fixed monthly charges also discourage energy 18

conservation. It is best to increase the volumetric rate paid by customers because the 19


higher cost encourages conservation. The customer can take steps to reduce usage and thus 1

lower the gas bill. The customer cannot reduce fixed monthly charges. 2

Q. WHAT DO YOU RECOMMEND? 3

A. I recommend keeping the residential customer monthly charge at $11.75. However, if the 4

Commission decides that it should be increased, I recommend that in the interest of rate 5

gradualism, it be increased by no more than $1 to $12.50. 6

XI. MRP and IRIP Surcharges 7

Q. DO YOU AGREE WITH THE APPROACH THAT THE COMPANY HAS TAKEN 8

IN CALCULATING THE RATE SURCHARGES FOR THE MRP AND IRIP? 9

A. No. The Company has calculated a single surcharge for each rate schedule representing 10

the average revenue requirement from the capital investments made over the five-year 11

period from 2021 to 2025. 12

This approach creates a significant mismatch between the amount of revenue billed to 13

customers versus the costs incurred each year. The result is that in the early years of the 14

program customers pre-pay for costs that will be incurred in the later years of the program. 15

For example, in the first year of the program in 2021, the revenue requirement according 16

to the Company’s calculation is $683,742. However, the Company would bill customers 17

$3,996,809, or nearly $4 million, thus significantly over-recovering its costs. 18


this event were to occur, the Company would have recovered $8 million in revenue and 1

only incurred about $3 million in costs. The result would be a gigantic windfall for 2

SEMCO Gas, particularly since under the Company’s proposal there would not be any 3

reconciliation of costs incurred versus amounts billed to customer either annually or at the 4

end of the program. 5

Q. IS THERE A WAY TO AVOID THIS POTENTIAL PITFALL? 6

A. Yes. The best way to avoid the mismatch issue and potentially the problem of an over-7

recovery of costs is to establish annual surcharge rates for each year of the program which 8

the Commission could approve in this rate case proceeding. In addition, there should be a 9

requirement that at the end of each year, the Company would file a simple reconciliation 10

to show that it has spent at least the targeted capital expenditures used in the calculation 11

of the revenue requirement for the annual surcharge rates. If the Company has underspent, 12

the revenue requirement applicable to the capital underspending should be recorded as a 13

deferred liability to be refunded to customers as part of the next rate case. This simple 14

mechanism would provide the needed protection for ratepayers and would ensure that the 15

Company spends the targeted capital expenditures. 16

Q. SHOULD THE MECHANISM ALSO COVER ANY OVER-SPENDING BY THE 17

COMPANY AND RECOVERY OF THE EXTRA REVENUE REQUIREMENT? 18

A. No. There is no need for a symmetrical mechanism in this case, because the Company 19

controls the amount of capital spending that it will undertake in any year. The Company 20


should be able to manage its construction program so that it spends the target amount and 1

no more or no less. If it chooses to spend more in a given year, that is a choice it has made 2

and it should absorb any related costs until the next rate case when an assessment of the 3

prudency of the capital spending is made. 4

Q. ARE THERE OTHER ADJUSTMENTS THAT SHOULD BE MADE TO THE 5

CALCULATION OF THE MRP AD IRIP SURCHARGES IF THE COMMISSION 6

DECIDED TO APPROVE BOTH PROGRAMS? 7

A. Yes. The calculation of the annual revenue requirement should be updated based on the 8

pre-tax cost of capital that the Commission approves in this rate case. 9

Additionally, the Company has calculated alternative surcharge rates that limit the per 10

customer surcharge to $1,000 per month. This limit benefits transportation customers in 11

rate schedule TR-3. By limiting the amount charged to TR-3 transportation customers, the 12

remaining revenue requirement is spread and recovered from the other rate schedule 13

customers. This is not a fair a reasonable ratemaking approach. 14

If the revenue requirement allocation procedure allocates an appropriate amount to a rate 15

schedule, then that revenue needs to be recovered from those customers within that rate 16

schedule. If the MRP and IRIP revenue requirement was included in base rates, it would 17

be fully recovered from those customers that participate in that rate schedule. There is no 18

valid reason to limit the recovery of revenue from certain customers because the revenue 19

requirement is billed on a per customer basis within the MRP and IRIP. If the Company 20


believes that the monthly surcharge per customer is embarrassingly too high for rate class 1

TR-3 customers, then the alternative solution is to develop a volumetric surcharge per Dth 2

billed, and not to shift the extra revenue to other customers. 3

Q. DID YOU RECALCULATE THE SURCHARGE RATE FOR EACH PROGRAM 4

BASED ON THE ANNUAL REVENUE REQUIREMENT APPROACH AND THE 5

PRE-TAX COST OF CAPITAL THAT YOU PROPOSE IN THIS RATE CASE? 6

A. Yes. In Exhibits AG-33 and AG-34, I have calculated the annual surcharges for each year 7

from 2021 to 2025 for the MRP and IRIP, respectively, using my proposed pre-tax cost of 8

capital and assuming the Commission approves both programs. 9


A. The average surcharge rates proposed by the Company for the MRP and IRIP are not fair 11

and reasonable. Therefore, I recommend that the Commission reject those surcharges and 12

instead approve annual surcharge rates and a simple annual reconciliation procedure that 13

ensure the Company spend the targeted annual capital expenditures for the programs or 14

sets aside the revenue requirement for the amount of targeted capital expenditures 15

underspent for later refunding to customers. 16

Furthermore, I recommend that the Commission reject the proposed MRP and IRIP 17

monthly surcharge limit of $1,000 and the shift of revenue recovery from rate schedule 18

TR-3 customers to other customers. 19


XII. Facility Improvement Demand Surcharge 1

Q. ARE PROPOSING ANY CHANGES TO THE FACILITY IMPROVEMENT 2

DEMAND SURCHARGE PROPOSED BY THE COMPANY? 3

A. Yes. On page 15 and 16 of his direct testimony, Company witness Walter Fitzgerald 4

proposes a Facility Improvement Demand (“FID”) surcharge to charge transportation 5

customers for their share of costs incurred for the construction of interconnection facilities 6

with interstate pipelines in conjunction with building the Marquette Connector Pipeline. 7

The interconnection costs will benefit all customers groups of the Company, including 8

GCR, GCC and transportation customers. GCR and GCC customers will pay their share 9

of the costs through a Balancing and Demand Charge billed through the GCR mechanism. 10

Transportation customers will pay their share of the pipeline interconnection costs through 11

the FID surcharge. 12

In the 2019-2020 GCR plan in Case No. U-20245, the Company proposed two other 13

pipeline interconnections with Vector Pipeline at Cassopolis and DTE Energy at Adair. 14

The total estimated cost of the two interconnections is $4,181,000.25 In settlement of Case 15

No. U-20245, the Company, the AG and Staff agreed that a portion of the $4,181,000 16

should be charge to transportation customers and included in the FID surcharge set in this 17

rate case. Assuming that the Commission approves the settlement of Case No. U-20245, 18

25 Walter Fitzgerald direct and supplemental testimony and Revised Exhibit A-10


I propose that 26% of the $4,180,000, or $1,086,800, be included in the calculation of the 1

FID surcharge. 2

Q. DID YOU REVISE EXHIBIT A-34 (WEF-04) TO INCLUDE THESE ADDITIONAL 3

COSTS? 4

A. Yes. In Exhibit AG-35 I have added to the amount previously identified on line 11 of 5

Exhibit A-34, the amount of $1,642,500 for the year 2020 and $2,537,500 for 2021, for a 6

total amount of $4,180,000. The additional amounts change the surcharge rate for 2020 7

from $0.0239 to $0.431 per Dth, and for 2021 from $0.0239 to $0.0535 per Dth. 8


A. I recommend that the Commission approve the revised FID surcharge rates I have 10

calculated in Exhibit AG-35 for each of the applicable years. The Commission should also 11

approve a procedure to update the FID surcharge as new interconnection projects are 12

approved in future years. 13

XIII. Adjustments To Revenue Deficiency 14

Q. WHAT ARE THE TOTAL ADJUSTMENTS AND THE REVISED REVENUE 15

DEFICIENCY YOU RECOMMEND? 16


A. Exhibit AG-36 summarizes the adjustments to rate base and operating income. The net 1

result is a revised revenue deficiency of $8.4 million, which is a reduction of $29.7 million 2

from the Company’s requested level of $38.1 million. 3

I recommend the Commission adopt these adjustments and issue an order granting rate 4

relief to the Company in an amount not exceeding $8.4 million. 5

Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY? 6

A. Yes, it does. However, I reserve the right to amend, revise and supplement my testimony 7

to incorporate new information that may become available. 8

Appendix A

Experience and Qualifications of Sebastian Coppola

1

Mr. Sebastian Coppola is an independent energy business consultant and president

of Corporate Analytics, Inc., whose place of business is located at 5928 Southgate

Rd., Rochester, Michigan 48306.

EMPLOYMENT BACKGROUND

Mr. Coppola has been an independent consultant for more than 15 years.

Before that, he spent three years as Senior Vice President and Chief Financial

Officer of SEMCO Energy, Inc. with responsibility for all financial operations,

corporate development and strategic planning for the company’s Michigan and

Alaska regulated and non-regulated operations. During the period at SEMCO

Energy, he had also responsibility for certain storage and pipeline operations as

President and COO of SEMCO Energy Ventures, Inc. Prior to SEMCO, Mr.

Coppola was Senior Vice President of Finance for MCN Energy Group, Inc., the

parent company of Michigan Consolidated Gas Company (now DTE Gas

Company).

During his 24-year career at MCN and MichCon, he held various

analytical, accounting, managerial and executive positions, including Manager of

Gas Accounting with responsibility for maintaining the accounting records and

preparing financial reports for gas purchases and gas production. In this role, he

had also responsibility for preparing Gas Cost Recovery (GCR) reconciliation

analysis and reports, and supporting preparation of testimony for the cost of gas

reconciliation proceedings before the MPSC. Over the years, Mr. Coppola also

held the positions of Treasurer, Director of Investor Relations, Director of

Accounting Services, Manager of Corporate Finance, Manager of Customer Billing

and Manager of Materials Inventory and Warehousing Accounting. In many of

Appendix A


2

these positions he interacted with various operating areas of the company and was

intricately involved in construction and operating programs, defining gas

purchasing strategies, rate case analysis, cost of capital studies and other regulatory

proceedings.

ENERGY INDUSTRY EXPERIENCE

Mr. Coppola has been an independent consultant for more than 15 years.

Before that, he spent three years as Senior Vice President and Chief Financial

Officer of SEMCO Energy, Inc. with responsibility for all financial operations,

corporate development and strategic planning for the company’s Michigan and

Alaska regulated gas utility operations and non-regulated businesses. During the

period at SEMCO Energy, he had also responsibility for certain storage and

pipeline operations as President and COO of SEMCO Energy Ventures, Inc. Prior

to SEMCO, Mr. Coppola was Senior Vice President of Finance for MCN Energy

Group, Inc., the parent company of Michigan Consolidated Gas Company.

During his 24-year career at MCN and MichCon, he held various

analytical, accounting, managerial and executive positions, including Manager of

Gas Accounting with responsibility for maintaining the accounting records and

preparing financial reports for gas purchases and gas production. In this role, he

had also responsibility for preparing Gas Cost Recovery (GCR) reconciliation

analysis and reports, and supporting preparation of testimony for the cost of gas

reconciliation proceedings before the MPSC. Over the years, Mr. Coppola also

held the positions of Treasurer, Director of Investor Relations, Director of

Accounting Services, Manager of Corporate Finance, Manager of Customer Billing

and Manager of Materials Inventory and Warehousing Accounting. In many of

Appendix A


3

these positions he interacted with various operating areas of the company and was

intricately involved in construction and operating programs, defining gas

purchasing strategies, rate case analysis, cost of capital studies and other regulatory

proceedings.

Mr. Coppola is intricately knowledgeable of capital markets and financial

institutions. As Treasurer and Vice President of Finance, he has directed the

issuance of more than $2 billion in securities, including common stock, corporate

bonds, tax-deductible preferred stock and high-equity value convertible securities.

He has established bank lines of credit, commercial paper and asset acquisition

facilities. He has had extensive interactions with equity and debt investors,

financial analysts, rating agencies and other members of the financial community.

ENERGY INDUSTRY REGULATORY EXPERIENCE

As a business consultant, Mr. Coppola specializes in financial and strategic

business issues in the fields of energy and utility regulation. He has more than

forty years of experience in public utility and related energy work, both as a

consultant and utility company executive. He has testified in several regulatory

proceedings before State Public Service Commissions. He has prepared and/or

filed testimony in electric and gas general rate case proceedings, power supply and

gas cost recovery mechanisms, revenue and cost tracking mechanisms/riders and

other regulatory proceedings. As accounting manager and later financial executive

for two regulated gas utilities with operations in Michigan and Alaska, he has been

intricately involved in operating and construction programs, gas cost recovery and

reconciliation cases, gas purchase strategies and rate case filings.

Appendix A


4

Mr. Coppola has extensive experience with gas utilities in the areas of gas

operations, gas supply and regulatory proceedings. He has led or participated in

the financial operations, gas supply planning and/or gas cost recovery

arrangements of two major gas utilities in Michigan and in Alaska. He has

prepared testimony in multiple electric and gas general rate cases, Power Supply

Cost Recovery (PSCR) and Gas Cost Recovery (GCR) reconciliation proceedings,

Cast Iron and Pipeline Replacement Programs and other regulatory cases on behalf

of the Michigan Attorney General, Citizens Against Rate Excess (CARE), the

Public Counsel Division of the Washington Attorney General, the Illinois Attorney

General and the Ohio Office of Consumers Counsel in electric and gas utility rate

cases, including AEP Ohio, Ameren-Illinois Utilities, Avista, Consumers Energy,

Detroit Edison, MichCon (DTE Gas), Michigan Gas Utilities Corp, PacifiCorp,

Peoples Gas, Puget Sound Energy, SEMCO, Upper Peninsula Power Company and

Wisconsin Public Service Company.

As accounting manager and later financial executive for two regulated gas

utilities, he has been intricately involved in construction materials procurement,

gas purchase strategies and CGR reconciliation cases. He has had direct

responsibility for preparing GCR reconciliation analysis and reports, and

supporting preparation of testimony for the cost of gas reconciliation proceedings

before the Michigan Public Service Commission (MPSC). He is intricately familiar

with construction projects, the power supply and gas cost recovery mechanisms,

gas supply and pricing issues, and regulatory issues faced by utilities.

As manager of customer billing, Mr. Coppola developed intricate

knowledge of customer billing and meter reading operations. As manager of

Appendix A


5

materials inventory and warehousing accounting, he also developed intricate

knowledge of pipeline and materials procurement, warehousing and construction

operations including safety compliance issues. Mr. Coppola has testified

extensively on gas utility pipeline, service lines and inside meters replacement

programs related to at-risk pipes that provide safety issues to customers and the

general public.

In his role as Treasurer and Chairman of the MCN/MichCon Risk

Committee from 1996 through 1998, Mr. Coppola was involved in reviewing and

deciding on the appropriate gas purchase price hedging strategies, including the

use of gas future contracts, over the counter swaps, fixed price purchases and index

price purchases.

In March 2001, Mr. Coppola testified before the Michigan House Energy

and Technology Subcommittee on Natural Gas Fixed Pricing Mechanisms. Mr.

Coppola frequently participates in natural gas issue forums sponsored by the

American Gas Association and stays current on various energy supply issues

through review of industry analyst reports and other publications issued by various

trade groups.

Specific Regulatory Proceedings And Related Experience:

o Filed testimony on behalf of the Michigan Attorney General in SEMCO Energy Gas Company (SEMCO) 2019-2020 GCR Plan case U-20479.

o Filed testimony on behalf of the Michigan Attorney General in Consumers Energy Company (CECo) 2019-2020 GCR Plan case U-20233.

Appendix A


6

o Filed testimony on behalf of the Michigan Attorney General in DTE Electric Company (DTEE) 2019 PSCR Plan case U-20221.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas Company (DTE Gas) 2019-2020 GCR Plan case U-20235.

o Filed testimony on behalf of the Michigan Attorney General in Michigan Gas Utilities Corporation (MGUC) 2019-2020 GCR plan case U-20239.

o Filed rebuttal testimony on behalf of the Illinois Attorney General in Nicor Gas 2018 rate case on capital expenditures and rate base additions in Docket 18-1775.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2017-2018 GCR reconciliation case U-20076.

o Filed testimony on behalf of the Michigan Attorney General in Consumers Energy (CECo) 2017-2018 GCR reconciliation case U-20075.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 gas rate Case U-20322 on several issues, including operation and maintenance expenses, capital expenditures, cost of capital, rate design and other items.

o Filed testimony on behalf of the Michigan Attorney General in Michigan Indiana Power Company (I&M) Tax Credit C Calculation in case U-20317.

o Filed direct testimony on behalf of the Illinois Attorney General in Nicor Gas 2018 rate case on capital expenditures and rate base additions in Docket 18-1775.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas Tax Credit C Calculation in case U-20298.

o Filed testimony on behalf of the Michigan Attorney General in CECo Tax Credit C Calculation for the Gas and Electric Divisions in case U-20309.

o Filed testimony on behalf of the Michigan Attorney General in Upper Peninsula Power Company 2018 electric rate Case U-20276 on several issues, including excess deferred taxes, cost of capital, rate design and other items.

Appendix A


7

o Filed testimony on behalf of the Michigan Attorney General in DTE Electric (DTEE) 2018 rate Case U-20162 on several issues, including operation and maintenance expenses, capital expenditures, cost of capital, rate design and other items.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 Tax Credit B refund for the Electric Division in case U-20286.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 Integrated Resource Plan in case U-20165.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 Tax Credit B refund case U-20287 for the natural gas business.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2018 Tax Credit B refund case U-20189.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 electric rate Case U-20134 on several issues, including capital expenditures, cost of capital, rate design and other items.

o Filed direct testimony on behalf of the Illinois Attorney General for the reconciliation of the rate surcharge for the Qualified Infrastructure Program (Rider QIP) of the Peoples Gas and Coke Company’s (Peoples Gas) in Docket 16-0197.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2016-2017 GCR reconciliation case U-17941-R.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO Energy Gas Company (SEMCO) 2018-2019 GCR Plan case U-18417.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 Tax Credit A refund case U-20102.

o Filed testimony on behalf of the Michigan Attorney General in I&M 2018 PSCR Plan case U-18404.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2018-2019 GCR Plan case U-18412.

o Filed testimony on behalf of the Michigan Attorney General in Upper Peninsula Power Company (UPPCO) 2018 Tax Credit A refund case U-20111.

Appendix A


8

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2018 Tax Credit A refund case U-20106.

o Filed testimony on behalf of the Michigan Attorney General in DTEE 2018 PSCR Plan case U-18403.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2018 PSCR Plan case U-18402.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2017 gas rate Case U-18999 on several issues, including revenue, operations and maintenance costs, capital expenditures, cost of capital, rate design and other items.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2017 gas rate Case U-18424 on several issues, including revenue, operations and maintenance costs, capital expenditures, cost of capital, rate design and other items.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2016 PSCR reconciliation case U-17918-R.

o Assisted the Michigan Attorney General in the review of several GCR and PSCR cases during 2017 and 2018, and proposed terms for settlement of those cases.

o Assisted the Michigan Attorney General in the filing of comments with the Michigan Public Service Commission relating to rate case filing requirements in case U-18238, refunds of tax savings from the lower federal tax rate in case U-18494 and Performance Based Regulation.

o Filed direct and rebuttal testimony on behalf of the Illinois Attorney General for the reconciliation of the rate surcharge for the Qualified Infrastructure Program (Rider QIP) of the Peoples Gas and Coke Company’s (Peoples Gas) in Docket 15-0209.

o Filed testimony on behalf of the Michigan Attorney General in DTEE 2017 electric Rate Case U-18255 on a several issues, including revenue, operations and maintenance costs, capital expenditures, cost of capital, rate design and other items.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2017 electric rate Case U-18322 on a several issues, including

Appendix A


9

revenue, operations and maintenance costs, capital expenditure programs, cost of capital and other items.

o Filed direct and rebuttal testimony on behalf of the Illinois Attorney General for the re-opening of proceedings in the restructuring of the Peoples Gas’s main replacement program and gas system modernization plan in Docket 16-0376.

o Filed testimony on behalf of the Michigan Attorney General in the Upper Michigan Energy Resources Corporation (UMERC) application for a certificate of public necessity and convenience to build two power plants in the Upper Peninsula of Michigan in case U-18202.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO application for a certificate of public necessity and convenience to build a pipeline in the Upper Peninsula of Michigan in case U-18202.

o Filed testimony on behalf of the Public Counsel Division of the Washington Attorney General in Puget Sound Energy’s 2016 Complaint for Violation of Gas Safety Rules in Docket No. UE-160924.


o Filed testimony on behalf of the Michigan Attorney General in CECo 2015 Power Supply Cost Recovery (PSCR) reconciliation case U-17678-R.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2016 gas general rate case U-18124 on a several issues, including revenue, operations and maintenance costs, capital expenditures, working capital, cost of capital and other items.

o Filed testimony on behalf of the Illinois Attorney General for the restructuring of the Peoples Gas’s main replacement program in Docket 16-0376.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2014-2015 GCR Plan reconciliation case U-17332-R.

Appendix A


10

o Filed testimony on behalf of the Michigan Attorney General in the formation of UMERC and the transfer of Michigan assets of Wisconsin Public Service Corporation and Wisconsin Electric Company to UMERC in Case U-18061.

o Filed testimony on behalf of the Michigan Attorney General in CECo Court of Appeals Remand Case U-17087 for review of the Automated Meter Infrastructure (AMI) opt-out fees.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2016 electric Rate Case U-17990 on a several issues, including revenue, operations and maintenance costs, capital expenditure programs, cost of capital, rate design and other items.

o Filed testimony on behalf of the Michigan Attorney General in Michigan Gas Utilities Corporation (MGUC) 2016-2017 GCR Plan case U-17940.

o Filed testimony on behalf of the Michigan Attorney General in DTEE 2016 electric Rate Case U-18014 on a several issues, including revenue, revenue decoupling, operations and maintenance costs, capital expenditures, cost of capital, rate design and other items.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO 2016-2017 GCR Plan case U-17942.


o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2015 gas general rate case U-17999 on a several issues, including revenue, operations and maintenance costs, capital expenditures, main replacement program, Revenue Decoupling Mechanism (RDM) program, cost of capital and other items.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2016-2017 GCR Plan case U-17943.


o Filed testimony on behalf of the Michigan Attorney General in CECo 2014-2015 GCR Plan reconciliation case U-17334-R.

Appendix A


11


o Filed testimony on behalf of the Michigan Attorney General in SEMCO 2014-2015 GCR Plan reconciliation case U-17333-R.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2015 gas general rate case U-17882 on a several issues, including revenue, operations and maintenance costs, capital expenditures, main replacement program, infrastructure cost recovery mechanism, cost of capital and other items..

o Filed testimony on behalf of the Michigan Attorney General in CECo Gas Choice and End-User Transportation tariff changes case U-17900.

o Analyzed the gas rate case filings of MGUC in Case U-17880 and assisted the Michigan Attorney General in settlement of the case.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2014 PSCR reconciliation case U-17317-R.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas 2013-2014 GCR Plan reconciliation case U-17131-R.

o Filed testimony on behalf of the Michigan Attorney General in DTEE 2014 electric Rate Case U-17767 on a several issues, including operations and maintenance costs, capital expenditures, AMI program, cost of capital and other items.


o Filed testimony on behalf of the Illinois Attorney General in Ameren Illinois Company’s 2015 general rate case on operation and maintenance costs in Docket 15-0142.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2014 electric Rate Case U-17735 on a several issues, including sales, operations and maintenance costs, capital expenditures, cost of capital, AMI program, revenue decoupling and infrastructure cost recovery mechanisms.


Appendix A


12

o Filed testimony on behalf of the Michigan Attorney General in MGUC 2015-2016 GCR Plan case U-17690.


o Analyzed the electric rate case filings of Northern States Power in Case U-17710 and Wisconsin Public Service Company U-17669, and assisted the Michigan Attorney General in settlement of these cases.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2013-2014 GCR Plan reconciliation case U-17133-R.

o Filed testimony on behalf of the Michigan Attorney General in MGUC 2013-2014 GCR Plan reconciliation cases U-17130-R.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO 2013-2014 GCR Plan reconciliation case U-17132-R.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2014 gas general rate case U-17643 on a several issues, including revenue, operations and maintenance costs, capital expenditures, main replacement program, cost of capital and other items..

o Filed testimony on behalf of the Illinois Attorney General in Wisconsin Energy merger with Integrys on the Peoples Gas and Coke Company’s Accelerated Main Replacement Program Docket 14-0496.

o Filed testimony on behalf of Citizens Against Rate Excess in Wisconsin Public Service Company’s 2013 PSCR plan reconciliation case U-17092-R.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2014 PSCR plan case U-17317.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2014 OPEB Funding case U-17620.




Appendix A


13

o Filed testimony for Citizens Against Rate Excess in Wisconsin Public Service Company’s 2014 PSCR plan case U-17299.

o Filed testimony in March 2013 on behalf of the Michigan Attorney General in CECo’s electric Rate Case U-15645 on remand from the Michigan Court of Appeals for review of the AMI program.

o Filed testimony for Citizens Against Rate Excess in Upper Peninsula Power Company’s 2012 PSCR plan case U-17298.

o Filed testimony on behalf of the Michigan Attorney General in MGUC 2012-2013 GCR Reconciliation case U-16920-R.

o Filed testimony on behalf of the Michigan Attorney General in DTE Gas Company 2012-2013 GCR Reconciliation case U-16921-R.

o Filed testimony on behalf of the Michigan Attorney General in CECo 2012-2013 GCR Reconciliation case U-16924-R.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO 2012-2013 GCR Reconciliation case U-16922-R.

o Filed testimony for Citizens Against Rate Excess in Upper Peninsula Power Company’s 2012 Power Supply Cost Recovery (PSCR) reconciliation case U-16881-R.

o Filed testimony in Puget Sound Energy’s 2013 Power Cost Only Rate Case on behalf of the Public Counsel Division of the Washington Attorney General in Docket No. UE-130167 on the power costs adjustment mechanism.

o Filed testimony in PacifiCorp’s 2013 General Rate Case on behalf of the Public Counsel Division of the Washington Attorney General in Docket No. UE-130043 on power costs, cost allocation factors, O&M expenses and power cost adjustment mechanisms.



o Filed testimony on behalf of the Michigan Attorney General in CECo’s 2012 electric Rate Case U-17087 on a several issues, including cost of service methodology, rate design, operations and

Appendix A


14

maintenance costs, capital expenditures and infrastructure cost recovery mechanism and other revenue/cost trackers.

o Filed reports on gas procurement and hedging strategies of four gas utilities before the Washington Utilities and Transportation Commission on behalf of the Washington Attorney General – Office of Public Counsel in April 2013.

o Filed testimony on behalf of the Michigan Attorney General in MGUC and SEMCO 2011-2012 GCR Plan reconciliation cases U-16481-R and U-16483-R.

o Filed testimony for Citizens Against Rate Excess in Upper Peninsula Power Company’s 2012 Power Supply Cost Recovery (PSCR) plan case U-17091.

o Filed testimony in MichCon’s 2012 gas Rate Case U-16999 on a several issues, including sales volumes, revenue decoupling mechanism, operations and maintenance costs, capital expenditures and infrastructure cost recovery mechanism.

o Filed testimony on behalf of the Washington Attorney General – Office of Public Counsel on executive and board of directors’ compensation in the 2012 Avista general rate case.

o Filed testimony for Citizens Against Rate Excess in Upper Peninsula Power Company’s 2011 Power Supply Cost Recovery (PSCR) reconciliation case U-16421-R.

o Filed testimony on behalf of the Ohio Office of Consumers Counsel in AEP Ohio’s power supply restructuring case in June 2012.

o Filed testimony on behalf of the Michigan Attorney General in MGUC and SEMCO 2012-2013 GCR Plan cases U-16920 and U-16922.

o Filed testimony for Citizens Against Rate Excess in Upper Peninsula Power Company’s 2012 PSCR plan case U-16881.

o Filed testimony for Citizens Against Rate Excess in Wisconsin Public Service Corporation‘s 2012 PSCR plan case U-16882.

o Filed testimony for the Michigan Attorney General in CECo’s gas business Pilot Revenue Decoupling Mechanism in case U-16860.

Appendix A


15

o Filed testimony for the Michigan Attorney General in Consumers Energy Gas 2011 Rate Case U-16855 on several issues, including sales volumes, operations and maintenance cost, employee benefits, capital expenditures and cost of capital.

o Filed testimony for the Michigan Attorney General in SEMCO and MGUC 2010-2011 GCR Plan reconciliation cases U-16147-R and U-16145-R.

o Filed testimony for the Michigan Attorney General in Consumers Energy 2011 electric Rate Case U-16794 on several issues, including electric sales forecast, revenue decoupling mechanism, operations and maintenance cost, employee benefits, capital expenditures and cost of capital.

o Filed testimony for the Michigan Attorney General in CECo’s electric business Pilot Revenue Decoupling Mechanism in case U-16566.

o Filed testimony on behalf of the Michigan Attorney General in SEMCO and MGUC 2011-2012 GCR Plan cases U-16483 and U-16481.

o Filed testimony for the Michigan Attorney General in Detroit Edison 2010 electric Rate Case U-16472 on several issues, including revenue decoupling mechanism, operations and maintenance cost, executive compensation and benefits, capital expenditures and cost of capital.

o Filed testimony for the Michigan Attorney General in SEMCO 2009-2010 GCR reconciliation case U-15702-R.

o Filed testimony for Michigan Attorney General in MGUC 2009-2010 GCR reconciliation case U-15700-R.

o Filed testimony for Michigan Attorney General, in Consumers Energy Gas 2010 Rate Case U-16418 on several issues, including sales volumes, operations and maintenance costs, capital expenditures and cost of capital.

o Filed testimony for Michigan Attorney General, in SEMCO 2010 Rate Case U-16169 on several issues, including sales volumes, rate design, operations and maintenance cost, executive compensation and benefits, capital expenditures and cost of capital.

Appendix A


16

o Filed testimony, for Michigan Attorney General in Consumers Energy 2009 electric Rate Case U-16191 on several issues, including sales volumes, revenue decoupling mechanism, operations and maintenance cost and capital expenditures.

o Filed testimony for Michigan Attorney General, in MichCon 2009 gas Rate Case U-15985 on several issues, including sales volumes, revenue decoupling mechanism, operations and maintenance cost, capital expenditures and cost of capital.

o Filed testimony for Michigan Attorney General and was cross-examined in Consumers Energy 2009 gas Rate Case U-15986 on several issues, including sales volumes, revenue decoupling mechanism, operations and maintenance cost, capital expenditures and cost of capital.

o Prepared testimony and assisted the Michigan Attorney General in discussions and settlement of SEMCO and MGUC 2010-2011 GCR Plan cases U-16147 and U-16145.

o Prepared testimony and assisted Michigan Attorney General in settlement of SEMCO 2009-2010 GCR case U-15702.

o Prepared testimony and assisted Michigan Attorney General in settlement of MGUC 2009-2010 GCR case U-15700.

o Prepared testimony and assisted the Michigan Attorney General in discussions and settlement of SEMCO 2008-2009 GCR case U-15452 and reconciliation case U-15452-R.

o Prepared testimony and assisted Michigan Attorney General in discussions and settlement of MGUC 2008-2009 GCR reconciliation case U-15450-R.

o Prepared testimony for Michigan Attorney General in SEMCO GCR 2007-2008 Reconciliation Case U-15043-R.

o Prepared testimony for Michigan Attorney General filed in MGUC 2007-2008 GCR Reconciliation Case U-15040-R.

o Participated in drafting of testimony for all aspects of SEMCO rate case filing with the Regulatory Commission of Alaska (RCA) in 2001.

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o Filed testimony in 2001 before the (RCA) and was cross-examined on the financing plans for the acquisition of Enstar Corporation and the capital structure of SEMCO.

o Developed a cost of capital study in support of testimony by company witness in the Saginaw Bay Pipeline Company rate request proceeding in 1989.

o Prepared testimony for company witness on cost of capital and capital structure in MichCon 1988 gas rate case.

o Filed testimony in MichCon gas conservation surcharge case in 1986-87.

o Testified before MPSC ALJ in MichCon customer bill collection complaints in 1983.

o Participated in analysis of uncollectible gas accounts expense for inclusion in rate filings between 1975 and 1988.

o Participated in analysis of allocation of corporate overhead to subsidiaries and use of the “Massachusetts Formula” at MichCon and at SEMCO in 1975 and 2000.

o Prepared support information on GCR and rate case-O&M testimony at MichCon from 1975 to 1988.

o Filed testimony in MichCon financing orders in 1987 and 1988.

o Participated in rate case filing strategy sessions at MichCon and SEMCO from 1975 to 2001.

o Provided Hearing Room assistance and guidance to counsel on financial and policy issues in various cases from 1975 to 2001.

EDUCATIONAL BACKGROUND

Mr. Coppola did his undergraduate work at Wayne State University, where

he received the Bachelor of Science degree in Accounting in 1974. He later

Appendix A


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returned to Wayne State University to obtain his Master of Business

Administration degree with major in Finance in 1980.

Documents

DANA NESSEL ATTORNEY GENERAL